Lynn Peterson - Chairman, President and CEO
Kodiak Oil & Gas Corp (KOG) Johnson Rice Energy Conference Call October 1, 2013 11:00 AM ET
Okay. Next we are going to start off with another pure play Bakken, Kodiak Oil and Gas, and we have Lynn Peterson to present.
Good morning and thank you. Started a few minutes late there, we got tied up in the last meeting. We are a pretty straightforward story, Bakken 100%. Everything we have is now North Dakota. We have divested everything we have had in Montana. So we are 100% North Dakota. Currently, have about 190,000 to 195,000 net acres in the basin. We are operating seven rigs today. We have a 50% interest under another rig running with ExxonMobil on an AMI that we have on the east side at Dunn County.
We are looking to spend about $1 billion this year, I think we are pretty well on-track to close out the year pretty much in that range. We have set our production guidance to 30,000 to 34,000 barrels a day on average for the year, again, I feel pretty good where we are at. I think, realistically, we will probably be at the lower end of that. We will probably tighten the guidance up here as we go out in the third quarter, but very comfortable with where we are at.
Continuing to work on reserves, we are seeing big increases as we have gone through the year. We will touch on mainly these items here in just a bit.
Again, as we look at our operations today, we are going to continue to run seven rigs. We have two full time completion crews. We have had been down to one crew here most of September, bringing the second crew back in this following week, we will march through the rest of the year, pretty much at that same rate of pace.
We continue to work on our down spacing, we will get into that here in just a short time. We are looking to try and figure out efficiencies, as far as how we are going to develop this play, build out the infrastructure, and move ahead.
This is a map of the North Dakota Williston basin. Again, you see all of our acreage in North Dakota. We throw out some EURs in different areas. Again, as we look to the play -- if you look at our Dunn County acreage is still being our -- probably premier acreage, we are looking at EURs anywhere from 850,000 up to 1 million barrels over here.
The next largest area for us is kind of what we refer to as our Koala, Smokey, and Polar area here in the middle of the block. Probably a little bit lower, but these wells are performing extremely well, probably in that 650 to 800, 850 type number. I think if you get on the edges of play, where we have very little acreage, just kind of the southwest, some up here in Divide County. Certainly we are looking at much lower EUR, somewhere in the 350 to 450 range. I will caution that our well costs are much different up there. When we speak of our well costs, we talk about our wells, 90% of our activity that is down through to the heart of the play here.
So, we will continue to march forward here this year. As we look at our reserves, you can see we have had pretty dramatic growth. Again, as we continue to work on our down spacing here as we go out of the year, we are going to be working on Netherland, Sewell, our independent reservoir engineers, determined how to book our PUDs. Typically, we’ve got to maintain the two to three type inventory in our PUDs, that's worked out pretty well for us. Certainly as we talk about 12 wells, we have a lot of flexibility on how we want to do this, as we are going out the year. So, we will stay tuned and that will be addressed here in the next few months.
Production, we have had a pretty steep increase as this slide depicts. Again today, we are producing somewhere around 36,000 to 38,000 BOE per day, with our two completion crews going through the fourth quarter here, we expect to exit the year, north of 40,000 barrels. I feel comfortable, as I mentioned earlier, on our guidance numbers out there. Again, I will probably caution everybody that we believe they will be towards the 30,000 range at this point.
Speaking of our CapEx, again, the pie chart over the lower left depicts how we spend our money. I think this is a pretty fair representation for the balance of the year. About 10% is going to spent in the outlying areas, we refer to as our Grizzly and Wildrose areas. The bulk of our money is going right into the heart of the play, principally in the Polar, Koala and Smokey areas, and again it's a reflection of our two down spacing programs, where we did a 12 well program in each of these areas.
I think as we look at well cost here, we have seen a great change in that. Again, as we entered the year where we are probably running in the $10.5 million to $11 million wells today, I think that number is probably at $9.5 million. We certainly had our wells pushing down to the 9.2, 9.3 number, and I think as we go through the fourth quarter, our goal is to try to reach to the 9 million type number.
When we give you these numbers, these are full producing wells, that's putting wells on production. So that includes our resurface facilities. We use 100% ceramics and really 90%, 95% of our acreage, so again, depicts the entire well costs.
People often ask where we are seeing the costs, changes, obviously our drilling days, as this map shows, we will reduce our drilling days from probably a low 30s, 18 months, two years ago to the day we are running in the high teens. Q2, we averaged about 18 days per well. We think we got that a little bit better here in the third quarter. Our target is to get to 15 days per well. Again, all these things will help us push these well costs down, closer to the $9 million range.
We often get asked how our well performance is looking. We tried to give a little representation in a couple of areas. Again, the graph to the left is a 750,000 EUR type of well. We tried to lay, and represented a group of our Koala and Polar wells over the top of that. The green lines are the wells drilled in the Middle Bakken. The red ones are wells drilled in the Three Forks formation. We don't differentiate between the upper and middle members, first and second benches. You can see just generally speaking, I think our Three Forks are a little bit inferior to our Bakken, and we have always spoken to that fact, but generally pleased with where they lay out on these charts.
The one to the right, certainly that's our Dunn County acreage. We have often spoken and had 1 million barrel wells over here, I think that certainly depicts that. We do have a limited number of Three Forks over here that were drilled. Clearly, one of the better wells is Three Forks.
So the list shows you that we are tracking along with what we are putting out here in the public. Again, I think if we look at today's price, oil price, $100 to $103, differences are going to be running, as prices in the third quarter close to double digits. We are probably going to be netting somewhere around $95 a barrel, on a realized price. Certainly very robust economics. Best scenario you can see here is a $95 less seven, so I think our current activity is certainly above here, and I believe our reserves are tracking very well.
I'd like to get into a little bit of what we are doing on a down spacing program, I think this is really where the basin is headed. We chose to do two of these projects. We did one in our Polar area, just east of the city of Williston. We took the Middle Bakken formation, we spaced our wells about 800 feet apart, allowed us to put six wells into 1,280. We have a 500 foot lease setbacks on either side, again about 800 foot difference between the two well bores.
When we looked at the Three Forks, we tried to look at this a little bit different. Again, that 800 feet horizontal separation, we chose to alternate them between the middle and the upper Three Forks. Our interpretation of the Three Forks quite frankly is that, we believe that when we frac the well, and the middle member here that we are seeing communication into the upper member. We look at this as kind of one large tank of oil. I don't believe it really differs from a lot of industry statements. There are some people that talk more of these, be in different benches, separate reservoirs. We don't feel that way. We don't think it really matters at the end of the day, because you are going to need more wells to drain the same amount of oil.
So I think as we have gone through this, one of our wells, I will show you in just a bit, we took a full barrel core down through the lower Three Forks member, (inaudible) initial oil saturation all the way down. We believe our best reservoir, the Three Forks, lies in these upper two members. This has been all of our work today. We drilled a number of wells prior to 2013 in the middle member, several in the upper. We drilled a number of our wells down through, what we call the TF3 marker, which is a separation between the two intervals. And in that case, we seem to get the best penetration rates from a drilling standpoint. We also seem to be able to initiate our frac stimulation work (inaudible).
So I will show you here in just a bit, we are going to change our design a little bit on our next pad, and see if we can improve our results.
So we will start with our Polar project area; again, just to use (inaudible) Williston. If you look on the map over on the left side, you will see the green lines are the Bakken, drilling again 800 feet apart. The Middle Bakken are the orange numbers, alternate between upper and middle for the most part. The well on the west is the one we took [sidewalk core] on. We did about a 9 mile micro-seismic program over this area. All of this data is still pretty early, and I just want to caution everybody, we are trying to get the information out, because everybody keeps asking for it. It's out there in the public domains. We want to go ahead and talk about it.
We recently put our 30 day numbers out here for all the wells. You can go back and look at the history of all the wells in this area. These wells are falling right in line. I think the things we were looking at is when we frac the wells, and did we see communications offsetting wells. The answer was no, we really did not see, hardly any communication to offsetting wells. I think as we look at production, we tried to shut one well in, and see if we see any changes in offsetting wells. Again, we are just hardly seeing any interference between well bores here.
Certainly very positive in that regard, then the question arises why do you need more well bores within the DSU? There is a school of thought, certainly with a little bit of communication, perhaps we are breaking the rock up a little better, and you will get better numbers out of all of them. So we move the rig in, just to the east here, this red square here. We are drilling a series of four wells off that pad. Two in the Middle Bakken member, again the green lines; two in the Three Forks. These wells, we spaced about 600 feet part -- 600, 650 feet apart. If we are successful and if it looks right, this would allow us to put a seventh well into each of these formations. So ongoing work, again I think it's all positive at this point, we are pretty excited with what we have seen.
As we traveled around on the conference circuit, we mentioned one of our wells, you will see right here. IP for a much lower number than the rest of the wells, everybody was in a panic. Quite frankly, we knew we had a sand plug at the time. I think if you look at our 30 day numbers, you see it cleaned up in the first couple of weeks, so it has actually performed right in line with the rest of them. So we are not seeing really any difference between upper and middle. We still believe that this is one interval, and so we would expect to see consistent numbers, and I think we have been pretty successful with that.
So let me try to take these numbers, because everybody always want us to project quickly how we are doing here. We took three type curves that we just showed on that other one, 850, 750 and 350. We tried to overlay some of the early production numbers. Again we normalize these things, we have had wells shut-in, we have done some different things. We tried to take the down base out of this, and this is only just kind of our cursory review. Let's not take this and run too quickly with it. But as you can see, the Three Forks again, or the Middle Bakken are in the green lines here. They are tracking on this 750 type of range, and I think that's indicative of the previous slide that I showed you. We would expect the well to follow that trend.
When we look at the Three Forks, again, we believe they are a little bit inferior to the Bakken wells. You know, are they 10% less 15? We don't believe that's far from the truth. At the same time, clearly this is one of the best wells in the 12 well group. We probably got in some natural traction there, and it's a real horse. So it just gives you a little bit of indication, I think of where we are trending here, and we are pretty excited moving forward.
I think as we continue to look at our CapEx here and what we are doing in 2013, and really looking to 2014, we continue to put on hedges, certainly as we look at 2013 and the balance of the year, we are probably hedged upwards to 60% of our 2013 guidance, or a little bit better, almost 70% now. 2014, as you know, there has been a big backwardation of the curve, where we recently have put on some $96 numbers for 2014. We are going to continue to try to work that up, currently about 40% probably, what we anticipate for 2014. So I think we are in pretty good shape there, we will continue to push the envelope here, and try to increase 2014 in particular. 2015 is going to be a bit slow. I mean, I think we are all aware of that. If we see an opportunity, we will certainly move in that direction.
From a balance sheet standpoint, I think everybody is pretty well aware. We got about $1.55 billion out on bonds. The first tranche was done in November of 2011. First time issuance at eight and eight. We followed it up in January 2013. The rates have changed 5.5%. We did one in July, when we wrapped up our latest acquisition, that again was priced right 5.5%. Most of these are eight year bonds. So staggered out through 2022.
As we look at a margin barrel, I think this is an important slide again. People talk about differentials, and it's important, but I think the realized price is really what matters at the end of the day. So the number you see, again at the very top, this is a BOE, barrel of oil equivalent. From that, we deduct our G&A, our lease operating expense, our production taxes. Lease operating expense, trended upward in the first quarter of 2013, we have seen a downward trend through the second quarter, and we expect that to continue in the third quarter. I think going forward, we are looking for a number in that 6, 6.25 range.
We are going to continue to see some improvement, I think on our water handling side. Offsetting that improvement will probably be, just maintenance issues as our wells get a little bit older. We complete our first well, I believe in May of 2009, so those wells have just gone past four years here. So we anticipate we will see a little bit more maintenance going forward. But I think at 6, 6.25, that's probably a reasonable number.
We put the adjusted EBITDA number up here, just kind of short metrics currently. We are certainly running above, what we typically do on a debt-to-EBITDA type number, currently probably in that 3.5, 3.8 range. I think as we -- that's based on a 12 months trailing EBITDA number. If we look at our current month, our current quarter run, certainly looking forward, we quickly get back into our 2, 2.5 range. So we are pretty comfortable.
We have about $1.1 billion available on our revolver, leaving us about $500 million of drypowder at this point. One thing we are pushing at Kodiak is to get cash flow neutral, cash flow positive in 2014. We think we turn the corner, probably sometime midyear, as we exit the year we certainly ought to be in a cash positive position. So I think we got great liquidity, we are really braced here to move forward.
Quickly touch on the production and kind of circle up with the infrastructure build out. I think everyone is aware, production is approaching 900,000 barrels, probably will be 900,000 barrels here for August. Rig count has come down, I think it is just a direct reflection of our efficiencies. When we first started, we were drilling about nine or 10 wells max per year, per rig, today we are pushing on 13 wells. So we continue to push that envelope, trying to work on our mob and demob times, I think as we get more into development, we should be able to bring this down. So we are going to continue to see this production ratchet up. I would expect the rig count to stay pretty flat.
We get asked a lot of times, how Kodiak falls in the big scheme of the things. This slide, why I would never tell you it's accurate, it's pulled from the NDIC, and that's almost accurate as the data that's provided by the operators. But I think you will recognize a lot of the companies that we are above and below here. We are certainly moving up the number here, it has been a great year for the company. I think we have finally hit on full stride here. We are certainly -- this is an operated basis, this is not a net basis. Again, if you look at our August numbers, we are operating about 45,000; again, as I mentioned on a net basis, we are probably in the mid 30s. But anyway, just kind of shows you, I think where Kodiak fits in this thing.
Finally, we will talk about capacity build out. Again, most of our oil, we sell at the wellhead, we are going to continue to sell at the wellhead, we have not taken capacity on either rails or pipelines. A lot of our oil has moved to Tesoro, who is our largest purchaser. We know a lot of that oil is going to the West Coast, Anacortes facility out in the Seattle area. I think the total build out in the basin is about 1.5 million barrels for rail. I think again today, probably 500,000 to 600,000 is moving by rail. So there is plenty capacity in that regard.
Pipeline, we have tried to push more oil recently to pipelines, so we are getting a little better pricing in that regards. But there is going to be -- continue to build out and I think we have overcome that in the Williston. I think as all operators out there, I think we are all pretty comfortable that we have plenty of running room ahead of us from a transportation standpoint, and I think we have overcome many of the challenges that existed over the last couple of years.
With that, kind of just to wrap it up. Again, I think the company has grown into a pretty sizable entity from an acreage standpoint. We have really challenged our team to buy and look for quality acreage. We are not looking for number of acres. We are now looking at ourselves, compared to many of the companies out there, on an acre -- per acre basis, I think we are right at the top of the class. Liquidity, financially, we try to maintain a pretty conservative approach, we have pushed the envelope when we have had to. The markets have treated us very well from a bond standpoint. We are pleased to get off our last issuance, 5.5 to the time I think we surprised everybody, including ourselves. We didn't expect that.
Again as I look at these down spacing, I think our entire team is excited, what we have seen. We have not seen a degradation of reserves here in our opinion at this point. They look very similar to all the other wells we drill in these specific areas. We will get our next program out here, the Smokey area. You know, most of those wells are already out -- because they have been completed over several quarters, but again, we are not seeing any interference to speak on, that will materially impact what we are doing. So we are excited about it, and certainly when we look at the base and differentials, it's on a whole different ballgame what it was two years ago. So pretty excited where we are at. We look forward to moving ahead.
So that -- are they doing Q&A, or we just go to break out room? Okay. Thank you very much. Appreciate your time this morning.
[No question and answer session for this conference call.]
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