Kodiak Oil & Gas Corp (NYSE:KOG)
Global Oil and Gas Conference
May 21, 2014 / 8:30 A.M. E.T.
Lynn Peterson – President, CEO
James Henderson – CFO, Treasurer
Betty Jiang – UBS Securities
Good morning everyone. Thank you Betty, thank the UBS team for hosting us again this year. Looks like it's a good turnout.
Kodiak is a pretty straightforward story. It's all about North Dakota, it's all about the Williston Basin, so we'll see if we can get this going and we'll be good to go.
Currently we're operating 7 drilling rigs. We have about 171,000 net acres. Production is growing; it's a growth story. We're currently somewhere around 38,000 to 40,000 barrels a day of production. Guidance set out at somewhere between 39,000 and 42,000 for the year. So I think we're on good track to meet the guidance that's been put out.
We had to spend about $940 million doing this. I think the first quarter was a little slow as we came through the winter period. We're ramped up here, running strong here as we go through April and May.
Again, just touch on the growth. We're looking to achieve somewhere around a 35% to 40% growth here in 2014. As I mentioned, the first quarter was a little bit light for us as we came through the winter period. It was pretty cold up in North Dakota this year. We hit stride kind of in March, as everything started warming up. Our completions are moving along in great shape here as we exit May and feel good about the rest of the year.
I mentioned $940 million CapEx, down a little bit from a year ago. We anticipate drilling and completing about 100 net wells. So about $890 million is allocated drilling completion costs, with additional $40 million for infrastructure and roughly $10 million allocated for small leasehold acquisitions, kind of bolt-on activity.
As we look at the year, the first quarter we completed 19 net wells. We're on track really to hit our target of about 100, so the next three quarters we ought to average somewhere between 26, 28 wells net per quarter. And again, we look back at April, May, we've completed about 10 net wells in each of those months, so again, good shape to move forward.
All of our activity really for the balance of the year is going to be down through the core area. I'll show you in just a bit. Most of our acreage is really located in the deeper part of the basin, where we see the biggest reserves I think throughout the basin. We'll talk a little bit about our well cost and economics later on, but you can see we're driving these down.
Currently our AFBs are somewhere between typically $8.5 million to $9 million, depending on exact depth and distance. These numbers have been driven down largely because of efficiencies. We've taken our drilling days down immensely from a few years back. We continue to work on our completions, tweaking it. You can hear a lot of chatter about different types of completions going on and I think the whole industry is evolving as this play moves forward.
Reserve wise, again, significant growth year-over-year. We should continue that trend as we continue to drill out, working our downspacing and develop reserves.
This is a map of the North Dakota side of the basin, where all of our properties are located. We'll start on the right hand side of the map. This is Dunn County. Just south of the Parshall field, which is really a discovery of the current day Bakken as we know it. Some of our best wells over here. EURs let's say from low 750,000 to well over 1 million barrels. We continue to run 1 rig over here. We've been working on the infrastructure. That's come along great in the last six months. I think we're on track really to probably move a second rig in here later this year. So significant results over here.
The area we're going to talk a lot about today, we call our Polar, Koala area, kind of northern McKenzie County, southern Williams County. It's an area where we've done a lot of activity. Looking at downspacing, we've got some results that we'll share with you this morning. We spent a great deal of time building out infrastructure. We're currently able to sell much more of our gas than we have previous quarters. I think we're kind of looking for third quarter here to improve that one more step.
We'll throw this out just to show economics of the play. Again, four different type of EURs, 900,000 down to 600,000 within each one of those. We tried to get three different pricing scenarios; 95, 85 and 75. Each of those, we deducted $10 for base and differentials. I think that's probably a fair number. We've seen this number float around a little bit, but I think with the addition of the rail, which we'll touch on later, these differentials ought to stay in this ballpark. So we're comfortable with that.
We're using a per average well cost of 8.7, again, kind of midpoint to where our APs are today and coming down. So you can see, the economics are pretty robust. These wells I think the key to all of this is how quick you get your money back and kind of in the worst case scenario, you're looking at about a two-year payout. Certainly we've had wells payout in less than a year. So, it at least gives you an idea of what we're trying to achieve here.
On the right side, some of our early wells that we've drilled, trying to overlay them on different type curves. The green lines are our Bakken wells. The red lines are the Three Forks wells. When we look at Dunn County, and I think it's important to note, as you move around the basin, you see different numbers here for Bakken and Three Forks and I think as we look at Dunn County, we see a Three Forks well being very comparable to a Bakken, slightly less, but very comparable.
I think as you go down the Nesson Anticline, you see Three Forks wells have exceeded Bakken wells in a lot of cases; some prolific wells in that area. As we get to the west, again, over in our Polar area, we look pretty much at Three Forks being about 15% less than a Bakken well. I think you can see this, again, all the red lines are in the lower end of the scale here. The green lines are at the top.
So this is what we spent the last couple of years doing. We can start at the very top. We took a full 1,280 acre spacing unit, we set out to drill 12 wells in that 1,280; 6 of them were placed in the middle Bakken member, placed wellbores about 800 feet apart. We went down into Three Forks. We refer to the Three Forks as Upper Middle Lower, also referred to as first, second and third benches. Our opinion is that this is a large reservoir of oil. We don't believe that each of the intervals are separate reservoirs. We think as we stimulate these wells, we see communication between the intervals.
We set our first program up more or less in a Chevron pattern where we alternated between Upper and Middle. Again, the wells were separated about 800 feet apart.
We lay out our production through seven months here. You can see the wells are performing quite nicely and again, falling about that 15% change between Middle Bakken and Three Forks.
I'd like to point out, there's a lot of discussion about new completion techniques, things that are changing the basin. I think it's all great, but I'd like to point out when we look at our wells at 180 days, the Middle Bakken wells have cumed over 101,000 barrels of oil. The Three Forks wells about 85,000 barrels of oil. So on average, nearly 94,000.
I think this compares extremely favorable to our peers that are putting out new numbers for new completions and I think we set the bar here and I think we're moving forward in pretty good shape.
I think the important part of that again, is payout. When we look at a pad of wells, you can use about 140,000, 150,000 barrels to reach payout. Again, after seven months, we're at a little over 100,000 barrels of oil.
We then moved to the DSU just to the east. We tried to tighten this up one more time. Based upon microseismic work we did, core analysis work that we continue to work on, we felt like we could go a little bit tighter. We're set out to drill a total of 16 wells in this drilling spacing unit. We've drilled 4 and completed 4. We've got 3 rigs sitting on the other 3 pads right now. So as we move through the year, we'll drill the remaining 12 wells and get them completed.
This is a project that will take us in probably to the fourth quarter of this year. We put out 30 and 60 day numbers on the first 4 wells. Again, I emphasize it's an extremely low small sample. We've had a lot of comments are we seeing degradation of reserves and all this and quite frankly, it's way too early to discuss any of this. We need to get some production data.
You've got a 2 well sample in the Bakken, 2 well sample in Three Forks. I think when we look to Middle Bakken, we're pretty comfortable. You look at Three Forks, it looks lighter than our first project. Again, these wells were completed in January and February this year. The first project was completed July and August of last summer. So weather conditions play a part.
We'll continue to monitor these wells and look forward to providing additional data. You'll note that we're also going to drill a couple of wells, the 7th and 8th wells in the Middle Bakken. We're going to go down kind of in the lower part of the middle member, the top part of the lower member. Try to see if the wells are economic at that point. Again, I think we've got to be careful looking at per well data. What we're hoping is maybe as we stimulate those wells and we crack the rocks above them and we're hoping that we'll improve the productivity of the wells that sit right above those horizons.
So we're going to start talking more about economics of the DSU, because I think it's important to not get too critical on a per well basis and think about how much oil we're able to get out of a 1,280, which I'll bring to the next point here.
So again, there's been a lot of discussion about degradation of reserves. We don't know. As we look at the early production data, they look pretty encouraging. I think certainly we're pleased where we're at today. So we tried to do a little bit of hypothetical example here of the way we look at this at least. Again, on the left-hand side, it was an 8 well spacing unit. We drilled 4 in the Middle Bakken; 4 in the Three Forks; spaced about 1,000-1,100 feet apart. These are the type of reserves that we had put out previously on wells that we drilled; about 750 for the Middle Bakken, again, less for the Three Forks. You see a net present value for the full DSU on the drill-up basis of about $100 million.
So let's go to the 12 well program, again, put the spacing about 800 feet apart in each reservoir. We said let's drop the reserves by 10%, just to show degradation. We drill this out and you can see we increased the MPV of the drilling spacing unit by nearly 20% to 120 million. We've taken that one more step to 16 wells, again, dropping the reserves one more time 10%, to get them to a lower number. And we could argue about the drop in EURs, but just to show this effect. I think it's important to note that we can see a degradation in reserves but by drilling more wells, we're getting more oil out of the DSU and we're driving the net present value forward, so I think it's important to keep in mind here.
Again, as you look at all these numbers, pay-up, I keep driving that home, because if we can take our money and we can get it back out of the ground in 18 months to two years, this play works all day long.
Touching on the financial side of this a little bit, we're pretty well hedged for 2014; about 60%, 65% of our guided production. As you guys know, the curve has got a big backwardation. We're light for 2015, as I think all the industry is. We'll continue to watch this. I think we'll see some improvements as we go through the year and we'll continue to layer on these.
From a balance sheet standpoint, the company is I think in pretty solid shape. We've got about $1.5 billion out on long-term bonds. We currently have a $1.35 billion revolver, of which $700 million has been drawn at this point, leaving us with roughly $650 million of liquidity.
I think the next slide here will talk a little bit about where we're at from an EBITDA and CapEx spend. Again, we're trying to push towards the fourth quarter being kind of neutral this year. As we look at 2015, I think that's where we finally turn the corner and get to a positive position. I think our first quarter is indicative of that. While we were light on production, when we looked at the gap between EBITDA and CapEx, we were pretty pleased with the small outspend. So I think we're making progress on that and I think we're on track to achieve what we've set out here.
Just looking on the left-hand side, again, you guys know oil price has been pretty robust here, so this play yields a very high margin.
Looking at production, again, rail has been instrumental in moving oil out of here. I think it's really been the focus of everything that's going on. As we move oil to the East Coast, West Coast, down to the Gulf Coast, we're going to use all facets. We use pipe. We're going to use rail.
We get a lot of questions about what we're hearing from the rail side. I think there will probably be some more regulations; there always is out of these type of events. I also think it's here to stay and we'll get through it. I don't think it's going to be a material cost to us as producers. And I think we're going to continue to grow this thing out. I think we've got plenty of capacity. The basin is currently producing about 1 million barrels a day. If the rail and pipe were combined, we'd certainly have excess capacity today and I think that will stay ahead as we move down the road.
So I'm going to go ahead and turn this back to Betty for Q&A, if there are any questions. I would just let you know, there's a lot of detail in the appendix here if you guys want to go on a per well basis. We put all the data out. We try to be pretty transparent. Betty?
Betty Jiang – UBS Securities
Great. Any questions from the audience? I'll kick it off first. You alluded to other operators testing new completion techniques and your wells right now are already looking pretty comparable with other people's bigger wells, but are you testing or planning to test any new completions yourselves or what's your view on slick water fracs and coiled tubing completions, etc?
Betty, we continue to evolve. I guess we don't talk about it maybe as much as other people, but we're continue to tweak our completions. We have not done a slick water per se. We're looking at it. We're lightening our own fluids, still using cross-linked gels. So we're evolving through this and we're watching data. Obviously we bought property that it was all slick water fracs. We had some pretty good information. We continue to watch. I think multiple entry points, all the things that you guys hear every day; we're doing all those things.
I just thought it was interesting as we look at our numbers; we're staying very much with the competition here.
Betty Jiang – UBS Securities
And then you said earlier you were potentially moving a second rig to Dunn County later this year. Is it in addition to the 7 rigs that you are currently running or are you moving 1 rig?
It's just reallocation of rigs. I think we've got 5 running over in our Polar, Koala area. We've got 1 in Dunn County. I guess we have 6 in the Koala and Polar area and 1 over in Dunn County. We've looked to taking a second one over there. As I said, the infrastructure is getting built out. These are prolific wells over there. So we're doing well.
Betty Jiang – UBS Securities
Are you testing any downspacing or cost spacing test?
Well, we're doing a lot of work, but we're doing more with the 4-well pads, as opposed to 12 type numbers. Again, we have better rocks over there. We have more natural fracturing. We may get by with less wells. We're working more up as kind of a 5 and 6-well type number over there as we look through that area.
And we've done a lot of work both north and south of the river there and getting some good results out of it. I think what's encouraging over there is that Three Forks is somewhat mirroring the Bakken; probably a little bit less, but not much.
Betty Jiang – UBS Securities
And since you started talking about seeing capital neutrality pretty soon and potentially by end of this year, so do you think you are more likely to accelerate once you reach that point where you can bring back that cash flow or potentially paying down debt after that?
I'll let Jimmy answer that. He controls the checkbook.
Yes. I think that probably the leading candidate for investing the excess cash flow would be to add a rig and accelerate, if we think that we can continue to accelerate and stay within cash flow or keep our debt metrics at a very nice level and still deliver nice growth each year.
I think there are two things, if I could just add a little bit there. Everybody asks us about when we're going to accelerate. We'll try to work on the downspacing here at the same time. The two are going to kind of come together, I think, at the right time here. We need to have an understanding of how close we want to put these wells, so we can drill them properly. And I think as we look kind of to 2015, this all kind of comes together. We've had enough history on the wells that we're going to start feeling more comfortable about it. We should be to that kind of neutral positive cash flow position. Then we can push on the accelerator a little bit if we want to. It's kind of a combination.
I think the other item we should mention here is the gas. There's a big push to improve our gas sales, capturing the gas and not flaring it. We're making some great steps. The basin has come a long ways. But I think we've got some work to do and we're working with our gas purchasers, primary one being Oneok, trying to get the right size pipe into these areas, trying to get the compression stations built in certain areas. And again, we've got to improve on that. We should be at a much higher percentage than we are today. And I think as we go through the balance of the year, you're going to see that number improve. And again, I think it all kind of comes together next year.
Betty Jiang – UBS Securities
Great. Any questions?
You know, the $940 million, we've got $40 million allocated to build out infrastructure. Most of that is well connections, some water disposal work that we continue to improve. But the bulk of it is going to drilling completion costs.
The 2 wells we're drilling down in the lower member, we look at that as exploration. We don't believe that we're going to make the same type of wells but I think it's work that we need to do to test that and see what we can get out of them. But the majority is just going to be development drilling as we work through the year.
You know, I think we're closing the gap on that. I would expect it to come down or at least maintain flat as we drill more wells. We've got all of our trunk lines for the most part, built into these areas. We've got a lot of our water disposal, which we'll be able to add additional wells. So I wouldn't expect that number to increase significantly as we move forward.
I'd point out that a lot of the infrastructure spending is on the midstream company side of the ledger. We of course pay for it through gathering fees and such, but whenever we're talking about the buildout of gas infrastructure specifically and oil transportation, that's paid for by the midstream companies. So there is a significant amount of spending. I know Oneok's capital budget up here is $1 billion, so that's where a lot of the dollars are being spent.
Betty Jiang – UBS Securities
No, I think we're good.
All right, well thank you very much, appreciate your time.
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