Lynn A. Peterson - Chairman, President and Chief Executive Officer
Kodiak Oil & Gas Corp. (KOG) Barclay’s CEO Energy Conference September 11, 2013 3:05 PM ET
We’ll get started with our next presentation. I am pleased to welcome Kodiak Oil & Gas to our conference. With us for the presentation today is Lynn Peterson, Kodiak’s CEO.
Lynn A. Peterson
Good afternoon, thank you [Jerry] [ph], thank you to the Barclay Group for including Kodiak this year, first time I am presenting here, so thank you all.
We’ll begin this I think everybody’s seen enough of this by, at this point in the day that we’ll move forward. Kodiak is a pretty straight forward story. We are a one basin play, Williston Basin. All of our capital is going there, so all of our activity is located in North Dakota. So it’s a pretty simple story to get your arms around in a hurry.
We currently have about 200,000 net acres. We continue to clean up our latest acquisition. That number's probably going to change a little bit as we go through the balance of the third quarter and into the fourth quarter but at end of it we should be pretty close to that.
We're currently operating seven rigs. We also have an AMI [Area of Mutual Interest] with ExxonMobil where we participate at least one to two rigs, it all ties with 50% interest. So pretty active drilling program, probably spent close to a $1 billion this year and be close to about a 100 net wells.
So at this point in September I think we are on strike to meet all these numbers that we’ve put out to everybody. We put production guidance out here of 30,000 to 34,000 for the year. And as we move through September we are currently producing somewhere between 36,000 and 38,000 BOE per day here. So I think we are in good shape and we are excited to get through the balance of the year.
We’ll talk about reserves here in just a bit and then we’ll get into our financial metrics little bit later on the presentation. I think the big thing as we go through this we’ve de-risked our block of acreage. We feel very confident in the Bakken and the Three Forks relative block. I think as we are continuing to work on down spacing let me just preface this whole thing by this, it's all early, we are doing lot of work this year ourselves as well as a number of operators, I think the Basin's improving.
I think we are certainly going to a tighter spacing. People ask us about years of inventory, I think we are comfortable saying we are somewhere probably between 12 and 15 years at our current rate here. We’ll get into this little bit more later on as we get a little more comfortable with our down spacing programs.
Kodiak, we were the first team I think to go up there and drill off of a pad. We started in November of '08. I think today we are moving more wells per pad. Currently we are drilling about everything on four well pads; we are going to try some eight well pads but we are going to do it with two rigs trying to shorten the time between first spud and first sale. So things are going on and we are going to continue to work through this as we move through the year.
This is a map of our acreage, just depicts the entire North Dakota side of the play. We are going to talk a little bit about our Dunn County acreage; it's over on the east side of the Basin, just South of Parshall. Truly this is still where we are getting our best reserves.
We are going to call back to these numbers later on and I’m going to try to lay out some wells along our decline curves to document these EURs that’s somewhere in the 800 to a 1 million barrels I think we feel comfortable throughout that block we’re seeing those type of numbers.
Same way as we talk about our Polar and Koala area, kind of North and South of Missouri River, just east of Williston. Again probably a little bit less quality but certainly in this 700 plus minus range upwards, to probably 850 to 900.
So we’ll pull back to this just an overall map just so you know the green lines are Bakken wells, the orange lines, I know it’s kind of [inaudible], these are Three Forks wells, we do not distinguish between the intervals of Three Forks to anything drilled in the Three Forks depicted as an orange line.
Before we get into the fun stuff we’ll talk a little bit about SEC requirements here. Reserves, we ran independent third party Netherland Sewell as our reserves as of June 30th. We also did the acquisition in late July, closed it, those numbers [were added] [ph] by internal reservoir engineers.
Today we are sitting roughly on about 140 million barrels of oil here. I think as we go through the balance of the year all of our pud calculations, everything is going to start to change. It’s going to be kind of interesting how we treat this I think as we go through the balance of the year. But certainly we should see a ramp-up as we go out of 2013 and continue into 2014.
Production wise, I’ll touch on little bit, we continue to pretty ramp up here. We actually - the second quarter we averaged about 23.2 like the first quarter was little below 22. Again currently we’re producing somewhere between 36,000 and 38,000 with expectations to push through to 40,000 by the end of the year and if we accomplish all this we should end up right in the range we put out between 30,000 and 34,000 BOE on average.
Talk a little bit about our capital expenditures, and I might just say that when we talk here we’re going to talk about wells drilled in the deeper part of the basin, wells where we’re using 100% ceramic proppant. Our well cost today probably run about $9.5 million, that’s come down from 10, 10.5 earlier in the year and certainly as we came out of 2012 we were closer to 10.5, 11. So we are seeing the nice drop in prices. Some of this is efficiency and some of it is well cost. So we’re continuing to work with our third party providers, and we’re making some good progress here brining these well costs down.
Again we anticipate spending about $1 billion for the full fiscal year, part of that will be for infrastructure build out, principally salt water disposal wells and in addition gathering lines to connect the salt water disposal lines. So that activity is ongoing and we’ve got all the wells drilled that we intend to drill this year. We’re continuing to hook these up to gathering systems and then as we get in ’14 we will have a few more disposal wells. But we are pretty pleased with where we’re at, at this point.
Down in the lower left hand corner you will see a pie chart, just showing you really where our activity is. Again the deep part of the play we consider the Polar, Koala, Smokey areas as well as Dunn County, the two areas are a little bit outliers for us, so what we call Wildrose up to the North and our Grizzly stuff down to the South West. Again probably around 6%, 7% of our budget we spent in those two areas. So the point being is we’re in the core part of our acreage and these are wells we’re seeing very consistent numbers out of.
I think when we look back to our well cost one of the highlights here is seeing our drilling days and I look back over a year ago and we are probably spending 25 to 30 days on these wells maybe that was 18 months ago. Today Q2 we average at 18 days, our goal is really to get to 15 days. So we’re continuing to get some efficiencies. I think our drilling guys have done a superb job here trying to drive these days downward.
Completion wise we’re currently running two fulltime 24 hour frac crews. One has been on contract with us since the beginning of 2012. The second one we kind of use off and on. They’re actually down for about three weeks here. We will bring them on at the end of September probably run through the balance of the year. So, we should be completing somewhere between 25 and 30 wells pretty regularly on a quarterly basis.
We tried to put a little chart together to show kind of really what we’re up to here and why we’re doing this. We show three types of EURs here, 650,000 barrel well, 750,000 barrel well, and 850,000 barrel well. So, what we attempted to do is take our Polar wells, and we took a sampling of the wells and we’ve overlaid along the 750,000 barrel EUR curve.
As you can see we have several wells, the green lines are the Bakken wells, the red lines are the Three Forks wells drilled in the area, and I think generally we have been pretty straight forward. We’ve always felt that the Three Forks throughout most of our acreage is slightly less than the Bakken.
I don’t what’s that number, 10% or 15% less than Bakken probably in that range. I think you will see that throughout our presentation, which you would clearly see some of our Bakken wells are exceeding the 750, and that’s why I mentioned earlier we see there is really kind of 750 to 850 type of number for the Bakken, probably 650 to 750 number for Three Forks
Overall, in the 850,000 EUR slide we’ve overlaid our Dunn County acreage. This is probably where we have the most history. We started drilling there in 2008, 20009. As you can see, we have -- clearly we have several wells exceeding an 850-type decline curve. We feel strong we have several in the million barrel plus range.
We have one Three Forks wells holding right in there with the Bakken wells, it is kind of interesting, and you will see this as we go through the presentation. While everything is pretty consistent, we certainly have areas and wells where you will see a Three Forks well performing every bit as good as a Bakken, but I think I’ll just start to show you we could back up these numbers, we see them -- all these numbers have been normalized for downtime, I would point that out.
So, we’ll get into our down spacing program, and I know there is kind of the buzz at the whole Williston right now. We have done a couple projects. I’m going to talk primarily about the one we call our Polar Block, just north of the river, east of Williston.
We chose to put six wells in the middle Bakken member. We put these wells about 800 feet apart. We went down into Three Forks, and we also drilled three wells there, but we alternated between what we referred to as the upper member and the middle member, also known as one and two.
Our attitude on the Three Forks, we believe this is actually one reservoir. We don’t believe there is a separation between the two, that it’s a seal. We believe we fracked a well in the middle member. We get communication up into the upper member and vice versa. So, we laid them out just alternating across again about 800 feet apart. I guess it would be about 400 feet of the middle Bakken wells. So, we did this in two different places. Again, we’ll talk about the one on the north, we call our Polar Block I.
We had put our IPs [out that] (ph) got after the NDIC. So, we went ahead and put everything out earlier on IP rates. Production rates, we were putting out our normal production rates that we do every month. We’ve taken this opportunity to show our 30-day rates, again these are normalized for down days, which you can see on average, we’re about 1,000 BOE per day. So, I think we’re really consistent with what we’ve seen on previous wells in the area before we started going to the tighter spacing.
I’d note; one, when we were doing all of our 12, we drilled four wells off of three pads here. We completed the inside pad first, 327 pad; we then brought two crews in and completed the outside pad simultaneously for the most part. We have one well down the list, it was a Three Forks well that we had some plugging at the surface. When we IP the well, you’ll see it IP’ed for about half or the rest of them. We thought it was sand plug and as we have produced this well, it has come clean. You can see on a 30-day rate, it’s knocked out everybody else. So today, it’s performing in line with the other wells.
So what we saw, we did a micro seismic project around this whole 1280 acre, and we’re starting to get some of the preliminary information out of that. And I guess not to get ahead of ourselves, but to date again with only limited days of production here, we are pretty encouraged with what we’ve seen.
We didn’t see a lot of communication when we were fracking these wells. We were looking for pressure in offsetting wells, we didn’t see a lot of that. As we’ve gone through first 30 or 60 days of production, we continued to shut wells in here and there to see if we see an impact on an offsetting well. To date again, we have not seen anything that makes us very nervous at this point.
So we’re pleased to date, we’ve got a rig running just to the east of this pad, the square -- red square you see on this map. We’re actually tightening it up a little bit. We’re going to do about 600 foot spacing in these wells. Again, there will be two in the middle Bakken, two in the Three Forks, and they’re going to be between 600 and 700 feet, and really that would allow us to probably put one more well in these DSUs.
Again, we look at the Bakken different than Three Folks. I think we’re probably pretty content where we are at in Three Forks. I think from the middle Bakken standpoint, we think we still have an opportunity to maybe look at a little further down spacing. So, we took all these wells and we tried to overlay them on some type curves. And again, I’ll preface this one more time, this is early-time data, but unfortunately in the world we live in, we can’t keep anything secret. So, everything gets out there. So, we decided to go ahead and put it out here and try to walk through it.
The green lines are middle Bakken wells, the red lines are Three Forks. Again, we didn’t distinguish between the upper and middle members of Three Forks, which fills one package. As you can see, we put three types of curves out here; 650, 750, and 850. Generally speaking, again I think you see the same trend, our Bakken wells are slightly outperforming our Three Forks wells, and they’re kind of trending in a typical 750,000 EUR-type decline curve.
If we look at the Three Forks, again, I think they’re probably 10%, 15% lesser quality than the middle Bakken. At the same time, you’ll see the one at the very top of the Three Forks. So again, I think we’ve got to be prepared to continue work on this, continue to see what long-term production number are.
I don’t want anybody drawing conclusions from what we put out here, because we certainly haven’t at this point. But again, we’re encouraged from what we’ve seen to date, we’ve got a [core] (ph) in one of these wells. We’ve got it in the lab right now. We’re trying to tie it into our micro seismic trying to do a lot of science here as we move through that.
So, while we are excited about it, I just want to keep this all within perspective, but I think at least I will tell you that we think we can move beyond seven and eight wells per DSU here.
Kind of getting into the financial side of the operation, we continue to be pretty active on the hedging program, sort of with recent oil -- spike in oil prices. We’ve layered on some additional hedges both in 2013, starting to reach out 2014. We’ll continue to work 2014 and see how 2015, as you guys know there is a big backwardation of the curve out there, so we are trying to be pretty patient as we look to layer on additional type hedges.
Probably from a financial perspective, if you look at the trailing six-month EBITDA number, we're higher than we’d like to be from a debt-to-EBITDA number. I think as we look at our current quarter and extrapolate forward, we are pretty comfortable where we are at. The company right now has about 1.55 billion of bonds out there. We did the first offering back in November 2011 and in 2008.
We did a second one I believe in January 2013 here at 5.5 we closed one here in July with our last acquisition for additional 400 million at 5.5%. So we’ve got these spread out through 2019 to 2021. We are pretty comfortable where we are at from financial. We probably, today we have about a $0.5 billion liquidity on a revolver. We chose to leave some debt on that side of it.
We’ll be going through a redetermination later this year or down space [inaudible] get into that determination we should see our revolver grow. So what we are really pushing for is trying to get cash neutral cash positive in 2014. We think the first half of the year we’ll probably be outspending a little bit on the cash flow basis.
As we get to the second half we think we should be at least neutral if not positive. So we are excited it’s taken a bit, but it’s gone pretty fast quite frankly and I think we’ll have the company in great shape here.
When you look at the margin on a barrel of oil, we throw this out to just kind of show you where we are at. Again the numbers at the top that’s our price for BOE, so you can’t tie it to oil, you got to look at on a BOE basis. We are continuing to work on our least operating expense. We had a little bit of tweak upwards in the first quarter, came down a little bit in second quarter we’ll continue to make progress we’ll get a more of a water disposal wells connected, and get trucks off the road.
But I think a six dollar number is probably a reasonable LOE as we look going forward. Certainly, the G&A metric is really a function of production here so we should continue to see that come down. We get a lot of discussion about differentials, certainly it’s been a little bit all over the board.
It's really a direct result or really WTI going closer into Brent. First quarter this year we were about $3.5 off the WTI, second quarter about $5.50. Today, we are probably pushing high single-digit low double digit type numbers and again primarily a function of WTI to Brent.
A lot of our oil is moving by rail, getting to that area in just a bit. From an EBITDA number, we continue to make improvements in each quarter. I think the trend will continue. So talking about the basin in general right now I think there is roughly 185 rigs to 190 rigs running in the basin.
You can see that was down from the peak of a little over 200 I think in late ’12, third quarter ’12. Really I think there's a direct relationship with efficiencies we are seeing in our rigs. We are able to drill wells, like I said we’ve driven our drilling days down from mid 20’s to high teens. We often get to mid-teens here as we go through the balance of the year and then in the next year.
So we are drilling more wells with the same amount of equipment. You continue to see the production out of the basin and I think we are pushing through 850,000 barrels. And I think that’s going to continue to grow at least in the near term.
We always get asked where we fit in the big scheme. How Kodiak stacks up to the rest of operators? This graph is data prepared by the NDIC that is North Dakota Industrial Commission. It’s gross operated production. As you can see in June, Kodiak was operating just about 36,000 barrels. That number has moved up to 45 and we are getting close to 50 here as we move through September. So we’ve made a lot of great strides.
Again you can look at this as net production. This is gross production. You then have to take royalties off, back down to your working interest. So anyway I think these are pretty recognizable names here, above us and below us. So we will continue to push those forward as we go through the balance of the year.
Talk a little bit about crude, again we saw our oils are well ahead, clearly a lot of oil is moving by rail. Our Polar area that's north of Missouri, thereby Williston, lot of that's going into to the coal terminal, and a little town in Epping, North Dakota. Biggest purchaser in that particular area is Tesoro. We sell a lot of oil to them. A big portion of that is going to the west coast to the Washington area.
So percentage wise I am going to tell you we are probably 60% to 65% today on rails, the balance on pipe. By the fact we sell -- well ahead, we are able to move our production around a little bit from one purchaser to another in trying to access the best markets available.
I think I will wrap it up here and…
We do have time for a few questions before moving to the breakout.
Lynn, a question for you on down spacing, how much time do you need to really evaluate the performance of these wells and get comfortable, do you need to drill them tighter or you are at the right spot?
Lynn A. Peterson
You know we told everybody, I think as we go through the year-end and do our reporting towards the end of February, we should start to have a pretty good handle on it. I mean clearly everybody likes to have a year or better, but we are not afforded that time in this environment anymore, but I think at least if we get six to seven to eight, we will start to have a better handle, feel more comfortable with it.
Would some of that then be reflected in the year-end '13 reserves.
Lynn A. Peterson
Well, I think this is one interesting thing we talked to Netherland Sewell a little bit and there is a little [hedge pricing] going on because historically we have kind of booked one pud for every PDP that we have, basically only had two years of puds out there on our books. I think clearly at this point this is a resource play, you can probably book whatever you are comfortable with and it's going to be interesting. I guess I better hold off on that till we have a little more dialog with Netherland.
Any other questions for Lynn? I'd like to thank you for being here.
Lynn A. Peterson
And I'd like to do the same [Jerry] [ph], appreciate the invitation. And thank you for we had two full days of one-on-one. Thank you very much, appreciate it.
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