Call Start: 08:00
Call End: 08:26
Whiting Petroleum Corp (NYSE:WLL)
Wells Fargo MLP, Pipeline & Energy Conference
December 11, 2013 08:00 AM ET
Jim Brown - President and COO
David Tameron - Wells Fargo
Good morning everybody, and again my name is David Tameron. I am with Wells Fargo covering the E&P stock on the equity side. Welcome to day two of the energy conference. We are pleased to have up, most favorite of mine, a Denver based company Whiting Petroleum. Whiting, as many of you know, is dominant positioned in the Bakken. They recently acquired in the acreage in the Niobrara very exciting program, and that I am sure that Jim Brown will tell us about. Jim Brown has been with the company, this year is his 20 year anniversary, I believe; President and COO. And so with that I will turn it over to Jim Brown. Thanks Jim.
Thanks Dave, and thanks for inviting us here to your conference, and it’s something we look forward to every year. Good morning everyone, welcome to the 8 O’clock presentation. I hope everybody has got a bright eyed and bushy-tailed out there; maybe we are going to do that. Okay, skip right through the, maybe we are going to skip right through the, I like this slide a lot. Because it shows a lot of the things we got going on at Whiting right now. It’s the things that we accomplished, basically, second and third quarter of this year.
We sold half of our interest in what we call our Big Tex play down in the Delaware basin for $150 million. Later in the third quarter we actually purchased some acreage 17,000 net acres and 2400 BOEs per day, up in the Williston Basin. That was a bolt-on acquisition, sort of fit really well in two programs we got going up there, the Hidden Bench project and Missouri Break. So that added some operated drilling spacing units, right into those two plays.
July 15th of this year we closed on the sale of our Postle field there in Texas county Oklahoma. That was a project we had been working on for some time. There is little anticipation in the market that we were going to get that done. We did get that acquisition closed and ended up bringing $816 million into the corporation. I just wanted to point out third quarter we made up the production for Postle and also we made up that reserve. We sold about 40 million barrels of reserve. Third quarter we replaced both the production and the reserves from that divestiture that we made.
We have got three really exciting exploration plays going on right now. We have talked about one of them. It’s the Brown Dense. We are about to start our first horizontal well in the Brown Dense. The other two projects we have tech core in all of them. I have drilled a well in one of those, it was just our test of concepts well to see if we can produce hydrocarbon and we were able to get that well to produce it. It’s currently shut in, and we’re permitting eight additional wells out there.
The other project, we have finished drilling our first horizontal well. We are going to start the completion on that next week. We are currently drilling our second well in there. We’re just exploring the pay zone right now. Once we get that done, we are going to back up, look back and then drill a horizontal out of that well. So we are very excited about both of those projects. And then the bottomline on here is like the kind of bringing forward what we already talked about.
We did a reserve update. July 31st of this year after we made the Postle sales, just for our bank engineers to make sure that we, that our borrowing base would not be decreased with that sales. As it turns out we’ve actually increased our borrowing base as we got to year-end.
As you know about Whiting petroleum, just about 93,000 BOEs a day in the third quarter, almost 400 million BOEs of reserve, and we’re an oil company; 79% oil, R/P ratio of 14 years. And you know one of the knocks against Whiting was, you guys, we don’t understand you guys, we’re not a peer play, we can't figure out what makes up the corporation. We’re becoming a lot simpler.
If you look at this chart right here, 81% of our production comes from the northern Rockies. Big majority is that from the Bakken up in North Dakota. As we get into next year, you’re going to see the DJ basin and the Niobrara add significantly to that Pie-chart. So very simply, Whiting is at Northern Rockies, Williston Basin producer. That 13% green slice on the Pie is our North Ward Estes field which is the big CO2 flood project down in the Permian basin.
This just gives you a snapshot of our acreage positioned up in the Williston basin just over a million growth acres, 730,000 net acres up there scattered about those plays. You can see highlighted in green on here, the acreage that we acquired that I mentioned earlier, that 17,000 net acres fit right in very well for our Missouri Break and Hidden Bench project. If you look across all those different projects we have going in the Williston Basin, this diagram right here shows how we currently envision developing each one of those projects.
And I am not going to go through each one of these, but I just want to mention that we have high density pilots where we are taking our down spacing down into, as you can see in the middle Bakken, a lot of places at drilling, 7 day wells in the middle Bakken and an equal number of wells into the Three Forks. There are certain areas in the field out in the middle of the basin where we think we have lower benches of the Three Forks that are going to be productive. We have not yet drilled any of those, but we have those tests online for early 2014.
I have mentioned the high density pilot, and we just provided this slide into our slide deck recently just to show you all the different configurations we’ve got going on. A couple of them are working very well. The more high density pilot hidden bench, you can read it on this slide I’m pretty sure but if you look in your slide deck that you guys have those infield wells are performing very well.
I just want to mention down here the Privratsky well down in the lower left corner. What we were trying to do there is actually over develop. We’re trying to drill too many wells in there to see if we could get our reservoir engineers some information a little faster. So our plan for the Pronghorn area, we’re currently drilling three wells in the Pronghorn sand for spacing unit. What we think we’re going to end up doing with our high density is drilling one well in between all of those so we’re going to end up with roughly five, five-and-a-half wells for spacing unit if we have places where we can drill a lease line well.
The interesting thing that we’ve observed on these Privratsky wells, we drill those two infield wells they came in at pretty good IPs. But we’ve also seen the production on the two outboard wells, the two existing wells; production has gone up on those two. So production on the existing wells has gone up by about 25% since we drill those infield wells, frac them, and to put them on production. This is a phenomena; it’s not just unique to down here in Pronghorn. As we’ve drilled infield wells in Sanish, we’ve seen that time and time again. And we think we’re just doing a better job with these new wells, new completions to get break up our Vice President of Exploration and Develop, his big thing is break more rocks, that’s what we’re trying to do.
And that’s what we’re demonstrating with this slide in our deck. We have had great success once we moved over to Cemented Liners and Plug & Perf Completion. And the past couple of days that we’ve been talking to investors people say now we’ve been doing Plug & Perf for years. Yes, people have. What they haven’t been doing is doing Cemented Liners and Plug & Perf. And we think the combination of those two techniques have really revitalized completions up in the Williston Basin.
And we provided this slide deck just to show you, what we’re showing on this slide are places where we have a direct comparison with an offset well. So this isn’t all of the cemented liners we run in the Williston Basin but it’s all of the places where we have a direct offset completed with sliding sleeves or some of these could be Plug & Perf; I think there is a couple on here that are uncemented Plug & Perf but we have a direct comparison between the cemented liner and an uncemented liner. And you can see we’re getting pretty good uptick in the 30-60-90 days cums out here, we are very hopeful that that’s going to carry on into new law.
The other thing you’ll notice we seem to be getting a little bigger bang for the buck in the areas that have the remote challenge to produce. So we’ve seen the bigger benefit out on the western side in Missouri Breaks. The benefit has been a little less pronounced. The over day were 12’s down there in the lower right, I mean the first well that we’ve drilled in there had a cum of, I think is the 60 day cum of 40,000 BOEs and if you look at the offset with the cemented liner, the 60 day cum is 50,000 BOEs. Both of those were very good wells to begin with. But on a percentage basis we just not seeing the big uplift in the better areas, but it’s definitely helped us in some of the more challenging areas.
The other thing we get asked about well that this is if you guys are doing this what’s it done to your well cost? Basically, what happens if we are submitting the liner, that old technology that’s fairly inexpensive technology, if we run 30 sliding fleets and 30s well packers, the cost of all that equipment is somewhere in the range of $350,000. If we cement the liner we don’t experience that cost and as I mentioned, cement is pretty inexpensive. But what we do have to, the cost that we do incur are the Plug & Perf activity. We have to have wire line, perforating guns all that out there it takes us about a day to pump a sliding fleet frac job with 30 stages. If we do one of these Plug & Perf, it takes anywhere from five day to seven days. So the cost savings we have while not having to buy all the jewelry and equipment we run down whole, we pretty much spend that with the extended period of time it takes us to do the Plug & Perf Completion. So you can see over here bottom line it turns out to be just about a wash.
I’m going to jump down into the DJ Basin, now just northeast of Denver out in beautiful wells County, Colorado. We’ve assembled just over a 100,000 net acres out here. We’re drilling horizontal Niobrara wells. To date, we have drilled Niobrara A and B wells and we’re going to be testing the state here very quickly. Why we leased where we leased? If you Google it you can go out there and find a geologic phenomena in Colorado called the Colorado Mineral Belt. It’s an area across Colorado of higher heat flow. If you check the bottom hole temperatures out here in Eastern Colorado, in between those two red lines, bottom hole temperature you’re going to encounter is a lot higher than it is outside of those red lines.
I’m not going to go into the geologic reasons for all this but it basically tracks all the way across Colorado you could track it all the way down into the [Durango] area. A lot of the old mining that’s going on in Colorado is associated with it, hence the name Colorado Minerals out. It tracks right out over the eastern plains that actually provides the bounds on Wattenberg field out there track it on out and that’s why we leased out here at Redtail. If you look at everything works absolutely beautifully like we have it designed right now through all four phases of our development. We have about 3,400 wells to drill out here in Northeastern Colorado.
So that’s a pretty huge inventory target that we’re going after. Right now, we’re going to be concentrating our development on the tank of the red acreage down here, we call that Phase 1. The primary reason we’re doing that is that the first place we shot 3D seismic that is outlined in the purple line on here. We don’t really need the 3D seismic to tell us where to drill. We do need the 3D seismic to help us plan our wellbore path. We have found that to be very critical. We have just finished shooting another 3D out here, outlined in the blue line out here. We have got nearly proceeding done on that particular 3D. We’re starting to incorporate that into our well planning.
We currently have three rigs running out here. We have had one rig out here for about the past year and half. We had our second rig in June and we had our third rig just this past month in November. We are going to add a fourth rig in January, February next year. We are going to add a fifth rig in the June, July timeframe next year, and we’re going to add a sixth rig just about a year from right now, next December. So we’re very excited about this project. One of questions we’re frequently asked is what’s your takeaway ability out in this part of basin? Actually, we picked a pretty good spot to find an oil and gas field.
If you look just to the North of it there are two pipelines that we used to know a great deal about that’s wrecks and trailblazer. As you might have imagined there is space available for gas both of those pipes, we are not doing it. Trail polygraph is currently building the residue line from near trailblazer pipe down to our gas plant which is under construction and we will have online in February of 2014. The Pony Express line out there, to the east of us, was in oil service at one time its pass has been converted to gas service, and it’s now been converted back into oil service, I believe open season on that pipe close today. I think that’s today is the day we’re attempting to pull down some space on that.
They’re going to build a terminal over in drilling where they will both rail access and pipe access, so we’re working on that just to South to West down here is an NGL line. When we start our gas plant, we’re going to trucker NGL out of here but we’re working on perhaps getting tied into that NGL pipe so we can pipe our NGL out of here. We have contract provide water for our fracking that water is being piped to our location, so we’re trying to take all the trucks off road. We’re trying to be a good as corporate citizen as we can be out here Northeast Colorado.
I want to comment, this is not in the highly populated part of the Colorado. Population density out here is about one person per square mile. So we aren’t disturbing a lot of folks out here in West Country. You can also see the cost estimate for our gathering our midstream asset out here that we’re going to spend some in 2013, majority of this will be a 2014 spend.
Why the Niobrara? Why are we out here? This slide pretty much some geographic, if you look at the just to Niobrara A and the Niobrara B, you get 59 million barrels of oil in place for spacing unit, if you do this exact same calculation on the Niobrara North Dakota, you get 30 million barrels in place in Bakken and Three Forks, like in Sanish field. There is twice the oil in place here in the Niobrara than there in the Bakken; just a marvelous target to go after.
We just provided you; we don’t know what the recovery efficiency is going to be out there. We have made a lot of estimates. We have run a lot of models. We give you a range what we think. The recovery is going to be out there and you can see these are very attractive EUR to go after on our well basin. Currently, we’re trying to determine what our ultimate spacing is. As we have learned in North Dakota, the sooner you can figure out what you our ultimate development pattern looks like the better rock you’re. When you have to go back in and like we in Sanish we are on our third round of drilling in field wells; that’s a very inefficient process.
So we’re trying to figure it out, out here in the Niobrara. The top two up there the 27L Pad, 27K Pad, we drilled all those wells. We have fracked the 27K Pad during the process of flowing back and cleaning those wells out. Right now, we’re actively fracting the 27L Pad as we speak. Those two Pads would drill 16 wells for spacing unit. We feel very comfortable with drilling on that particular pattern; however, the test of denser pattern we have the Horsetail Pilot set up down here. We’re going to drill eight wells of one Pad in what would eventually give us 32 wells for spacing unit that would give us of this particular Pads two Niobrara A well to Niobrara B well and four Niobrara B well.
If we did across the entire spacing unit, we would end up with 8 A wells 8 C wells and 16 B wells. We’re just going to give a test out here to see what happen. We feel very comfortable with the 16 wells. We’re going to see what happens with the 32 wells pattern. If you look at the wells that we have completed since we, just a big change we’ve made here in the Niobrara is the amount of propane (Ph) we’re pumping. Our standard frac job out here when we started in the play was in 3 million plus or minus pound for frac job, what we have gone to now is something up around 7 million pound per frac.
Since we have gone to the higher profit volume we have seen a dramatic increase in our well performance. The question we were asked these nine recent wells down here we cherry pick those, as those are the nine best, no, those are the nine wells we’ve completed this way since we changed our completions technique. As the red line on this slide demonstrates, we’re very consistently beating the 400 MBOE types. So we’re feeling pretty confident about the economics and the wells we’re drilling out here. Currently we’re drilling wells for about $6.5 million. We think we can get that cost down into the $4.5 million to $5.5 million when more drilling these in development mode and the difference is at 640 versus the 960 space well. Currently about 60% of our spacing units are 968 per unit and about 40% are 640. The reason for that is just that the state of Colorado we couldn’t go all 960 if we would strand the 320 out there somewhere. So they’ve asked us to, some of our spacing units convert them back to 640.
Once again third quarter of 2013 based on a price receipt and also on the amount that we’ve delivered to the bottom line one of the best quarters we’ve ever had. So we’re very proud about that. And with that I will entertain any questions anyone may have.
[Indiscernible] just asked about capital allocation Niobrara versus the Bakken.
Sure at Whiting we do what we do to this highly intricate calculation we call Poker math. And so basically if you look up it’s up in the Williston Basin if we’re drilling a well 600,000 BOE well, and let’s just, to keep the math simple, let’s just say we’re getting $50 a barrel, we’re netting $50 a barrel which is that last slide that was like a pretty reasonable number. So we’re getting $30 million of future net revenue from the wells in the Williston Basin and we’re doing that for $7.5 million, we’re getting just over 4:1 on our money I have to say.
If you do the same math down the Williston, or get them in Niobrara let’s just say 400,000 barrels and we feel pretty confident we’re beating that 400,000 BOE type curve. But we’re doing, we're getting $50 a barrel so that $20 million of future net revenue if we can get our wells down on the $5 million, $5.5 million range very similar economics. So we think the Niobrara competes very well for capital dollars across our program; and that’s why we’re continuing pursue the Niobrara.
Yes, I was just wondering if you could give a update on the timing of when you might be or talk about the three new oil resource plays that you guys have been acquiring acreage interest.
Sure. We kind of learned a little bit several years ago when we talked a little prematurely about one of our plays in the Williston Basic called Pronghorn. We had data that’s probably go either way. I think we’re going to be a little more conservative on when we talk about these I would be very surprised if you hear anything about it on these plays until at least third quarter of ’14 somewhere in there unless we have some very good results and we’re able to get out there and repeat it and move it on. But I wouldn’t expect anything too early in 2014 financing (Ph).
This Bakken crude consult whether it discount to WTI, could you go into the mechanics there as there not enough takeaway capacity refinery outages that are temporary or what kind of factors you’re going into that? And how do you live around that?
Yes, there is a number of things that have contributed to that recently. There have been several incidents at refineries I know there is incident in refinery this been an clear refinery in Wyoming the superior refinery or that’s the refinery in superior was Onsen it seems like there was one other incidence somewhere also the BP Whiting they had their cope are up and running they were running sweet crude through that. They started to switch over to heavy crude which is what the cocker was actually designed to handle.
Then the other things that, the incidence in Eastern Canada with that rail incidence that has now disrupted some of the plants to take crude to the West Coast all the sudden the West Coast isn’t excited about having trainloads of crude ahead of their direction. How we have at Whiting, how we try to combat but how we try to plan for all this. Every, most places where we deliver oil we have optimality to either get on rail or go on pipes. So now Enbridge has their rail facility of perfect running so you can take oil back out of the fight to get it on rail it’s ended somewhere down in the southern part of the Williston Basin.
We have the ability to get into several pipes and also a couple of different rail facilities down in that part of the world. We kind of somewhat like hedging. We don’t think we’re going to be smart enough to gain the market all the time so we just try to diverse ourselves across rails, pipes, all sorts of different ways to get it out there. Hopefully that will be right more often then we’re wrong if we do that. So that’s how we plan to get around it it’s backed.
David Tameron - Wells Fargo
Thank you, just a quick question, you mentioned on your last comments, transferring the process that you are doing now in the Williston to the Niobrara. If you do that that will lower your cost; are there an apples-for-apples comparison in terms of the wells you are drilling in the acreage and things like that, that the same process in transferable, that you can get the similar result?
In a growth sense, yes; I mean what, we’ve taken a lot of the things that we have learned in the Bakken and we have moved them down for the Niobrara. One of those seems cemented liner. On the, when I had the slide up here, that showed the pilots we were doing, on one of these pilots with cemented liners on through the well and sliding sleeves on through the well just to get in our direct comparison. Everything we currently know about what we are doing with the cemented liners, we think should work and should give us better results in the Niobrara. But I have often said mother nature isn’t an engineer, and so what you think work, sometimes you got to go try it to prove it does or doesn’t.
Some of the intricacies, some of the finer point of the frac jobs aren’t transferable. Some of the fluids, some of the techniques we use, some of those things take a little time to figure out. Peter Hagist is sitting in the back; they’re who runs our Permian operation. One of the things we have found is some of the things we try to transfer from the Bakken down to the Permian, it didn’t work so well. We had to kind of put on our turning wheel and go learn something that on the Permian. That was a little tougher of learning through the frac. But generally, yes. And if you look at the Stealth plays we are after, a lot of the background technology that we have used and developed in the Bakken and other places with our rock lab in Denver, we are utilizing that technology to help us gain a toehold in these new plays.
Great, thank you everyone, thanks for your interest in Whiting.
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