Oasis Petroleum Inc
Q2 2014 Earnings Call Transcript

Published: 31 Jul 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Second Quarter 2014 Whiting Petroleum Corporation Earnings Conference Call. My name is Glenn, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Eric Hagen, Vice President of Investor Relations. Please proceed, sir.

[Eric Hagen:]

Thanks, Glenn. Good morning, and welcome to Whiting Petroleum Corporation Second Quarter 2014 Earnings Conference Call. On the call for Whiting this morning is the Whiting management team. During this call, we'll review our results for the second quarter of 2014 and then discuss the outlook for the third quarter and full year 2014. This conference call is being recorded and will also be available on our website at www.whiting.com. To access the call and the webcast, please click on the Kodiak Acquisition button on the homepage. Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on Slide #2 and in our earnings release. Reconciliation of non-GAAP measures we refer to and the GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-Q for the 3 months ended June 30, 2014, is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

[James J. Volker:]

Thank you, Eric, and good morning, everyone. As you've all seen from our first quarter release, Whiting had a very strong second quarter and set several company records. With a focus on the Bakken and the Niobrara, our production reached a record 109,760 BOEs per day, which represents a 9.7% sequential increase over the first quarter of 2014. We believe Whiting continues to be primed for growth and increasing production. We're a company on the move. We announced an agreement to acquire Kodiak Oil & Gas on July 13, 2014, which will create the #1 Bakken/Three Forks producer in the Williston Basin. Our record production generated record discretionary cash flow of $556 million. In this light, we raised our production guidance for 2014 to a midpoint of 20% over 2013, up from a midpoint of 18%. Our new completion methods are generating strong results. Based on our midyear reserve estimates, the EURs associated with our well completions using cemented liners and plug-and-perf technology were approximately 23% higher than wells completed with uncemented liners and sliding sleeve technology. We believe there could be additional upside from the use of coiled tubing and slickwater frac technologies. We currently have 11 slickwater fracs, either underway or planned for the third quarter of this year. At our Redtail prospect, in Weld County, Colorado, we spud our 30F pad in the Horsetail area to test a 32-well spacing pattern in the Niobrara A, B and C zones. Separately, our first 8-well pad, the Razor 27I, a 16-well pattern, came on stream on April 15, 2014. It is our strongest pad to date, currently producing 4,700 BOEs per day, an average of 588 BOEs per day per well. As you can see on Slide 5, 86% of our total production in the second quarter came from our Rocky Mountain region. The Bakken/Three Forks represented 73% of our total production. We are a focused company. Our focus is aligned with our expertise and capabilities, as well as our focus on shareholder value. On Slide 6, we provide an overview of our plays in the Williston Basin, where we control nearly 675,000 net acres. Notable achievements this quarter include the completion of a well in the second bench of the Three Forks. This well, the Skaar Federal 41-3TFHU well located in our Tarpon field flowed over 6,000 BOEs per day. At Missouri Breaks, we performed a slickwater frac on the Sundheim 21-271H well in August of 2013. This well achieved a 44% greater 120-day average rate than the offsetting well. At Hidden Bench, the 11 wells we completed using cemented liners and plug-and-perf technology had an average IP rate of 2,872 BOEs per day, a 50% increase over the average of our Hidden Bench wells completed with our prior sliding sleeve technology. Slide #7 shows our Redtail field in Weld County, Colorado, where we target the Niobrara formation. We've been very pleased with the performance of the field. Our first 8-well pad, the Razor 27I, came on stream on April 15, 2014, and is currently producing approximately 4,700 BOEs per day. The pad drilled 4 wells into the Niobrara A zone and 4 wells in the Niobrara B zone on a 16-well spacing pattern. The 90-day rate for the A zone came to 553 BOEs per day per well, while the 90-day rate for the B zone averaged 498 BOEs per day per well. Moving to Slide 8. We spud our 30F pad located in the Horsetail township in early June. This 8-well high-density pilot will test a 32-well per drilling spacing unit pattern in the A, B, and C zones. If successful, our potential drilling locations at Redtail could increase to more than 6,600 gross wells. Now Mike Stevens, our CFO, will discuss our financial results in the second quarter of 2014.

[Michael J. Stevens:]

On Slide #9, you can see our second quarter 2014 adjusted net income available to common shareholders was $167.9 million or $1.40 per diluted share. Our discretionary cash flow in the second quarter totaled a record $556 million. This total represented a 26% increase over the $441 million in the second quarter of 2013. Our guidance for the third quarter and full year 2014 is detailed on Slide #10. You'll note, we are guiding for a 7% production increase for the third quarter over the second quarter. Also note that our LOE per BOE was down in the second quarter and is expected to remain lower in the third quarter. During the quarter, we decided to terminate our production participation plan and replace it with a more conventional cash bonus program starting in 2015. This has been fully accounted for in our second quarter numbers, and there will not be any special charges associated with this change. On Slide #11, our second quarter EBITDA margin was at a record level of 71% of our blended realized price per BOE. This validates our longstanding strategy of focusing on oil. On Slide #12, you can see that we continue to maintain a strong balance sheet, with $227 million of cash on hand and nothing drawn under our bank credit facility. Slide #13 shows that our 2 senior notes and senior subordinated note continue to trade above par. It also shows that we're well within all of the covenants in our credit agreement and our bond indentures. Slide #14 shows our crude oil hedge positions. At this point, we're over 53% hedged for the remainder of 2014. On Slide #15, you'll see our strong fixed-price gas contracts that continue to net us over $5 per Mcf. Also of note, our new fixed differential crude oil sales contracts. We will be selling 20,000 barrels of oil per day out of Redtail, beginning in July 2015 at a price equal to NYMEX less $5 to $6. With that, I'll turn the call back over to Jim.

[James J. Volker:]

Thank you, Mike. I'd like to talk about our recently announced agreement with Kodiak Oil & Gas. On Slide 17, you can see why this transaction makes so much sense for all shareholders. The combination of Whiting and Kodiak will take 2 very successful focused businesses and create the leading Williston Basin player. On the left side of this slide, you can see in red, our various plays within the Williston Basin. Whiting was an early entrant into the Williston through our Sanish position. And because of our early presence in the area, we have been and continue to be at the forefront of Bakken and Three Forks development. The blue area represents Kodiak's acreage. As you probably know, Kodiak has done a terrific job of establishing a tier-1 acreage footprint in the core of the Williston Basin, which, like Whiting's acreage, sees some of the best economics anywhere in the play or, for that matter, anywhere in the U.S. When looking at both of our positions together, you can see just how complementary the 2 really are. There are many areas in which the combined companies will benefit from offset acreage positions. And together, we create an extremely attractive position in the Central and Eastern Williston Basin fairway. At the right, you begin to see what the combination will do relative to our peers. It will vault us to the leading Bakken/Three Forks producer, as measured by Q1 '14 production and operated rig count. In the bottom right, we show a combined 18 operated rigs active in the play as of July 13, 2014. The combined companies' leading oil weighted platform will drive meaningful production and operational synergies. On Slide 18, you can see that our inventory of drilling locations in the Williston Basin is robust and continues to grow. I should note that the growth that we show here is not only what we will get through our acquisition of Kodiak. It's also due to the success Whiting has had on a stand-alone basis year-to-date. On the left side, you can see where Whiting was at the end of last year. The net drilling locations on the right side combined Kodiak's acquired locations, along with those we've added this year through our combined continued efforts as of June 30. On a pro forma basis and including our own organic growth, our net Williston Basin drilling location count increases 158%. Moving on to Slide 19. I'll mention that on Slide 17, that Whiting and Kodiak have complementary acreage positions. Here on Slide 19, we show a closer view of our combined position in the Central and Eastern Williston fairway to demonstrate just how close in proximity some of our acreage truly is. This should give you a feel for the efficiencies we think are possible. As you can see, through this combination with Kodiak, we will add very significant acreage that is adjacent to Whiting's positions in the Central and Eastern Williston fairways, creating an advantage for ourselves from cutting-edge geoscience at our in-house core lab here at Whiting and what we believe are our state-of-the-art completion techniques. In particular, in the Central Williston Basin, we expect the Bakken first and second benches of the Three Forks to be highly productive. As I mentioned earlier, Whiting recently completed a well at our Tarpon acreage in the second bench of the Three Forks for over 6,000 BOEs per day. I'll spend a minute on Slide 20 just to emphasize exactly what this transaction will do for us from a size and scale perspective relative to our closest peers. Pro forma for the transaction, Whiting will be an $18 billion initial enterprise value entity based on Whiting and Kodiak's share price prior to announcing the acquisition. Our first quarter 2014 annualized EBITDAX was in the $2.8 billion range, and we will have significantly larger reserves and production. As you can see, we have comparable, if not greater, EBITDAX reserves and production than many of our peers who have substantially greater market valuations. We believe this transaction will help narrow this valuation disparity. It's an exciting time for Whiting and our shareholders, as we continue to set records for production and cash flow. We continue to improve our completion methods in the Williston Basin. The EURs associated with our completions using cemented liners and plug-and-perf technology were approximately 23% higher than wells completed with uncemented liners and sliding sleeve completion technology. Production from our Redtail Niobrara field continues to grow at a rapid pace. We spud our 30F pad in the Horsetail township in early June. The 8-well high-density pilot will test a 32-well per drilling spacing unit pattern in the A, B and C zones. We have become a better and more focused company as we continue in our efforts to maximize shareholder value. This call is primarily about what we believe is our compelling second quarter results. And given our prior call and information release covering our acquisition of Kodiak Oil & Gas, we ask respectively that you limit your questions to Whiting's operations and second quarter results. Glenn, please open up the conference call for questions.

[Operator:]

[Operator Instructions] And your first question comes from the line of Brian Corales with Howard Weil.

[Brian M. Corales:]

Two questions for you. One, the deeper test, that was a fantastic rate. How many of those deeper tests, I guess, throughout your acreage have you all drilled? Or is this kind of the first one, the deeper Three Forks test?

[Mark R. Williams:]

This is Mark Williams. This is our first test of the second bench at the Three Forks here in the Central Basin -- or excuse me, a third bench at the Three Forks in the central part of the basin. We think that the third bench has the potential to work through our Tarpon area and beyond, but we'll take it incrementally as we step out from Tarpon.

[Brian M. Corales:]

Okay. And then in the Niobrara, the Horsetail pilot, are you all drilling that just with 1 rig? And when can we expect to have those results? So will they be there for next quarter update?

[Mark R. Williams:]

They are being drilled. It's on a pad. So we really have to do that with 1 rig, which means that those wells are drilled sequentially. And so in addition to the 8 wells that are mentioned there, we have 4 that are drilled off of the pilot. So there's really a total of 12 wells, which is why there's a bit of a delay there. So we're expecting that we'll have all those wells drilled, frac-ed and on production sometime after the first of the year, probably by the end of January.

[Brian M. Corales:]

Okay, all right. And I know I probably shouldn't ask 1 more. But the -- so the timing of production in the Niobrara, it is going to be pretty lumpy. And then January, we should see a big surge. Is that kind of -- am I thinking about that right?

[James J. Volker:]

I think what's happened there is we're going to be at 5 rigs at that point. So we think that having a larger -- a higher rig count will smooth a lot of that out. It already has happened. And so we've got a lot more going than just that Horsetail pilot.

[Operator:]

Your next question comes from the line of Joe Allman with JPMorgan.

[Joseph D. Allman:]

So when we think about the new completion design, should we think about some of those new techniques working in some areas better than others? So for example, say coiled tubing, like, would you expect that to work well throughout your Bakken and throughout your Niobrara play? Or do you think that's more applicable just in certain areas, and then your plug and perf is more applicable in certain areas and the same with slickwater frac? Would that be -- do you think that's going to be applicable throughout or just in certain areas?

[Rick A. Ross:]

This is Rick Ross. I'll comment on the coiled tubing completion that we're doing now. I think that will probably be applicable in certain areas of the basin, one in particular would be Sanish Field, possibly in our Redtail prospect. Our state-of-the-art completion of plug-and-perf cemented liner, I think that's applicable across the entire basin. It's working very well for us. The slickwater jobs, we're actually in the midst of testing those. As we said in the commentary, we've got 11 either underway or completed across 4 of our prospects. So we're, at this point, trying to determine where it works well, and we'll certainly apply it. At this point, I can't answer. But we do believe it will work in the Central Basin pretty well.

[Joseph D. Allman:]

Okay, that's helpful. And then a separate question. On the Three Forks, could you just -- I know that Brian just asked a question about that. But just clarify like how many Three Forks wells you drilled so far and where you drilled them. And when I look at some of your old presentations, I see sort of the thickness and the depths of the Three Forks, it seems as if you go further west, it gets -- it's kind of -- it's thinned out. And in places like Hidden Bench and Tarpon, it seems deeper. So where do you think the Three Forks, whatever bench, is going to be most prospective?

[James J. Volker:]

That's a pretty broad question. But I can tell you in general that the central part of the basin where the bulk of our acreage is, there at Cassandra, Tarpon and Hidden Bench, and going west, at least to North Dakota border, it has Three Forks potential. We've gotten good Three Forks production already. And in general, we're drilling 1 Three Forks well for every Bakken well through that area that I just mentioned. The lower benches of the Three Forks are another question. And so they tend to be a little bit more restricted in the upper part of the Three Forks, but it hasn't been completely defined as to where the limits of production are within the Central Basin there. We also think that the second bench extends east to the Nesson. And we've actually tested the second bench over in Sanish as well successfully, as have other operators in that area. So I'd say that the periphery of the second bench is yet to be defined. And certainly, that's the case with the third bench as well.

[Operator:]

Your next question comes from the line of David Tameron with Wells Fargo.

[David R. Tameron:]

Let me -- in the Niobrara, could you guys just talk about -- and maybe I missed it in the prepared remarks, but can you talk about whether the wells are tracking compared to the EURs? I know in prior quarters, you've kind of said they're tracking above, but can you just give us an update on that?

[James J. Volker:]

Well, I'll let Mark comment in a second. Yes, you're right that they above our 420,000 BOE type curve. But we haven't revised that upward yet. We want to watch it for a while. Results, I would say, are in the range of 25%, in some cases up to 50% higher. And we're going to watch it. And once we get probably somewhere around another 90 days to 6 months of production history, then our reservoir engineers will be making appropriate adjustments in our reserves. Do you want to comment...

[Mark R. Williams:]

You said it.

[James J. Volker:]

Mike says -- or Mark says he agrees.

[David R. Tameron:]

All right, fair enough. And this may violate the -- I don't know if this violates your comment about not going the Kodiak route, but I'm just trying to think about the combined company for 2015. How should we -- I mean, just from a big picture standpoint, should we thinking about A plus B, and you're just assuming the whole capital budget? Or is it going to be A plus B less some high grading, less a C type? Is there anything you can comment on that?

[James J. Volker:]

Well, I think we've already said in our presentation, and I would refer you back to that presentation, where I think you can answer your question there, Dave, that we are going to add 5 more rigs to their 7. So it is an incremental increase in their drilling budget and an incremental increase in the number of net wells that are going to get drilled. So it's -- that's where part of the growth is going to come from. Basically, the fact that perhaps as a result of their leverage, they were a little constrained. And the fact that Whiting was a company designed to be somewhat underleveraged compared to the peer group, that's going to allow us to limber up some of that capital we have available to generate greater growth for the combined entity. But thank you for not violating the rule without saying so.

[Operator:]

Your next question comes from the line of Michael Hall with Heikkinen Energy Advisor.

[Michael A. Hall:]

I just want to follow up a little bit on that Razor pad, the production profile on those wells. So I'm looking at it, right, it seems like -- are these still on an incline after roughly 100 days? And how does that compare to what you all kind of bake in on your forward expectations typically?

[James J. Volker:]

Rick wants to answer that one. He's been waiting for somebody to ask that one.

[Rick A. Ross:]

I would say they are still on an incline. They have a little bit different type curve than what you see in North Dakota with more of a hyperbolic nature. These come on and continue to increase over 90 and 120 days and then flatten out and going to a decline after that.

[Michael A. Hall:]

And so I guess, what I'm trying to understand a little better is kind of within you all's type curves and forward outlooks that the guidance is built around, how long until those wells turn over in your base assumption? I mean, is that outside the norm on that Razor pad? Is it -- has it been inclining longer than you typically model? Or is it pretty consistent?

[James J. Volker:]

Steve Kranker, VP of Reservoir Engineering wants to answer that part for you.

[Steven A. Kranker:]

Yes. So the 27I pad is very encouraging. That's our strongest pad to date, with all 8 wells exceeding our current type curve. They are on the incline. That's partly a combination of us choking them back initially. We're not going for record production rates. We're going for longest sustained ultimate recovery. And about 120 days is the longest we've seen for a well to clean up and get to its peak production, and then they go on a more gradual hyperbolic decline.

[Michael A. Hall:]

Great, that's helpful. I appreciate the color. And then I guess, last one of mine, can you just remind me in the DJ what you all experience has been so far with the Niobrara C bench? So I think you'll have some test on that within that 30F pad. But I'm just looking for a reminder on what your experience has been before with that bench?

[James J. Volker:]

Right, yes. So the C bench is something that we've recognized on logs and core for quite a while. When we compare it initially to the B and A, the combined B and A especially, we think it's not in communication with either of those. So it means it has to be drilled and completed independently. But the reserves there look quite good to us or at least in terms of the oil in place. So in terms of our actual drilling, the 30F pad is really our first chance to test that. It has been tested, and I'd say successfully, by our neighbor to the south there. And so they've got a couple of wells that looked pretty good in the C. And so what we're trying to do right now is decide whether or not this is going to be a full add to our current development pattern, an augmentation essentially to the A and B development pattern. And so this will be our first chance to really determine that, which, if it is successful, it's going to be huge additional number of wells for us and obviously increase the number of reserves as well.

[Operator:]

And your next question comes from the line of John Freeman with Raymond James.

[John Freeman:]

The first question I had on the coiled tubing frac, again on that 93 stage completion, last quarter, given one that was 85 stages and it was sort of a -- like a combination of like 60 stages that were coiled tubing and the remaining were plug and perf, of these 93 stages, was that a similar sort of hybrid job?

[Rick A. Ross:]

This is Rick Ross. That was a full 93 coiled sleeves that we completed. So that was a record.

[John Freeman:]

Okay. And then could you give me an idea of kind of how at least preliminarily the costs compare? And I know on the 85 stages, it was sort of a combo job. It was like $8.8 million. What do this one coming at?

[Rick A. Ross:]

I would say we don't have all the costs in. But my estimate would be we'd probably be plus $300,000 over a plug-and-perf cemented liner job.

[John Freeman:]

Okay, great. And then I just had a follow-up on what Mark discussing earlier on sort of these deeper Three Forks benches. Outside of Tarpon and Sanish, when and where will we get the next deeper test? I mean, next quarter, are we going to get some results in potentially Cassandra or somewhere else?

[James J. Volker:]

Well, we are testing -- well, I should say we're actively drilling the upper bench of the Three Forks at Cassandra, very successfully, I might add. We've had 5 wells in there. Two of which were Three Forks that look great. The second bench, we will test there eventually, pro forma Kodiak. We think we've got opportunities there as well. And so it's a little early to say exactly where the deeper benches are going to end. As I mentioned before, we can see the areas that have been positively affected by it so far. But I think we'll have a lot more color on that by the end of the year in terms of the production itself.

[Operator:]

Your next question comes from the line of Jason Smith with Bank of America Merrill Lynch.

[Jason Smith:]

Just to stay on trend with the lower Three Forks. Could you just remind us, Jim, how much of the lower benches are included in your current inventory locations?

[James J. Volker:]

We haven't really included any of that in our actual inventory of locations other than you refer back to our -- we have the wine [ph] rack that we put together. That shows exactly how we've done it. And so that table that we've shown previously and the wine rack show where we believe they may be prospective. And that really is the second bench at Tarpon. It's really the only one that we've added in any significant second bench opportunities, so as you -- so we're seeing deeper benches there. And certainly, the chance that we'll have that in Cassandra, but those would be all new land fills [ph].

[Jason Smith:]

Do you guys happen to have a 30-day rate on that well?

[James J. Volker:]

Don't think we do yet. I think it's -- we're just about 30 days' worth of production on that. So just a little bit shy.

[Jason Smith:]

Got it. And then in the release, you guys also mentioned on the slickwater fracs that you expect the cost of those to move towards plug and perf when you move into development mode. Can you just let us know where you are today on the cost side and what exactly you need to do to get it lower?

[Rick A. Ross:]

I guess, I'd start out and say that we believe we can do the slickwater jobs for fairly close to the cost of a cemented liner plug and perf. And to follow up on that, as you know, some operators in the basin are using 100% ceramic in their slickwater jobs with good success and some are using 100% white sand with very good success. Our game plan would be to use the same proppant that we're using on our cemented liners. So most of our operations would be sand. And some areas in the deeper part of the basin would be 30% to 40% ceramic and the rest white sand. That said, I think we can do them for, as I said, the same costs as we're currently doing our state-of-the-art completion with cemented liners.

[James J. Volker:]

Which is about the same [ph].

[Jason Smith:]

And where are they today?

[James J. Volker:]

About $8.5 million.

[Rick A. Ross:]

Our cost in Sanish area were just right around $7 million. Deeper part of the basin would be about $8.5 million.

[Operator:]

Your next question comes from the line of Brian Velie with Capital One Securities.

[Brian T. Velie:]

Quick question. Just trying to determine where the beef [ph] was for the quarter within the Williston area. Is it possible to kind of get in to whether Western Williston, Southern Williston and Sanish all grew sequentially? Or is one particular area driving the growth more than another?

[James J. Volker:]

They all grew sequentially.

[Brian T. Velie:]

Okay. So no -- I know Western Williston, it seemed for a while, was outpacing the others. But at this point, it's pretty much everybody's enjoying the same success?

[James J. Volker:]

All areas contributed pretty equally, yes.

[Operator:]

And your next question comes from the line of Jason Wangler with Wunderlich Securities.

[Jason A. Wangler:]

Curious, with obviously what you're seeing with these new completions and seeing these great well results, as you start to look, and whether it's your engineers or the third parties, later this year, what are you expecting or what are you thinking as you look at the puds and things? They are either already in the books or that will be booked as far as those EURs? Are you expecting a pretty decent bump just given what you're seeing?

[Steven A. Kranker:]

I'd have to say that the early results you're seeing here when we quoted the 23% increase in EURs was limited to the wells where we had the best side-by-side comparison in Pronghorn, Hidden Bench and Missouri Breaks. But we're getting in more data all the time across all the areas that are getting cemented liner plug and perf. Yes, it will be in our year-end reserve report. We have the expectation that a lot of our areas are going to see that type of a reserve increase. But it's obviously not in last yearend’s reserves that we've already reported. Yet to come.

[Jason A. Wangler:]

Great. And then just maybe on the hedges, as you go out to '15, still, I guess, probably building a book, but how you see that shaping up. Is it going to be -- '15 going to be pretty much similar to how we have been in past years, call it, 50-ish percent number as we get closer to that time frame?

[James J. Volker:]

Yes.

[Operator:]

Your next question comes from the line of Jeff Robertson with Barclays.

[Jeffrey W. Robertson:]

Jim, a question on the Williston Basin. Does the increased scale that you all will have present any new opportunities around some of the gathering and processing of infrastructure that you all -- that Whiting has put in to add value or to maybe enhance the product pricing you receive up there?

[James J. Volker:]

Well, the answer is that Kodiak has actually done a pretty good job of lining up good third-party services. But we think that as a result of our experience up there, it gives us the opportunity to weigh, in the areas that they haven't already committed, the opportunities to put in our own gathering. So if I had to give you a percentage, I guess, I would say, there's probably somewhere in the range of 1/4 to 1/3 of their acreage where we think we might be able to do some of our own gathering. And also, in answer to your question about result increases in margin, then yes, you're right. When we do process ourselves, we do tend to see a lift in value. Good question. Thank you.

[Jeffrey W. Robertson:]

And does it change the way you all will think about some of the fixed price contracts you've done on oil or the length of time on the -- with the scale of the asset base?

[James J. Volker:]

The fixed price contracts that we have, of course, are gas. Then as you correctly state, we have fixed price differentials off of NYMEX for some of our oils, specifically that which is attributable to Redtail. And we did that because we saw an opportunity as people were coming to us as a large -- I guess, I'll put this way, in their minds and in our minds, somebody was going to be a very large producer in the area, to get us to commit our crude to their lines. And in return for that, we were able to negotiate differentials off of NYMEX that are approximately half of what the current differential is, if you looked at that area today. And so our VP of Marketing was out ahead of it on that and got us some great deals from first one pipeline and now a second.

[Jeffrey W. Robertson:]

And last question, Jim, you all -- with some of the acreage that you all retained down in the Delaware Basin, can you talk at all about what Whiting's capital plan is for that, either the rest of this year or next? Have you seen enough from your partner to get more involved or look at it as an asset you might want to market at some point in the future?

[James J. Volker:]

Well, we do remain active in Texas, in general. The Permian Basin, in particular, we do have a new wildcat play going on down there, and we'll have results of that by the end of the year. And the great part of it is that as a result of the great group of people that we have in Midland, I think we have the technical capability to pursue and not only our North Ward Estes project, but also some of the exploration plays that our geoscience has led us to. So that's one of the, in my opinion, most advantaged things that Whiting has, which is a great geoscience team, relying upon the latest technology, as well as, I'm going to say, a lot of personal experience by our geoscience team in that area, so that we're not necessarily out there competing for what everybody else is drilling. But we're looking for new oil resource plays in areas where acreage positions are available at reasonable prices. I'm talking about $100 per acre rather than thousands and thousands of dollars per acre. I'm talking about generally better net revenue interest that would be available when compared to the so-called hot areas of the basin. So that's the way we like to play Texas and it's worked well for us in the past, and I think it's going to continue to work well for us for a long period of time.

[Operator:]

Your next question comes from the line of Gail Nicholson with KLR Group.

[Gail A. Nicholson:]

When we look at the Razor 27I pad, the sand volumes that you pumped through those wells, was that your normal job? Or was that a tad bit higher?

[Steven A. Kranker:]

Volumes we're pumping recently, we are still experimental a little bit size, but that would be on the upper end of what we've been doing. Lower end would probably be in the 5 million pound range.

[Gail A. Nicholson:]

And then how much incremental cost would that be?

[Steven A. Kranker:]

Oh, probably, $300,000 -- $200,000, $300,000, something like that.

[Gail A. Nicholson:]

And then looking at the remaining wells that you guys planned to drill on the Williston in '14, what percentage of those wells are going to be utilizing some combination of plug-and-perf cemented liner or other new completion techniques versus sliding sleeve?

[James J. Volker:]

I think we stated earlier that we've gone -- we really aren't using sliding sleeves, except in very rare instances, anymore. So we've gone almost entirely to cemented liner plug and perf, but are augmenting that with the coil fracs, primarily because of operational efficiencies. But really what we're trying to do there is maximize the number of entry points. And both of those technologies give us the opportunity to do that, both the cemented liner plug and perf, as well as the coil fracs. What we're hoping for as an incremental gain is the slickwater fracs on top of that, and that's what we're testing right now.

[Operator:]

Your next question comes from the line of Pearce Hammond with Simmons & Company.

[Pearce W. Hammond:]

Jim, love to get your perspective on the Colorado ballot initiative, setback rules, et cetera, kind of how you see all that playing out?

[James J. Volker:]

There are actually 4 initiatives on the ballot, 2 are very pro oil and gas and 2 obviously are more restrictive. But in summary, obviously, we hope that the 2 that are pro oil and gas pass. And so far, the polling indicates that they will. The polling is somewhat mixed. And on the others, the anti-oil and gas ones would be those that generally have a setback of 2,000 feet and then others that basically result in the ability of the municipality or a county to have a separate set of oil and gas regulations from that of the state. So while it's questionable whether those antis will be successful with the ballot or beyond that constitutional, because I'm sure if they are passed -- I think it's the attorney general of the state of Colorado who's been quoted to saying that he wouldn't want to defend the constitutionality of those anti-measures. But on the positive side, I can say that there's really no problem for us created by that type of 2,000 foot setback on any of our Redtail-Niobrara acreage. We're able to -- frankly, there's only a -- I think out of 3,000, there's only about 24 that would be impacted out of 3,300-plus locations. There's only about 24 that might be impacted, and we simply solve that by moving where the wells are located and can still drill up all of our acreage. So we're not challenged by that. And I think there are largely -- there's a fairly large number of operators who basically are out there in the eastern side of Weld County that are unaffected by these wells. So I don't really look at it as being a problematic issue for companies, except a couple that are somewhat challenged by having their acreage sort of close to municipalities on the more western side of the Williston Basin -- of the DJ Basin, of the DJ Basin.

[Pearce W. Hammond:]

And then my follow-up is how is CO2 availability right now in North Ward Estes?

[James J. Volker:]

It's great. I mean, we have all the CO2 we need to execute our plan. We also had taken a fairly large acreage position in New Mexico, where we're drilling our own CO2 supplies. So we're in good shape for supplying North Ward Estes for its entire lifetime.

[Operator:]

Ladies and gentlemen, we have no further questions. I will now turn the call over to Mr. Jim Volker for closing remarks.

[James J. Volker:]

I'd like to thank all of our Whiting employees and directors for their contributions to an exceptional second quarter and our exciting plans for the remainder of the year. Eric?

[Eric Hagen:]

Jim Volker will be presenting at EnerCom, the energy conference in Denver at 9

[James J. Volker:]

Thanks, Eric. In closing, we want to thank all of you on this call for your new and continuing interest in Whiting Petroleum Corporation. We look forward to meeting with you soon.

[Operator:]

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect, and have a great day.