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On July 31, 2014, Whiting Petroleum Corporation (“Whiting”) held a second quarter earnings conference call, a replay of which will first be made available on Whiting’s website on August 1, 2014. The following is a transcript of such call.
Operator
Good day, ladies and gentlemen, and welcome to the Second Quarter 2014 Whiting Petroleum Corporation Earnings Conference Call. My name is Glen, and I will be your operator for today. At this time, all participants are in listen-only mode. And later, we will conduct a question-and-answer session. [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 today, Mr. Eric Hagen, Vice President of Investor Relations. Please proceed, sir.
Eric K. Hagen
Thanks, Glen. Good morning, and welcome to Whiting Petroleum Corporation’s second quarter 2014 earnings conference call. On the call for Whiting this morning is the Whiting management team.
During the call, we’ll review our results for the second quarter and then discuss the outlook for the third quarter and the 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 home page.
Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause the actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on slide number two, 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 three 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 number one 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 un-cemented 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 fracks either underway or planned for the third quarter of this year.
At our retail prospect, in Weld County, Colorado, we spud our 30F pad in the Horsetail area to test a 32-well spacing in the Niobrara A, B and C zones. Separately, our first eight-well pad, the Razor 27I, as 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 five, 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 six, 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 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 21-27-1H 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 at 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 number seven 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 eight-well pad, the Razor 27I, came on stream on April 15, 2014 and it’s currently producing approximately 4,700 BOEs per day. The pad drilled four wells into the Niobrara A zone and four wells to 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 eight, we spud our 30F pad located in the Horsetail township in early June. This eight-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 number nine, 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 number 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 number 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 number 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 number 13 shows that our two senior notes and senior subordinated note continue to trade above par. It also shows that we are well within all of the covenants in our credit agreement and our bond indentures.
Slide number 14 shows our crude oil hedge positions. At this point, we’re over 53% hedged for the remainder of 2014. On slide number 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 two 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 two really are. There are many areas in which the combined companies will benefit from the offset acreage positions, and together, we create an extremely attractive position in the Central and Eastern Williston Basin Fairway.
At the right, we 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 2014 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 company’s 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 standalone 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 combine 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 un-cemented 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 eight-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.
Glen, please open up the conference call questions.
Question & Answer Section
Operator
[Operator Instructions] And your first question comes from the line of Brian Corales with Howard Weil. Please proceed.
Brian Corales
Good morning, guys, and good quarter.
James J. Volker
Thanks, Brian.
Brian Corales
Two questions for you. One, the deeper test, that was a fantastic rate. How many of those deeper tests throughout your acreage have you all drilled? Or is this kind of the first one, the deeper Three Forks tests?
Mark R. Williams
Hello. This is Mark Williams. This is our first test at a second bench in the Three Forks here in the Central Basin – or excuse me, the third bench of 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 Corales
Okay. And then in the Niobrara, the Horsetail pilot, are you all drilling that just with one rig? And when can we expect to have those results? 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 one rig which means that those wells are drilled sequentially. And so in addition to the eight wells that are mentioned there, we have four 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, fracked and on production sometime after the first of the year, probably about the end of January.
Brian Corales
Okay. All right. And I know I probably shouldn’t ask one more, but the – so the timing of production in the Niobrara, it is going to pretty lumpy and in January we should see a big surge. Is that kind of – am I thinking about that right?
Mark R. Williams
I think what’s happened there is we’re going to be at five rigs at that point, so we think that having 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.
Brian Corales
Okay. All right. Thanks, guys, and good quarter.
James J. Volker
Thanks, Brian.
Operator
Your next question comes from the line of Joe Allman with JPMorgan. Please proceed.
Joe D. Allman
Thank you. Good morning, everybody.
James J. Volker
Good morning, Joe.
Joe D. Allman
So when we think about the new completion designs, should we think about some of those new techniques working in some areas better than others? So for example, like coiled tubing, like would 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
Hi. 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, the 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 four 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.
Joe D. Allman
Okay. That’s helpful. And then a separate question. On the Three Forks, I know that Brian just asked a question about that, but just clarify like how many Three Forks wells you’ve drilled so far and where you drilled them. And when I look at some of your old presentations and I see some of the thickness and some of the depths of the Three Forks, it seems as you go farther west, it thins out and in places like Hidden Bench and Tarpon it seems deeper. So like where do you think the Three Forks, whatever bench is going to be most prospective?
Mark R. Williams
Well that’s a pretty broad question, but I can tell you in general that the central part of the basin where the bulk of acreage is at Cassandra, Tarpon and Hidden Bench and going west at least to the North Dakota border has Three Forks potential. We’ve gotten good Three Forks production already and in general, we’re drilling one Three Forks well for every Bakken well through that area that I just mentioned. The lower benches of the Three Forks are another question. 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 of the Nessen [ph] 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 that periphery of the second bench is yet to be defined, and certainly that’s the case with the third bench as well.
Joe D. Allman
All right. Very helpful. Thank you.
Operator
Your next question comes from the line of David Cameron with Wells Fargo. Please proceed.
David Tameron
Hi. Good morning. And congrats…
James J. Volker
Good morning, Dave.
David Tameron
On the acquisition.
James J. Volker
Thank you.
David Tameron
Let me – in the Niobrara, could you guys talk about, and maybe I missed it in the prepared remarks, but can you talk about where the wells are tracking compared to the EURs that on prior quarters you 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 are 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 six months of production history, then our reservoir engineers will be making appropriate adjustments in our reserves.
David Tameron
All right…
James J. Volker
Do you want to comment, too?
Mark R. Williams
[indiscernible] pretty much it.
James J. Volker
Mike says – or Mark says he agrees.
David Tameron
All right. Fair enough. And this may violate – 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 think about A plus B and you 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. But we are going to add five more rigs to their seven, 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 under-leveraged compared to the peer group is 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 of saying so.
David Tameron
Yeah, I’ll dig into that more offline. Thanks. I appreciate the color.
James J. Volker
All right. Thanks. Bye.
Operator
Your next question comes from Michael Hall with Heikkinen Energy Advisors. Please proceed.
Michael Anthony Hall
Thanks. Yeah, just want to follow up a little bit on that Razor pad, the production profile on those wells. So if I’m looking at right, it seems like – are these still on an incline after roughly 100 days? And kind of 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 increase to increase over 90 and 120 days and then flatten out and go into a decline after that.
Michael Anthony Hall
And so I guess, because I’m trying to understand a little better, is kind of what – within y’all’s type curves and forward outlooks that the guidance is built around, how long until those wells kind of turn over within your base assumption, meaning is that outside the norm on that Razor pad? 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.
Michael Anthony Hall
Thanks.
Steven A. Kranker
The 27I pad is very encouraging. That’s our strongest pad today with all eight 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 to get to its peak production and then they go on a more gradual hyperbolic volume.
Michael Anthony Hall
Great. That’s helpful. I appreciate the color. And I guess the last one of mine. Can you just remind me in the DJ what your all’s experience has been so far with the Niobrara C Bench, which I think you’ll have some tests on that within that 30F pad, but I just looking for a reminder on what your experience has been so far with that bench.
Mark R. Williams
Right. Yeah, so the C Bench is something that we’ve recognized on logs and core for quite a while. When we compared it initially to the B and A, the combined B and A especially, we think that it’s not in communication with either of those. So it means it has to be drilled and completely independently. So the reserves there look quite good to us or at least in terms of the oil in place. In terms of our actual drilling, the 30F pad is really our first chance to test that. It has been tested and I’d successfully by our neighbor to the south there. And so they’ve got a couple of wells that look 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. If it is successful, it’s going to be a huge additional number of wells for us and obviously, it increases the number of reserves as well.
Michael Anthony Hall
Great. I appreciate the extra color. Congrats, guys.
James J. Volker
Thank you.
Operator
And your next question comes from the line of John Freeman with Raymond James. Please proceed.
John Freeman
Good morning, guys. Nice quarter.
James J. Volker
Thanks, John.
John Freeman
The first question I had on the coiled tubing frac, again on that 93-stage completion. Last quarter, you all had given one that was 85 stages and it was sort of 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 coil 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 cost compared? I mean, I know on the 85-stage it was sort of a combo job that was like $8.8 million. What did this one come in at?
Rick A. Ross
We’d say we don’t have all the cost 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 was discussing earlier on some 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?
Mark R. Williams
Well we are testing – what I should say, we’re actively drilling the upper bench of the Three Forks at Cassandra, very successfully, I might add. We’ve had five 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 productive limits of it.
John Freeman
Great. Well I appreciate it, guys. Congrats again on the deal.
James J. Volker
Thanks.
Operator
Your next question comes from Jason Smith with Bank of America Merrill Lynch. Please proceed.
Jason Smith
Hey. Good morning, guys.
James J. Volker
Morning, Jason.
Jason Smith
Just to stay on trend with the lower Three Forks, can you just remind us, Jim, how much of the lower benches are included in your current inventory locations?
Mark R. Williams
We haven’t really included any of that in our actual inventory of locations, other than – if you refer back to our – we have a wine rack that we put together that shows exactly how we’ve done it. And so that table that we’ve shown previously in the wine rack shows where we believe they may be prospective. And that really is – the second bench at Tarpon is the really the only one that we’ve added in any significant second bench opportunities. So we’re seeing deeper benches there and certainly there’s a chance that we’ll have that in Cassandra, but those are [indiscernible] .
Jason Smith
Do you guys happen to have a 30-day rate on that well?
Mark R. Williams
I don’t think we do yet. I think it’s – we’re just about at 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 fracks 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 cemented liner plug-and-perf. And to follow up on that, as you know, some operators in the basin are using the 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 cost as we’re currently doing our state-of-the-art completion with cemented liners.
James J. Volker
Which is about [indiscernible]
Jason Smith
And where are they today?
James J. Volker
About $8.5 million.
Rick A. Ross
Our cost can be in Sanish area we’re just right about $7 million. In the deeper part of the basin we’d be about $8.5 million.
Jason Smith
Great. Thanks, guys.
Operator
Your next question comes from the line of Brian Velie with Capital One Securities. Please proceed.
Brian Taylor Velie
Good morning, guys.
James J. Volker
Good morning.
Brian Taylor Velie
Quick question. Just trying to determine where the beat was for the quarter within the Williston area. Is it possible to kind of get into whether Western Williston, Southern Williston and Sanish all grew sequentially or is one particular area driving the growth more than another?
Eric Hagen
They all grew sequentially.
Brian Taylor 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?
Mike Stevens
All areas contributed pretty equally, yes.
Brian Taylor Velie
Okay. Great. Thank you so much.
Operator
And your next question comes from Jason Wangler with Wunderlich Securities. Please proceed.
Jason A. Wangler
Good morning, guys. 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 pads and things that are either already on 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?
Steve 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 we were going to divest, site-by-site comparison, 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-perfs. Yeah, it’ll 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 year-end’s reserve that we’ve already reported. [indiscernible]
Jason A. Wangler
Great. And then just maybe on the hedges as you go out to 2015, still I guess probably building a book, but how you see that shaping up. Is it going to be 2015 going to be pretty much similar to how we have been in past years, call it 50%-ish percent numbers as we get closer to that timeframe?
James J. Volker
Yes.
Jason A. Wangler
That’s all I needed. Thank you, boys.
James J. Volker
Thanks.
Operator
Your next question comes from the line Jeff Robertson with Barclays. Please proceed.
Jeffrey Woolf Robertson
Jim, question in 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 have – 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 that probably somewhere in the range of a quarter to a third 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 resultant 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 Woolf Robertson
Thanks. 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 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 oil, 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 it 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 crew 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 look 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 Woolf 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 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 the great geoscience team, reliant 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.
Jeffrey Woolf Robertson
Thank you very much.
Operator
Your next question comes from the line Gail Nicholson with KLR Group. Please proceed.
Gail A. Nicholson
Good morning. When we look at the Razor 27I pad, the sand volume that you pumped through those wells, was that your normal job or was it a tad bit higher?
Rick A. Ross
Volumes we’re pumping recently, we were still experimenting a little bit with 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?
Rick A. Ross
Probably $200,000, $300,000 something like that.
Gail A. Nicholson
And then looking at the remaining wells that you guys plan to drill in the Williston in 2014, 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?
Mark R. Williams
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 coil fracks, 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 fracks. What we’re hoping for as an incremental gain is the slickwater fracks on top of that and that’s what we’re testing right now.
Gail A. Nicholson
Great. Thank you.
James J. Volker
Thank you.
Operator
Your next question comes from the line of Pearce Hammond with Simmons & Company.
Pearce W. Hammond
Congrats on a great quarter.
James J. Volker
Thanks, Pearce.
Pearce W. Hammond
Jim, I’d love to get your perspective on the Colorado ballot initiatives, back rules, et cetera, kind of how you see all that playing out?
James J. Volker
Well there are actually four initiatives on the ballot, two are very pro oil and gas and two obviously are more restrictive. But in summary, obviously, we hope that the two that are pro oil and gas pass. And so far the polling indicates that they will. The polling is somewhat mixed on the others. The anti-oil and gas ones would be those that generally have the setback of 2,000 feet, and then others that basically result in the ability of a 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 at the ballot or beyond that, constitutional, because I’m sure if they are passed that I think as the Attorney General in the State of Colorado has been quoted as 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 for us by that type of 2,000-foot setback on any of our Redtail Niobrara acreage. We’re able to – frankly there’s only, I think out of 3,000 there’s only about 24 that would be impacted out of 3,330 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’s a fairly large number of operators who basically are out there in the eastern side of Weld County that are unaffected by it as well. 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.
Pearce W. Hammond
Great. Thanks.
James J. Volker
DJ Basin – of the DJ Basin.
Pearce W. Hammond
Yeah. Thank you for that detailed answer. And then my follow up is, how is CO2 availability right now at 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 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.
Pearce W. Hammond
Thank you, Jim.
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
Great. Thank you, Glen. 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 K. Hagen
Jim Volker will be presenting at EnerCom’s The Energy Conference in Denver at 9:40 a.m. on Monday August 18. And Jim will also present at Barclays’ CEO conference in New York City at 11:45 a.m. on September 2, and he’ll be the luncheon keynote speaker at IPAA’s OGIS West Conference in San Francisco on September 22. So we look forward to seeing you at those events.
James J. Volker
Thanks, Eric. In closing, we want to thank all of you on this call for you 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.
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Forward-Looking Statements
This communication contains statements that Whiting Petroleum Corporation (“Whiting”) believes to be “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including statements regarding the expected benefits of Whiting’s proposed acquisition (the “Acquisition”) of Kodiak Oil & Gas Corp. (“Kodiak”) to Whiting and Kodiak and their shareholders, the anticipated completion of the Acquisition or the timing thereof, the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the combined company, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. These risks and uncertainties include, but are not limited to: the ability to obtain shareholder, court and regulatory approvals of the Acquisition; the ability to complete the proposed Acquisition on anticipated terms and timetable; Whiting’s and Kodiak’s ability to integrate successfully after the Acquisition and achieve anticipated benefits from the Acquisition; the possibility that various closing conditions for the Acquisition may not be satisfied or waived; oil and natural gas prices; level of success in exploration, development and production activities; the impacts of federal and state laws; the impacts of hedging on results of operations; uncertainty regarding future operating results and plans, objectives and expectations; and other risks described under the caption “Risk Factors” in Whiting’s and Kodiak’s Annual Reports on Form 10-K for the period ended December 31, 2013 and Whiting’s Quarterly Report on Form 10-Q for the three months ended June 30, 2014. Whiting assumes no obligation, and disclaims any duty, to update the forward-looking statements in this communication.
Important Additional Information and Where to Find It
This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of a vote or proxy. The proposed Acquisition anticipates that the Whiting shares to be issued pursuant to the Acquisition will be exempt from registration under the United States Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 3(a)(10) of the Securities Act. Consequently, the Whiting shares will not be registered under the Securities Act or any state securities laws. In connection with the proposed Acquisition, Whiting and Kodiak intend to file relevant materials with the SEC and other governmental or regulatory authorities, including a joint proxy statement and circular. INVESTORS ARE URGED TO READ THE JOINT PROXY STATEMENT AND
CIRCULAR AND ANY OTHER RELEVANT MATERIALS WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT WHITING, KODIAK AND THE PROPOSED ACQUISITION. The joint proxy statement and circular and certain other relevant materials (when they become available) and other documents filed by Whiting or Kodiak with the SEC may be obtained free of charge at the SEC’s website at http://www.sec.gov. In addition, investors may obtain copies of these documents (when they become available) free of charge by written request to Whiting Investor Relations, 1700 Broadway, Suite 2300, Denver, CO 80290-2300 or calling (303) 390-4051 or by written request to Kodiak Investor Relations, 1625 Broadway, Suite 250, Denver, CO 80202 or calling (303) 592-8030.
Participants in the Solicitation
Whiting, Kodiak and their respective executive officers and directors may be deemed to be participants in the solicitation of proxies in connection with the proposed Acquisition. Information about the executive officers and directors of Whiting and the number of shares of Whiting’s common stock beneficially owned by such persons is set forth in the proxy statement for Whiting’s 2014 Annual Meeting of Stockholders which was filed with the SEC on March 23, 2014, and Whiting’s Annual Report on Form 10-K for the period ended December 31, 2013. Information about the executive officers and directors of Kodiak and the number of Kodiak’s ordinary shares beneficially owned by such persons is set forth in the proxy statement for Kodiak’s 2014 Annual Meeting of Shareholders which was filed with the SEC on May 9, 2014, and Kodiak’s Annual Report on Form 10-K for the period ended December 31, 2013. Investors may obtain additional information regarding the direct and indirect interests of Whiting, Kodiak and their respective executive officers and directors in the Acquisition by reading the joint proxy statement and circular regarding the Acquisition when it becomes available.