Chord Energy Corporation (CHRD) Q1 2013 Earnings Report, Transcript and Summary

Eric Hagen - Vice President of Investor Relations James J. Volker - Chairman, Chief Executive Officer and Director of Whiting Oil & Gas Corporation James T. Brown - President and Chief Operating Officer Michael J. Stevens - Chief Financial Officer and Vice President Mark R. Williams - Senior Vice President of Exploration and Development David M. Seery - Vice President of Land

Will Green - Stephens Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Pearce W. Hammond - Simmons & Company International, Research Division Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division Phillip Jungwirth - BMO Capital Markets U.S. Scott Hanold - RBC Capital Markets, LLC, Research Division Paul Grigel - Macquarie Research Raymond J. Deacon - Brean Capital LLC, Research Division

Good day, ladies and gentlemen, and welcome to the Quarter One 2013 Whiting Petroleum Corp. Earnings Conference Call. My name is Sharon and I'm your event manager for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. This call will be limited to 1 hour. Prepared statements will be approximately 10 minutes to allow more time for Q&A. [Operator Instructions] And I would like to turn the call over to Mr. Eric Hagen, Vice President of Investor Relations. Please proceed.

Thanks, Sharon. Good morning, and welcome to Whiting Petroleum Corp.'s First Quarter 2013 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 first quarter of 2013, and then discuss the outlook for the second quarter and full year 2013. This conference call is being recorded and will also be available on our website at www.whiting.com. To access the call and webcast, please click on the Investor Relations box on the menu and then click on the webcast link. Please note the forward-looking statements disclaimer and the discussion of non-GAAP measures on Slide #2. And please take note that our Form 10-Q for the 3 months ended March 31, 2013, is expected to be filed later this week. Reconciliations of non-GAAP measures we refer to and the applicable GAAP measures can be found in our earnings release and in our webcast slides. And with that, I'll turn the call over to Jim Volker.

Good morning, ladies and gentlemen. And as always, thanks for joining us. We'll move quickly through our presentation and get to your questions as soon as possible. We're pleased to report that we're off to a very strong start in 2013, our 10th year as a public company. Production in the first quarter of 2013 grew 4% sequentially over the fourth quarter of 2012, and we're on track to post a year-over-year production gain of between 12% and 16%. At our 88,000 net acre rig tail Niobrara prospect, in the DJ Basin, our most recent completion came in at 860 barrels of oil equivalent per day. We plan to step up our activity there in the second half of this year. Slide 3 clearly shows 74% of our total production is coming from our core Rocky Mountain region. Currently, more than 60% is coming from the Bakken and Three Forks in the Williston Basin. Slide #4, shows our 2013 capital budget of $2.2 billion. 52% of our drilling budget is being invested in the Northern Rockies and that of course includes our Middle Bakken, Three Forks and Pronghorn Sand plays in the Williston Basin. In addition, over half of our non-op land exploration expense, facilities and work over cost incur in the Northern Rockies. So the Northern Rockies is about 70% of our total budget. On Slide #5, we provide an overview of our plays in the Williston Basin where we control more than 700,000 net acres. In the footnote, you'll see our average acreage cost in the Williston Basin is a very attractive $526 per net acre. Production was up in all 3 of our core areas in the Williston Basin. Our Western Williston area, which contains our prolific Hidden Bench and Tarpon prospects, increased 27% over fourth quarter levels. Currently, the second quarter is off to a good start as we're flowing back 12 wells, 5 in Hidden Bench and 7 more across Pronghorn, Cassandra and Sanish. Also of note, in Q1, in the Western Williston, our results are at our Missouri Breaks area. There, we completed 3 wells during the quarter, with an average IP of over 1,200 BOEs per day from the Middle Bakken. This includes our best well to date in the field, the Miller 34-8-1H that tested 1475 BOEs per day. In the Sanish field, we continue to experience strong results as we continue to develop the western half of the field, and that's evidenced by our recent Roggenbuck 21-25H, Middle Bakken well, that tested 2053 BOEs per day. At Sanish, we plan to spud our first high-density, Middle Bakken pilot in May. If successful, this could add nearly 200 additional net drilling locations to our Sanish inventory. And as you know, Sanish is the sweet spot of the basin. In addition, to the Sanish high-density pilot, we plan to spud our Pronghorn, where obviously we're developing the Pronghorn Sand and our Hidden Bench, where we're developing the Middle Bakken, high-density pilots in June, which puts us on track to report preliminary results on the third quarter call and more definitive results by Q1 2014 as we watched production results. If successful, this would add over 116 net locations at Pronghorn and over an additional 160 net locations at Hidden Bench. Slide 6 shows that current takeaway capacity from the Williston Basin is more than 1 million barrels per day compared to current production of approximately 840,000 barrels per day. The recent increases in off-take are largely due to additional rail. The excess capacity has led to much narrower differentials in the Williston Basin. And now Jim Brown will highlight our recent exploration results outside of the Bakken.

Let's start on Slide #7 with our Redtail prospect in Wells County, Colorado where we target the Niobrara formation. We and offset operators have been moving to larger fracs with encouraging results. Our most recent completion, the Razor 26-3524H flowed 861 BOE per day from the Niobrara B zone. It has averaged over 600 BOE per day over the past 2 weeks. The well's 6364-foot lateral was fracture stimulated in a total of 32 stages. We utilized the plug and perf completion techniques and pumped over 5 million pounds of proppant. We hold the 74% working interest and a 59% net revenue interest in the Razor well, which was drilled on a 960-acre spacing unit. We believe that in development mode, we can drill and complete this type of well for under $6 million as reductions in drilling times have been offsetting increases in frac volumes. To put this in perspective, our average Niobrara B well has IP-ed around 500 BOE per day. Most of these wells were drilled on 640 acres spacing with 4500-foot lateral utilizing sliding sleeve frac jobs in the 2.5 million pound range. In summary, longer laterals and longer frac jobs have enhanced well performance. We are moving a second rig into Redtail mid-July and are planning for a third rig by year end. Permitting for our gas plant is proceeding and we are on schedule to have the gas plant online early 2014. Moving to Slide 8. We completed the May 25O2H at our Big Tex prospect, blowing 674 barrels of oil per day from the Upper WolfCamp formation in January, 2013. The well's peak 30-day average was 400 barrels of oil per day and the well is currently producing over 200 barrels of oil per day. Based on the performance of this well, we plan to drill at least 3 horizontal Upper WolfCamp wells at Big Tex in 2013. Mike Stevens, our CFO, will now discuss our financial results in the first quarter of 2013.

On Slide #9, you see our first quarter 2013 adjusted net income available to common shareholders was $111.6 million or $0.94 per diluted share. Our discretionary cash flow in the first quarter totaled a record $401.1 million. This total represented a 14% increase over the $351.9 million in the first quarter of 2012 and a 5% increase over the fourth quarter of 2012. On Slides 19 and 20, we showed reconciliations to these non-GAAP measures. Our guidance for the second quarter and full year 2013 is detailed on Slide #10 and shows continuing quarter-over-quarter and year-over-year production increases. On Slide #11, our first quarter EBITDA margin increased to 67% of our blended realized price per BOE. On Slide #12, you can see that we continue to maintain a strong balance sheet with total long-term debt of $2.1 billion and a total debt-to-capitalization ratio of 37%. Slide #13 shows that our 2 senior subnotes are trading above par. It also shows that we're within all of the covenants in our credit agreement and our bond indentures. Slide #14 shows our crude oil hedge position and includes our 3-way oil collars that we put on for 2013. On Slide #15, you'll see the new swaps that we recently put on at attractive prices. We're now 70% hedged on our oil production for most of 2013. On Slide #16, you'll see a strong fixed price contracts that continue to net us over $5 per Mcf. I'll turn the call back over to Jim Volker.

Thanks, Mike and Jim. Ladies and gentlemen, Whiting is a higher margin oil company, and our production is on track to grow 12% to 16% in 2013. We're encouraged by the continuing results at our Williston Basin and Niobrara prospects, and estimate that we could have nearly 20 years of future drilling on those 2 plays alone. Personally, I believe this is an opportune time to own Whiting stock. We plan for and we are experiencing success at 10 major prospect areas as we speak to you. And this year, we'll test new prospect areas during the year. So operator, will you please open up the conference call for questions? Thank you.

[Operator Instructions] Your first question is from the line Will Green with Stephens.

I wonder if we could start on the Permian. Can you guys remind me how many stages, how long the lateral was on that May 25O2 and how that will compare to the additional test you guys are going to be doing later this year?

Yes, that was about a 40 -- 4,000-foot lateral that we drilled out there on that May well. I believe we frac-ed that with 16 stages, and -- well, yes, 16 stages and that was with the cemented liner and plug and perf completion. So that's the procedure that we are planning to take forward. What you're going to see us do on these new wells is you're going to see us ramp up the size of frac and the number of stages that we pump on those frac jobs considerably from where we've been.

Got you. I appreciate that. And then, one other item, I noticed you guys -- the Permian acreage count has kind of dropped, are you guys swapping, selling, letting acreage go? Just, if you could add any color on that, that'd be great.

We let some acreage on the far eastern side of our block drop just because the results over there weren't as good as the central and western portions.

Right. I appreciate that color. And then, what's the timing on the Niobrara? What’s the timing on when you guys will have some density tests, 8 or 12 well pads? Are you guys thinking that far ahead at this point, just any color on that would be great?

Right now, we have 1 rig working out in our Redtail project. But we're going to be bringing a second rig on towards the beginning of July and that rig is designed to do pad drilling. So that will initiate our essentially high-density, and we're -- I should say, we're currently going through a regulatory process to allow us to drill up to 16 wells per spacing unit right now. That's something that should be through by July 1. And we will begin pad drilling at that time and that will take place with our second rig. And as we mentioned in the call earlier, we're looking at bringing a third rig on towards the end of the year. So both of those rigs will be dedicated to doing pad drilling. So we've identified a really nice area and getting all that permitted and ready to go.

And just to expand on that last answer briefly, I'd simply say that we've been watching with great interest, not only the results of our own wells, of course, but the wells that other people have been drilling. And both of those tend to indicate that this higher density that everyone's talking about and planning to go to, including ourselves, is resulting in what I would call, synergistic frac-ing. So we're -- this is a very high OOIP area. And we think the more we bust up that rock, the better the recovery will be, and certainly, the preliminary results to date tend to underscore that. And so we're excited. We're excited about this area and we really believe we could be active here for a number of years.

Your next question is from the line of David Cameron with Wells Fargo.

I'm not -- I think it was Jim Brown who mentioned this, but can you talk a little more about exactly what you did different in the Razor well, as far as more stages and more sand, I guess Jim used the word synergistic frac-ing, can you just talk about exactly that approach versus the other ones?

Sure, the synergistic frac-ing didn't really play a part in this Razor well because it was a one off, I mean, we drilled it a single well in the spacing unit. But Dave, what we did do is we pumped 32 stages on that frac, which was considerably more than what we have pumped on our previous frac jobs, it was a plug and perf frac job. So what that does is by taking all of the material or all of the equipment out of the wellbore, we were able to get the tow zones frac-ed much more efficiently down there, and then we also cranked up our proppant considerably. We were well over 5 million pounds of propane in there, which is about double what we have been pumping up there, all of those seems to have given us very encouraging results.

Okay. And I think you may have mentioned this, but the one rig going forward, what's -- is this the new design that you're going to test on future wells?

What we're doing is we are comparing this sliding sleeve in the plug and perf. We are pumping the frac job almost identical to the one that we've just pumped. The only difference is we're using sliding sleeves. So that will give us an idea of which one works better, the sliding sleeve or the plug and perf. I think we are definitely going -- leaning towards more stages, more proppant. And then as Mark William's alluded to, we are very interested in starting to drill these on tighter spacing and then benefit from the results of synergistic frac-ing. As you may have seen some information put out by other people, the greatest recoveries they've seen to date have been on the higher density wells or the lower spacing wells. So we're very anxious to get going on that program.

Okay. And with that, I thought you guys threw that 35 million barrel in place number, oil in place number, what's a realistic recovery?

If you look at that 35 million barrels oil in place number but we've originally started planning was sort of a 4 well per spacing unit type of a program which would've only given us about a 3% recovery efficiency based on the EURs that we are projecting at that time. So as we get to higher and higher density, that recovery efficiency goes up, and we think we could vary -- without any difficulty at all, get up to 12%. And just incidentally, if you look at and compare that to what we're experiencing in the Bakken, we have enough production history up there to say that 11 -- 10% to 11% is very achievable. We think we can actually get higher up there as well. So we're still well under the threshold of recovery efficiency given the very high OOIP up here in the Niobrara. That is not the limiting factor and so -- what we're really saying this whole idea behind the synergistic frac-ing is that you're getting a mutual benefit by getting these wellbores closer together. So in other words, the stimulation from the second well, you're going to have a very positive effect on the first well that you drilled and vice versa

Your next question is from the line of Brian Corales with Howard Weil.

Back to the Niobrara, can you talk about how much of the acreage you think you've de-risked at this point? And also talk about what zones outside of just the Niobrara B that you all have tested?

Well, I'll respond quickly on that. We really believe that as a result of our drilling and drilling done by others, that 100% of our acreage out there has been put into what I would call, it's really out of the resource play or it's out of the resource category and moved into P1, P2, P3 and effectively then, that it's all de-risked in one way or another. So that's because there have been wells drilled basically north, south, east and west of our acreage position, as well as a pretty much north, south, east and west within our acreage position. The 2 zones that we're currently producing are the B and the A within the Niobrara. And I'll ask Mark to expand on this. But anyway, we feel confident that in terms of net wells out there, there's at least roughly 1200 net wells to be drilled by Whiting.

And to answer your question about the other zones, the other prospective zones that we're looking at right now are both the Codell and the Niobrara C, we've been quite focused on the A and B. We just -- we've got an awful lot to get done out there, and so you'll see us testing the Codell probably later this year and presumably the Niobrara C as well, we're working out plans for both of those. But all 4 of those are prospective and produce within the greater area around Redtail.

Okay, if I could do one more. This is the last one. The ratio was 6000 foot lateral, is that kind of the most what you think is optimal or you want to -- is 4000 better or will you even try to press it further and go to what some of your peers have done and gone even closer to 8000 or 9000 feet?

At this time, we've spaced about 60% of the area out there on 960-acre spacing units and the remainder on 640. Just the work we've done, just on the efficiency of drilling and the efficiency with our completions, we think the 960 spacing unit is kind of the optimum way to go, which gives you a lateral in that 6300- to 6500-foot range, somewhere in there.

Your next question is from the line of Tim Rezvan with Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I have 2 quick questions. First, I was hoping you could give an update on the pads you're pursuing with the Postle field sale or potential trust? And how comfortable you remain with this first half timeline you've spoken about recently?

Well as Whiting has set, Postle was a potential candidate for sale or other monetization like a royalty trust. As we've taken actions during the first quarter by putting some crude oil swaps in place that we could attach to those properties that we are considering for potential monetization. And I think timeline, as you've described, is what we've answered is reasonable when questioned in the past. However, we do not comment on the current status of ongoing M&A activity because it is ongoing M&A activity. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And I appreciate that. And then second, can you provide some specificity or earning technical details on what exactly you're doing with your Sanish infill testing program? And can just confirm is that 191 net locations you're looking to add?

Yes, we can confirm that. And Mark, why don't you talk about the Sanish?

Yes, if you look at Sanish and particularly at the Middle Bakken right now, the pad that we've been drilling on is essentially 4 Middle Bakken wells per spacing unit. But when you look at Sanish compared to other areas across the basin, the OOIP essentially, is as high as it is anywhere in the basin. It's actually about 22 million barrels per 640 acre unit, so we believe that we're significantly under density there with respect to the amount of oil in place. So what we're trying to do is we're -- we have 4 pilots that we've defined around the field, where we're going to go in and test the idea doing high-density infill drilling. And so the hope is and we have very good reasons to believe that we can get a recovery efficiency up above that 10% or 11% number that I mentioned before, up to somewhere around 15% or possibly even 20%, we don't exactly what that number's going to be just yet. But we think, again, that the OOIP in Sanish field is what justifies this, and so we're going to be testing that here starting really here in the second quarter through the third quarter. We'll have some preliminary results towards the end of the third quarter. I think it will be pretty definitive by the end of the year.

Your next question is from the line of Mike Kelly with Global Hunter Securities.

I was hoping to check in with you guys and hear where your heads' at right now on potential monetizations outside of the Postle field. I know in the past you've talked about bringing in JV partners on some of a more exploratory portions of the Williston and also the Niobrara. We just love to hear if it still fits into the strategy right now?

Well, I'll try to be as responsive to that question as I can. We definitely had some ideas about where we should and why we should joint venture some prospects. And our thinking there was Big Tex and perhaps Redtail and perhaps 1 or 2 areas in the Williston. And what we noticed was sort of, I guess I'd say, it was probably a result of perhaps some macroeconomic things and then happening in some moderation in oil prices, we noticed sort of a what I would call, a falloff in activity, and I think that was pretty well reflected in, what I would call, first quarter M&A and activity. However, we have seen now a resurgence of interest, a lot of calls coming in about those particular areas that I mentioned, and whether or not we would still be interested in doing that. We are, however, now, further down the development of those, obviously, Redtail is in our opinion, if not a home run for us, and by that, I mean, like a grand slam home run, it's at least knocking in 1 or 2 runs. So as to whether or not we'd be willing to do something at Redtail, I can't answer that at this time other than to say, it's less likely. It's like everything else, everything has a price. And some people are quite interested in it. So we remain open to proposals, but we're not out there actively marketing Redtail at this time. And separately, there is continued interest at Big Tex. Obviously. Our results there have improved. Although we haven't drilled as many wells there as we did at Redtail. So it's in a position where it's more likely that we would be willing to let somebody in on that one. On the other hand, I do think that drilling done by us and our neighbors both to the north, to the west, to the south and certainly, as far east is kind of the center of our acreage position there has the de-risked that particular play significantly from where we were 3 months ago. So I hope that's helpful to you. The answer is yes, we're still considering doing something. But I would say that the odds are far less likely at Redtail and still reasonable at something that Big Tex where it's less developed than Redtail.

That's good color, appreciate it, my follow up would be on the Redtail then if it is less likely that you bring in the JV partner, what does this asset look like in terms of activity? How many rigs do you have on it in full development mode, which I would imagine, it happens at some time in '14 after the gas plant is fully up and running?

Good guess. And my responding guess, because nobody knows for sure yet, but probably 5 rigs, I'd go out there and that far.

Your next question is from the line of Pearce Hammond of Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Jim, given your success there at Redtail specifically with this Razor well, how should we think about EURs at Redtail?

Initially, our thoughts were that 300,000 was the right ballpark number, obviously, based upon the results of our last few wells and although we only sort of named one, here, we've actually drilled several wells there and the average is around 500 BOEs a day IP. But the more recent ones as result of what Jim Brown just talked about here the way we're completing them, since we're hitting them with a bigger frac and more stages. We're getting up to around 800 barrels a day IP and the great thing is they're holding in there. Several weeks later, 600 barrels a day. So I would say that if you think of a higher number, we haven't put a number on it yet, but it certainly encourages us to perhaps something that might start with a 4, we'll see. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then I noticed a nice uptick in your Redtail acreage, are you still trying to acquire additional leasehold in the area?

We have our crack land man, Dave Seery on that, I'll let him answer.

Yes, right now, we're doing some strategic trades with other players out there, but yes, we're still acquiring acreage deals that we've had in the hopper for quite some time. So we're solidifying our position. Pearce W. Hammond - Simmons & Company International, Research Division: Great, and then last one for me, if you can provide any color on the lower benches of the Three Forks and Whiting's potential prospectivity and kind of what you're seeing, but also what you're hearing from some other operators up in the Bakken Three Forks?

I'll take a crack at that. The lower benches of the Three Forks have been a big area, big interest for a lot of people. And we believe in the central part of the basin, where our Tarpon prospect is, where our Cassandra prospect is, and to some degree, where Hidden Bench is, that we're seeing a charge from the lower Bakken shale down through the first bench and in some cases, down into the second bench. We've been able to confirm that with core. We're a little bit hesitant to extend it much beyond that both aerially or by depth and so that's-- we're just going by the evidence that we've seen so far from the core that we've taken but we're optimistic that continued drilling could lead to defining that deeper charge in other parts of the basin.

That I'd refer you to Page 6 of our fourth quarter news release for 2012 and you'll be able to see exactly -- we name exactly there and in the slides which are complete investor presentation, we've shown an abbreviated version of that here today, we're replacing our wellbores. So page 6 of Q4 and then the current slide presentation full-blown one shows you exactly where we're placing our wellbores. I would like to say that one of the things that I think our geoscience has pointed out to everyone is that part of our acreage what we have what we consider to be the Bakken silt zone here which we think is really just as attractive as some of the third -- say, like the second or the third bench.

Your next question is from the line of Mike Scialla with Stifel. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Looking at your Slide 7, it looks like you've drilled now in the Niobrara more than 30 wells, is that correct?

Yes. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: And of those, how many of those have been completed at this point?

Get a whole table on that for you. Page 22 I believe. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: So 20-plus and I guess you've just given us results on a few now, I'm just wondering, you did mention that the Razor had a higher IP rate than I guess your average previously was around 500. Is that, do you think primarily because of the completion difference or is there any variability you're seeing in the geology across what you've drilled so far?

I'd say that there is -- what we really demonstrated here with our most recent completions which should in addition to the Razor, would include our Horsetail well and our 2 recent Wildhorse wells. Those really reflect the change in our completion strategy. And so as Jim Brown mentioned, we're increasing the size of our frac jobs, we're drilling longer laterals, and we believe that the higher density drilling that we're embarking on here is going to -- will all lead to better results in that play. In terms of the geologic variability, we have really seen pretty consistent results, I would say, from 1 end of the field down in the southwest side where our Wildhorse wells all the way up to almost to the northeast end of the fields where our Horsetail well is. And Horsetail well frankly is as good as the Razor well is. And so I think we can draw a line between those 2 and say that pretty much everything through there is good. That leaves a fair bit of our acreage position still untested. And we -- with our first rig, which is not a pad rig, the one that we're using right now, we're going to continue to try and to find the areas both further to the north and to the east. Part of the reason we haven't developed that area to the northeast yet is because the 3D seismic data is essential to geo-steering in this formation. There's a fair number of faults and we have to be aware of those, let the geo-steer through them. So we're right now, in the process of shooting a second 3D seismic program which is going to compass most of our acreage on the northeast side of the field. And that will give us the opportunity to get out there and start stepping out and expanding the development area that we've got.

But just to summarize the numbers for you there, Mike, we've now drilled a total of 26 wells there, as you indicated. 22 of those are Niobrara B and essentially, if we take a look at the sort of progression of IPs, it's basically gone from 400 barrels a day then the 500 barrels -- that was like 400 barrels a day on the last 10 and out of the last 5, 500 barrels a day and over the last well like the plays the Razor well, approximately 800 barrels a day. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: So just a handful, or maybe the 2 or 3 that you've done with the bigger frac jobs in the longer laterals?

Correct. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: And was that Horsetail well done with the bigger frac job?

Was not. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Was not. Okay. And have you tried any Niobrara A with a longer lateral bigger frac jobs?

Not yet, they both been sort of science wells. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Got you. Okay. And then just the last one, anything new on Pronghorn, anything changed in the size of the sweet spot there or any new update on Pronghorn at all?

The biggest thing we're doing at Pronghorn right now is high-density pilot, similar to what we're doing up there at Sanish. We've been drilling out on a 3 well per spacing unit pattern. And so we're going to test, downspacing and configuration of our spacing units there, such that, if we make the jump, we'll go from 3 wells to 5 wells per spacing unit. We continue to develop the east side of the field of what we call the Marsh area, and we're getting very good results there, and so we're starting to do pad drilling now on the east side, just as we have in the main part of Pronghorn over in the west side, so that's also new.

Mike, if I could add onto that, the one thing that we have seen is we've gotten into the pad drilling at Pronghorn, maybe what we referred to earlier is the synergistic frac-ing, as we frac-ed multiple wells on a pad, we have seen some pretty consistent results utilizing that. So I think that's a benefit maybe a little extra benefit we're getting out of the pad drilling at Pronghorn. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: So is it fair to say that you think you've pretty well identified where you want to drill the extent of the good area there and now it's kind of figuring out just what's the proper density and maybe the full-blown development scenario for Pronghorn, is that fair?

I think that you'll see us continue to test the edges, especially as we go to the southeast. So I don't think we really defined or limited the reservoir yet. There's still more we've got to do there. We've been pretty focused on developing the core of the area, but there's still a fair bit I think we need to do as we go further into our acreage position on the southeast margins especially.

Your next question is from the line of Phillip Jungwirth with BMO Capital Markets.

On Redtail, is there any potential to pursue higher density development there than what you've laid out in the primary inventory count that assumes 8B Bench and 4B Bench, 4A Bench location?

Yes. As we mentioned earlier, we're right now, before the regulatory agencies, with a 16 well per spacing unit pattern. That will be applicable to our 640s and to our 960s. If we can just determine that the A and the B zones separately need really such separate stimulations, there's a possibility -- we're not ready to do this yet, but there is a possibility that we can end up doubling that number and going up to 32 wells per spacing unit. We just haven't determined that yet. We really need to get in here and start drilling on our high-density pilots. We have 2 that are planned right now, where we're going to go in on a 16 well density and do a B, B, B, B. It's actually 4 Bs adjacent to each other and right next to that, we're going to do a B, A, B, A and really see and test in geologically identical environments, which those 2 configurations are going to work best. I think there's a decent chance that we'll end up being able to develop each of those zones separately and that will lead to yet another doubling, but we're not quite prepared to make that leap in logic yet.

Great, and will all or most of your Niobrara wells going forward be completed with this new completion design? And then they when would you expect to go back and test the Codell?

Yes, to the first question. And we are working up another Codell. We did drill up a Codell test early in the program out here. It was -- we're still have a lot to learn on how to drill and complete these wells and so it was a moderate well. But we do have another Codell test planned for later this year. So we are working on it, we're just trying to get the B and the A program. We've got quite a bit on our plate just with the 2 upper benches of the Niobrara there.

And then in Missouri Breaks, the Miller well, was there any change to the completion design there? That's well a day in the field? And then where in the field is that well drilled, was it to the western, eastern or southern part of the acreage?

That was in what we call East Missouri breaks, and no, we used our pretty standard completion technique on that well. It was a 30 stage frac job. I don't remember exactly the proppant, but I'm going to say 3 million pounds plus or minus of proppant used on that well.

And then production in the southern Williston I think was up 3% quarter-over-quarter, is that just due to timing around pad drillings or is there any reason that production wouldn't be up more there?

No, you nailed it, those are actually [ph] the reason.

Okay. And then last question, are there -- is there any expectations for North Ward Estes production this year?

Well, all I can tell you is that we're very pleased with the results of North Ward Estes in our forecast early in the year. Based upon our independent engineering that particular field should today, be somewhere around the 8700 BOEs a day. And today, as I sit here speaking to you, it's 8990. So it's doing better than our forecast.

Your next question is from the line of Scott Hanold with RBC.

It seems that you all have talked a lot about this plug and perf and in bigger fracs. And I think in the past, you've been known as a good use of sliding sleeves fairly successfully. Do you -- is there a chance that when you look at your sort of core Bakken program, you'd reconsider things or it's just the geology in certain areas, just more amendable to that plug and perf?

We think it's primarily a geologic thing. We -- up around the edges of the basin, if you look at where the predominance of the Whiting's acreage is, Sanish, Pronghorn, Williston, Clark, Missouri Breaks, we're up on the side of the basin or the edge of the basin where our pressures aren't quite as great, temperatures aren't quite as high. And around there, I mean, we have done, I don't know how many studies looking at plug and perf and sliding sleeve. And I can honestly tell you we can see no difference. I know the last study we looked at, we compared 7 wells and we ended up with 3 better, 3 worse and 1 right in the middle. So we don't see any difference between plug and perf and sliding sleeve around the edge of the basin. When you get out into the middle, when you get out in the Hidden Bench, Tarpon, in those areas, you're higher pressures, higher frac gradient, taking all the sliding sleeves out of the wellbore, cleaning up the wellbore so you reduce all your friction pressure and all that while you're pumping your frac job, we have seen a benefit to that in those areas. We're wondering about the same thing down at the Niobrara, which is why we've tried it, and why we're going to continue to evaluate that technology. Our offset operator down in the Niobrara pumps pretty much all sliding sleeve jobs. So we're using that in the comparison. As then we go down into the Delaware Basin, down at Big Tex, deeper, hotter, higher frac gradient, we have seen a benefit going to plug and perf, so I'm just going to say, we're not locked in to 1 technology, we have a very open mind, and we'll do whatever works the best.

Well, we letting the rocks tell us what to do.

Okay. That's it, that's a good way to think of it. And in just in terms of when you set out your budget of what was it, $2.2 billion, I mean, did that assume this type of program? Because I think that was the plug and perf will be a little bit more costly? And then as you obviously add the rig to the Permian, I mean, is there sort of an expectation, sort of activity increase in the back half of the year that could have an upward bias to your CapEx outlook?

Well a; yes, we took the fact that some jobs will be plug and perf and some jobs will be sliding sleeves, and to consideration in our budget, we do it to that detail. And then second, the guidance on CapEx is the guidance. So at this point, there's not enough, I'm going to say, change, even though yes, we are going to drill a few more wells there is not enough change to change the bottom line number there of $2.2 billion. Mr. Brown and Mr. Walton in our drilling group are having such good efficiency changes for us in getting even wells outside the Sanish drilled on a more timely basis that the efficiency gains getting lower cost per well are allowing us to hold that number at $2.2 billion while adding up a few more wells to the total well count.

Okay. Now I understood. And then if I could ask one more question, on the Postle Hill, I know you don't want to get too specific about the things that you are or could be looking at, but I mean, I would assume that you're looking at all options and can you give us a timeline on when you think you could provide the market sort of a definitive update if you do something and-- if at all? And then second to that question, if you did monetize that asset, where would that funds go to, would it be some debt pay down, would it increasing activity, and if so, where?

Well, I've already answered the first part of your question, Scott. And the second part, is that yes, it would go to debt pay down and in our planning, that obviously, gives us somewhere more availability under our borrowing base because the price at which we would sell or monetize is greater than the value that the conservative bankers give you within your borrowing base. So we would be a large number above the reduction in the borrowing base in terms of the amount of any pay down. So yes, it would provide the opportunity to accelerate drilling under our current plan. And we would have the ability to do that as a result of the monetization.

Okay. What would be your favorite areas to get more active? Would it be both the Bakken and the Niobrara, seems to be areas that have that opportunity at this point?

Certainly, they're very attractive, absolutely.

Your next question is from the line of Paul Grigel with Macquarie.

Jim Brown had talked about bringing down that well cost at Redtail despite using more proppant. Could you guys maybe elucidate with the cost of the Razor well was and then what drivers you're seeing in the development mode that could bring that down below the $6 million you mentioned?

Yes, our guys are doing a really great job out there. We are consistently drilling these wells with the rig that we have out there in under 14 days. And so that's either -- that's a 640 or a 960. We feel very confident when we get a pad rig out there and just mow down -- what our plan right now is to drill 4 wells off of each pad, we're going to drill 4 to the north, 4 to the south. And once we get in that mode, we think that we can knock the days on location down considerably from that. So we're seeing, I don't want to put a number out there, but we're looking at a very sizable efficiency gain just by doing that. Also, when we get into a bigger frac program out there, we're looking at piping water to locations. So we don't -- we won't -- we'll take all those trucks off the road, I just think there's a lot of efficiencies we can gain and we're going to be headed towards -- we'd like to get under $6 million, we'd like to get down to that $5.5 million range on these wells.

Okay, great. And then just turning to the balance sheet real fast. With the notes coming due here within a year from now, I know you guys have been somewhat adverse to terming out debt previously, but is that something that we should look for potentially moving forward? Or is that once Postle maybe settles out and seeing what the repayment plan would be going forward?

Well, obviously, we would have -- we do have, currently, and would have with or without the Postle sale, the ability to retire that debt using our borrowing base. So and then we would see after that time as to whether or not we just wanted leave it on the borrowing base and hopefully pay it down over time or whether we'd want to refinance it. So no decision has been made yet.

And your next question is from the line of Ray Deacon with Brean Capital.

I had a question -- I guess for Jim Brown, I had a question on the acreage in Redtail, if you feel what you have is blocky enough and can you talk a little bit about how much drilling would be kind of required to hold your leases together for the next couple of years?

Yes, I mean, as Dave Seery mentioned earlier in the call, we're currently doing some swaps with other folks just to consolidate our acreage position out there. He's also working on a couple of different acreage deals that are either very near our block or right in our block right now, I don't want to comment a great deal on that. But yes, we're feeling very confident about that. I believe I'm going to have to look around the room just to make certain -- I believe with the single rig that we have running out there we're going to pretty much be HBP'd with all of our acreage by the end of the year. So, or very close to it anyway.

Got it. And how about -- is there any update on the horizontal Red River? Is that still something for this year, do you think?

We have -- we've been drilling at Big Island mostly vertical wells here. We have our first test of horizontal test coming up here in -- probably spud in mid-July. And so we're excited about that and we think the implications there are great. If we're successful at that, then we think that we can build pretty high-density drilling. And go our vertical program there is pretty much been targeting what we call Red River [ph]. The ideas with the horizontal well, we think that there's a possibility that we can develop in the sort of a regional pay, the porosity amount which is around 4%. The vertical wells we've been targeting 10% porosity, but with a long horizontal, we think we can reduce that threshold and therefore, make essentially all of our acreage out there developable. So we'll test that in July and if we're successful, we'll quickly move forward to start testing that around the totality of our acreage position there.

Okay. Great. And I guess just one last one, a follow up on the Niobrara. If you -- I guess, Noble this morning said that they're increasing their, EURs on long laterals from 750,000 to 1 million barrels, in some cases, and I guess if you kind of look at the -- have you -- I know you're much earlier on, but in terms of productivity of their acreage versus yours, do you see much difference, I guess?

We've mapped all of that. We're very familiar with their acreage positions. It's contiguous, I'd say overlapping with ours on parts of it. So we tend to look at it a little bit differently perhaps than they do. But I'd say the geology is very similar between the 2 development areas. So we just maybe approach the reserve allocation a little bit differently. But those numbers are like they could be reasonable. I think they drilled a few more wells than we have. So perhaps they know some things that we don't. But, we're approaching that number. As you've heard, we've started to increase our reserve estimates as well, we're not quite to the number that we just mentioned though.

Your next question is from the line of Gil Yang [ph] with Fischer [ph].

Could you comment on -- I know you made some comments already regarding the expectations for the downspacing in Sanish, but you comment on, in terms of what your expectations are EURs might be? Will they be -- would there be some interference obviously versus the original EURs you're getting of the 750s to the 950s? Or would it be more interference of the more recent result that you're seeing in the area?

We haven't done any of this yet so the real issue there is we're -- what we're doing is we're looking at the balance between potential interference but we're offsetting that with what we think is going to be an increase in recovery efficiency going from 10% recovery efficiency of the oil in place up to a number that's higher than that, perhaps 15%, perhaps 20%. So as we get our wells closer and closer together, we think that we're going to experience significant increase in recovery efficiency above where we are. So are the infill wells going to be as good as the original wells? There's actually a possibility that they may be better because of this effect that we've been talking about that we're calling we think we've mentioned now 4 or 5 times in the call, but synergistic frac-ing. And so as these, what we call the stimulated rock volume, the area that we're affecting via our stimulations begin to overlap, we think we're breaking up more rock and therefore our recovery efficiency is going up. So I hope to be positively surprised on the upside there, but we're not going to know until we get in here and try a few of these and as we've mentioned, we'll get results back around the end of the third quarter, possibly as late as the end of the fourth quarter.

Right. Are you doing a test around wellbores that you drilled early on in the development phase or later on in development phase?

Both, so different -- the areas that we're doing this in right now, in Sanish, we've got 4 of these planned. At our Hidden Bench project, we have 2. At Pronghorn, we have 1 and then we're actually considering doing 1 over our Missouri Breaks area right now, as well. So at the Sanish obviously, that's a more mature project. We've been out there for a lot longer. So that scenario where we'll come in and offset some wells that have been in production for more than a couple of years.

And in terms of the synergistic frac-ing, is there -- has there been any indications in the Bakken that, that works?

Well, the answer is yes, we've seen even with respect to our existing pattern that when we shut in a well, that's an existing well, drill another well next to it or frac another well next to it, that when we put the first well back on production, it comes back on at a higher rate.

I would like to turn the call over to Jim Volker for closing remarks.

Thanks again, Sharon. I'd like to thank all of the Whiting employees and our directors for contributing to our fast start in 2013 and for the exciting plans we have for the remainder of 2013. Eric?

Jim Volker will be presenting at both the Susquehanna Conference in New York City and the Citi Conference in Boston the week of May 13. Rick Ross, our Vice President of Operations, will participate in a panel discussion at the RBC Global Energy Conference in New York City on June 3. And we will also present at the IPAA OGIS Conference in Toronto the week of June 10. And we look forward to seeing you all at those events.

Thanks again, Eric. In closing, we want to thank you all on this call for your new or continuing interest in Whiting Petroleum Corporation. Again, we think it's a very opportune time to own our stock. We look forward to meeting with you soon.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.