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

John Freeman - Raymond James & Associates, Inc., Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Will Green - Stephens Inc., Research Division Duane Grubert - Susquehanna Financial Group, LLLP, Research Division Phillip Jungwirth - BMO Capital Markets U.S. Pearce W. Hammond - Simmons & Company International, Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Michael Hall Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division Gail A. Nicholson - KLR Group Holdings, LLC, Research Division Ann L. Kohler - Imperial Capital, LLC, Research Division Gil Yang

Good day, ladies and gentlemen, and welcome to the Quarter 2 2013 Whiting Petroleum Corp. Earnings Conference Call. My name is Patrick, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Eric Hagen, Vice President of Investor Relations. Please proceed, Sir.

Thank you, Patrick. Good morning, and welcome to Whiting Petroleum Corp.'s second 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 second quarter of 2013, and then discuss the outlook for the third 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 the webcast, please click on the Investor Relations box on the menu and then click on the webcast link. Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on Slide 2 and in our earnings release. Reconciliations of non-GAAP measures we refer to and the applicable GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-Q for the 3 months ended June 30, 2013, is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

Good morning, everyone. We're going to move through our presentation quickly and get to your questions about our strong quarter as soon as possible. Production in the second quarter of 2013 grew 4.8% over the first quarter of 2013, and we're on track to post a year-over-year production gain of 12% net after the sale of 7,560 BOEs per day, associated with the Postle Field assets. Our record production in the second quarter translated to record discretionary cash flow of $440.9 million, up 42% over the second quarter of 2012, and strong adjusted earnings of $121.3 million, which were up 41% over the second quarter of 2012. All of our core areas contributed to our record quarter at our 88,000 net acre Redtail prospect in the DJ Basin, our most recent completion floated over 1,400 BOEs per day. We moved in a pad-capable rig to Redtail last week. So we now have 2 rigs running there and third rig will arrive in October. And our initial plans are to add 2 more rigs in 2014 to get our total to 5 rigs. Slide #4 shows that 75% of our total production came from our core Rocky Mountain region, and more than 63% from the Williston Basin. Slide 5 shows our revised 2013 capital budget of $2.5 billion. Accelerated drilling in our Williston Basin and Redtail areas account for almost $200 million of the $300 million increase. We're already seeing the benefits from this faster pace of activity. Our third quarter production forecast is 8.5 million BOEs, which underscores the fact that we expect to replace the sale of 7,500 BOEs a day at Postle. Increased efficiencies in the Williston Basin are allowing us to drill more wells than planned, with the same rig count of 20 rigs. On Slide 6, we provide an overview of our plays in the Williston Basin, where we control 700,000 net acres. In the footnote, you'll see that our average acreage cost is an attractive $549 per net acre. Production was up smartly in our Western Williston area, it increased 44% over first quarter levels. This includes increasing production from our Missouri Breaks area, where a new completion technique has enhanced production results. In addition to the Weber 24-30H well cited in our press release, we also recently completed the Berry 14-11H well at a rate of approximately 1,600 BOEs per day. Currently, the third quarter is off to a good start. For the month of July, we have 28 wells on the frac schedule and 24 for August, so almost one per day, and we are on track to accomplish that schedule. Jim Brown will now detail our new development area at Redtail.

Let's start on Slide 7 with our Redtail prospect in Weld County, Colorado where we target the Niobrara Formation. We are employing larger fracs that are generating excellent results. Highlighting recent drilling results at Redtail was the completion of the Razor 33-2813H, which flowed over 1,400 BOE per day from the Niobrara B zone. The well's 6,047-foot lateral was fracture stimulated in a total of 32 stages, using our new frac design. The well was drilled on a 960-acre spacing unit. We have also applied this new frac design to our 640-acre spacing unit wells with positive results. The razor 25-2514H flowed 636 BOEs per day, the well's 3,716-foot lateral was fracture stimulated in a total of 18 stages. We moved the second pad-capable rig into Redtail last week and are planning for a third rig in October. Permitting for our gas plant is proceeding and we expect to have the gas plant online in early 2014. Each pad-capable rig can drill approximately 24 wells per year. Moving to Slide #8, you can see that the original oil in place in the Niobrara A and B zones are a combined 59 million BOE for a 960-acre spacing unit. This is twice the OOIP that we see in the Bakken formation. Our current inventory estimate of 2,400 gross wells is based on 12 wells per spacing unit. But as you can see on the slide, with only 10% recovery and 370,000 BOE EUR per well, we should be able to drill 16 wells per spacing unit. Slide #9 shows the production result from our most recent 6 wells, using our new completion design, are consistent with a 400,000-BOE type curve. Mike Stevens, our CFO, will now discuss our financial results in the second quarter of 2013.

On Slide #10, you can see our second quarter 2013 adjusted net income available to common shareholders was $121.3 million or $1.02 per diluted share. Our discretionary cash flow in the second quarter totaled a record $440.9 million. This total represented a 42% increase over the $310.5 million in the second quarter of 2012 and a 10% increase over the first quarter of 2013. Our guidance for the third quarter and full-year 2013 is detailed on Slide #11, and shows that we plan to largely replace the 7,560 BOE per day associated with the Postle sale in one quarter. Also, LOE is expected to decline post the Postle sale. On Slide #12, our second quarter EBITDA margin continued to be strong at 67% of our blended realized price per BOE. On Slide #13, you can see that we continue to maintain a strong balance sheet. And Slide 14, shows that our 2 senior sub-notes continue to trade above par, it also shows that we're well within all the covenants in our credit agreement and our bond indentures. Slide #15 shows our crude oil hedge position, including the new 3-way oil collars that we put on for 2014. At this point, we have 59% of our oil volumes hedged in 2013 and 35% hedged in 2014. On Slide #16, you'll see our strong fixed-price gas contracts that continue net us over $5 per MCF. I'll turn the call back over to Jim Volker.

Ladies and gentlemen, with our Postle sale, we further demonstrated the value of our asset rationalization strategy. Similar to what happened during our Whiting USA Trust II transaction, we are on track to replace most of that production sold within one quarter of the sale while delivering double-digit annual production growth. Importantly, the Postle sale frees up capital to accelerate development of new, high-value projects like Redtail. Operator, please open up the conference call for questions.

[Operator Instructions] Gentlemen, your first question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: First question I had, obviously, this new completion design in Missouri Breaks is yielding dramatically better results, and I'm trying to get a sense of kind of where you all are in the process of expanding this new completion technique to some other prospect areas and would it have, potentially, any applications even in, maybe, your Lewis & Clark prospect?

John, Mark Williams here. Yes, the new completion technique at Missouri Breaks is primarily going to cemented liners and plug and perf approach, and we've hit -- we've seen a nice uptick there. The other areas that we think that it will have application to do include Lewis & Clark, where we've got a very large drilling inventory, as well as Hidden Bench, our Cassandra Project, those would be the primary ones. John Freeman - Raymond James & Associates, Inc., Research Division: And, Mark, in terms of timing, like when do you think we might hear something like on this new technique at Lewis & Clark?

Well we're applying that in terms of pilot tests on -- across our acreage position. And so for Lewis & Clark, our -- we have a number of wells in the queue there. We have some Federal permitting problems that keep the flow of wells or the number of wells that we're drilling there, somewhat limited, but we will be trying that here pretty soon. That's probably in the next 3 months. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And then could you give me sort of a cost comparison with this new technique versus what you were doing on the sliding sleeve and uncemented?

In general, it's about at breakeven. We think that the cost of doing uncemented liners and plug and perf is pretty much a trade off with -- the increased cost from that is pretty much a trade off with the cost savings from not having to do a sliding sleeve. So it's about at breakeven, maybe an additional 5% or so.

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

Just kind of want to carry forward on the Williston, can you tell about when you get comfortable on -- if you're going to apply downspacing or -- the Sanish looks to be working, is that an area that you feel comfortable going forward, full-phase downspacing? And any other downspacing tests? When do you think you'll have some sort of results?

The answer is yes to that. We are doing a couple of things right now. We've got 2 pilots that we're doing on the west side of the field. We have, already, in the east side of the field, where the reservoir quality is best, we have the most oil in place. We've already really started doing downspacing there. In that part of the field, we have not really drilled the Three Forks formation. So rather than that, we've begun drilling the D zone, the deepest part of the Middle Bakken all along the D. And we've got several of those wells underway currently. So it's already happening there at Sanish. And the greater question right now is what about the west side where we've got tremendous amount of potential? Those 2 pilots will be completed and will be in a position to make some concrete statements about how we're going to apply that towards -- right here towards the end of the year, probably early in the fourth quarter.

Okay. And then one on the Niobrara, you talked about 16 wells in this -- to properly developed section. Is that just the A and the B? Or does that also include any C potential or Codell potential? And I think some neighboring operators are talking, potentially, 32 wells or 36 wells per section. And just kind of seeing if that's apples-to-apples with what you all are discussing.

I think what we're seeing there is that the A and the B are definitely the primary target. And you could see that on the slide that we have in the presentation, here on Page 8. The OOIP is outstanding in both of those zones. The Niobrara C is also a very good zone. We're focused on the A and the B primarily because we can stimulate both of those together with a single well, and so that really gives us a big uplift. We do think the C is a very viable target. The Codell, were not quite as confident in yet. We just haven't really gotten as far into looking at the Codell. Our focus is definitely the A and the B, right now. As far as the 32 wells go, it makes sense to go ahead and permit for that many wells, the real question is, is are we going to develop on that many. And so the scenario there would be that you could drill 16 A and 16 B wells if you were able to get up to that level. I think we sort of convinced ourselves that for right now, 16 is the right number, but you could -- it's possible that we could get up to 32 as well.

Your next question comes from the line of Ryan Oatman with SunTrust.

Niobrara results obviously looked very strong. Can you just talk a little bit about your learning there and how that play has evolved for you in a broad sense?

This is Jim Volker. It's evolved from all the wells we've drilled in the past there. And basically, at this point, we've got our well cost down to around $5.5 million per copy. And we believe that, that's going to give us an EUR of somewhere in the range of 500,000 to 600,000 BOEs per well. So when we compare that with all of our inventory, including the Bakken, we see it as basically in that 5 to 6:1 on your money range, just like we see the Bakken. The only difference, really, economically to us is that we're really just at the beginning of the development phase at Redtail or, of course, we're well into it across our 6 major Bakken plays.

And about -- the frac volumes have been a very definite uptick for us. We've gone from 2 million pound fracs up to 7 million on our 960s and -- so that's been a game changer for us, certainly in the last quarter.

Okay. And I guess, looking at Slide 9, it does sound like there -- it looks like there's some potential upside to that 400 MBOE-type curve there based on the extended performance. Can you talk about just kind of the declines you're seeing? Seems like after 30, 60, 90 days, that the declines just, maybe what the curve would have. Can you talk a little bit there? And then just want to clarify from the last question, on that recovery estimate, is that comparable to the 400 on the slide or are we talking maybe a 960 versus a 640-acre spaced well?

Well as you could see on the curve there, on Page 9, that you're referring to, if you just look at the cum so far, compared to the cum on a 400-MBOE type curve, we're actually outpacing that a little bit. And we've seen, with some of our recent completions the production rate is very stable. We don't -- we're not far enough into the last 6 wells to really even start to forecast any kind of a decline rate. In fact, a couple of them are still increasing. And so we're pretty comfortable with that. The uplift, just in terms of the initial rates compared to the older wells is somewhere around the 150 barrels a day higher than the wells that we're drilling prior to increasing our frac volumes. So that's the uplift. We're just not far enough into it right now to be able to say where they're going to peak, but we're definitely seeing a different type of decline curve with this larger frac volumes.

Just to clarify one thing on the slide, it's Eric Hagen. Slide 8 is based on a 960 and the wells on Slide 9, those are based actually on a mix of 960 and 640s. So...

Got it. That's helpful. And then realizing it's early in the play, one of your large peers is discussing a potential for very good recoveries from these extended-reach lateral wells versus the normal lateral wells. Do you see, I mean, 960s is kind of the way to go if lease hold provides, or do you think there's some instances where a 640 might make more sense?

960s seem to be the optimal well bore length. We looked at doing 1,280s. They're just -- the one-to-one ratio between the vertical depth of the well and the horizontal length is something we felt pretty comfortable with. And also from spacing considerations out there, there are a number of things that say that 960s are the optimal length.

Great. And then just one last one for me, and I'll hop back in the queue, and this has been very helpful. Can you discuss any of the geological well work that you've done on the Niobrara and what conclusions you're able to draw from that regarding the prospectivity of your acreage as a whole? With kind of -- I guess, my goal and what I'm getting at here is what portion of the acreage do you think you can replicate these Razor-type results or these Slide 9-type results across your acreage?

Well, looking out -- say there's -- the Razor area is where we have really focused our efforts in terms of the larger frac volumes. But you'll recall that we've had some very good wells on the older stimulation design up in our Horsetail township and also in our Wildhorse township. Those 3 townships is where we have focused most of our drilling effort today. And the reason for that is that's where we have 3D seismic data. It's absolutely essential to have seismic data in order to do geosteering. We also feel very confident that as we go to the north and east that we're going to see very good results. Our 2-mile area, the wells that we've drilled up there, while they didn't have the flashy IPs, have held in there extremely well, very good oil cuts. So we think that as we apply larger frac volumes to some of the more peripheral areas, we're going to get very good results, whether they'll be as good as a Razor township is yet to be seen. The other thing to mention there is we've just completed our second 3D seismic survey, which covers a lot of the acreage on the East and North side. So we've essentially shot out the rest of our acreage position, which puts us in a position to develop a broader portion of our acreage, and we'll be testing that. As we go forward, we -- I mentioned already that we're going to be in a 5-rig program by the first quarter of next year. One of those rigs is a standalone rig that we're using to sort of delineate the, what I call, the extremities of our acreage position, so you'll see us continue to do exploration as well as the development. All great questions.

Your next question comes from the line of Will Green with Stephens.

So I wanted to start on the Niobrara. I think I heard you as guys correctly saying that you think that you'll ultimately be able to stimulate the A and the B with one well. Were these recent Razor wells that you guys talked about, were that -- were those just in the B or were they stimulating the A as well?

Those were just in the B, so far. We've drilled one A well in this area. But for the most part, those are all in the B. As we go forward with this first pad rig that we have, we're going to be doing 2 side-by-side pilots, and one of them will be essentially a B, A, B, A type configuration. Then right next to that, we'll be doing all 4 wells in the B zone. The spacing on those will be per 16 well per unit type of spacing. So we're going to have a side-by-side comparison to really say which is the optimal way to develop, I think both of them are going to be good, but we'll -- it'll be -- end up being one of those 2, most likely.

Got you. And then we noticed that the Permean looks like came back into the budget for 7 wells this year. Can you guys talk about any kind of completion changes you're doing there? What kind of lateral stages are you guys planning down there?

We've had good luck with our most recent wells. We think that longer laterals, 5,000-foot plus, larger frac jobs, somewhere in the 5 million-pound range to 6 million-pound range, is going to give us better results. So the wells that we're teeing up now will have those attributes. So we are changing the design and we've been encouraged with the most recent results. That's why we've increased the number of wells.

Your next question comes from the line of Duane Grubert with Susquehanna Financial.

Jim, I understand the idea of taking the Postle proceeds and increasing your budget. But for the people who read the press release and they read, "Oh guidance is up a couple of percent and spending is up 14%." To sort of cut a shortsighted view of how to read that, how do you explain that to an investor who would say, "Why is your spending up and your production isn't up proportionally?"

Well, of course, the reason for that is that we're pretty early into the application of funds from the Postle sale. So I would simply say, what you probably ought to do is apply that yardstick, maybe about 6 months to 9 months from now when we're more in the development phase and where we're spending a little bit less on land, that sort of thing. And then I think you'll see that kind of pop that you would expect.

Okay. And then you mentioned the incremental focus in the change in the Permian Basin. But on North Ward Estes, in particular, can you give us just a brief update on how you're thinking about that project as part of the whole portfolio?

Well, of course, we, as a company, love North Ward Estes simply because it provides us an opportunity to take in a field from about 4,000 barrels a day, when we bought it up to perhaps 20,000 barrels a day, and essentially taking it from 4,000 to just under 10,000 barrels a day as we sit here talking to you today. So that field really continues to perform or outperform each one of our expectations per phase. And I can say that the 2 phases that we're in now are doing exactly that. Pete, I'll let you flush that out if you like.

Sure. Just to expand on that. We've got good results from our 2 most recent phases. We're executing very well down there. And we think that same performance is achievable in a number of additional phases. You probably remember the development schedule for that field stretches out for a number of years. So it's a matter of continuing that execution, and I think we'll continue to see the same results.

And just to finish that off, is it more about the rock or are you actually changing what you're doing to get better-than-expected result?

The rock certainly has -- there is some variation, subtle variations around the field. But by and large, the field is all very productive. There are some refinements in the flooding mechanism in terms of how much water, how much CO2 we're putting into the ground. So there have been some refinements in operations and there are some subtle differences in geology.

Yes. Duane, thanks for asking. Really just to sort of remind folks, everything that's in front of us there at North Ward Estes is that, as of January 1 of this year, we had about 114 million BOEs in P2 and P3. So talk about a great area to go to move reserves into the proved category, really just by executing our plan and continuing to develop as we have over the last 5 years. So I really think that's a great area, very few companies have the ability to look at a particular spot and know, with the kind of confidence that we have in North Ward Estes, that over a period of time, we can add over 100 million barrels.

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

So if I take your current 400 MBOE-type curve at Redtail, I think it would equate to an F&D cost of mid to high teens, which is probably at least $5 better than the Bakken. Similar commodity mix, lower production taxes. So my question is how do returns at Redtail compare to what you're drilling in the Bakken? And then as you ramp activity there, how could that impact the overall capital efficiency of the company?

Well I think you're right about that in the sense that all those factors that you talked about in terms of F&D per BOE and in terms of the production tax helping us, we would see both our Bakken and our -- I'm going to say both our better Bakken areas and Redtail in the 5 to 6:1 on our money kind of multiple. In terms of IRR, a bit higher at Redtail than in the Bakken. But again, I wouldn't sell the Bakken short because of all the advancements happening in technology. But we refer to here today, I really think these multistage fracs with many more ports in them could continue to improve the recovery of OOIP in the Bakken. So we're sort of, over the next year or so, expecting an improvement in that area in the Bakken as I think are a number of our operators.

Well if I could just jump in here and add one more comment. In Redtail, a single rig, right now, we're estimating can drill 24 wells per year or about twice the number of what a rig can drill up in the Bakken. So if you look at a 5-rig program out here in 2014, that would be roughly a 10 rig program up in the Bakken. So we think we're getting after this one pretty good.

Right. So it's that a 5-rig program. Is it, I'm assuming, a flat CapEx budget within -- Redtail comprise call it 20% to 25% of the total CapEx?

Yes, about 1/4.

And then on the Southern Williston, what would a normal backlog of wells waiting on completion be? You had 13 at the end of the quarter. And then can you tell us how many wells you expect to be turned to sales in the second half versus the first half?

Sure. What causes that is at Pronghorn 4 of our 5 rigs are drilling on pads. And so they're drilling either 2 or 3 wells off of each pad. And I don't know why it happens this way, but the rigs all start to seem running in sync, so we get a big, big group of wells all ready to complete at the same time. If you look at -- Jim mentioned, we have 28 wells on the frac schedule for July, up in the Williston basin, 10 of those were in Pronghorn. So we're getting a big chunk of those on production. A big chunk of those is already on production.

Okay. Great. And then last question, can you tell us where the one Gulf Coast rig is drilling?

Yes. That's been publicly disclosed. Some people have asked us on a prior call. So, Mark, why don't you expand on it and give him a little bit of the geology as well as the history?

Okay. Well, I could just say that we've discussed this a little bit before, we have an exploration project right now in Northern Louisiana where we're testing the Smackover, lower part of the Smackover, we've acquired pretty extensive acreage position there. And the play really is looking at liquids-rich condensate reservoir in the basal part of the Smackover. You'll recall that there's some of other companies that have been doing Smackover exploration further to the north, up into Southern Arkansas. It's a very different play than what we have here. That's normally pressured up there. Where we are, it's deeper, it's hotter, it's very liquids and condensate-rich and much higher pressure. So this is a relatively new play you'll see, we're really the first ones in here. So we're drilling our first well, currently. It's a vertical well and we're using that -- both the core, to get a better feel for the reservoir, and we'll use that as a monitor well for an upcoming horizontal well that's essentially right next to that, that we're going to be drilling here this next quarter.

Mark, mention how much acreage we have there.

Yes, we're right at about 100,000 acres, and we've got a little bit more to acquire there before we drill.

I hope that's helpful.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Jim, just one question for me. With the compression in the Brent-WTI spread as of late, has this impacted your crude marketing strategy or your thoughts on moving crude via rail?

Well I think our marketing strategy is that we want to have the ability to switch hit, in other words, to go down the pipeline or to use rail. And so we're roughly, at some times, as high as 40% of our crude going out by rail, it's the best guess on our part, and 60% going out by pipeline. And of course, it's that competition between those 2 methods of moving crude out of the basin that's caused the differential to narrow. Early on, of course, I would say and probably, overall, philosophically, we're a believer in the lower cost of the pipeline. But thank heaven for all the people who've come in and built rail facilities because it really has provided the competition that's caused the pipeline crude oil purchasers to become a lot more competitive on the price. So -- and therefore, the differential. So we can go either way with our crude, doesn't matter whether we're talking about our crude coming out of the Sanish area or our crude coming out of our other areas, we can go either way with rail. And essentially, what happens is that the oil goes to the highest price market, it makes its way there, and that helps crush the differential.

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

Curious on Redtail, that you, obviously, been talking a lot about. The activity going up and you got a gas plant coming in first quarter '14. What are your thoughts on the take away from that area, what are you seeing on that?

If you're talking about gas, the fortunate thing we have where our acreage position is located is there's 2 two big major gas pipelines right through there. And that's, remember, when we used to talk about Rex and Trailblazer and all that thing in years past, well there's -- believe me, there's ample room in both of those. So that's where we're looking to go with our gas. Right now, we're selling most of our oil into the local market in there. We're selling to Suncor down in Commerce City here in Denver. And we're also selling some to HollyFrontier up in Cheyenne. We are talking with 2 different people looking at railing oil out of there. And then there's also an oil project where they're going to convert the Pony Express line. Pony Express was a crude oil line, they converted it to natural gas service, they're now looking at converting it back into oil service. So we are very optimistic about the off-take capability out of the basin, out of the DJ.

That sounds great. And then with the -- and I'm sorry if I missed this, but with the 5 rigs you talked about, one is going to kind of be a standalone and go and explore, are you going to start drilling on those pads beside the 2 pilots with all 4 rigs as you add them? Or is there going to be kind of oneoffs until you get more and more comfortable with how you want to move forward?

Well, I mean, like the first pad rig, we're moving in -- that we moved in last week. The first well we're drilling that is just a oneoff. And that's kind of just to get us and the rig on the same page. When it finishes this well, which is going to be probably this week, we're going to move it over, and it's going to start right in on a pad development drilling, this A, B pattern that Mark just talked about.

Your next question comes from the line of Tim Rezvan with Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Just wanted to follow-up on that last question a little bit. Just to confirm, so you don't see the gas plant as being any kind of near-term bottleneck, you think you have plenty of other options?

Yes, I mean, we have -- one of the acreage positions that our land guys bought out there was actually some producing acreage. And with it, we acquired a small gas plant. And that gas plant, has a capability of about -- our guys have gone through it and upgraded it, but about 3 million cubic feet a day, there is also some third-party gas processing out there that we're connected to right now. So those are kind of the stop gap measures to get us from where we are today until we get our gas plant on in early '14. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. Okay. I appreciate that. And then broadly on the Redtail, can you talk about what the second quarter production was and what assumptions are baked into your full year production guidance?

I'm just looking at the sheet here, finding the exact numbers for you, but we're around 3,000 BOEs a day. We've ramped up to that towards the end. So in the guidance we have further continuing ramp up going on for the rest of the year.

Your next question comes from the line of Mike Kelly with Global Hunter Security.

Jim, I got a strategic question for you. Post the Postle sale here, I was hoping you could comment on any efforts on the portfolio high grain [ph] side of things. Last year, there have been some talk of JVs happening in a variety of different areas. What's on the list now for you? And maybe you could comment just on the new ventures program as a whole as well, and if there's anything that's really on the horizon that we might see from you guys in the second half of the year there?

Okay, Mike. Well, first of all, our view of what would be JV-able or things that we'd want to JV would change as we take the risk profile off and de-risk things with our drilling. So, for example, I think we would not be very interested in doing anything these days at Redtail. So really, I'm not going to comment further on JVs at this time. And then in terms of -- about our other exploration areas, other than to say that, as I've said in the past, we have, in addition to things that we've talked about on the phone here today, we have 2 other I would consider secret or stealth plays that we're working on, and both with large acreage positions of a couple hundred thousand net acres. And we'll be testing those between now and year end, and we'll be happy to let you know when we have some results there. But essentially, we're very excited about these new areas. They've led us through the science that Mark and his team and the engineers here have applied predominately starting with the analysis that we can do right here in our own core lab. They led us to some new oil resource areas, and we're excited about testing them and I look forward to having some results for you around the end of the year.

Okay. Follow up. The earlier results look very encouraging with the new completion tweaks and techniques up in the Bakken. Keith, is this too early to start talking about quantifying what the EUR implications could be up there? I think we talked in some of the western portions of the play, EUR is at 400,000. What could this potentially do to those EURs?

Well what we have so far are completion results with the new technique up there in Missouri Breaks. Missouri Breaks is sort of along the western periphery of our acreage position there. But that was a very significant uplift. It's, essentially, a twofold uplift in our 30-day average rate. We're essentially doubling the rate over there. To take that and apply that ratio directly to EURs is probably a little premature. But one thing we can say is that if you do compare the early rates of these wells to rates that are, say, year end in the production history, there's a pretty good conformance there. So I don't think we're going to see a doubling of EURs. But I think it's going to be a very significant bump. And as we've already talked about, we think that, that same completion technique is going to be applicable over a very significant portion of our acreage position, especially on the western half of the basin.

Your next question comes from the line of Michael Hall with Heikinen Energy Advisors.

I guess, I just wanted to get a little more clarity around the impact of the positive results out of Redtail as we start thinking towards 2014. The -- you talked about a 5-rig program, 24 wells per rig. It's about, call it, $660 million, in terms of the program for '14. Is that probably -- and apologies if I missed this at the beginning, I had to jump on a little late, but is that expected to be additive to the Bakken program? Or is that going to -- you'll swap some capital out of the Bakken into the DJ?

Additive.

And of those 24 wells per rig, is that a number that could also be tied to sales, or is that just a number that would be drilled, and so does the 660, maybe biased a little lower as you build up a little bit of the completion backlog?

Correct, yes.

Okay. That is helpful. And then, I guess, the one other thing at Redtail, just to sort of close that loop on the timing of these -- the test around whether or not it's better to do a stagger type B, A, B, A completion versus B, B, B, B when do you think you might have those sorts of results?

Well, as we discussed, we're just embarking on the drilling of those wells right now to get to the bulk of those pilots, that's going to take, obviously, 3 months or so, and then we've got to complete them and look at them. I think we're going to have a solid answer by the end of the year for that. But, frankly, I don't expect there to be a significant difference between the 2, I'll be surprised if there is. But it's not going to slow us down in terms of our development program. And -- but I think the end of the year is we'll have definitive results.

Okay. That's helpful. And then, it's the last one on my end. Just trying to better understand how to think about shaping the completion -- the pace of completions in the Williston for the rest of the year. You talked about 28 wells on the frac schedule in July, 10 of those in Pronghorn. I'm curious where the other 18 are allocated to in July. And then just any other commentary around the pace of completions throughout the rest of the year would be appreciated.

We keep -- we try to keep our inventory of completions down as low as we can. And with 20 rigs running up there, roughly, we have about 20 at any one time that are in the queue, being completed at one time. And with the pad drilling going on there, that gets a little -- that sometimes gets a little higher, a little lower, but we generally try to keep that as low as we can. And our pace of completion will pretty much just keep up with our pace of drilling for the rest of the year. And that -- the wells in queue should stay relatively constant. So you won't see a big difference in our pace.

Your next question comes from the line of Mike Scialla with Stifel. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Mark, you've mentioned that you already had success with the higher drilling density on the east side of Sanish Field. Can you elaborate on that a little bit? I'm thinking what kind of distance between laterals you've already tested? And maybe what kind of rates you're seeing relative to the original wells? And of those 190 additional potential Sanish locations that you've talked about, how many maybe you're convinced at this point that you can really drill based on what you've seen already?

Well what we can say there on the east side is that we have -- we've gone -- in addition to our Middle Bakken program, we've got a Three Forks program going out there. And the Three Forks has been very successful along the western half of the field. Along the eastern half of the field, we feel like it's better to target those wells into the lower part of the Middle Bakken, rather than the Three Forks. So if you look at overall drilling density, we're really doing the same thing on the east side of the field as we have been doing on the west side of the field. When you map out the OOIP in the Middle Bakken, the sweet spot of the entire area is right on the boundary there between Sanish and Parshall, so that's where we've got very -- what I'd say, our highest confidence, that the recovery efficiencies are going to be justifiable. Anywhere between a 10% and 15% recovery efficiency is going to justify those in-fill wells. So that's what gave us the confidence to go ahead with that program. Right now, on our schedule, we've got approximately 20 of those wells slated between now and the end of the first quarter. So in terms of what we have in the way of results so far, we don't have an awful lot of that just because we've -- it's just the timing of our program, we've really just started on that. So what we're really doing there is substituting lower Bakken -- or should we be substituting a Three Forks well with a lower Bakken well.

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

I just had a quick -- 2 questions. You mentioned in the past that you might be doing some re-fracs at Sanish on some older wells, and I was just curious if there was any update on that?

Yes, we've got 3 of them queued up to re-frac. And we're just in the process, right now, of prepping those 3 wells, getting those ready to go. So hopefully, we'll have something here in the next quarter or 2. But we do have 3 wells queued up. Yes.

Okay. Great. And then looking at Missouri Breaks, the new completion techniques, you're definitely getting better results. Is that -- have all those wells been concentrated more in the eastern side of Missouri Breaks versus that western side, as you move further into Montana? And then do you plan to test that western portion of Missouri Breaks?

The answer is the area that we've tested, so far, is in the Montana side. I'd say, with respect to our entire Missouri Breaks prospect, it's sort of in the central to slightly eastern, but we think it's going to have widespread application. We are currently testing that concept on the western side of our acreage there. So Missouri Breaks, we're really in the early stages. We've just completed HPP-ing our acreage position, which means that we've got one well for each of our spacing units there, so we've got a lot of running room already in the -- what I'd say the 2/3 of Missouri Breaks, the area that's on the -- the eastern 2/3 of that area. This pilot that we're drilling right now, will prove up [ph] the western side.

Your next question comes from the line of Ann Kohler with Imperial capital.

Great. Just a couple of questions. One, what were the net proceeds from the sale of Postle?

$850 million.

Perfect. Wonderful. And then regarding Redtail, looking -- just for clarification here. So basically, will the -- the one rig that comes on, will that be starting to drill at the pace of 24 wells next year? Or is that going to be more selective and drill sort of in different locations? So we shouldn't include kind of that kind of a timeframe?

We're putting -- we think all of those wells are going to be drilling roughly that pace. We actually hope for a little bit of improvement beyond the 24. The one rig that we have out there right now is a standalone rig. And that will continue to drill kind of one well for every 2 weeks. And then the one that we've just brought on is a pad rig. Initially, we think that it's going to be drilling pretty much the same pace. So that 24 wells per year is a good average for all of them, we think. Hopefully, by the end of the year, we'll be able to say that, that number is 30 or something like that. But for right now, I think that's a pretty good number.

Perfect. Wonderful. And then I did notice in the presentation, in your comments, you did indicate that your -- the costs are currently around the $5.5 million level, but there's sort of a range of $4 million to $5 million, $5.5 million. What would bring it down to that lower level? And is there any timing on that?

So we have both 960-acre units out there and 640-acre units, which means that our laterals are either 7,500 feet or 5,000 feet. And so the lower number that you just mentioned would apply generally to the 640-acre shorter laterals, the 5,000-foot laterals.

And will there be any opportunity to reduce those costs further? Or the current numbers are a pretty good estimate?

We think there's still some dollars to take out of the equation right now. We think we can perhaps get some of the services to be a little more competitive and get some more dollars out of there. And we also know our drilling guys are going to become more efficient the more they turn this into a manufacturing process. So we think we can peel another 5%, 10% out of the well costs out here.

Great. Any timing in terms of when you might look to do something in the C zone or the Codell?

We're definitely going to be testing the C zone of the Niobrara with the standalone rig here, over the next several months. And we're just trying to come up with the right strategy. We're pretty focused on the A, B right now, but the C is definitely something worth thinking a lot about, and we'll be testing as we go forward.

Codell is -- right now, what I'd say is we're probably going to let others try and prove that up for us, and we'll see how that works. We've already drilled a couple of Codell wells, and once we crack the nut on it, we'll get after it. We haven't done that yet.

[Operator Instructions] Your next question comes from the line of Gil Yang with DISCERN.

You mentioned that you have 3D seismic over much of the Niobrara now. Does the 3D de-risk the -- what you see in 3D, at all, de-risk the acreage or do you still need to drill the wells? And maybe can you just comment on what you're seeing in terms of thickness from the 3D you've processed so far?

Sure. 3D, its primary utility is helping us geosteer our wells and stay in zone. So the one thing I'll say is the Denver basin has extremely good seismic qualities or good reflectivity. And so -- but it turns out there is a lot of very small faults that are pretty much all over our acreage position there that we have to steer across. And so that's why we run the 3D to begin with. It's very hard to use the seismic characteristics to help us define a reservoir. That really comes a lot more from our coring program and our logging program. And so what we do for a lot of these wells, the standalone wells, is we drill what we call a stiletto hill, we drill vertically, and we core all the way through the Niobrara. We analyze that. That's where we get the best information about where -- what we can develop. And as it turns out, the A and the B have -- or the A is really good, the B maybe average, and vice versa. So it just helped giving us a lot more clarity in -- the coring program that we're doing, is giving us a lot more clarity on how the reservoir is distributed. And so that's what we have to do to really prove up the rest of our acreage positions, it really comes more from drilling than seismic.

From the coring that you've done so far, to the north, can you compare that sort of combined A B package to the A B package to the south?

Well, I don't want do give away too much there, but what I will say is that we've been very encouraged by what we've seen in the A zone in some of the different areas of the field. A lot of people use resistivity mapping in there to try and figure that out the. Unfortunately, in a carbonate reservoir, that is -- that gives you about a 50% solution. You really have to take the core and look closely at the core. But I will say that we're quite impressed by what we've seen in the A, in a couple of the different areas of the field. I'm not going to give much more granularity than that because we're still acquiring acreage out there. But the A looks to me like it's every bit as good as the B in a couple of different merits.

Okay. And then just sort of last question related to this is that when you developed -- when you discovered then developed Pronghorn, you sort of stepped out a lot of different areas, different subareas of Pronghorn and tried to scope out there both sides before you started a full-scale development. Do we -- should we expect to see Niobrara or Redtail develop in that fashion? Or are you going to start around Razor and expand outward and some of the activities still concentrates in that Razor area first?

Both. The pad rigs are going to work in Razor and Horsetail and Wildhorse townships. And then the standalone rig will be used to help delineate our acreage position. So by...

So you're going to say it's an expansion from those 3 areas with -- and the one rig, sort of, poking holes all over the place?

Right, the one rig will be -- it's not to say that it can't drill development wells as well and that we may end up doing some of that. But we have that flexibility with a K21 [ph] rig that -- to help us delineate our acreage positions.

Ladies and gentlemen, this concludes our question-and-answer session. I would now like to turn the call back over to Mr. Jim Volker for closing remarks.

Yes. Thank you, Patrick. I'd like to thank all of the Whiting employees and directors for their contributions to a successful first half and our exciting plans for a successful second half of 2013. Eric?

Jim Volker will be presenting at EnerComs, the energy conference in Denver, on August 12. And he'll also be presenting at Barclays CEO conference in New York City, the week of September 9. And then at IPAA's OGIS West Conference in San Francisco, the week of September 30. And we look forward to seeing you all at those events.

And thanks to everyone on the call for your interest in Whiting Petroleum Corporation. We look forward to meeting with you soon.

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