Eric Hagen - Vice President of Investor Relations James J. Volker - Chairman, Chief Executive Officer and Director of Whiting Oil & Gas Corporation Michael J. Stevens - Chief Financial Officer and Vice President Rick A. Ross - Vice President of Operations Mark R. Williams - Senior Vice President of Exploration & Development Steven A. Kranker - Vice President of Reservoir Engineering/Acquisitions

John Freeman - Raymond James & Associates, Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Michael A. Hall - Heikkinen Energy Advisors, LLC Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division Subash Chandra - Jefferies LLC, Research Division Jason Smith - BofA Merrill Lynch, Research Division Paul Grigel - Macquarie Research Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Jason A. Wangler - Wunderlich Securities Inc., Research Division

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 Whiting Petroleum Corp. Earnings Conference Call. My name is Erica, and I'll be your operator for today. [Operator Instructions] I would now like to turn the call over to Eric Hagen, Vice President of Investor Relations. Please proceed.

Thanks, Erica. Good morning, and welcome to Whiting's First Quarter 2014 Earnings Conference Call. On the call for Whiting is the Whiting management team. During the call, we'll review our results for the first quarter, and then discuss the outlook for the second quarter and the full year 2014. This conference call is being recorded and will also be available on our website at www.whiting.com. To access the call and the webcast, please click on the 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 the 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 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 March 31, 2014, is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

Thanks for joining us, everyone. We recently announced the retirement of Jim Brown, effective June 17, 2014, and the promotion of Rick Ross and Pete Hagist. Rick and Pete will be joining Mark Williams at the Senior Vice President level. Jim Brown helped build Whiting into one of the premier operators in the Williston and DJ Basins, and his leadership resulted in an exemplary environmental and safety record over his tenure. We thank Jim for his many contributions, and we wish Jim and his family all the best. Out here we're going to give Jim a little round of applause. Jim. Moving on to first quarter results. We'll give you a concise update and get to your questions as soon as possible. Whiting is a focused company. We're a major player in 2 of the hottest U.S. oil plays in the last 40 years, the North Dakota Bakken and the Colorado Niobrara play. As you can see on Slide 4, we're also a company on the move. We had a record discretionary cash flow of $482 million, which is up 20% over the first quarter of 2013. In the first quarter of 2014, production from the Williston Basin averaged a record 73,325 BOEs per day, an increase of 27% over the first quarter of 2013. We completed Phase I of our gas processing plant at our Redtail Niobrara field and have begun selling gas. Our drilling to date at Redtail confirms 16 wells per spacing unit. We now plan to spud our 30F super pad in the Horsetail area in May to test the 32-well spacing pattern. In Q1, we sold our remaining interest in Big Tex for $76 million. So in total, we netted $227 million or $3,100 per net acre for Big Tex. We successfully tested new coiled…

On Slide #15, you can see our first quarter 2014 adjusted net income available to common shareholders was $126 million or $1.05 per diluted share. Our discretionary cash flow in the first quarter totaled a record $482 million. This total represented a 20% increase over the $401 million in the first quarter 2013. Our guidance for the second quarter and full year 2014 is detailed on Slide 16. You will note we are guiding second quarter production to increase 9% over the first quarter of 2014. On Slide #17, our first quarter EBITDA margin continued to be strong at 68% of our blended realized price per BOE. On Slide #18, you can see that we continue to maintain a strong balance sheet, with $400 million of cash on hand and nothing drawn under our bank credit facility. Slide #19 shows that our 2 senior notes and senior subordinated note continued to trade above par. It also shows that we're well within all the covenants in our credit agreement and our bond indentures. Slide #20 shows our crude oil hedge positions. At this point, we are at 53% hedged for the remainder of 2014. On Slide #21, you'll see our strong fixed-price gas contracts that continue to net us over $5 per Mcf. Also of note are our fixed differential crude oil sales contracts at Redtail, where we've locked in a differential of $4.75 per barrel off of NYMEX. I'll turn the back call back over to Jim Volker.

Whiting continues to set records for production and cash flow. We continue to improve our completion method in the Williston Basin, with our latest method delivering results over 70% better than our prior completions. At Redtail, our gas plant is onstream, and we have validated a 16-well per drilling spacing unit pattern and established a 420,000 BOE type curve and our current production is ramping up nicely. We continue to believe that Redtail is a Whiting within Whiting. We continue to divest non-core assets and concentrate on our high-IRR Bakken and Niobrara. We sold our interest in Big Tex for over $3,100 per net acre and booked a nice gain on sale. As result of these actions, we have become a better and more focused company, as we continue in our efforts to maximize shareholder value. Erica, please open up the conference call for questions.

[Operator Instructions] And your first question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: I want to talk a little bit more about this latest completion design on the coiled tubing conveyed frac. How much -- how many more of these do you have planned to do? And how many would you need to see before you'd be convinced that this is the way to go, instead of the previous technique you'd been using?

I'll mentioned that to Mark Williams. This was really an experiment, and it's still fairly early. One point, I think, that's important to make, we're really impressed by the results of the cemented -- or the coiled tubing conveyed technique that you see there on Page 8. The other ones still believe are very valid, are plug and perf with 3 and 5 perf clusters per stage. It looks like the 5 are a little bit better. We do think that, because this is early, those 2 wells did not have the benefit of having the frac plugs cleaned out. So we think that those are also probably under-reported on this slide a little bit. It's just very early. Nevertheless, the coiled tubing conveyed is clearly a big step forward for us. And there's a couple of kinks we've got to work out here. Currently, we have to do a combination of both the coiled tubing conveyed in the [indiscernible] well, just over [ph] 2,000 feet of the wellbore are conventional plug and perf with 3 perf clusters per stage. We can't get the coil all the way out in there. So there's a couple of things we still got to -- a couple of bugs we still got work. Ultimately, we think the cost is going to come down a little bit. But I will say, John, that I think this is going to be widely applicable to us. We're trying one right now at Redtail. They will have actually 80 stages in it. This one was 60. And we've already seen good results in Sanish using this. We've done 2 wells at Sanish, and we're going to be trying it in a number of our other Williston properties. So I really can't see any reason why this wouldn't be very widely applicable. It really allows us to get more entry points in all these tight rocks. John Freeman - Raymond James & Associates, Inc., Research Division: And is there -- was there somebody else in the industry that was already doing this and we just hadn't heard about it yet? How did you all run across this technique?

I think the main thing there is we've been on a hunt to find technologies that can get us more entry points -- more reliable entry points. With the open annualist [ph] technique that we've had before, that just wasn't there. And so we've made incremental changes. Jim Brown was the one, I think, that originally found this. So we've all been working really hard to try and come up with different techniques that will allow us more entry points. And this one really answered that call for us. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And then just last question for me, and I'll turn it over to somebody else. Do you still think there's potential to have some downspacing -- further downspacing opportunity on Missouri Breaks and Pronghorn? Is there something you're waiting to see to where those might be able to go the way of what we've seen in some of the other fields?

Yes. So at Pronghorn, we have been drilling on 3 wells per spacing unit, and there's a significant portion of the field that we've already tested for high-density infill. In Pronghorn, what that means is either infilling with 2 additional wells between the 3 existing ones, or in the case where we've got an adjoining spacing unit, a third, what we call, lease line well, so to 6 wells to a good portion of the field. So we're planning for success there. We're going ahead and permitting a whole bunch of these things. We will probably start developing the single down-space program towards the end of the year at Pronghorn. At Missouri Breaks, we're still testing. We're pretty comfortable right now with 4 wells per spacing unit. But we think that downspacing is going to be applicable at Pronghorn. We're already planning at Hidden Bench, as we said earlier in the call. That'll commence probably right around year and, downspacing there. Cassandra, it's still too early to say, but we've got some great downspacing opportunities at Sanish right now. I think we're going to say lot of potential infills. One point I would make there, Sanish had the highest OIP of any part of the entire Williston Basin. Right now, our drilling density there is 3 wells per spacing unit. If you look at just about anywhere else in the basin, you're seeing operators, including Whiting, that are drilling it at more than twice that density -- in some cases 3x that density. So we believe we got tremendous opportunity. We've got -- given the oil in place [ph] we've got in that field. So you'll see us hot after that here in the next year.

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

Jim Brown, congrats on the retirement. Get some sunshine. Can you talk about -- when you're talking about capacity that you have at Redtail, can you just give us a snapshot, with all the processing capacities coming on, what's the -- how much capacity do you have as far as production?

Sure. This is Rick Ross. As Jim mentioned, we brought on our Train 1 [ph] at Redtail gas plant, which is a refrigeration plant with a capacity of 20 million a day inlet rate. And we are currently working on a Train 2 [ph], which would add another 50 million a day capacity scheduled right now for first quarter of next year. So that would bring us up to a total inlet rate of 70 million cubic feet a day. And we're looking forward beyond that at this point as well of what the future needs would be.

Okay. So just dummy this down for me. So 70 million a day, what should be the conversion of -- I'm trying to back into production numbers?

GOR's about 1,000 to 1,200 GOR would be a good rate, Dave, to convert.

Okay, good. And then just as a follow-up, I guess. Can you guys give us any framework around the trajectory we should expect out there as far as year end, where should we be looking? I know, previous call, you talked about 25,000 barrels per day for -- out in 2015. But how should that trajectory look come December 31 of this year?

I would say, we're looking at kind of a linear ramp each quarter the next 3 quarters to get -- and I think you're referring to the hedge volumes we have, which are gross numbers, in January 2015, Dave?

Yes.

So I think, Rick, would that be correct if really linear ramp -- are we seeing any lumpiness -- we're going to have lumpiness quarter-to-quarter with pad completions.

We'll pick up the pace a little bit in the third and fourth quarter with additional rigs, Dave, as we bring that on, so slight increase towards the end.

So I mean -- so just to clarify we're talking 10,000, 15,000 exit rate. I'll just ask the question.

We're not going to cite exit rates. Just, we don't typically give exit rates, because they're spot rates. We don't think they're really terribly indicative.

Okay, but 20,000 gross for January's kind of a number that I can work from.

Good question. Thank you, and the answer is yes, Dave.

And our next question comes from the line of Scott Hanold with RBC Capital Markets.

Question on the downspacing that you've done so far in the Niobrara on the Razor pilot, I believe it is. It sounds like you're -- that's been successful. What have you seen from the well performance of the 16 wells per drilling unit spacing that leads you to the 32 wells? Have you basically seen no interference at this point or can you give a little color on some of those wells?

Yes. We dug 2 high-density pads now on that 16 well density, our 27K and 27L pads. And basically, I think the thing that is most impressive about these high-density pads is the consistency of performance. So everything that we can see tells us that we're on track. We have both 640s and 960s out there. But the 960s clearly look like they're going to exceed the 400 MBOE type curve and the 640s are a little less than that. They're approximately 2/3 of that number. So these pads are all consistent, all seem to be performing at that -- at or above that 400 MBOE type curve. I think we're saying 420 in there, but there -- both A and the B zones appear to be working very well. We think that there's going to be a little bit of a variability in different parts of the field as to which one is actually better. But both of them seem to be working very well for us right now.

I was just going to say, just to remind you that the 27K pad tested essentially an 8 well in the A -- 8 well in the B pattern. And the 27L pad was actually all in the B. So in a sense, we've kind of tested different components of the super pad already. 27L was equivalent to like a 16-well pattern and B -- putting them all in the B. Super pad may work. Now we're kind of combining those into a big pad.

Okay. So the Horsetail or super pad is really introducing some of the C development into this whole pattern. Is that kind of the main point of that?

There's really one important point to make there. And that is as we are on the front end of the development at Redtail, what we're trying to do with the 30F pad is take a step beyond what we think right now is likely to be the development pattern. To date we think 16 wells per spacing unit is going to be right. We are doing this 32-well pad really to try and prove to ourselves that that's accurate. And so that is the primary objective of that pad. There's a secondary objective to test the C zone, which we see it in core [ph]. We like what we see there. Our neighbors to the south of us have had good success in the C zone. We think there's every reason to expect that C zone to work, and we want to know that upfront before we start marching through and systematically drilling out the field. And so it becomes a part of our development pattern. We don't have to have to come back in later and drill C wells. So we're really trying to understand those 2 aspects with the 30F pad. It's a little bit unusual. But if you asked us today, I think we see say that 27K pad, the A, B, A, B pattern, 16 wells per spacing unit is probably where we end up.

Understood. And then my follow-up was as just as you march north in the Niobrara, you're going to be doing some drilling up there, I guess, later this year. Obviously stepping back and looking at -- you'd, I guess, have a Whiting within a Whiting. Is that -- obviously, do you need some of that work as good as the stuff further to the south. Can you remind us geologically if there are any changes in the Niobrara as you go north?

Well, I'll take the Whiting within a Whiting comment. I would say, the majority of that is really based on what we've already shown you in Horsetail, Wildhorse and Razor townships. If you look at our 5-year plan, we're going to drill over 1000 wells, concentrated mainly in those townships, where we have a very high working interest. And so that underpins a large degree of the statement of Whiting within a Whiting. And then furthermore, we're working to increase our working interest to the north and the east and have more concentrated acres -- as we delineate it with more drilling, so...

And then I would just like to point out that we're blessed in this area. We are blessed, because we have great services to the north of us, 2 big takeaway interstate pipelines. We're blessed to the east of us with a very large takeaway oil pipeline. We have the Denver oil market. We have the Wyoming oil the market. And most importantly, we have the plethora of data that is available to us from old logs that go all the way back into the '40s, '50s and '60s. So this was the playground for the Denver independence. So we have an excellent idea of the thickness of the A, the B and the C across our entire acreage position. And so while one may thin or one may thicken in a particular area, we're highly optimistic about the entirety of our acreage position working in at least 1 or 2 zones across the acreage position. And we've seen nothing to deter us. To go on and comment early on then, again, sort of a desirability of this area, I'd like to say that as a result of what we are doing out here, I mean, we're being contacted by many refiners who like this crude oil and are willing to make long-term commitments to take this crude at differentials in the range of what we show you on Page 7 of our press release. That is only about $4.75 off of NYMEX. So we see a long history here for Whiting. Try to remember that this part of the Rocky Mountain Basin has been a producer here since the 1940s. And, really, the the DJ Basin as exemplified by the Wattenberg Field has been a primary producer, going all the way back to the '70s. So it's been telling us for years that there's a huge amount of oil in place. First, we attacked it with refrac-ing of vertical wells. Now with the current technology, we're employing horizontal wells at multistage frac-ing. So the geology is well known, the oil in place is well known and then say our geoscience team here picked an area where the Niobrara in particular is in the oil expulsion window. And I think it's going to work across our acreage position obviously to varying degrees because Mother Nature is not homogeneous, but there's nothing that we've seen that would deter us from applying more and more capital and a greater number of drilling rigs out here as we move forward.

Okay. I appreciate that color. And maybe more directly to -- specifically what this was alluding to is that I think last quarter you mentioned there was an interesting data point further to the North, and I'm just trying to think in terms of as you drill those first few wells toward the North, kind of -- given the geology, should we expect that you're going to perform hopefully to that 400,000 MBOE or 420,000-type curve? And -- or does the reservoir thin a little bit to the North? And so it'll be good but maybe not as good as [indiscernible]. If you could have any color around some of that.

I think the only thing that we think ourselves right now is that we expect on the 960s, we expect the range of reserves to be in the 400,000 to 500,000 BOEs on the 960s. And as you might expect, about 2/3 of that for the 640s, across our acreage position or about 350,000 BOEs. And the cost, of course, come down on the 640s to about $4.5 million and the costs are approximately $5.5 million on the 960s. So I know when you put that in your model, you'll see that IRRs are in the 100% range. So this is my opinion. Maybe you want to say a Whiting within the Whiting or the potential for another Bakken for us. It has all of those things going for us. And you couldn't have found an oil field in a better place in terms of takeaway capacity, in terms of lack of an urban population around it. Out here, the population is only about 2 people per square mile. And the greatest thing is that the county and the ranchers and farmers out here from whom we leased want us in the area because they are the mineral interest owners. So we're going to do a good job here of being good stewards, collecting all of our gas, processing it, maximizing the value of that gas stream and being good neighbors to all of our constituency out there, both the county and our actual residential neighbors. By that, I mean, the few ranchers and farmers who are there. Mark, do you want to add something?

Yes. I'd just make an additional comment out here. As we talk about moving to the North, we have a program designed this year, we're going to drill 6 wells starting this summer that will go delineate the East, Northeast and all along the West side of our existing acreage position. As an important thing to remember, last March we changed our frac design. We essentially went from 1.5 million-pound sand volumes up to 7 million pounds sand volumes. When we did that, the equation changed out here. And so since that time, our drilling has really concentrated in this area, where we are in Razor and Horsetail and Wild Horse. But with these 3 additional locations on the East side and the 3 on the West side -- I should say Northeast side and 3 on the West side, we're really going to extend the reservoir with this new frac design. That's really the idea here is to see how it performs. We've got a handful, as do other companies' wells are in there, and they're okay wells. We think that they'll perform a lot better with this new stimulation. And you mentioned one -- the data point that we talked about last quarter, there is one good well up on the Northwest side already that we're sort of playing off of. But it's not one of ours. It was drilled by a competitor, and it looks like it's a darn good well. So we're not the only ones drilling out here. We're going to -- we're hoping to have a little activity by some of the offset operators as well. But there's no reason that we can see that as we continue to move North and Northeast and West, that these results aren't as good as they are where we are right now.

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

I have just a quick question on the Niobrara and the production ramp, and maybe I'll ask a little different than Dave Tameron did. But can you talk about how many completions you all had in the first quarter versus kind of what was planned for the year?

Yes. We had about 8 net, 9 gross completions operated. And we're ramping up to a pace of around -- Rick, 25 to 30 per quarter? Is that -- something in that range?

Yes. That's in the right range. And I guess -- this is Rick. One thing to point out, in the first quarter, a lot of those completions came on fairly late in the quarter as well. We liked the performance. We liked what we were seeing, and we were just -- a little bit of weather impact. So not as much impact in the first quarter for those completions.

That's helpful. And one follow-up on -- the new completion technique with the coil tubing, obviously, looks interesting. Since you're all going to try that in other areas of the Bakken, are you all going to try that down in the Niobrara as well?

Yes. We've got one that's coming up here shortly that we'll be doing 80 stages on. So we did 60 on the one at Missouri Breaks. And we're going to try 80 here at the Redtail.

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

A lot of mine have been addressed, but I guess, first in the Williston, how much -- we had really consistent positive results from these new completion enhancements and we continue to push that bar even further with the coiled tubing development. How much longer do you think you really need until kind of we should be thinking about gearing up the EUR in the Williston as well? Kind of, what sort of order of magnitude you think [indiscernible] at this time?

So I think we -- Mike, we answered that in the last quarter call a bit. I mean we said that we were -- in the past, we had always talked about the range of sort of 400,000 to 600,000 barrel wells. And we've said that we think now we're closer to a 600,000-plus barrel average. But we haven't really given a -- other than that range, like if it's EUR, I mean, it varies by area. But it looks like you're seeing that kind of an increase across the board in each area. On the low-end, being pushed up from 400,000 closer to 600,000.

Okay. And so if I take that and kind of apply that through the model, understanding Excel [ph] doesn't always reflect the reality. You've got an accelerating growth profile kicking off here in the second quarter. You just talked about kind of linear growth from the second into the third and third into the fourth. As I look to '15, it looks like pretty material acceleration in total annual gross, '15 versus '14 gross. Am I getting ahead of myself there or are we seeing we a step change in [indiscernible] repeatable growth?

Yes, I mean, I think we've said that as we invest more in the Niobrara and implement the new completion designs, we should continue to see increased capital efficiency and better growth per dollar spent. But I just don't think we want to talk about 2015 growth rates at this point. Still a lot of 2014 ahead of us.

That's fair. And then last is the [indiscernible]

Michael, we -- the only thing I would say is that we're basically very optimistic about not only what's happening in the Bakken, but what's happening in the Niobrara. And while we're not prepared to make, say, 2015 guidance at this time, there's nothing that we have seen to date that would deter us from continuing to concentrate in those 2 areas and harvest these improvements that we've seen in completion design. And then we expect to see, as we move into the end of 2014 and into 2015, we expect to see those be reflected in our reserves. So we're optimistic about the effect of these improvements, really, in technology and the improvements in the completion to help us add reserves at declining at the B cost. I think you see in the first quarter, Michael, that even though we dropped some rigs and had lower activity, we still had a large impact from weather and didn't get as much done the first quarter as we will, we still managed to keep the production flat. And you can see the very rapid acceleration in the second quarter, 9% quarter-over-quarter growth. So I think you're already starting to see the impacts of both the Niobrara and the new completion designs, just in our quarter forward guidance.

Yes, wouldn't disagree. Great. And then on the coiled tubing designs, are there any changes in costs associated with that? Or how should we think about that?

Material change on that or?

Yes, this is Rick Ross. In terms of costs we expect in the Bakken, it would be about $700,000 more on the scope units that you looked at on one of the slides. We think performance probably will more that offset that and we think we can probably bring that cost down a little bit over time. There's some real advantages in the cycle times to the coiled tubing completion, too. You don't have to pump as much fluid. The pump comes [ph] down, at least [ph] to clean the wellbore when you're done so you don't have to clean it out and you can put it immediately onto production. It's a lot faster to frac it that way, too.

Yes, so that would improve our cycle times. We could bring on more production per rig running out there, so that would help then to offset the higher cost in another way, having higher operational tempo.

Your next question comes from the line of Mike Scialla with Stifel. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: You're getting real comfortable in moving from the pilot stage to the development stage with the spacing in the Bakken now. How about the Three Forks, where do you stand there?

We've been testing the Three Forks throughout the basin. In the area -- the Central Basin, our Tarpon project, we recently took a core and I'd say that's the most optimistic Three Forks -- the best-looking Three Forks I've seen. It's got a good charge all the way down through what we call the third bench there. And so we're very confident that we're going to be able to develop the deeper part of the Three Forks throughout Tarpon. We've also had some really good results immediately to the North up there in our Cassandra project. We talked about one of the Cassandra wells. That was the Middle Bakken well, but we also drilled a Three Forks well up there that is comparable in initial rate. And so from what we can see right now, we're going to be able to develop all of the Three Forks up at Cassandra. We still don't know about the second bench up there, whether it's -- how well it's going to work, but we're very encouraged by the consistency of the last 3 wells that we drilled up there in Cassandra. They're very high rates. We used the new cemented liner plug and perf completions up there, and so we're pretty confident about that. And then the Three Forks down at Hidden Bench is -- that's an area that we're still working on trying to develop a technology to go after what we call the Bakken Silt. It's really part of the Three Forks but it sits between the lower shale, which is the source rock and the Three Forks proper. It's present only over a fairly isolated area there. But it covers most of our Hidden Bench property, and so we're drilling in the upper part of the Three Forks and trying to optimize the completion there. I think we're close to cracking the nut there but there's some real technical challenges with the drilling. But once we get that, a couple more wells in there, I think we'll be able to develop that pretty broadly across Hidden Bench. And then, of course, at Sanish, we've been developing the Three Forks all along. And we're continuing to do that. And so I think there's a decent chance we'll have some second bench opportunities at Sanish, but the first bench is pretty pervasive there. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: So I guess as I look at that Slide 9, the wine rack, as Jim likes to refer to it, the locations that you said are new objectives for the or potential high density, you feel pretty confident about that in the Middle Bakken, that's kind of where you're going and then for the Three Forks, there's still some testing to do to convince yourself of that potential. Is that a fair way to characterize it?

I think that diagram is pretty accurate today. I think what it shows -- the different colors on there really represent where we are in our testing and development of each of the different objectives. The ones that were going to have the biggest impact for us, I think Sanish by doing what -- if you look up there in the Middle Bakken, you'd see that's a double downspace. Recognizing that we've been developing this field with 3 wells per spacing unit, there's an opportunity to get at least one well and possibly 2 wells through most of the field. That's a lot of locations. We got a big acreage position there. And then we talked about Three Forks opportunities. Cassandra, there's a chance for the second bench. There's a chance for a second bench at Sanish, but I think we've covered that pretty well already. So I think that it's pretty accurate of where we are today. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. Great. And then last one, I think you may have mentioned this. But at Sanish, the -- my understanding was you were feeling more confident on downspacing the western side. Has that changed at all? Do you have confidence to do that over the whole field now? Or is it primarily limited to the Western side of the field?

We've got the western and central part of the field. We have clear downspacing opportunities. The eastern side is very fractured, but we've got some other things in the works, probably not a good time to talk about them just yet. But we've got some other things that are in process right now that we think could really help us out on the east side and potentially have a lot of locations and high recovery efficiency over there as well. So there's a lot of things that we're really not talking about just yet in here, but we do have some reasons to be pretty optimistic over on the east side that maybe can get to next quarter.

Your next question comes from the line of Subash Chandra with Jefferies.

A couple of questions. First, could you remind me again the role Colorado Mineral Belt played up in the Niobrara Redtail area and what that might mean for sort of a northern expansion? And then secondly, these wells that -- with these new completion techniques, if you can talk to the bottom hole pressure data, whether that's giving us any clues on acceleration versus recovery factors?

I'll take the first one. First here about the Colorado Mineral Belt. We talked about it quite a bit over the last couple of years. It was a key part of our leasing strategy out here, recognizing 2 things. A lot of higher heat flow out here. And essentially the Niobrara source rocks being right in the oil generation window. So the intersection -- and if you think about the Denver basin, the structure contours here are running north-south, the Mineral Belt is running northeast. So the intersection of those 2 lines, the peak oil generation being along the north-south line and then the Colorado Mineral Belt or the zone of high heat flow running sort of northeast was what led us to lease where we did in Redtail. And so our lease position, all of it, is really representation of what we believe the full development potential is out there. There's a lot of people, ourselves included, that started out early on mapping resistivity out there. Resistivity is a good initial indicator. But you really need core data to fully understand it because of the high resistivity of the limestone reservoir that we're drilling in. So I just want to make that part clear. So we continue to believe in all of our acreage position out there. As far as the second part, the reservoir pressure, I'll let Steve talk about that. Steve?

This is Steve Kranker speaking. Rest assured, we're doing some cutting edge reservoir engineering work on the downhole pressures and the implications for pure acceleration versus unique reserves in the interference of wells as we downspace. We have an array of downhole service read-out gauges. We have used memory gauges in the past. And in particular, there's a lot of planning going on right now with our 32 wells density pilot at the 30F pad, where we're going to take that pressure data. So to date, our engineers are finding that we do not expect to see in the first several months any interference between these wells. And it's going to be in that 6 to 18 months area before we know whether wells are interfering with one another. And one of the big drivers of why we're doing the 30-well -- 32-well density pilot is get that answer twice as quickly. So yes, we are doing that pressure work right now and we'll be able to report on that in the subsequent quarters or maybe by year end.

Just one other comment on there. We've got a backstop in terms of the oil in place there that I think is very important. We had that in the previous presentation. If go back a couple of quarters, you can see that the oil in [ph] place is what gives us the confidence to be drilling on these higher densities. So we know that there's the oil there, the question is one of recovery efficiency, and that's what Steve is talking about and that we're going to be testing.

Are there any information to be conveyed by it if you were, say, comparing the Skov wells by different completion designs?

I think it's still a little bit early on that. We're only a month into the completion on the Skov and we really -- we're very impressed by what we've seen so far. But I wouldn't count out the plug and perf with cemented liner completions just yet either. I think they're a little bit artificially suppressed on this slide because we have not yet had the opportunity to clean those out. So I think that you can see improved performance from those as well. Different areas -- Rick, you can speak to this, but different areas, I think the operational efficiency is what's really driving this.

Yes, I think certainly the coiled tubing approach applies in very well in Redtail because we can get all the way out to the end with coiled tubing, so that's something we're going to look pretty quickly. And I think it'll apply in select to maybe wide areas in North Dakota as we get a little bit more data.

But that -- being able to get in and do this in 1 day is a pretty big deal.

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

Just wanted to wish Jim Brown all the best in retirement. So in Redtail, just coming back to the well cost there, you guys have talked about $5.5 million. As you focus more on pad drilling, can you maybe talk about your ability to drive those costs lower?

I think at this point, we're saying $5.5 million to $6 million is the range for the 960s. And I think we've made very good progress on the stimulation side in driving costs down. To answer your question, I do think we still have some efficiencies and some ideas left to test to shorten cycle time and some logistics on moving freshwater in for the frac. So I think there's potential to continue to move those.

Okay. And then just one other question on hedging. So for 2015, you, guys, you have the basis hedges in, but you're not hedged otherwise. So Jim, can you maybe talk about just your thoughts on hedging '15 at this point?

Yes, we've been looking at putting some hedges on. We might start doing it quarterly here soon. We like to get ceilings around $100 if we can, and the strip has moved up recently and gotten us closer to that. So I think as you -- as we get back to the second quarter here, we'll start layering some in for '15. Hopefully, eventually, getting to around 50%, maybe 60% hedged on our oil.

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

Definitely congrats to Jim Brown on his retirement. looking at Slide 13, it notes there's a mix of 640- and 960-acre space wells since March. Do you guys have a breakdown of how many 640s and how many 960s went into the type curve building?

Well, it's very similar to our overall field development patterns, about 4 640s and 13 960s. And that type curve is the actual plot or the data we've used just extrapolated out to a full type curve. So about 25% 640s.

And we should assume 25% roughly going forward for development?

It's a little bit higher, it's around 30% going forward. But as Jim Volker indicated, we're looking at something between 400,000 to 500,000-barrel range for the 960s, and about 350,000 for the 640s, with costs about $1 million less for the 640s. That's basically the data underpinning that curve and those economics.

And what was the geographic concentration of those?

Those were spread across our acreage from the Horsetail unit in the East to the -- all the way down to the tip of the Wildhorse unit there in the West. So it spans our acreage pretty broadly from the East to West.

[indiscernible] shows it pretty nicely.

Okay. All right. And changing to the Williston Basin, can you guys just touch on the progress that has been made in March and April in terms of getting the wells waiting on completion down? And if there's been any challenges with a longer winter, where kind of on the momentum on the operational standpoint comes from post a tough January and February.

I would say we had a good April at this point. Still some weather, small weather effects. But I think we're doing great in terms of performance and reducing downtime, and our cycle time on completion looks pretty good right now.

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment.

Regarding the coiled tubing completion, the no drill out and clean dispute [ph] advantages are pretty easy to understand. I don't want to ask you to get too deep in the weeds, but can you add some color as to why you think this method works better?

I'll take a crack at that. We've made a big concerted effort to try and access as much reservoir as we can, and we're doing that through increased number of entry points. And so if you look at the slide on Page 8, there's a column, it's the fifth one from the right side, that looks at the number of entry points. And so you can see between the plug and perf and the coiled tubing conveyed completions that Skov 3H well had 85 entry points. What's really significant about that is that 60 of those, we absolutely know that those were entry points because when we frac-ed those stages, all of that fluid went out through that discrete set of, that frac port, essentially. So we've got to cement behind the pipe. It really couldn't have gone out anywhere else. And so we know exactly the fluid volume that went out into each one of those. With the plug and perf, we could see trackable [ph] total frac volumes, and we have 3 or 5 perf clusters per stage, but we don't really have a way to tell us exactly how much went out into each stage. So the total number of possible entry points are listed there at 90 and 150 respectively. But how many of those actually took, it's difficult to say with a high degree of confidence. I think that's the -- one of the big advantages I see is you know that with the cemented -- sorry, the coiled tubing conveyed ones, you've got an entry point right there and they're nice and very evenly spaced up and down the wellbore. And so you're doing a good job of rubbelizing the rock, I guess is what I should say there.

Sorry, just to make sure that I understood what you were just saying, so even though you have microseismic in some of your projects and so forth, you really can't confirm how many of those entry points in the 90 or the 150 are really taking, but with the coiled tubing, you can. And if so, is there something unique about the coiled tubing thing that just gives you greater clarity on which ones are working or not?

The coiled tubing, it's empirical there because it can only go out one and only one place. When you open that port up, that it has to go out there. You've got to cement behind the pipe. There's nowhere else it can go but out into the formation. The microseismic is a great tool for being able to tell us the overall area that we're affecting by our fracs but it's not -- this is direct evidence and we can tell by our pump schedule essentially, exactly how much frac volume is going out in each one of those perforations. So there's no guesswork involved. It's pretty direct.

Okay, yes. That was really helpful. I appreciate that. As my follow-up, if I can ask it, from looking at the various developments things, it looks like all your development plans don't go any lower than the second bench of the Three Forks. And I was just wondering, have you actually tested any of the lower zones and you've just eliminated it from the development plan on that basis or is there an exploration project that hasn't happened yet?

The Tarpon area has third bench development, and we will be drilling the third bench there. And the other areas -- second bench is probably as deep as you'll see us drill.

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

Just curious, you talked about on the release at least -- obviously you're going into the C up in the Niobrara, but also you did mention the Codell. Is that kind of the plan after looking at the C in the downspacing units or when do you kind of see going after that?

So we recognize the Codell there. We're scratching our heads over it just a little bit. We see some good opportunity there. And I think that some of the wells in the general area that have been drilled, there's been a couple of Codell wells drilled. I'd say at this point, we're a lot more optimistic about the C zone. We can map that, and we mapped the oil in place. We've got core over it that tells us pretty discretely what's there. And so I'd say that's where we're going to focus our efforts, at least initially. You'll probably see us try a Codell well here some time, probably early next year would be my guess.

Okay. I will now turn the call back over to Jim Volker for any closing remarks.

Thanks, Erica. As always, I'd like to thank all of the Whiting employees and directors for their contributions to a successful first quarter, and our exciting plans for the remainder of the year. Eric?

Jim Volker will be presenting at the Williston Basin Petroleum Conference in Bismarck, North Dakota, on May 22; Rick Ross, our Senior Vice President of Operations, will be participating in the RBC Energy Conference in New York City, June 2 and 3; and Pete Hagist, our Senior Vice President of Planning in Permian Operations, will be presenting at the OGIS Energy Conference in Toronto on June 4; and Pete will also present at the Global Hunter Conference in Chicago on June 24. And we look forward to seeing you all at these events.

In closing, ladies and gentlemen, we thank you all on this call for your new and continuing interest in Whiting Petroleum Corporation, and we look forward to meeting with you soon.

Thank you for your participation in today's conference. This concludes the presentation. I will only [ph] now disconnect, and have a great day.