Chord Energy Corporation (CHRD) Q3 2013 Earnings Report, Transcript and Summary

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

John Freeman - Raymond James & Associates, Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Michael Hall Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division Brad Carpenter - Wells Fargo Securities, LLC, Research Division Paul Grigel - Macquarie Research Jason A. Wangler - Wunderlich Securities Inc., Research Division John C. Nelson - Citigroup Inc, Research Division

Good day, ladies and gentlemen. Welcome to the Third Quarter 2013 Whiting Petroleum Corporation Earnings Conference Call. My name is Celia, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Eric Hagen, Vice President of Investor Relations. Please proceed, sir.

Thanks, Celia. Good morning, and welcome to Whiting Petroleum Corporation's Third 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 third quarter of 2013, and then discuss the outlook for the fourth 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.

Thanks, Eric. Good morning, everyone, and thanks for joining us. We'll get to your questions just as soon as possible. Whiting is a major player in 2 of the hottest Lower 48 U.S. oil plays in the last 40 years, the North Dakota Bakken, and now the Colorado Niobrara play. In the Bakken, we're applying a cemented liner and a plug and perf completion design across the Williston Basin and getting results 50% to 75% better than prior completions. In addition, our first 2 higher density wells at Pronghorn had average IPs of 1,368 BOEs per day. At our Western Williston area, production increased 46% over the second quarter of 2013, driven by strong drill bit results. At our Redtail prospect of the DJ Basin, we continue to generate strong and consistent results, with 30-day production rates of approximately 450 to 500 BOEs per day and we've moved into development mode with pad drilling. As you can see on Slide 3, we are a company on the move. We sold 32,000 net acres in our Big Tex prospect in the Delaware Basin for $150 million. We acquired 17,300 net acres and 2,420 BOEs per day in the Williston Basin for $261 million. We sold our Postle enhanced oil recovery project for net proceeds of $816.5 million. In Q3, we added 32,400 net acres in our Redtail, Niobrara prospect. We are accelerating development at our Redtail prospect, where we estimate we have more than 3,300 future gross well locations and where well costs are only approximately $5.5 million per well and EURs are estimated at over 400,000 BOEs per well. We have also accumulated 500,000 new net acres in 3 new oil resource plays at an average price of $228 per net-acre. On Slide 4, you can see we're on track to post year-over-year production gain of 13% despite the sale of 7,560 BOEs per day associated with the Postle assets. And we would be up 23% excluding the production associated with the Postle sale. Our record production in the third quarter translated to record discretionary cash flow of $450.5 million, up 31% over the third quarter of 2012. We also had strong adjusted earnings of $153.2 million, which were up 69% over the third quarter of 2012. Slide 5 shows 81% of our total production came from our core Rocky Mountain region. Approximately 70% of the total came from the Williston Basin. All of our core areas contributed to our record quarter. On Slide 6, we provide an overview of our plays in the Williston Basin, where we control nearly 730,000 net acres. Slide 7 shows our new and improved completion design in the Williston Basin, where we have instituted the use of cemented liners to enhance plug and perf results by achieving a better breakup of the near wellbore reservoir. As you can see, we have 3 entry points per stage with the cemented liner. Therefore, for a 40 stage frac, we have a total of up to 120 entry points and are breaking up the rock more effectively and more efficiency than with an uncemented liner, where we had only 30 entry points. Slide 8 shows some examples of our Lewis & Clark and Pronghorn prospects of results from our new completion design in the Southern Williston Basin, where results were up 50% higher than the offset wells. I'd also like to point to our first 2 higher density wells at our Pronghorn prospect. Both of these Privratsky wells were completed in September using cemented liners and plug and perf technologies. They came online at an average of 1,368 BOEs per day. This pilot is testing 7 wells per spacing unit versus our prior plans of 3. We are very pleased with these well results. On Slide 9, it shows several more side-by-side completions at our Hidden Bench and Missouri Breaks prospects, where we achieved higher production using cemented liners and plug and perf technology. Initial production rates were 40% to over 100% better than offsetting wells. On Slide 10, the 8 wells that we completed using our new completion design at Missouri Breaks had average initial production rates of 1,290 BOEs per day, more than double the 587 BOEs per day average from the previous 31 area wells, which were completed using uncemented liners and sliding sleeves. Slide 11 illustrates the improved cumulative production that we are seeing from our new completion technique. The red lines indicated production from our new completion design, while the blue line reflects our previous completion technique. 30-day cumulative production from our 8 new cemented liner wells was 60% better than the prior 31 wells that use sliding sleeve technology. Slide 12 shows that for the comparable wells we highlighted in the side-by-side comparisons, our well costs for our new cemented liner wells were flat, with the adjacent wells using older completion technology. Jim Brown will now discuss our new development area at Redtail.

Let's start on Slide 13 with our Redtail prospect in Weld County, Colorado where we target the Niobrara formation. I want to point out 2 wells we completed in the third quarter that bracket our Phase I acreage which has 899 potential gross drilling locations: the Horsetail 18-0713H averaged 452 BOE per day over the first 30 days of production; and the Wildhorse 04-0424H averaged BOE 492 per day over the first 60 days of production. A third rig is scheduled to arrive at our Redtail field by November 4, 2013. We currently plan to add a fourth rig in January 2014 and a fifth rig in June 2014. Our drilling has shifted to pad drilling. As of last Monday, we had 3 wells flowing back, 2 wells waiting on completion, frac-ing operations were ongoing on a 4-well pad, and our 2 drilling rigs, both drilling on pads, drilling 4 wells on 1 pad and 8 wells on a second. Our development plan for the Redtail prospect is to drill 8 wells per spacing unit to the Niobrara B and 8 wells per spacing unit to the Niobrara A. We estimate that we have more than 3,300 gross locations and 1,650 net locations at our Redtail prospect on this development pattern. Phase I alone has nearly 900 future well locations. And in Phase I we have an average working interest of approximately 85%. Moving to Slide 15. You can see our facilities plan for Redtail. Please note that our gas processing plant with an inlet capacity of 15 million cubic feet per day is scheduled to start up in January 2014. Our new completion design is generating strong and consistent results. We have transitioned to plug and perf completions and higher sand volumes of 6 million to 7 million pounds per well. Slide 16 shows that the production results from our most recent 8 wells, using our new completion design, are outperforming a 400,0000 BOE type curve. Our results are consistent, as 6 of the 8 wells are at or above the type curve. Please note that these are not like Bakken wells that achieve their peak rates within the first 4 or 5 days. Typically, our Niobrara wells take about 30 days to reach max rate. On Slide 17 is our Big Tex prospect in the Delaware Basin. We recently entered into an agreement to sell just over 32,000 net acres and approximately 200 net BOE per day to a private buyer for a total consideration of $150.1 million. Of the total net acres, 30,822 net acres are located in Pecos County. The sale is expected to close by October 31, 2013. The transaction will bring a new operator to the area whose drilling we expect will help us de-risk our remaining 41,173 net acres at Big Tex, which is primarily located in Pecos County, Texas. Slide 18 shows our North Ward Estes enhanced recovery project in the Permian Basin. Net production from North Ward Estes averaged 9,610 BOE per day in the third quarter of 2013, a 4% increase over the 9,275 BOE per day in the second quarter of 2013. Mike Stevens, our CFO, will now discuss our financial results in the third quarter of 2013.

On Slide #19, you can see our third quarter 2013 adjusted net income available to common shareholders was $153 million, or $1.28 per diluted share. Our discretionary cash flow in the third quarter totaled a record $450 million. This total represented a 31% increase over the $343 million in the third quarter of 2012. Our guidance for the fourth quarter and full year 2013 is detailed on Slide #20. Please note that our DD&A rate came down this quarter and is anticipated to remain below our first half of the year trend in the fourth quarter. This is because we had strong, proved developed reserve adds in the third quarter. Also note that LOE is expected to go up slightly, due to the payout of our oil gathering system at Robinson Lake, as our profitable midstream operations are currently collapsed into LOE. This LOE increase will be offset by a similar realized oil price increase. On Slide #21, our third quarter EBITDA margin continued to be strong at 64% of our blended realized price per BOE. On Slide #22, you can see that we continue to maintain a strong balance sheet, with over $1 billion of cash on hand after our recent bond issues and nothing drawn under our bank credit facility. Slide #23 shows that our 2 senior notes and 2 senior subordinated notes continue to trade at or above par. Note that we have given notice to redeem our 2014 notes on October 31, 2013, using $250 million of our bond sale proceeds. It also shows that we are well within all of the covenants in our credit agreement and our bond indentures. Slide #24 shows our crude oil hedge position, including the new 3-way oil callers that we put on for 2014. At this point, we are at 55% hedged on oil for 2014. On Slide #25, you'll see our strong fixed-price gas contracts that continue to net us over $5 per Mcf. I'll turn the call back over to Jim Volker.

Thanks, Mike. As you can see, this is an exciting time at Whiting. We are a company on the move. Cash flow hit a record $450.5 million, up 31% year-over-year. Drilling results in the Williston Basin are up 50% to 75%, better than prior completions. We have acquired an additional 32,400 net acres at Redtail and an additional 17,300 net acres at our Hidden Bench and Missouri Breaks prospects. At Redtail, we estimate we have over 3,300 gross well locations, where we estimate completed well costs are only $5.5 million per well and EURs are over 400,000 BOEs per well. We also sold less than half of our Big Tex acreage for $150 million. We sold our Postle enhanced oil recovery project for $816.5 million net and paid down bank debt. As a result of these actions, we have an exceptionally good balance sheet, which we're using to accelerate production and reserve growth at Redtail and in the Bakken. Celia, please open up the conference call for questions.

[Operator Instructions] The first question comes from the line of John Freeman, Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: The side-by-side comparisons that you all have been giving in the last few presentations on the well performance and the AFEs is extremely helpful, so I appreciate you guys doing that. The first question I have, on the Niobrara, could you give me an update on, last quarter, you announced the results on the Razor well. And just so I can kind of comp it, at least relatively in the Horsetail and the Wildhorse, do you have the 30- and the 60-day rates on the Razor?

Yes, we'll get those for you here, shortly. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. I can ask some other questions while you're looking at that. And then if I'm looking at it right, of what you all have done, shifting gears to the Bakken, has there just been the one well at Missouri Breaks where you all used slick water?

Yes. John, this is Jim Brown. Yes, to date, we've only done one slick water job, and that was the one well at Missouri Breaks. We've got several other in the queue, but that's the only one we've completed. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. So I shouldn't read anything into it in terms of you just did the one, there wasn't anything you didn't like about it, you just haven't necessarily gotten around and testing on more?

That's correct.

Yes. We liked the results, John. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And do you have any plans to sort of uptick on your -- the amount of profit you're using? And I realized it's a lot more than what you're doing on the deal design, but there are some others that are using more than the 4 million pounds.

John, we've tried a range of proppants -- I'm speaking just in the Williston Basin now. But we've tried a range of proppants, so I'm going to say, probably as high as 8 million pounds, and then on down. We sort of found a sweet spot in there, I'm going to say, in that 4 million to 5 million pound sand or proppant, I'm not going to say just sand, but proppant range, somewhere in there. John Freeman - Raymond James & Associates, Inc., Research Division: Okay, great. And then the last question for me. I know that last quarter you all talked about at least, early on, based on the results and it seems to still be the case based on the latest data, that your Niobrara EURs seem to be trending a lot closer to that 500 to 600 range versus the 400 EUR range. And I'm just curious like when do you think you'd feel confident enough and have enough data and production history to where you'd maybe more officially want to start to raise the EUR guidance? And I'll stop there.

Yes, probably within about 6 months at the latest. And we might be able to do it here within the next 90 days or so, John. Separately, I'd just like to go back and say, one of the great things about what we're doing in the Bakken is that we're able to get these increased rates and we believe increased EURs and hold our well cost flat at about $7.5 million per copy.

John, in the Razor 33, the 60-day rate was 721 BOEs per day and the 90 was 646.

The next question comes from the line of Joseph Allman, JP Morgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: With the Pronghorn downspacing test, are you -- is the distance between the laterals there, is it about 700 feet? And are you seeing some interference? And do you think that is the right inter-lateral spacing?

The Pronghorn downspacing, we did something a little unusual. We kind of -- when we set that pilot up, what we decided to do is between the 3 existing wells that we had at Pronghorn, we drilled 2 of the downspaced wells between 2 of those 3 existing wells. So we actually overstepped what we think the development pattern would be by just a little bit. And so it really make -- the idea there is we're testing a density of at least 7 wells by drawing both of those wells between existing wells. So we were particularly encouraged by the high rates around 1,500 BOE per day, those downspaced wells. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So is the distance between the laterals somewhere around 700 feet? And do you think, based on the very early data you have at this point, you think you've got the right downspacing gear? Or is there any data to suggest you might need to go even more dense?

I think that spacing is approximately correct, 600 to 700 feet. What this tells us is we have more than enough room to put 1 lateral between each of the 3 existing laterals. In other words, we bracketed or we put a bookend on that density. And so going forward, at least for the better part of the field, we're pretty comfortable that we're going to be able to put at least 1 lateral between the existing wells. [indiscernible] And the -- okay, so the other issue is the one of interference. And the only thing we could say this early in the stage of the flowback is that the offset production from the 2 adjacent wells that were there prior to our downspaced locations actually gone up over a period of about 30 days. And so anywhere between about 10% and 50%. So it's too early to say whether there's any -- what the long-term effects of the interference are going to be. But that's very positive news that the offset wells, the pre-existing offset wells are up by probably an average of 30%.

Let's just say we're breaking up more rock and getting the benefit of synergistic frac-ing. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Great. And then just a follow-up. On the Niobrara, so that graph that you showed in today's presentation is very helpful. In terms of the production, what is the gap in production between the wells using the new completion techniques and the wells using the old completion techniques?

Well, I think all you have to do is look at the far right-hand side there, and look at the cumulative production over that 30-day period. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. So I don't have that in front of me right now. So like, basically, are you saying 50% higher just on average when you're looking at side-by-side comparison?

[indiscernible] in the Niobrara, you're saying what's the difference between -- the old completion technique is mainly using sliding sleeves with lower sand volumes. Is that -- and you're saying compare that to the new higher percent volumes plug and perf? Joseph D. Allman - JP Morgan Chase & Co, Research Division: Exactly.

It basically took us from a recovery over the first 30 days of approximately 6,000 barrels up to approximately 16,000 barrels. And the average is approximately 15,000 barrels. So essentially more than doubled.

The next question comes from the line of Ryan Oatman of SunTrust.

I do want to dig in a little bit on this new completion design in the Bakken. I mean really incredible uplift in rates here. Can you talk about where this design came from and how it's evolved over the past months? Just a little bit of history.

So essentially, the -- people have been doing plug and perf completions in the Williston and the Bakken, in particular, for quite a while. We've done a combination of plug and perf and sliding sleeves. But what's common about the older completions is that they have an open annulus. And the difference that we've applied here is a cemented liner and what that really does for us is, in combination with plug and perf, is it sort of forces the entry point. So we do multiple perf clusters for each stage, but the key there is that the frac does not wander into the annulus or up-and-down annulus, and typically break out in one location as the older style did. Instead, with the cemented liner, we're focusing the frac right into the reservoir at the locations where we have each of these perf clusters within a stage. And I think it's really well illustrated on the graph, the diagram that we show you on Page 7, you can really see that. And for each perf cluster, we have the opportunity to have a single entry point for each one of those. And then you multiply that by the number of stages, the 120 entry points. The gist of it is, is what we're trying to do is break up each -- break up the reservoir rock all along the wellbore. The previous design, with only one entry point, whether it be plug and perf or sliding sleeve, without that cemented annulus, you really only probably have 1 entry point per stage. And that's -- if you take a 10,000-foot lateral and 30 stages, it's roughly the length of a football field between our fractures, which just isn't even enough to adequately process the reservoir.

So it sounds like each individual frac stage is maybe more effective by the fact that you're doing 3 points per stage, and then also by using the cemented liner, it sounds like you're more able to effectively make sure that each one of those frac stages is effective. Is that kind of a fair summary?

That's correct. We can't say for sure that each one of those perf clusters breaks down with the frac. But we're giving it every opportunity to do so. So if even half of them break then we double the number of entry points per stage.

Ryan, it's Jim Brown. I wanted just -- I just want to throw in one more comment too. Other operators have had success with this in the basin. One in particular, the folks that operate Parshall field, just to the east of us here in Sanish. So we're not alone on this one. There's others that have also demonstrated the viability of this technique.

Okay. And you guys obviously are one of the few companies that have your own core lab and, obviously, the science that you have available to you. Based on your work there, why do you think this completion design works better in certain areas? And do you see variability between this design working in, say, a Missouri Breaks versus a Pronghorn? Any initial thoughts on why that might be?

Well, I'll take a shot at that, as we've had many discussions about that very topic at our management meetings. And I can simply say that basically, once you get away from Sanish, the rock's a little harder, a little tighter. It seems to work across all of our acreage positions, and we see essentially what we're doing here is simply getting, in terms of the distance away from the wellbore, a better and more consistent frac up and down that wellbore. Because of the cement that's there, we're able to direct it. And as a consequence, get out, as you suggested in your question, somewhere in the range of around 700 feet on each side of that wellbore, rubblize it effectively and efficiently, and essentially break up more of the rock and liberate more of the oil. And that doesn't -- so it doesn't seem to matter whether we're doing that at Pronghorn in the Pronghorn Sand or in the Middle Bakken at Hidden Bench. We're getting upward adjustments of between 50% and 70% in comparison to our prior IPs.

Okay. And then one final one for me, unrelated. It does look like you guys took the Niobrara gross location count up from 2,400 to 3,300. What is -- what gave you the confidence to do that at this time?

Well, I'd say it's important to recognize that 3,300 is the number that we use. We had a Niobrara bus tour here, if you -- 3 or 4 weeks ago. And what that number represents is the total number of locations, gross locations, that we have across our acreage position, both operated and non-operated in each of the phases that we have the opportunity to drill in. So it's really a reflection of the increased density that we are now proving up going to 16 wells per spacing unit, just taking that and looking at that across our acreage within what we believe the prospective part of Redtail is.

So in short, our confidence is high at 16 wells per DSU.

The next question comes from the line of Brian Corales, Howard Weil.

Can you talk about, I guess, the timeframe of de-risking the different stages or different phases in the Niobrara?

Essentially, what we're doing, we talked a little bit about our rig allocation. We've got 2 pad rigs as of this week. We'll have 2 pad rigs that are dedicated to essentially developing all of our acreage in Phase 1. But we still retain one rig out there that is going to be spending a good portion of its time, not all of its time, but a good portion of its time out defining the remaining phases of our acreage position. So one of the things that really allows us to do that is the completion of a 3D seismic survey that covers acreage outside of our Phase 1 area. We just got that data in and 3D is actually absolutely essential for drilling those initial wells in each of the spacing units outside of Phase 1. And so we're doing a combination of things there. We're taking our new 3D, which allows us to drill beyond our existing control. And we're HBP-ing each of those other units as well as defining any variability that happens to be in the reservoir. So we'll be continuing to do that with the -- with this particular rig over the next couple of years.

I'll add to that, essentially when we -- when you talk about de-risking, I think there's 2 ways to look at that: One is geologic risk; the other one is preparation, when are you ready to drill? And what Mark has done in answering your question here is to tell you that we will be ready to drill in all of these phases as we go through Phase 1, 2, 3 and 4 and shoot our 3D. In terms of geologic confidence, that is already very high. Why is that? It's because this area was a playground for the early explorers here back in the '60s and '70s looking for the D sand here which is deeper. So they drilled wells out here, many, many wells that we all -- and we have the logs on those. So we can tell what those logs look like. We can tell that the Niobrara A, B and C is there, essentially in consistent thickness across our entire acreage position. So that gave us the confidence after having tested that, and gotten good results that our entire acreage position out here, from a geologic standpoint, is de-risked. Now what we're doing is we're getting ready in terms of the logistics to drill it all. That's really where we are at this point. We're simply getting ready to drill it all up.

I just want to add one thing to that, Jim. Following up on Ryan Oatman's question before too, Brian, we've also done extensive core analysis across all of those phases, which we believe provides us better insight than a lot of our competitors who are just using, for example, soil log analysis. So we think we're getting direct readings from the core, and have very high confidence based on those that we have consistent geology across our positions.

But great question, thank you.

Yes. And just kind of, maybe to add to that, the significant kind of backlog awaiting on completion wells, is that a result of pad drilling? Or are you all trying to build up a backlog for your own processing facility to be put in place, or maybe a combination of both?

No, that's just the pad drilling, Brian. As I mentioned in my comments, we're already working through -- that was as of the end of the quarter. We're already working on a number of those wells that we're waiting on completion.

Okay, got you. And if I could squeeze one more in. You mentioned the undisclosed plays. Can you maybe comment on what phase or what stage those plays are in? Is it just a leasehold right now or you all actually drilling and testing? If you can comment, whatever you can say, I guess.

Well, I would say we have some definitive results for you in Q4. And yes, we are drilling currently on all 3 of those, 2 of them in particular, and we'll be pleased to announce those results in the fourth quarter. And really don't want to go too much further at this time, because we're still solidifying some of our acreage positions out there. But we've done core, and now we're drilling wells and we've been encouraged by the results of both of them. And we'll give you those results in our Q4 results.

The next question comes from the line of Jack Aydin, KeyBank.

In the Redtail, is the Horsetail well a cement liner type of well or there was another well that you haven't completed? Could you update us on that?

Sure, Jack. We've got one cemented liner in the ground out there, Redtail, we still have not frac-ed that well. All the wells we've given you to date are sliding sleeve completions -- excuse me, plug and perf completions. Excuse me, they're all plug and perf but they're all with swell packers, not cemented liner.

Great, that was a good question, Jack, thank you. And with that completion technique I'd call your attention to Page 16 of the slides that we sent, that in comparison to our 400 MBOE type curve over approximately 150 days, cumulative production for the type curve would be about 50,000 barrels whereas we're at about 60,000 barrels based upon the results of that 8 -- of those 8 wells. About 63,000 to be exact.

The next question comes from the line of Tim Rezvan, Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I'd thought I'd beat the dead horse a little more on the completion side. In the Bakken, is this new cemented liner and plug and perf approach, is that your primary completion that you're going to implement now across Missouri Breaks and Pronghorn and Hidden Bench, going forward?

Yes. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, that's an easy one. And then can you maybe kind of talk, there's been a lot of, I don't know, skepticism out there that this new design can be done at a similar cost. Is there a way that you can kind of -- without getting too in the weeds, address why there isn't inflation on the well cost side?

Sure, when we do a sliding sleeve, swell packer completion, all -- and let's just use a 30 stage completion to keep it somewhat simple. The cost of all that equipment that we run in the hole is in the $300,000, $350,000 range. So right off the top, we don't have to purchase that equipment. So we don't incur that cost. The cost to cement a liner in the well, that's proven oilfield technology. That's less than $100,000 to do that. So right there, we're gaining a fair amount on the well cost. However, that -- what we gain by not running all of that equipment, we spend because we have wire lines and we're running plugs in there and all that sort of stuff. So all in all, and as our slides shows, it all turns out to be about a wash. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Even with the 2 million tons of proppant?

Yes. The other thing we're doing, our drilling guys are just doing a super job. And we continue to take days, and so it isn't exactly an equal comparison because we're comparing wells we drilled a few months ago with wells we've recently drilled. But our drilling guys are continuing pull days out of there. So we're actually drilling the wells a little cheaper than we were even 6, 9 months ago.

Meaning we're getting it to PD in fewer days.

Yes. I'd just like to point to that Slide 12 again, because we give, in the Pronghorn field, the Obrigewitch results which are all completed off one pad. You can see the AFE dates, 4/18/2013. And you can see it, basically the same well cost between the sliding sleeve and cemented plug and perf. And so I think it's pretty definitive data that these wells are all going to be around the same cost.

But great question, thanks for asking.

The next question comes from the line of Michael Hall, Heikkinen Energy Advisors.

I guess a lot of mine have been asked and answered. Two I had remaining. Number one, big ramp in the Niobrara rig count, outlined in the release. What sort of production growth do you think could be supported from that asset by that sort of rig ramp, ballpark?

Well, I would say this: that's a question that really encompasses not only, I think, what we're doing there but what we're also doing in the Bakken. So I'll try to be…

I just mean on an asset level basis, Jim, not -- and if you don't want to go there that's understandable. That's all I was trying to understanding there was just on an asset level basis, kind of how you see that, from the capital efficiency?

Okay. Well I'll try to be as direct as I can. As we de-risk that area, the potential exists there to put as many as 12 -- as 20 rigs out there. And why that many? Well, it's because we have 3,300 drilling locations. We want to get all that developed out there within a period of 5 to 7 years. And so if you assume the kind of success that we have, then the numbers get very exciting. I mean they get very big because, basically, we would go from 5 to 8 to 11 and then jump to 20 rigs. And we would do that here, basically, we'd be starting at the end of 2014, we would probably add 3 rigs or so per year and get up to 11 or 12 rigs and then jump to 20. So without being maybe too optimistic there, I would simply say that I believe another Whiting exists within the Niobrara. Another Whiting, another current Whiting exists within the Niobrara.

Well, that's certainly substantial growth. Appreciate that color. I guess the other one I had was -- that was my second question. You've got some gathering assets and whatnot in the Williston. Are those sorts of assets potentially sources of funds? Not that you guys have a dire need for funds, obviously here, but just kind of trying to think through how those fit into the capital equation in the year and years ahead.

So the answer is yes, they do present a good opportunity for monetization. We have had many inquiries from infrastructure investors, some public, some private, who would like to come in and be our partners there. As you know, we own the 2 plants in the Bakken area, basically the one near Belfield and the one we call Robinson Lake, right in the center of the Sanish field. We own those 50-50 currently. And we do, in our full-blown slide presentation, show you the kind of cash flow that we think those will be putting out here by the time we get to the end of the year. So they are very attractive assets. On the other hand, we want to maintain control of those, because it's important to manage the operation of the plant with the growth of production in the field. And so as I think we show you there's -- we could add a couple hundred wells, for example, in the Sanish Field alone as a result of downspacing. And so, I don't think we'll make a decision on those plants, and in terms of their monetization and whether we should do it or shouldn't do it, until the early part of 2014, when we have a good handle on what our total gas production may rise to as a result of downspacing. So I hope that's helpful to you. But we do believe that, in round numbers, you could look at those -- that cash flow numbers in our investor presentation. I think the cap rates on those would be somewhere in the 7% to 10% range that we would realize.

The next question comes from the line of Hsulin Peng, Robert Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: So a quick follow-up question to the downspaced wells. I was just curious, do you think that EUR for your downspaced wells in Pronghorn versus a normal spaced well, would that be -- do you expect that to be a bit lower or about the same, based on the results you've seen so far?

About the same based on the results so far. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, sounds good. And then second question is regarding the new completion technique. Given that the IP rates are significantly higher, 50% plus higher, do you have any -- or what's the decline, early decline rates showing? Because I'm trying, for modeling purpose, I don't think I should be modeling 50% higher EUR necessarily.

Right. Well, at this point, what we're seeing is not a decline rate, but an incline rate, as a result of the fact that we just recently completed those wells and, basically, they've been going up as the wells clean up. But I would use -- I would go back and take a look at our regular investor presentation at that 600,000 plus BOE type curve there, and model based on that. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then last question, are you happy with where you are in terms of your acreage position in Big Tex? Should we anticipate more sale or even joint venture possibilities?

Well, we've said that we were open to both sale and joint venture. We got proposals from other companies for both. This opportunity to monetize, essentially half, little less than half of our acreage position, roughly 30,000 out of 70,000 net acres there, provided us an opportunity to, I thought, get the best of both worlds, that is we were able to retain what we think is good acreage. It's all good, and I think the buyer here is going to do well with it. But also benefit from the fact that they're going to be, as a result of where they're drilling, helping to prove up some of the acreage that we have, that is that we did retain. And then we will test the more northern parts. If you look at our Big Tex acreage, basically we split it in half between the north and the south. We kept the north, sold the south. And those people who are -- and our drilling was near the north end of the southern piece of acreage. So drilling that they will do there will help prove up some of our acreage on the north. And then we'll do some further drilling, which we're doing right now. We have 2 wells that are drilling even further north on that acreage position. And we're encouraged by the preliminary results we see from shows, et cetera, during drilling operations. So I think it's going to turn out to be good for all of us. Therefore, we have the flexibility to develop it and we'd have close to 100 wells that we could drill up there, if we elect to keep it. And if not, I think what we are doing and what our buyer to the South have done, will enhance the value of what we have left. So if you think we made a good per acre price sale on this acreage, I would expect that the next one will be at least as good if not better.

The next question comes of the line of Brad Carpenter, Wells Fargo.

Just a couple quick ones for me. First, going to Slide 16 of the presentation. I guess I would just like to gain a better understanding of this chart. You mentioned earlier in the prepared remarks that 2 of the 8 wells represented in that red line are tracking below the type curve? And I was curious, Eric, are those with less than 60 days of production history, so they naturally fall under there? Or are they further out on the curve but still tracking below that 400 MBOE.

There's 2 wells that are just slightly below the curve and we just want to be completely direct about that. So 6 of the 8 are well, well above and 2 are slightly below.

And only slightly, that's why the red line's above the black line. So the point here is that we're getting consistent results above the type curve.

Yes, the point is it's not like 1 or 2 or 3 of the 8 wells that are dragging up the whole average. It's 3/4 that are clearly above the type curve, and 2 that are tracking slightly to below to right around it.

Got you. Okay And regarding the footnote on the bottom that 4 wells are 640 and 4 are 960. If we split out those 2 subgroups, would we see a different...

Yes. You'd see that the 960 wells are all clearly above so.

Got you. And then staying in the Niobrara, you guys are planning that high density, A-B-A-B test Horsetail 1930 in October. Is that still on track? And should we expect results by the end of the year?

We're right in the process of completing completion on the first 2 wells of the A-B-A-B pilot. Just finished up actually yesterday. And so -- and we're monitoring all of that with microseismic. We have 2 more of those wells to complete, which will probably happen here within the next 1.5 weeks or so. And I think we'll have production results certainly by this time next quarter.

The next question comes from the line of Paul Grigel.

Just a quickly on the Bakken, one last question on the new completion technique. Has there been any analysis or thoughts onto how much of the improved IP rate is driven by the additional use of larger sand amounts versus the more focused entry points?

Yes. I mean we've done direct comparisons where we've used the plug and perf swell packer job, and then the plug and perf cemented liner. And we've buried sand volumes and all this sort of stuff. And we think the big factor here is not so much on the proppant volume as it is on just on the cemented liner that's causing us to get the better result. And Mark, you want to.

I'd just say, the increased entry points we're getting using the cemented liners, actually, if you look at it, we're going from 30 entry points up to 120. And we're probably not getting actually to 120, but somewhere up there. We don't know exactly where that number is. That's a 4-fold increase in the number of entry points. Our sand volumes are not going up by 4-fold. So most likely, what's happening here is we're actually getting a little less sand per entry point, but we're distributing it a whole lot better and breaking up the reservoir a lot better, which is a good thing in development mode because we're finally getting the maximum number of wells that we can into each one of our spacing units here. And so the main thing is we're breaking up more of the reservoir.

Okay. Great. And then turning to Redtail. Obviously, you guys are bringing in the new rig, hopefully over the next couple of weeks. It looks like it slipped a couple of weeks. I just wanted to touch, obviously, it's outside the floodplain, but any logistical challenges you guys have had, or what caused the slight movement in timing there?

The delay on this rig actually is a weather concern, on the other end where the rig was -- it's a brand-new rig, it's being built. They just had some delays weather-wise that caused them not to get the rig ready as quickly as they had originally forecast. As far as where we are out in Redtail, we had very -- we have none, 0, according to the flooding. The only issue we had was getting some services in there just because of muddy roads and impassable roads and that sort of stuff. But it was almost negligible, the impact on us.

Okay. And I assume, going forward, all of that in your area has been taken care of?

Correct.

Absolutely.

The next question comes from the line of Jason Wangler, Wunderlich.

Just curious down in Big Tex, obviously, with the sale. Is there any plan to go out there and drill or are you going to kind of watch what's going on around you before moving on?

Well, we have 2 wells out there right now, one that's in completion -- in the middle of completion operations, and the other one that's drilling. So the answer is, yes. And then we'll watch the results of those wells. In addition, we'll watch the results of others who are drilling near us and we'll determine at that point if we want to further develop or if we sell or if we want a joint venture, as all 3 opportunities are available to us.

Sure. And then just on the 0.5 million or so acres on 3 new resource plays, I won't try and get you to obviously go too far on that. But what's the activity level look like as you get into '14? Are we going to start looking at drilling onto these in the near term?

Well, we certainly hope so. I can just say that all 3 are exciting, primarily because they're oil, primarily because they're light sweet oil, primarily because they are typically of the flow stream. 90% -- 80% to 90%, we think will be oil or liquids. And one area might have a little bit more gas. But they're all true oil projects and they're all in great markets with good takeaway capacity. So we certainly hope so. And we're keeping some dry powder for that. But they could be additive to our production growth in 2014. And we certainly hope they will be.

Jason, we have Pete Hagist, our VP of Ops from the Permian on with us today, so I thought maybe it'd be helpful to just follow up on your first question, if that's okay?

Of course.

Maybe he can give you a little color on what other operators are doing out there. How we've changed our well design and are seeing better results and kind of some early indications on a current well that's flowing back so.

Jason, this is Peter. As we've talked about earlier, it's -- what's proved to be successful is getting more energy down into the formation, and cementing those liners and directing those fracs and then making more effective is proving successful at Bakken and I think we're seeing the same thing in the Permian Basin. So the 2 wells we're working on right now, we've done that. The lateral length is longer. Number of stages is greater. And the size of the fracs is greater. And so we have one flowing back now. And it's flowing back just very, very preliminary, just a few days. And it's coming back with good strong pressure and good rates. And similar to the Niobrara, it takes a period of time for those wells to ramp up. So that's a little bit different than the Bakken, but we're monitoring that and we're pleased with the results. So we continue to adapt, just like you see us doing in the Bakken. And I think all the operators in the Permian are doing the same thing. They're trying to find the right combination that makes these wells have their greatest potential.

The next question comes from the line of John Nelson.

You noted that your well backlog in the Niobrara was, I think, 10 wells at quarter end. Just maybe looking for some color as the rig count ramps over the next few quarters and also as potentially wells per pad might creep up from a 4 level, how should we think about that trending?

I think we're probably going to keep about that level, as we ramp up with rigs, and the reason being, our development plan, how we're planning to do this, moving forward is to drill 4 wells off of each pad. And so we're consistently -- you're going to have on any one pad, you're going to have anywhere from 1 to 3 wells sitting there waiting on completion until the rig gets done and moves onto the next one. So if we have 3 rigs out there doing that sort of drilling, we're going to have a backlog of wells sort of in that 10 plus or minus range out there. And we will be ramping up frac crews out there as we need them to keep up with our well backlog. But I don't think that's totally unusual to see that sort of number.

I agree. And then just a question on the Niobrara field trip presentation that came out intra-quarter. Thought it was really encouraging that it seemed like a number -- the number of 960 acre spacing units was higher than I would've envisioned. Is that sort of set in stone now, or how are you guys thinking about the mix of 9 -- 640 versus 960?

Well, that's a result of good land work. And so I'm going to let Dave Seery, our VP of Land, answer that question.

Yes, most all of that area, we've gone in front of the Colorado Oil & Gas Commission and then set up the spacing units. So the way the position currently looks is the way it's going to be.

Meaning predominantly 960s?

Predominantly 960s.

Predominantly being roughly 80% or how should we think about that?

That's a good number.

You can actually see them, if you look on Page 14 of the investor presentation, you can see exactly how we've got those spaced in there, where the 960s are, and where the 640s are.

Yes. And also I know that Dave's been working on some acreage trades and other deals up there too. So we hope to consolidate our acreage and even further increase the percentage of 960s.

Great. Last one for me real quick, what was the lateral length on the Horsetail well?

About 7,000 feet.

Yes, around 7,000 feet, Mark just said. It is slightly under, I think, 6,700?

Yes.

6,700 or so. So a longer lateral.

Ladies and gentlemen, with that being our last question, we'll turn the conference back over to Mr. Jim Volker, CEO. Please proceed, sir.

Thank you, Celia. In closing, I'd like to thank all the Whiting employees and directors for their contributions to a successful first 9 months and for our exciting plans for a successful fourth quarter. Eric?

Jim Volker will be presenting at the IPAA NAPE Conference in December 11, 2013. Jim Brown and Pete Hagist will be presenting at the Bank of America-Merrill Lynch Energy Conference in Miami on November 21. Mike Stevens will be presenting at the Bank of America-Merrill Lynch Leveraged Finance Conference in Orlando on December 3. Jim Brown and Pete Hagist will also be presenting at the Wells Fargo Energy Conference in New York on December 11. And Mark Williams will be presenting at the Capital One Southcoast Capital Energy Conference in New Orleans on December 12. And we look forward to seeing you at these events.

In closing, we want to thank all of you on this call for your new or continuing 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