Chord Energy Corporation (CHRD) Q2 2012 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

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 Biju Z. Perincheril - Jefferies & Company, Inc., Research Division Will Green - Stephens Inc., Research Division Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Joseph Stewart - Citigroup Inc, Research Division Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Ryan Todd - Deutsche Bank AG, Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Pearce W. Hammond - Simmons & Company International, Research Division Eli J. Kantor - Iberia Capital Partners, Research Division

Good day, ladies and gentlemen, and welcome to the Whiting Petroleum Corporation's Second Quarter 2012 Conference Call. My name is Ben, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to hand the call over to Eric Hagen, Vice President of Investor Relations. Please proceed, sir.

Thanks, Ben. Good morning, and welcome to Whiting Petroleum Corporation's Second Quarter 2012 Earnings Conference Call. On the call for Whiting this morning is the Whiting management team. During this call, we'll review our results for the second quarter of 2012 and then discuss the outlook for the remainder of the year. 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 the forward-looking statements disclaimer and discussion of non-GAAP measures on Slide 1. Please take note that our Form 10-Q for the 3 months ended June 30, 2012, is expected to be filed tomorrow. Reconciliations of non-GAAP measures we refer to and the applicable GAAP measures can be found in our earnings release and in our webcast slides. With that, I'll turn the call over to Jim Volker, Whiting's CEO.

Thanks, Eric, and good morning, everyone. Thank you for joining us. As you have seen in our 2012 Q2 release, Whiting continued its strong momentum in the second quarter, with production up 26% over the second quarter of 2011. We also replaced the 4,500 BOEs per day of production that was conveyed to the Whiting USA Trust II. Including those volumes in our second quarter production would have equated to a 33% production increase year-over-year. We continue to execute on our drilling program and have increased our guidance for the third time this year to a range of 20% to 23% production growth year-over-year. Our plan to drill 257 gross wells or 160 net wells throughout our core areas remains unchanged by high-grading our drilling fleet using pad drilling, white sand for frac-ing and sliding sleeve completions, we plan to efficiently reach our 2012 drilling goals. Now moving on to the slides. Slide 3 is a breakdown of our production by region. Our second quarter production averaged 80,700 BOEs per day, with 71% of our total production coming from our core Rocky Mountain Region and 60% from the Williston Basin. Combined with the 21% of our production from our 2 EOR projects, these assets comprise 92% of our production. Moving to Slide 4, you can see our revised 2012 CapEx budget. We have modestly increased our 2012 capital budget to $1.9 billion from $1.8 billion. Of the incremental $100 million of expenditures, $50 million is expected to be invested in recompletions and capitalized workovers, which we believe improve production. $46 million will be directed to our EOR projects, primarily for the residual oil zone at North Ward Estes, and $27 million is expected to be invested in nonoperated drilling. We also reduced our facilities budget by $23 million due to the Belfield gas plant sale. On Slide 5, we provide an overview of our Williston Basin plays. We control over 112,000 net acres in the play, which represents an increase of more than 10,500 net acres versus Q1 2012. The line on this map ties to the cross-section on the next slide. While we're on this slide, I'd like to discuss several of our recent developments in the basin. At our Missouri Breaks prospect, we acquired an additional 4,000 net undeveloped acres and now hold approximately 90,000 gross and 62,000 net acres. To date, we have drilled and completed 3 wells in the western portion of Missouri Breaks. We estimate ultimate recoveries of 300,000 to 400,000 BOEs per well. At our Big Island-Red River play, we have identified more than 50 vertical Red River prospects using 3-D seismic interpretations and porosity anomalies. All 5 vertical Red River wells drilled to date at Big Island have been successful. We are seeking and seeing very good rock quality and stable production from these wells. Estimated ultimate recoveries range from 200,000 to 300,000 BOEs per well, with an estimated completed well cost of only approximately $3.5 million. Sanish Field is the gift that keeps on giving. We recently completed our highest rate wing well. The Smith 41-12H well, which was drilled in the central portion of the field. It flowed 2,974 BOEs per day from the Middle Bakken. The well's 7,000-foot lateral was fracture stimulated in a total of 22 stages. We have also initiated pad drilling and completions at Sanish. Combined with our DWOP program, which stands for drill wells on paper, white sand and sliding sleeve completions, pad drilling is providing efficiencies for drilling and fracture stimulation that lead to an estimated savings of $2 million per well. These factors enable us to drill and complete our Williston Basin wells for approximately $7 million. Each rig now drills approximately 12 wells per year rather than 10 and allows wells to be efficiently frac-ed and placed on production sequentially, thereby minimizing equipment moves and truck traffic. Currently, 25% of our rig fleet in the Williston Basin is pad capable. We anticipate that over 50% of the fleet will be pad capable by year-end 2012. Moving to Slide 6. The cross-section on Slide 6 shows the reservoirs we target in each of our Williston Basin plays. Slides 7 and 8 give typical Sanish Field, Bakken and Three Forks production profiles. On Slide 9, our 2 typical production profiles for non-Sanish field, Bakken, Pronghorn Sand or Three Forks wells. The production profile EURs range from 350,000 to 600,000 BOEs. This reflects the range of our Lewis & Clark, Pronghorn, Hidden Bench, Tarpon and Cassandra prospect areas. Average well cost is approximately $7 million. As you can see, these wells have excellent economics at an $80 oil price. Slide 10 shows that Whiting continues to lead the pack in terms of cumulative production during the first 12 months from all Bakken and Three Forks wells drilled in North Dakota. Our 12-month average is more than 49,000 BOEs higher than the average of the next 25 operators. Slide 11 shows the infrastructure in our Sanish Field area, including our Robinson Lake Gas Plant. The Robinson Lake Gas Plant is currently processing 60 million cubic feet of gas per day, with a planned capacity of 90 million cubic feet gas per day. The plant is estimated to generate $40 million of operating cash flow in 2013, net to our 50% ownership. On Slide 12, we provide the same information for our Pronghorn field area, and our Belfield gas plant. The Belfield gas plant is currently processing 13 million cubic feet of gas per day, we an inlet compression in place to process 24 million cubic feet per day. We estimate that plant will generate $20 million of cash flow in 2013, net to our 50% ownership. As most of you are aware, we sold the 50% interest in our Belfield gas plant, gathering lines, both oil and gas and related facilities to Bitter Creek Pipelines, a subsidiary of MDU Resources. Under the agreement, Bitter Creek paid 60% of the capital cost for the project to date and will pay 60% of certain future capital cost in order to earn their 50% ownership. A $66.2 million payment was made to Whiting at closing capital cost to date. Fidelity Exploration & Production Company, also a subsidiary of MDU, has dedicated gas production from its development activity in the area for the gas plant. And we are pleased to have MDU as a partner. Whiting will continue to operate the facilities. In summary, we continue to execute on our 2012 drilling program, and we're on track to meet our 2012 guidance. In addition, we're also experiencing growing success in our emerging plays outside of the Bakken. To present our exploration results outside of the Bakken and our 2 EOR projects, I'll now introduce Jim Brown, Whiting's Chief Operating Officer.

Let's start on Slide 13 with our Big Tex prospect. Highlighting the recent drilling results was the completion of the May 2501. This vertical well was completed, flowing 323 BOE per day from the upper Wolfcamp formation. Currently, we are drilling a horizontal offset to the May well, which should help us determine whether to go horizontal or vertical in that area. As indicated on this map, this well was drilled on the west side of the prospect approximately 1 mile northeast of the company's Stewart 101 well. The Stewart well, also a vertical flowed 232 BOE per day from the Wolfcamp. On the north side of the prospect, we fracture stimulated the Legear 1102H, a horizontal Wolfcamp test. This well is currently flowing back oil and load water, up casing as it cleans up. Slide 14 shows our Redtail prospect in Weld County, Colorado, where we target the Niobrara formation. In the second quarter, we added approximately 4,500 net acres to our acreage position at Redtail, bringing our total acreage to about 107,000 gross and 79,000 net acres in the play. We resumed drilling operations at Redtail in June 2012. We currently have one well waiting on completion and one well drilling. Now I'd like to turn to our EOR projects, the Postle and North Ward Estes fields. Combined, they represent 39% of Whiting's total proved reserves and 21% of our current production. Second quarter production from the Postle and North Ward Estes totaled 16,780 BOE per day. On Slide 16, you can see the production forecast from the proved, probable and possible reserves at North Ward Estes. During the second quarter, the field averaged 8,630 BOE per day. This average rate was up 6% from the 8,125 BOE average daily rate in the second quarter of 2011. One of the largest phases at North Ward Estes, Phase 3B, is pressuring up with CO2, and we anticipate a production response by the first quarter of 2013. Now I'd like to turn the call over to Mike Stevens, our CFO, to discuss our financial results in the second quarter of 2012.

Our second quarter 2012 adjusted net income available to common shareholders was $86.8 million or $0.73 per diluted share. Our discretionary cash flow in the second quarter totaled $310.5 million. This compared to second quarter 2011 adjusted net income available to common shareholders of $120.3 million or $1.02 per diluted share and discretionary cash flow of $313.3 million. Compared to the second quarter of 2011, our discretionary cash flow was essentially flat as the increase in production offset the decrease in oil prices. On Slides #25 and 26, we show reconciliations to these non-GAAP measures. Our guidance for the third quarter and full year 2012 was detailed on Slide 18. The main change is that we have increased our production guidance to account for a strong first half. We now forecast third quarter production at a midpoint of approximately 82,600 BOEs per day. We've also adjusted our cash cost downward to better reflect our lower actual costs in the second quarter. Historically, we included the price of NGLs in our oil differentials and our guidance. In the second quarter, NGLs represented 11.2% of our total liquids production and sold for $37.45 per BOE or approximately 47% of our realized oil price. Going forward, we will break out our NGL production from our crude oil production along with the average price of each. We will continue to provide guidance for crude oil and natural gas differentials. On Slide 19, I'd like to point out that because our costs were approximately $2 per BOE lower than in Q1, our EBITDA margin remains stable at 65% despite a $12 reduction in our average realized price per BOE. On Slide 20, you can see that we continue to maintain a strong balance sheet, with total long-term debt of $1.42 billion and a total debt-to-total capitalization ratio of 30.3%. Slide 21 shows that our 2 senior subnotes are trading above par. It also shows that we're well within all the covenants of our credit agreement and our bond indentures. You'll see our current hedge positions and fixed price contracts on slides 22 and 23. We recently added 2 costless collars for our crude oil production that are effective from July 1 through December 31, 2012. The first one covers 75,000 barrels per month, with a floor of $80 and a ceiling of $96.45. The second one is for 100,000 barrels per month, with a floor of $80 and a ceiling of $96.70. I'll turn the call back over to Jim Volker.

Thanks, Mike. Ladies and gentlemen, in summary, Whiting is a high-margin oil company with an EBITDA margin of 65%, and our production is forecast to grow 20% to 23% in 2012. As I've previously stated, we're in a strong position by having over 712,000 net acres in the Williston Basin. At current oil prices, our discretionary cash flow, recent WHZ Trust unit sale and Belfield Plant sale will substantially fund our 2012 capital budget of $1.9 billion. Further, we estimate we have 10 years of future drilling inventory in our Williston Basin plays alone. Outside of the Williston, we're experiencing very encouraging results in the Permian Wolfcamp and DJ-Niobrara plays, and we're building significant acreage positions in new exciting areas. Operator, please open up the conference call for questions.

[Operator Instructions] Jim, your first question comes from the line of Mr. John Freeman from Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: First question regarding the well cost savings of about $2 million a well that's driven the complete well costs down about $7 million a well outside of Sanish, I'm trying to isolate just the difference in the completed well cost currently for well completed via pad drilling versus a stand-alone.

About $500,000. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And next for me, this year you all sort of stepped up the number of workover rigs that you all use relative to drilling rigs to somewhere around 1.5 workover rigs for every drilling rig this year to sort of better manage your backlog. And I'm trying to get a sense if now, given the strategy you've made on the drilling side where you're now basically drilling 12 wells per year per rig versus 10 previously, if that will have any impact on the number of workover rigs you're going to need?

Yes, John, we are in the process right now of working on additional contracts for additional service units up in the Williston Basin. We're currently looking for 6 additional rigs. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And can you give me roughly what the current backlog is on your uncompleted and shut-in wells at the moment?

Yes, our -- just the wells waiting on completion were in the range of about 28 today.

There really hasn't been a very significant increase in that. We're basically keeping up with the workovers that we had planned, and so we have that under control. And I think as we go forward in the year, you'll see us drive that down. John Freeman - Raymond James & Associates, Inc., Research Division: Great. And then last question for me and I'll turn it to somebody else. The -- it looks like most of the acres you all added during the quarter was on the Montana side. Obviously, you all continue to seem encouraged by what you're seeing over there. I thought we might get a Starbuck well this quarter. Is there any update there?

No, there's no update on Starbuck. I'll comment on it for you. Some of you who have, I'm going to say, been around in the business for a long time will recognize that Starbuck is essentially in the traditional Red River fairway. And we are excited by the 3-D that we're shooting over Starbuck. It holds the potential, as you'll hear us talk about and as we've already mentioned, but as I imagine we'll expand on here with respect to questions about the Red River. It holds the potential as well as other -- our prospect areas like Big Island, to be a very significant both traditional Red River producer as well as hold potential for the traditional Bakken zones. So what we're doing at Starbuck right now is shooting that 3-D and then we'll define the number of Red River opportunities that we have there, very similar I think to what you've seen us do at Big Island.

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

Can you talk a little bit about -- you guys give us a lot more detail like Robinson, which I know you've indicated about the potential for monetization in the past, is that a sign there? And then can you just talk about where you're at in other monetization within the portfolio?

I think I can do that for you by simply saying that we, of course, have an extensive inventory that we've derisked across all of our plays. And we've received strong indications of interest in participation in our newer Williston Basin, Permian and [indiscernible] basin prospects. And based on offers that we may receive and the continued results of our drilling, we may or may not elect to take partners in on some of those prospect areas. And in the future, we may also consider trust structures for not only some of our mature producing properties, but also our midstream assets as well. We don't have anything to announce for that right now, Dave, but I think you need only look at the cash flow that we've detailed for you here about our Robinson Lake plant and apply what I would say is the traditional sort of MLP multiples to that and you'll get an idea of the value that's probably not fully reflected in our stock price.

Okay. Yes, I understand you can't say a whole lot at this point. Just back to Missouri Breaks -- and I apologize if you mentioned this because I missed the first couple of minutes of the call. But can you just talk about where your well -- your well results have been on the western side. Can you just talk about what the prospects look on the eastern side and just give us a little bit more color on the entire play?

Well, I'll start out and then I'll turn it over to Mark. Basically, we've been very happy with the results we have seen on the west side, and that's essentially as we've refined our completion techniques. We've seen the IPs grow there up to around 700 BOEs a day, and they continue to improve as we come up with the correct cocktail to treat that zone during our frac. And basically, it's simply adding a bit more acid to the frac job. And we've seen continued increases, and we're very happy. And I would say we think that 300,000 to 400,000 BOE range that we gave for EURs will, hopefully, continue to increase. Then as we move further to the east, we definitely see improving reservoir out there as indicated, not only by our mapping, but also the results of other people's wells. And, Mark, would you like to comment a little bit further on the quality of that reservoir?

Yes. Overall, we're in a part of the Middle Bakken there that is -- that's been very [indiscernible]. It's the upper part of what we call the C Bench. That's why we lease there Missouri Break (sic) [Breaks]. But what we've seen on the Montana side is that the lithology or composition of that reservoir is slightly different just like it is in all of the other areas that we drill. Everywhere, it's slightly different. So we, over the first 3 or 4 wells here, have been trying to get, as Jim said, just the right way to treat that in our fracture stimulation treatments. In this particular instance, there's a little bit more calcite, so it seems to be working for us. And what clearly is working for us is we're putting a little bit of acetic acid and we lead in -- on each of the frac stages, and we're experimenting still with changing the pH of the frac fluids there. And so that's clearly working, and so I think Jim's really summarized the rest of it.

Your next question comes from the line of Scott Hanold from RBC Capital Markets.

So you mentioned a couple of areas that you have got some Red River potential down in Big Island, and obviously, you've used some 3-D, take a look forward over -- a little bit further to the west. How perspective across all your acreage is Red River? And I guess what effectively makes an area more prospective than others? Is it something geologically that happens that -- specific areas that make it look a little better?

Just make a comment about the Red River in general. Before the Bakken play, the Red River was 1 of the 2 most prolific plays in the basin, the other one being the Mission Canyon. But there's a fairway of production that runs through the Montana side primarily, in Roosevelt and Richland County. And if you look at all the drilling that's happened out there over the years, it's about 130 million barrels of oil have been produced from that fairway. Both our Starbuck prospect and our Missouri Breaks prospect are right in the middle of that fairway. And so the traditional way that people have approached exploration of the Red River is through 3-D seismic. We've been very successful over the years. If you remember Whiting back several years ago, we had 3-D driven program in the central part of the basin, back when gas prices were a little bit higher. We're essentially applying that same technology to all of our areas that we think are perspective in the Red River. But both Starbuck and Missouri Break are both right in the middle of that, as is Big Island. And you've seen the results that we've got there at Big Island. So we feel particularly good about those 3 areas with regard to the Red River potential.

And the fact that they're definitely in the oil window.

Okay. And, I mean, how does the rate of return, do you think, compare to like an unconventional Bakken well or a Permian well or Niobrara? Anything else you're doing? I mean where does it stack up in your inventory?

Well, the key there is that most of the Red River wells, essentially the inventory that we mentioned in the call here earlier, can be drilled as just what I call a plain-Jane well. They're vertical wells, they don't require stimulation, we can drill and complete those for somewhere in the neighborhood of $3 million to $3.5 million. I think $3.5 million is probably the upper limit of what we could expect there. So it really has a profound effect on the economics out there, especially if you think you can do between 200 and between 300 MBOEs per well. Those numbers are very attractive to us. But the other side of that is they're not hyperbolic. In other words, they don't decline very, very rapidly over the course of the first year. They tend to stabilize early on, and so you don't get quite as much flush production. But ROIs are very attractive, and so we're all over that.

Yes, we would normally think about that as being somewhere in the range of 5:1 on your money kind of potential, roughly around $15 million, $16 million of today's oil prices of future net for $3.5 million well cost.

Okay. Okay. And then my follow-up question, you were drilling the Deep Bench (sic) [Hidden Bench] well, the Chitwood well, I think it was in the McKenzie County. What's the update on that well? What did you find when you went down there and cored it?

So we -- the first thing I'd say there about Hidden Bench is that's turned out to be the one of the very best projects in the company. We're experiencing ROI -- or, excuse me, IPs there of over 2,000 barrels a day. We have -- we are just in the early phases of trying to delineate the Three Forks opportunity, and the Chitwood was the first of those wells. And so as we go forward, there's 2 more wells that we're going to be drilling yet this year in the Three Forks. But so far, we're not prepared to release the results of any of our Three Forks wells. But we're most excited about what we're seeing in the Middle Bakken. And as you are probably aware, that area, we believe, and other operators have been able to demonstrate this as well, can support up to 4 wells in the Middle Bakken there. And that's our -- that's going to be our real focus going forward. As I've mentioned, we're going to continue to work on the Three Forks there through the rest of the year. But we really like what we see on the Bakken there.

Yes, I mean, the Bakken is pretty good there. And I guess back to sort of the Three Forks, when you say you're going to drill 2 more in Three Forks, are you specifically saying just, what, the more the upper additional Three Forks? Or are you looking at some of the deeper benches, or do you think you're [indiscernible] the Three Forks pay?

We are coring to look at the lower part of the Three Forks. The upper part, being it right immediately adjacent to the lower Bakken Shale, is getting the bulk of that charge. It does look like there's some making it down to the second bench. Jury is still out on that. We'll let some of the other offset operators continue to work on that, but right now, we think that certainly the Middle Bakken, we've already demonstrated that. And we think the upper Three Forks is going to work as well.

If I could just add, Scott, it's Eric, typically, we drill a stiletto well down through all the perspective zones, in this case, to include the lower Bench, and we can come back and flood back and complete in the most perspective zone, which is typically the Middle Bakken. So -- but as Marc said, it's just inconclusive so far on the lower Bench.

The next question comes from the line of Biju Perincheril from Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: So in the Lewis & Clark area, so outside of what you call Pronghorn, can you talk about are you still running on 1 rig there? And can you give us any color on some of your recent exploration results there?

We've got 2 rigs working there right now, and we have -- the real focus for us here lately has been to define the extremities of that acreage position. As you know, it's a very large acreage position. It covers parts of 3 counties. And so we had previously been drilling sort of what -- in what I call the fairway in there along where the Bicentennial Field is. Recently, we've gotten a very good completion up on the northeast side, and we've gotten another one out on the west side. So we're continuing to trying to find that. The challenge for us is the size of our acreage position there. We've got a lot of acreage -- I'll be upfront about it, some of that is in federal lands, and it takes a while to get wells permitted there. So the combination of those 2 factors -- it's not moving forward as rapidly as some of the others are. It's just very big and a few complicating factors for getting wells permitted. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So how much of that, for a lot of you, feel at this point you have delineated? And are ready to move into a development phase in any of those subareas?

We are in the development phase in the central part, and we're seeing pretty good results there. This is in that area where the Bicentennial Field was. But we see wells come on and flatten very rapidly in there and at very good rates. So I would say that it's a combination. That central area, where you've seen us drilling in the last 2 years is a development program. We're now defining the extremities up in -- along, particularly along, the northeast side of the field. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then in the North Ward Estes, the residual oil zone project, what's the latest? If you use -- have you started CO2 injection there? And when do we expect to see initial results?

Well, the answer is, yes, we have CO2 going in the ground. And we expect to see some results in the first part of 2013. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then one last question, the Sanish Field, what's the latest count of these -- of the wing wells remaining to drill?

That's a good question. 50. We have 70. We've got -- I'm going to -- I'm just going to take a guess. We have 70 to go -- to drill in there. I'm thinking we've drilled something on the range of something in 20, so I'm going to say we have 50 of those left to go, something on that order.

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

I wonder if we could touch on the Pronghorn, the first Pronghorn pad you guys drilled. Could you guys maybe give me an idea of where that pad came in cost wise?

Yes, we drilled -- drilling the first 2 wells, we drilled the 2 wells for $8.8 million. That's both wells. So that's $4.4 million per well. And so our -- what we're thinking is we should be able to get the fracs and everything, the facilities, everything done for about $2 million a copy. So we're thinking those wells are going to be in the range of $6.5 million, plus or minus, somewhere in there.

Great. And then jumping over to NGLs, appreciate the extra color this quarter on that. Obviously, some weakness there like the rest of the industry. Could you guys maybe characterize what the typical NGL barrel looks like for you guys? And is most of that production from the Williston?

Yes, most of that production is from the Williston. And let me tell you, we have the ability to kind of change what our NGL barrel looks like, okay? At Robinson Lake, what are we able to ship down the Alliance Pipeline -- it used to be Prairie Rose, but Alliance has bought that. We have to take the C5 plus cut out of that. We take that out of our gas. We stabilize that and we either sell that as crude or we sell it as a diluent that's being -- somebody is trucking it up to Canada. But -- so the C-5 cut plus we get at Robinson Lake is actually getting something close to a crude oil price. That's about $500 to $700, or $700 -- 500 to 700 barrels a day that we're getting there. On the remainder of the gas product at Robinson Lake, we can either ship that entire stream through Alliance, down to the Aux Sable Plant, where they have the fractionation to recover ethane and then all other constituents. So we have that ability. The least we will ever get for our product going down Alliance is the BTU value of that product. Otherwise, I'm thinking we're looking at something that's on the range of about 20% of it is ethane. I'm looking at Chuck, our marketing guy, to get a nod on this one. And then the butane and propane, we can sell into the local market in North Dakota because we have fractionation capability at Robinson Lake, and so it's just whatever those local markets are there. Or we can ship it down to Chicago, sell it as a constituent down in that market. Or like I said, the least that we can get is -- or the best we can get, depending on the market, is just what the BTU value of that is. So that's what -- we have kind of the ultimate flexibility there. So that's why it's difficult for me to tell you what a specific NGL barrel looks like right now.

Sure, and I appreciate that. Given the flexibility you have, any commentary on pricing for third quarter or full year?

We don't think -- for the year as a whole or at least in the second half, we doubt that it'll drop below 50% of the price of crude.

Your next question comes from the line of Mike Scialla from Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I wanted to ask about North Ward Estes. I know your volumes there were up 6% year-over-year, but they've been kind of flat in the last 2 quarters. And you mentioned in your release that you're working on a new area there, the I guess Phase 3B, which is one of the bigger ones in the field. As you look forward, do you expect any sequential growth for the second half of the year? Or are you going to have to wait until that 3B area starts to respond some time next year?

We're probably going to have wait for 3B to respond in what's happening there. As we're pressuring up, that phase is producing -- or is proceeding a little slower than the other ones in North Ward Estes, which all our guys down in Midland are telling us is a good thing. That we're saying the richness in 3B is probably a little higher. We're probably not seeing the response as quick as we did in the other areas. So we have high hopes for this. And we're already starting to see some limited response out of 3B, but we'll probably see the big kick later in the year or perhaps into third -- or excuse me, first quarter of '13. And we remain very pleased and very optimistic about that one. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: So that delay, I guess, is an indication of it's taking more CO2 and the read through is that it's more -- the process may be better than the [indiscernible]?

That's exactly right, Mike, better reservoir. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then on Postle. You touched, Jim, about you've got candidates for trust. I think you've mentioned Postle might be one in the future. Any updates in terms of what the timing on that might be and the size and what you might do with the proceeds?

Really, nothing at this point, Mike. I hope that the message that comes across loud and clear here is that to date, and as a result of the moves that we've already made, as well as our flexibility with respect to the efficiencies of both the rig fleets and the frac fleets and the workover rig fleets that we're using, we think that we can stay at or very close to our discretionary cash flow for the next 2 years, '13 and '14, continue to grow at somewhere like our growth rate this year and not have to use the capital markets or sell some assets other than perhaps we might, as I've previously stated, consider some of the interest that's been shown in our -- in joint venturing on some of our properties. I am going to say -- and that decision will, of course, be subject to what we see on oil price. So I think we've got the ultimate flexibility here. And if there's anything that I'd like to come across in this call is that we're very pleased with the results across our prospect base. And as a result of the efficiencies that our drilling department and our operations department have been able to execute for us, we really see the ability to grow without having to take too many what I would say capital markets or sale or joint venture moves. On the other hand, we have the flexibility both as a result of our rig fleet and as a result, for example, of interest in doing joint ventures with us to stay within discretionary cash flow even if we see a further decline in oil prices. And we really don't believe that, that will have too much effect even if we saw, say, a $10 drop or even further $15 drop in the price of oil, too much effect on our rate of growth. So we're trying to maintain that flexibility to grow and stay right at or around our discretionary cash flow. We think that, that's the right thing to be doing so that we don't face what I would call the fiscal cliff that is out there if you don't do that. So that's our objective, and we seem to be able to have accomplished that here in Q2. And we're refining exactly what we're doing in order to be able to do that through the remainder of the year and into 2013. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I appreciate that. I guess -- well, if I'm hearing you right, that there's really no need to do something especially as big as Postle. If you did, would you even have, given what you see in terms of the, say, over the next year or 1.5 years, would you even have the ability to put those proceeds to work if you were to do something of that size?

It's Eric, I'll just follow up. I think Jim is very clear about it. But basically what we're saying is that we have the flexibility to do asset sales and to replicate the strategy we've enacted this year. We certainly have opportunity, opportunities emerging in our asset base, the Niobrara, Big Tex and Missouri Breaks types of things to accelerate. But it's all a combination of oil price, service costs and, as Jim indicated, maintaining within that discretionary cash flow. And if we do exceed that from time-to-time, in the past, we've always done trust-type transactions and then it's not dilutive to shareholders to plug that gap.

And we think you've seen the benefit, as Mike pointed out here earlier, as the -- that's coming from both of the reduction in LOE per BOE, as a result of some of those moves that we've made in the past. So if I can, to be clear, no, we don't have the need or the requirement to do any of those. Yes, we have the flexibility to do them. And we think we can continue to grow at a pretty attractive rate as we're growing now without doing those. So that's our objective. And I think we've done a good job executing on that plan so far this year. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Got you, okay. And then I wanted to ask on Big Tex. I think you have viewed that as maybe a combination of vertical and horizontal, kind of vertical on the west, horizontal on the east. Those thoughts changed at all now with the results you've seen? And do you have EUR estimates for any of those wells that you've drilled so far?

There's no change in that plan. And you want to comment on the EURs? It's kind of up your alley.

I think that what -- with the way -- the direction we see this going is with the vertical wells, especially the -- we see results consistent with what other operators have experienced out there, the 200 to 300 MBOE per well on the EUR side, and that's fairly attractive when you look at drilling costs that are in the $3.5 million range. So -- and we've got a lot of locations that we could do there vertically. In fact, we could probably do the entire thing vertically. The jury is still a little bit out on the horizontal well. Nobody, including ourselves, has enough production history to be able to establish an EUR for the horizontal wells. And we're -- so that's what we're working on right now. So it's a little early in the horizontal play, but I think the vertical plays are pretty well established by ourselves and others out there. So that's what I -- that where I think we're going to come in at. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: How is the production held up on the Big Tex North, at the 301H well that you announced a while back?

I think the last time I looked at it, it was doing about 135 to 150 barrels a day, holding up real good.

The next question comes from the line of Neal Dingmann from SunTrust.

Say, Jim, I just wanted to know on your guidance that's out there, kind of a question around -- you mentioned about the -- well costs have come down because of efficiencies. I was wondering around your CapEx out there, are you just assuming sort of flat well cost just on the service costs going forward? And if so, are you seeing any of the service costs come down?

Yes, our assumptions are for flat, and we do continue to see some downward pressure on pricing. But we haven't yet -- we haven't built that into our CapEx yet.

Okay. And then also part of that CapEx, I assume now that you've let a couple of rigs go. Does that assume the assumption that you'll have those rigs then running, Jim, for the remainder of the year?

Yes. The current rig count will continue to run for the rest of the year. The 3 that we've notified were on the lower end of efficiency. And so it's been our plan to release them for some period of time and essentially get the same number of wells drilled with fewer rigs.

Okay. And then just lastly, it's looks like part of the bump up in CapEx, just a little bit of it was from the EURs or from the Postle and North Ward, on those going after the primary residential -- residual oil. Was wondering now, once you kind of progress on that, will it be additional capital, in fact, maybe even this year required on that, or are you pretty well set on what your plan is?

No, that's going to carry us through this year, so we don't foresee any additional capital being required on the [indiscernible] project in 2012.

The next question comes from the line of Joe Stewart from Citi.

My first question is for you, Jim Volker. Just thinking about the stock's underperformance here today, I wanted to ask you what you think should be more important to investors, is it Whiting's ability to forecast oil and NGL differentials, or to hit or beat your production targets?

The latter.

Yes, yes, me too. Okay. So all joking aside, could you discuss how the wells drilled so far in Pronghorn during 2012 are performing relative to the 600,000 BOE-type curve?

Yes, at Pronghorn, our recent wells are holding up pretty well. I think our average out there for the last 6 wells is about...

1,700...

1,700 BOEs per...

1,700 BOE on an IP. Yes, we're seeing great results at Pronghorn. And then the pad drilling we're seeing on there as we get both -- the pads we've done recently have had 2 wells on them as we get these production bumps with 2 wells per pad coming online. We're very pleased with what we're seeing out there.

Got it. Okay. And, Jim, do you have the 30-day rates for several of those wells and the 6 wells that you mentioned?

Yes, they're very similar to the 2011 results. We've put that in our group presentation in the past. I can give those to you. But they're very similar to the 2011 Bakken results as well. I mean, but that would be towards the higher end of our EUR range, so around that 1,700 BOE range.

Right. And then moving down to the Permian, I know it's obviously early, but could you talk about what you've learned so far from the Legear well?

What we've learned so far is that we think it worked going horizontal. We're encouraged by the flow rates that we've been seeing up casing, which is good. And now we're in the process of putting it on pump.

Okay. And, Jim, do you care to mention what kind of flow rates you've seen while it's cleaning up?

We've seen peak rates around 500 BOEs a day.

Your next question comes from the line of Brian Lively from Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 follow-up questions. One, if you guys could talk a little bit about the return proposition in the residual oil zone. I know the Bakken, you guys have talked about, kind of in the 70% range from a rate of return standpoint. But how does the residual oil zone compete economically from a return perspective? And then how does that factor into your decision to allocate more capital?

This is Eric Hagen. I'll just preface that. When you look at portfolio management on your assets, you have to think of -- I mean, obviously drilling a Bakken well has a higher rate of return, but we're also looking at having the right composition of assets, so that we have the right kind of base decline rates that our portfolio is sustainable and blending those the right way. So I don't think you can just say -- and they're entirely different projects. I mean, one is we have the payout in a year, the other one is a multiyear project. So I'm not even certain that's real valid comparison. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, that's a good answer. So you guys then would -- I mean, that means you guys -- when you think long term, you want to keep, I guess, the CO2 floods within the portfolio than to manage the base declines?

But also it creates significant NPV. I mean, they're very large NPV projects. They add significant NPV to our portfolio over time, and they're very sustainable production rates and very large reserve adds. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And so you're saying that maybe the return is lower than a Bakken well, but the NPV is much greater because...

Yes, I don't think anyone in the industry would argue that the returns on EOR are going to be the Bakken well. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then on the Lower Bench, Three Forks well, just -- I guess I didn't -- maybe I was confused on the answer. You guys -- have you all completed the Chitwood well? And then just wondering, like, was it a special well, or it wasn't? Or are you just not trying -- want to talk about the Lower Bench at this point?

Well, we prefer not to talk about it. But to try to add some color to it for you, we didn't like what we saw there as well as what like in the Upper Three Forks and, of course, what we know is there in the Middle Bakken. So what we've elected to do is test it in a couple of other areas and core it in that rather large acreage position and see how it goes elsewhere on our acreage position. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. So it's still too early to write off the Lower Bench or anything like that. It's just you guys are just thinking about just kind of one well.

Correct.

Your next question comes from the line of Ryan Todd from Deutsche Bank.

Just had a couple quick questions. The Sanish field continues to show very strong performance. But some of the other areas, Hidden Bench, Pronghorn, in the second quarter, and I realize there's a lot of noise quarter-to-quarter, were maybe a little bit lighter relative with our expectations. Is that a result of more pad drilling, or is it just timing issues, or is there anything else going on there in the portfolio?

Well, I wouldn't -- first of all, I wouldn't draw those conclusions because that's not the case. We've been very pleased with the results that we've seen in the areas outside of Sanish, and frankly they've continued to improve when we look at quarter-over-quarter, month-over-month production versus our expected decline rates. So I can only say that I hope that what you could come away from this call with is that everything is working across our prospect base. It's working to the degree or above the degree that we anticipated in each of our prospect areas. And what Sanish, I'm going to say was and is for us, we think Pronghorn will be every bit as good. I just like to pause for a second and say that one thing I'd like the market to understand is that, that Pronghorn and the Pronghorn Sand is a brand-new producing zone that was anticipated, really, by no one else other than Whiting. It's named the Pronghorn Sand because of our prospect name. And one of our explorationists who's so instrumental in finding that new area for us has spoken at a number of AAPG conferences around the country, and frankly, he's been honored for that brand-new discovery. So I would harken back to the science that we've done in order to find what we believe are some of the best portions of the Bakken, Three Forks, Pronghorn Sand hydrocarbon system across the Williston Basin. And we're executing well on each one of those. They vary slightly from area to area, but they're all highly economic at $80, and frankly, at $70. So from time to time, I think that as we released results, people have tended to try to say that one area is significantly better than another or that we didn't see as good a results as we anticipated. Frankly, the results that we've seen are getting better in each one of our areas. So I can only underscore that we're executing well in each one of our prospect areas. They're performing at or above our expectations. And we don't see any of them that we think are falling below our expectations.

If I could just add some color to just your comments by area. So in the Hidden Bench area, we have a number of completions planned for the second half of the year. There's -- in that area in Tarpon, we have some federal permits. And so we'll see some of those in the second half of the year. And in Pronghorn, we had a lot of completions at year-end into the first quarter. And we've been shifting towards pads, as Jim Brown alluded to, and so we should see that pick up as well. So I think to try to micro analyze the quarterly -- quarter-over-quarter results, it's going to be really difficult for you to forecast it at that level for those reasons, so.

The other thing -- just to add specifics to the 2 that you've mentioned. At Hidden Bench, out of the first 12 wells, there are averages over 2,000 BOEs per day. It's 2,035 for those initial wells. At Pronghorn, as Jim Brown just mentioned, we're right around 1,700 barrels a day for the wells this year. So both of those are performing very well, among the best in the basin. And I just think it's important to clear that up.

Yes, and I didn't -- that's good. I appreciate that. I mean, I think the Pronghorn has generally exceeded all of our expectations over the course of the year so far. On Sanish, one question, one of your peers next door, Parshall, has started to explore some water floods there. Can you think -- you obviously have a lot more drilling left in Sanish than they have at Parshall. But as you think about the next leg down the line at Sanish, what are some of the things that you have and tapped on the line?

Well, if you want us to talk about the potential there for secondary or tertiary recovery, I can only tell you that we've done reservoir studies on that. I think everyone is aware that the Middle Bakken that we have is thicker than what exists over in the Parshall field. So we expect that if we can come up with a good way to get secondary or tertiary recovery, it'll be larger at Sanish than it is at Bakken because the zone is thicker and has much better reservoir characteristics. And having said that, the -- we're studying whether it would -- should be water or gas of one sort or another, everything from CO2 to nitrogen or even, for example, injecting natural gas into the reservoir. But that's down the road aways. However, it is a big prize. Every 1% is worth another 15 -- in the 20 million barrels. So it is a big prize, and it's out there in the future for us. We're well aware of it, and we're doing the right thing, that is we're developing the reservoir as we drill it out over the next couple of years in a manner that will lend itself to good secondary recovery if we'd like to go that way.

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

Just had one quick question as far as the hedging. Obviously, they roll off a bit after this year. What is the thought as we go into '13 and even in the '14 as far as hedging? I know you added a couple for the rest of this year, just this month?

The thought is that by the time we get out there to the end of the fourth quarter, we should be close to 50% hedged for 2013.

Your next question comes from the line of Pearce Hammond from Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: Jim, can you on the comment current M&A environment in the Bakken and how Whiting might able to participate in the continued consolidation in the basin?

Well, we have been. Some of the acreage acquisitions that we have been doing out there are from smaller operators. They tend to be private companies, not public companies. And it's been working pretty well for us, in part, because those particular sellers haven't had the scope and scale necessary to really mount a significant program in the basin. And while we're driving costs down, should they try to drill it themselves, why, of course, they'd be starting with very high costs. Pearce W. Hammond - Simmons & Company International, Research Division: Do you see a lot of foreign interest in the basin?

Well, obviously Statoil has come in. We do believe that there are other foreign companies out there thinking actively about it. Yes, a couple of contacted us in various capacities in order to try to gain what I would call a foothold and what a couple of them have described as, at least in their opinion, the best oil play in the United States. So while I can't say that we want or need them as a partner, they do remain active, and they do continue to try to gain a foothold there. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And just one follow-up, and I know it's obviously very hard to forecast oil price differentials, but do you expect some of the volatility we've experienced in the first half of the year as it relates to Bakken oil differentials? Do you think that should moderate some in the second half of the year due to some infrastructure improvements?

Well, we think there are a number of reasons for that. And I'll give you what we think is our -- have been our total NYMEX to lease price differentials. July was $16. August was $11. And as best as we can tell, based upon the prices quoted yesterday, the 25th, it's going to come down to about $6.50 for September.

Your next question comes from the line of Eli Kantor from Iberia Capital.

Just wanted to go back to the significant quarter-over-quarter uptick in volumes at Sanish real quick. Can you just tell us how should we be thinking about field level production there for the balance of '12 and in '13?

Well, we think -- we continue to think that as a result of the fact that we've got about 9 rigs working there and we'll continue to have that in the area for the foreseeable future, you'll see what I would call a gentle rise to then a flattening by the time we get out to 2014 perhaps. Let me correct myself. We got about 7 rigs there right now and 14 service rigs. And we're using those, as was mentioned earlier, in evermore efficient manner, so that essentially we're drilling more wells with the same number of rigs. And we're getting excellent response when we do these workovers that are part of the CapEx increase that we've mentioned this quarter. And as a consequence, we expect to continue to see a general rise in production until it finally peaks some time out there, perhaps 2014, 2015. We'll have to wait and see.

Okay, that's helpful. The increase in non-op CapEx, which one of your partners is ramping activity? And are you seeing increases in AFEs from your partners?

No, the AFEs from our partners generally range from around $8.5 million to $11 million, so they're higher than our costs. However, they typically tend to be in some reasonably good areas, so we've elected to participate, I will say that, in almost all of the wells that have been proposed by our partners. I can't say that there's any one that's really ramping up. I am looking around the room here and everyone is nodding their head up and down. So I can't say there's anybody who's really doing a major ramp-up that would affect acreage where we're partners with them. I would say the one thing that I've seen is that I do think that their well costs have been somewhat stubborn in terms of them trying to get their well costs down. And I think until they change from generally plug and perf to sliding sleeves and until the they have all the services available to them that we have available to us, that includes the frac fleets and the workover rigs, and until they sort of get comfortable with using white sand, their costs are going to be $2 million higher than ours.

Can you remind us again who are your most significant partners in the Bakken by rig count?

You mean just the companies we're contracting rigs from?

Who's operating the wells that you're participating in on a non-op basis?

We have several of the operators -- but if you look at that slide that we showed earlier that have the other operators in the basins, we see AFEs from almost all them. The ones that are most significant for Whiting would be Fidelity, Hess, probably the 2 top ones. And then we still see a few EOG, AFEs and Brigham AFEs. And then beyond that, it's kind of a mix.

We see a few from Oasis.

Continental is also in there.

And Continental. It's virtually everybody in what I would call the -- about the top 14 on our list there on Page 10, Slide 10.

Pretty evenly distributed among those names.

Are there any 1 or 2 that -- you're saying that the activity, non-op activity, is kind of spread evenly among those few basin group?

Can we move on from that question? I think we've answered it pretty clearly. We -- our non-op is distributed among those top 10 or 12 operators in the slide, pretty evenly. And we're not going to point any one out for having exceptionally high costs.

Okay. That's helpful. Last question for me. Trying to understand the new CapEx guidance and specifically how the line item well work, miscellaneous costs and other relates to previous guidance given for the Northern Rockies. My understanding is that the $50 million of well work, miscellaneous costs and other spend at least partially represents Bakken workovers that were previously included within the Northern Rockies CapEx guidance. If that's the case, on the face of it, while Northern Rockies CapEx is flat quarter-over-quarter at $851 million, it looks like when you include the workovers that have been broken out, Northern Rockies CapEx guidance has actually gone up. And I'm just trying to get a little clarity on that and figure out all the moving parts there.

Well, there are a lot of moving parts in that number. That's why we say miscellaneous, others. Some of it spans across all our different categories, the most -- the highest area is the Northern Rockies. That's true. It's also true that there was a component of that previously in the Northern Rockies area. So we've broken it out here just to be a little more clear. It's not specific wells, it's more wells that might be taken off for completion operations, to put back on. So we've just broken it down in its own categories, so it can be a little more clear since it's not a specific well being drilled.

Yes. So, I mean, just to be even more clear, so that category spans our asset base. The majority of it is centered in the Northern Rockies because it is a distinctly different -- it's not drilling, completing wells, it's workovers, recompletions and so on. We broke it out so you have a better idea of what we're spending our money on. And the drilling part of the Northern Rockies is just what I stated the parts to drill in complete wells.

Okay, so Bakken workovers weren't previously included in the Northern Rockies CapEx guidance?

Some of it was, yes, but it wasn't a big number. It's got...

[indiscernible] as we've gotten more and more wells, though, it's take off to do the completion operations, but we've now broken it up.

Thank you very much for your questions, ladies and gentlemen. That is all the time we have for questions. I would now like turn the call over to Jim Volker for closing remarks.

Well, great. I want to thank everyone. I thought those were all wonderful questions, and we're pleased to have been able to respond. I'd now like to thank all of the Whiting employees for a job well done to date in 2012 and for the exciting plans we have for the remainder of the year. I'll also express my thanks to our directors for their continued contributions to Whiting's success. Eric?

Mr. Volker will be presenting at EnerCom's Oil & Gas Conference in Denver, Monday, August 13; the Barclays' Capital CEO Conference in New York City on September 6. We'll also be participating in IPAA's Oil and Gas Investment Symposium, that's the week of September 24 in San Francisco, and look forward to seeing you all there.

In closing, we thank all of you on this call for your new or continued interest in Whiting Petroleum, and we look forward to meeting with you soon.

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