Chord Energy Corporation (CHRD) Q4 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

Jason Smith - BofA Merrill Lynch, Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division John Freeman - Raymond James & Associates, Inc., Research Division Michael Hall Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division John C. Nelson - Citigroup Inc, Research Division Michael Rowe Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division Gail A. Nicholson - KLR Group Holdings, LLC, Research Division Biju Z. Perincheril - Jefferies LLC, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Gilbert K. Yang - DISCERN Investment Analytics, Inc

Good day, ladies and gentlemen, and welcome to the Q4 2013 Whiting Petroleum Corp. Earnings Conference Call hosted by James Volker, CEO. My name is Mupendra, I'll be your event manager today. [Operator Instructions] I would like to advise all parties that today's conference is being recorded for replay purposes. And now I would like to hand over to Eric Hagen, Vice President of Investor Relations. Please proceed, sir.

Thank you, Mupendra. Good morning, and welcome to Whiting Petroleum Corporation's Fourth 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 fourth quarter and full year 2013, and then discuss the outlook for the first quarter and full year 2014. This conference call is being recorded and will also be available on our website at www.whiting.com. To access the call and the webcast, please click on the Investor Relations box on the menu and then click on the webcast link. Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on Slide #2 and in our earnings release, reconciliations of non-GAAP measures we refer to and the GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-K for the year ended December 31, 2013 is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

Good morning, everyone, and thanks for joining us. We'll get to your questions just as soon as possible. Our 10th year as a public company was a record year for Whiting Petroleum. As you can see on Slide 3, we're a company on the move in many ways. In 2013, we posted records in cash flow per share production and proved reserves. Our cash flow per share increased 24% over 2012. We're moving the Postle sale from both periods. Our production increased 21% and our proved reserves increased 31%. We grew our gross and net potential drilling locations by 47% and 66%, respectively. We also sold $917 million of non-core assets. As a result of these actions, we have an exceptionally strong balance sheet, which we've used to increase our position in the Williston Basin, accelerate development at our Redtail field and acquire over 500,000 net acres in 3 new potential oil resource plays. Slide #4 shows that our production topped 100,000 BOEs per day in the fourth quarter. Our reserves increased to 438.5 million BOEs. Our reserve mix is 79% black crude and 89% liquids and our R/P ratio is a healthy 13 years. Slide #5 shows 84% of our total production came from our core Rocky Mountain region. 73% of the total came from the Williston. Our 101,000 BOEs per day average production rate during the quarter was up 9% over the third quarter of 2013. Our year end 2013 proved reserves increased 31%, including the reserves, excluding the reserves associated with the Postle sale. We added 108.8 million BOEs through the drill bit and acquired 17.1 million BOEs. This translates into a 402% reserve replacement. Our 2014 capital budget on Slide #7 is $2.7 billion. We plan to invest $2.4 billion of the 2014 capital budget in exploration and development activity. Based on this level of capital spending, we forecast production growth of 17% to 19%. On Slide #8, we show our future potential drilling locations. Overall, our total locations increased 47% year-over-year. A large portion of the previous perspective locations have migrated to the identified primary locations category. This upgrade stems from drilling results that validated our geoscience work. In our core Northern Rockies area, our gross primary well count increased 39% over 2012. At the current drilling pace, we estimate we have 22 years of drilling inventory in the Williston Basin. In our core Central Rockies area, our gross primary well count increased 55% over year end 2012. We estimate we have 28 years of drilling inventory at our current drilling pace at the Redtail field alone. Calling your attention to Slide 9, we provide an overview of our plays in the Williston Basin where we control approximately 715,000 net acres. Slide 10 shows our new and improved completion design in the Williston Basin where we have instituted the use of cemented liners and to enhance the results, along with plug and perf method of completion. This achieves a better breakup of the near wellbore reservoir. Slide #11 shows the improved results achieved at Missouri Breaks, Pronghorn and Hidden Bench using the new completion design. Note, we have experienced productivity increases greater than 50% across Missouri Breaks, Pronghorn and Hidden Bench. On Slide #12, we show our development plan for our 6 primary fields in the Williston Basin. The drilling patterns in these areas form the basis of our inventory slide. Slide #13 shows the positive results we're seeing from our higher density pilots. Highlighting recent results were the completion of the Uran higher density wells at our Sanish Field. These 2 infill wells posted an average production rate of 1,352 BOEs per day versus the original 2 wells that had an average IP of 789 BOEs per day. Both infill wells were completed with our new completion design. Jim Brown will now discuss our new exciting Redtail field.

Let's start on Slide 14 for our Redtail field in Weld County, Colorado where we target the Niobrara formation. As you can see from the map, we are drilling some of the most profitable wells in the Niobrara trench, which extends from the prolific Wattenberg gas field northeast to the sweet spot we control in the crude oil window in the Redtail area. We moved the third rig to our Redtail field in November 2013. We currently plan to add a fourth rig in August 2014. Our plans are to drill 118 gross wells or 104 net wells in 2014. Our drilling has shifted to pad drilling. We estimate the total resource potential for Redtail to be 492 million BOE net to Whiting. This is why we believe Redtail is another current Whiting. As of February 1, 2014, net production from the Redtail field was running at about 5,100 BOE per day, up 58% from its fourth quarter 2013 average of 3,230 BOE per day. Our development plan for the Redtail field is to drill 16 wells per spacing unit; 8 wells to the Niobrara B zone; and 8 wells to the Niobrara A zone. In the next 1,000 operated wells we drill, we will have an average 84% working interest. Early results from our 27K pad, testing 16 well density with 8 wells in the A and 8 wells in the B and the 27L pad, testing a 16-well pattern in the B zone alone have been positive. In the second quarter of 2014, we plan to begin drilling a 960-acre spacing unit on a 32-well pattern. If successful, our potential drilling locations would increase to more than 6,600 gross wells. Our 30F pad located in our Horsetail area will test the Niobrara A, B and C zone. Slide 17 shows that the production results from our most recent 14 wells, using our new completion design, utilizing over GBP 6 million of profit are tracking above our 400 MBOE type curve. These results include the 4 wells on the 27K pad. Slide 18 shows our North Ward Estes recovery project in the Permian Basin. Net production from North Ward assets increased 14% year-over-year to an average 9,755 BOE per day in the fourth quarter of 2014, continuing the great performance of this field. Mike Stevens, our CFO, will now discuss our financial results in the fourth quarter of 2013.

On Slide #19 you can see our fourth quarter 2013 adjusted net income available to common shareholders was $104.8 million or $0.88 per diluted share. Our discretionary cash flow in the fourth quarter totaled a record $457.6 million. This total represented a 20% increase over the $381.7 million in the fourth quarter of 2012. Our cash flow per share in net debt to EBITDAX for the last 5 years is shown on Slide #20. Our cash flow per share has grown at a compound annual rate of 26% since 2009. Over the same time period, our net debt to EBITDAX decreased 21%. Our guidance for the first quarter and full year 2014 is detailed on Slide #21. Our guidance includes our current estimate of the effects of weather conditions. On Slide #22, our full year 2013 EBITDA margin continue to be strong at 66% of our blended realized price per BOE. On Slide #23, you can see that we continue to maintain a strong balance sheet, with nearly $700 million of cash on hand after our bond issues and nothing drawn under our bank credit facility. Slide #24 shows that our 3 notes continue to trade above par. It also shows that we're well within all of the covenants in our credit agreement and our bond indentures. Slide #25 shows our crude oil hedge position. At this point, we're 52% hedged for 2014. On Slide #26, you can see our strong fix priced gas contracts that continue to net us over $5 per mcf. You'll also see that we recently entered into a fixed differential crude oil sales contract that covers a portion of our forecasted volumes at our Redtail field. These cover escalating volumes for the years 2015 through 2019 at a $4.75 per barrel discount to NYMEX crude prices. I'll turn the call back over to Jim Volker.

Thanks, Mike. There's exciting growth scheduled at Whiting in 2014. As you can see, the actions we took in 2013 set the stage for another 10 years of rapid growth as we focus on the Bakken and the Niobrara. At Whiting, energy plus technology equals growth. Operator, please open up the conference call for questions.

[Operator Instructions] Our first question comes from the line of Jason Smith from Bank of America Merrill Lynch.

Jim, I'm just wondering, in the 17% to 19%, what is that based on, in terms of your Redtail-type curves and your Bakken curves as well given the recent outperformance you guys have seen?

So we're not going to cite for you an exact EUR. We are telling you, unequivocally, that all of the performance of all the wells that we've drilled and tested out there and now have outperformance, are now outperforming a 400,000 BOE type curve. And before we give you the final number, which we think we should do by the time we get to the end of this year, because we'll have a lot more information available, we want to see that continue to, I guess I'd say, get a good average over an even larger sample. And with respect to really across our acreage position in the Williston, things do continue to improve. Actual results indicate, I'm going to say, right up in our PDP reserves that occurred in 2000 and at the end of 2013. So nothing has really changed in the range of those type curves that we've shown you before and have had on our website. But we do, I guess I'd say, continue to see improved performance that would lead us year-over-year, we hope to continue to book some performance increases.

And Jason, if you're asking whether the impact of the new completion method is fully reflected in our production forecast...

Yes, exactly.

The answer would be no to that because we tend to forecast production looking at sort of the trailing last 6 months wells, well performance and only a portion of those, I think, about 40 wells out of over 200 we drilled last year the Williston basin were completed with submitted liners.

Yes, we hope that helps.

And in terms of just the longer-term trajectory at Redtail, obviously, you guys deferred the fourth rig to August, I mean is that due to just increased efficiencies and if you can maybe just, Jim, give us some color around how you see that ramp moving as we get into the future?

Yes, well, basically the rigs that we have out there are improving their efficiency and we're drilling more wells per rig. So we really don't need, didn't need that fourth rig to arrive until a little later in the year to get where we want to be in terms of the number of wells to be drilled out there. And also, to stay within our budget.

And on the longer term?

Well, on the longer term, I don't know what it tells you, but it tells me we've got a big inventory out there. And as we go forward, it does give us the ability to ramp up. So as production ramps up, it gives us the ability to add more rigs. And we want to grow, we have the potential to grow there. And maybe take that 20-plus-year inventory back to 10 years. We all understand present value and we'll do that. But we'll do that at a pace that is wise in comparison to our cash flow and keeps us around where our cash flow and our exploration budget can be basically close, if not equal.

Next question is from the line of Jason Wangler from Wunderlich Securities.

Just curious, Redtail, obviously, the A and B zones are what you're focused on. Is there any other zones that you're looking at? And granted, you have plenty of inventory with those, but is there any thing else you're going to try and attack either this year or kind of going forward?

Mark Williams would like to answer that one. Thanks for asking.

Yes, Jason, right now, our development plan is 16 wells per spacing unit, alternating A and B. But as you've seen and you can see on Page 16, we have high-density pilots that are testing beyond that, both in terms of well density, as well as new drilling. So the Niobrara C zone is something that we recognize as having a very significant opportunity and our 30F pad that's coming up here this spring we'll be actually starting the drilling on that late in March. We'll have 2 wells in the C zone. Those will be the first 2 C zone test that Whiting has drilled, offset operators have drilled the C successfully and we think that C is going to be good. But so we'll modify our development program as we see the results of those, both in terms of the well density and adding the C in to our development plan. So I think the good news is that we've got a great plan going forward. Right now, we're ahead of the game compared to what we're doing here to what we did, say, in Sanish, we're trying to test the upper boundaries of what we can drill early on in the play, recognizing we've got a large development program here, that's why we're doing these high-density pilots. I think there's a very good chance that we'll be able to add the C zone in, and we'll just have to wait see about going to 32 wells.

That's very helpful. And then just staying around there as far as the infrastructure, and obviously the gas processing plant coming on relatively soon, just how you're seeing the ability to, as you ramp this up to obviously, get the oil and the gas to the markets?

Well, you couldn't have picked a better place for, to have a brand-new oilfield. Number one, the population out there is only about 1 person per square mile, in some cases less. Second, as you can see, within a relatively short distance to the north of us, there are 2 interstate gas lines. And there's basically a lateral off of the trail blazer line being completed to us right now by Tallgrass, as we speak and it'll be ready, it is ready. So when we turn on our plant, we'll start selling gas and turn on the schedule for the month of April. In addition, aside from having both a robust market for the crude oil in Denver, and a robust market for the crude oil in Wyoming, refineries located in those 2 areas, we also had a pony express pipeline off to the east of this, just a short distance. So that we can take some of our crude there and if we few wish to go to Cushing and beyond, we can go there. Also products out of the plant has a nice line immediately to the southwest of our acreage position that provides another takeaway for our plant products in addition to trucks. So this is a great place. We're ready for it. Couldn't have occurred in a better area, or in my opinion, really at a better time in view of the infrastructure that is now available.

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

The Niobrara differentials that you've locked into, they seem relatively attractive prices, can you talk about what you're currently seeing in the market and in any way you can get increase of those differentials, an increased number?

Yes, Mike wants to answer that, he's been waiting for that one.

Yes, we're currently seeing around 10 to 12, it was a little worse than that later last year. So they're still up there a little higher than we like. We're very happy with these contracts at $4.75. We're looking at some other contracts potentially to lock in some more differentials. We think they're going to be attractive.

So just to comment on that, if you look, not only in this area, but in the Bakken as well, I think what this should tell us all, at least it tells me, is that if you're willing to commit your crude on a long-term basis to refiners in a particular area, then they're willing to work with you on the differential. And that's the dynamic that we've used both here and in the Bakken. And we intend, I might say, to continue to use in the Bakken and expand upon in order to keep our differentials there at a very acceptable level. So I think that's an important thing here to keep in mind. I can't over-emphasize, I guess, that at least in my humble opinion the market for Bakken crude is the Metroplex. It's basically the Midwest and the Metroplex from Philadelphia on north. And this crude, this light sweet crude is going to replace the light sweet crude that used to be imported in those refineries. The appetite there is large and it wants this crude. And really, it's just a matter of, in my opinion, a year or less until this crude becomes, if not the primary, then a very large portion of the crude that supplies that market. It is the United States' best combined driving markets, the Metroplex and the Midwest.

And Jim, switching tunes to the Bakken, can you talk about, the inventory chart is very helpful, so we do like that, that you all put out, does that include your down-spaced wells in the Bakken? And did you get any credit for down-spaced wells in your proved reserves this year?

So that includes selectively some down-spacing. But to answer your question, in terms of combination of down-spacing and the new potential reservoirs that we cite for you there on our wine rack slide, there's probably about another 1,000 wells that we could have added there as we move forward. And so there's upside to be added as we move forward. Mark, do you want to expand upon that?

The second part of the question there about whether or not we've moved that into our proved reserves, we've been, when we do the cemented liner completions, as well as the high density wells, we need about 120 days of performance data in order to get comfortable with the reserve add. And the timing worked out such that we, Steve Kranker can talk about this also, but the timing worked out that when we prepared our year end engineering database, we really didn't have enough performance data to move the majority of that results from either the cemented liners or the high-density infills into our reserved base. So there's a little upside remaining there, we've got a little dry powder.

Next question is from the line of Ryan Oatman from SunTrust.

I wanted to talk a little bit in the DJ Basin, talk about the 16 wells per DSU. How does the early production of those wells compare with wells that were drilled not on that type of a spacing?

So 14 of them sit, if you're really looking to what we've done there, last March we changed our completion design. It's much larger, frac volumes were up around 6 million pounds of sand. Virtually, all of the wells have performed very well since that time. You can see the type curve that we published out there that shows them tracking well above the 400 MBOE type. Only one of our high density pilots is included in that. So of the 14 wells, 4 of those wells are from our 27K pad. And if you look at the average of those wells, they're right in the hub along with the rest of them, so I would say that really no better or no worse, it's still pretty early for that pad. We're still flowing that back, but the initial results look just as good as the other ones.

Okay, very good. And then following up with Brian's question on the primary and perspective drilling locations, in terms of, I'm looking at Slide 12, you've got light gray and white in terms of current potential and new objectives. Can you kind of speak to one of those is in the primary count, are you including some of those potential grays or not yet kind of based on what you've, the early, how early it is in that program?

We've kind of went through that in the question just before yours. The issue there is we need 120 days worth of production data to add those into the reserve database. So in the well count, yes, some of those are added in. But in the reserve database, they're not. It's a matter of timing and so we're just waiting for performance data to get comfortable with the reserves but you'll see, selectively, as you pointed out earlier, depending on what projects you're in, selectively, we've started to include those as we've gotten comfortable with the results of our cemented liner completions and our high-density pilots. So I'll just take Sanish as an example there. We're very comfortable now that we can increase the density from the core that we've been drilling on to something much higher than that whether we're going to get all the way up to the number that are shown in there. You can see that we've added 2 wells in between each of our Middle Bakken wells, that's what our volumetrics are suggesting. We ought to be able to get to a significant portion of Sanish. Whether they'll all get there or not, I mean, that remains to be seen, but we now have the results of our first 2 high-density pilots in Sanish, they're very encouraging. So you'll see us for the rest of this year 2014 continuing to test that. We're looking at at this as sort of a high-end of what could be done there right now, but I think especially on the west half of the field there, we've got a lot of well in place, and the potential to move to put a lot more Middle Bakken wells in the Sanish.

Maybe I went over there a little fast but I try to quantify that for you by saying that based upon our best estimate, we think these numbers could go up by about a 1,000 wells.

That's great color on both an overall and individual field basis.

Next question is from the line of John Freeman from Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: Now that you've included Utah and along with some of the other new placements, specifically Utah in the location count. Is there any more kind of light you all could shed on that? I know there was some talk last call about, Jim, that you might have some results that you'll be able to share on this call?

For competitive reasons, we don't want to go much farther than we did in this table. The table, as you can see, tells you that we do have exploration plays going on in essentially Michigan, Utah and Louisiana. And we do have wells that we've drilled, essentially in each of those 3 areas. However, we're still in the process of acquiring acreage. We really don't want to go forward other than to say that we're encouraged by the initial results. And as we get more results, we'll be very pleased to release it to you. It's just not time yet. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. Can I just clarify then, in the chart, is the Rockies exploration that shows the 2,457 gross wells on Slide 8, is all of that Utah, is that just Utah?

Primarily Utah.

Yes, primarily Utah. Right. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And then just last question for me, and I'll turn it over to somebody else. Mark, last call, you all mention you've done the 1 slick water job but you had several more that were in the Q, has there been any update there, has there been additional ones done?

We're continuing to -- recross [ph] to doing a lot of work right now, adjusting the viscosity, if you will, of all of our fracs. And what we're trying to find is that right mix. So going purely to slick water, I think we've really only done a couple that are pure slick water right now, a lot more of them are linear gels or somewhere between a cross-link and a slick water. And that seems to be working pretty well for us and we're also modifying viscosity of our fracs between the early part of the stage and the last part of the stage. And that seems to be helping as well. So we really, I'd say, it's way too early to say that we're go entirely slick water, but we're trying to find it a happy medium in there. Jim?

Yes, John, we've got 1 queued up to do 1 more pure slick water job and we're going to do it exactly. We're going to do it where we can compare it exactly to just a plug and, cemented liner plug and perf to see if are we getting the uptick from the slick liner or from the slick water or can we get to the same point with a cemented liner plug and perf and generate the same end result. That's what we're trying to get when we directly test that concept.

[Operator Instructions] Next question comes from the line of Michael Hall, Heikkinen Energy Advisors.

Heikkinen Energy Advisors. I guess, just want a couple of quick follow-ups in the Redtail area. You've got, I think, quite a bit of a non-op acreage still within the totals there. Just curious to what extent there might be some opportunities to kind of help clean up that acreage position and maybe any available swaps or anything along those lines in the area? And just further unitize or larger units on the acreage block?

Michael, before we get started, I just want to point out, a significant portion of that is Noble operated in one of their very good fields. So I just want to point out, it's pretty high-quality non-op.

Very fair.

Well, first let's kind of -- if you don't mind, I'll kind of talk about what's happened there. What you're suggesting we do, we have been doing. And as a consequence, as you can see, our average working interest up there is now over 80%, basically around 84% working interest. So we have been doing a number of trades, and gets us in that position for the next thousand-plus wells out there. As to, I think, the second part of your question indicating that you'd like to know if there are more trades that can be done, we think there are additional trades or just purchases that can be done out there as not only we, but other operators, consolidate to raise their working interest in the areas in which they operate. So we're working on some more of those. I'm not sure we'll see the same kind of total increase that's taken us from roughly 60% to 84% for the next 1,000 wells. But as things go forward, I'm optimistic that for the next 2,000 wells, we'll improve upon our currently known working interest in those and raise our overall average to something more than approximately 50%, which is what our overall average is. So I think as we go forward, those things will happen naturally as we each work as other companies get to the point that they then want to trade. At some point, they get to that point. And it usually happens when they're getting ready to drill a particular area of their leases. Anyway, some of that just hasn't happened yet with some of the other operators.

I just want to point out, Michael, there was an issue, I think with the slides, you may not have seen it, but on our Redtail development plan, our 5-year plan basically is to drill 1,000 gross operating locations with an 84% working interest. So as Jim indicated, we've already done a good job of blocking up a lot of acreage to drill over the next 5 years or so.

That's great color, I appreciate it guys. And then I guess, I'm also curious in terms of how you're producing the wells in Redtail some, correct -- I think maybe you produce them a little differently in some of the offsets and just curious if can give any more color around that. And any plans to test any other production techniques or are you all set on the way you're doing things now?

I'd say, there's 1 big difference between our Niobrara wells and what we've been doing up in the Bakken, and that is we're finding much better well performance by allowing these wells, which are in a carbonate reservoir, essentially shaly, carbonate or model [ph] reservoir to flow back fine over the first month, 1.5 months. So what that means is we typically try to constrain the gas rate on this and so we open the choke up very gradually and we achieve peak rate somewhere between 30 and 45 days into the flow back. That's a big difference versus the Bakken wells, which typically reach the peak rate within a week or so. And so I think if we continue to allow the flow for that whole period and so that's been overall a positive thing. The other thing is as we're going to pad drilling, we're flowing all the wells into a manifold. And so we do individual well test on there, but essentially getting individual well test on those on about a once a week basis. So overall, I think we're seeing great results. The one thing that I think is compelling here to me is that our average peak daily rate out of the 14 wells we drilled since March is about, a little over 700 BOEs per day, which is -- really attest to the new completion design that we've got, the efficiency of that.

Next question is coming from line of Mike Scialla from Stifel. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Looking at Slide 15, I'm sorry, my eyes aren't very good, but in terms of the 14 wells that are beating your 400,000 BOE curve, have those been concentrated in the kind of Razor and Wildhorse area, if I'm seeing things right, or do they cover a broader area than that?

Mike, they span from the eastern portion of Horsetail down into the western area of Wildhorse, across the Horsetail Razor, part of the Wildhorse units, they're largely in the central part of our acreage. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Got it, okay. So northern area is still a little bit untested, any plans to try some drilling up there in that next -- year.

Thanks for asking, Mike. Mark's been hoping somebody would ask that..

On Page 14, Mike, you could see our bubble chart there and the activity is moving north. There's 2 wells of note up there that is sort of the north part of our Redtail acreage. One of them is on the northeast side. That's a very good well, it's our Horsetail -- it's a Horsetail well in our Horsetail township, and then there is a well that was drilled by on offset operator, not all of them are Whiting wells except on the northwest side. It also shows very good recent and very promising results that gives us confidence that we're going -- that we have extended this further to the north. In addition to those 2, we have 7 wells that we're, they're in our 2014 budget. This year, that will be designed to delineate other areas that we map out as being perspective right now. So we've got a full-blown development program going on, but we're continuing to delineate the rest of our acreage position, so we're still doing a little bit of exploration here, and there's a lot of work yet to do to fully evaluate, not only the high density, in the C zone that we're talking about, but extend the A and B development that we're already doing further to the north.

Just underscore what Mark is saying there, Mike, is that like any good oil man or any good analyst, yes, we want to confirm with well results that all of our acreage position is good. I just want to underscore for you that this area is blessed by old logs, old core, old wells, all of which we have studied now for almost 2 years. It gives us great confidence that this area that we leased is all either in the A or the B or the C or a combination of generally 2 zones within each area, be good in each one of those, because we do have the benefit of all those old wells that were drilled out there. This was the playpen of basically the Denver oil industry in the '60s and '70s as they drilled looking for the deeper D sand and J sand. And so we have all that, all those logs and consequently, the mapping of the Niobrara that's available to us. So yes, it's true, we haven't drilled and completed wells completely to the extremities of our acreage positions. But it doesn't look that different, it doesn't look different to us on those extremities for the most part than what we're drilling right now. So that's why we really believe this is another Whiting within Whiting. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Got it. That's very good commentary. If I could, sorry to beat Slide 8 to death here, but just to clarify, the potential locations, I think include both your 3P and your resource potential, are what you're calling your primary well count, does that correspond to the locations built in 3P reserve report, am I understanding that?

Largely 3P, so they do largely correspond, yes, so.

Next question, John Nelson, Citigroup.

I guess, just wanted to circle back to the fixed differential comments earlier, those related specifically to Redtail.

They do.

And over 2015, are they spaced fairly evenly over the course of the year or is that ramped?

Evenly.

So can I back into that we then should be exiting 2014 about 25,000 barrels per day, does that sound reasonable?

That math sounds accurate.

I guess, I should comment on that before it goes too far. Obviously, we have to make, what I would call, a risk assumption when we do that. So that represents the gross barrels on a risk assumption. So I would say, we've applied a fairly hefty risk factor to that, to our projections based upon our drilling plans, so.

It's a good point -- it's the gross volumes, yes.

Gross volumes and the risks.

Risk gross volumes.

So how should we thinking about the right working interest for those volumes?

We said we're typically drilling at 80% plus working interest wells the next 5 years. So you can kind of back into it that way. But of course...

We may be -- I guess, maybe how should we think about the ramp to that level over '14? Is it...

We don't -- I don't want you to go further than just that. It's like enough for you guys to calibrate your models.

Next question is from the line of Michael Rowe from Tudor, Pickering Holt & Co.

I was just wondering if you could comment a little bit. I'm looking at Slide 12 in your presentation where you sort of lay out your primary and prospective drilling plan across those 6 regions in the Williston. Could you comment about how that kind of changed over time, if I were to look at prior investor presentations?

I can comment on that because I make those. But basically, the biggest addition has been the addition of, more recently, high-density locations, which are in gray. If you would've looked back in 2012, there would have been none of those in any of our areas. And then also, the lower Three Forks in Cassandra, those are new. And as of this year and also, the lower Three Forks at Sanish, those are new locations as of this year. And in the Pronghorn field, when we first started drilling the Pronghorn field, we were planning to drill 2 to 3 wells per spacing unit. And now we're looking at 6. And we really prefer to drill a lot more aggressively at the end of 2011. So that gives you kind of a broad idea of what we've added over the past 2 years in terms of location counts, potential location counts.

Okay. And then just a follow up to that would be, I was wondering if you could comment about any sort of degradation in well performance that you see in the Three Forks, various Three Forks benches relative to the Middle Bakken.

Well, I just want to point out that we've had, for years now, and it seems to have become somewhat a controversy, but for years now, we've said that the Three Forks is probably going to be somewhere around maybe 90% of the Bakken well. And we said that in our Sanish Field for years, if you look back at presentations we've had out there, literally, since 2008. Now but across the whole basin, I think and Mark can probably add some color, but in some areas, the Three Forks will be as good and in some areas better than the Bakken. So you probably have to look at it regionally. Broadly, maybe across the whole basin, maybe 90% is good. Does that sound about right, Mark?

I think an awful lot of potential focus on the Three Forks and especially the lower Three Forks. The upper bench of the Three Forks has been firmly established as the vast majority of the basin. As you can see, we've got upper Three Forks just about all of our acreage. The lower part, the second bench of the Three Forks and the third bench of the Three Forks. The industry is converging as we are that the best area is the central part of the basin, so west of the cemented line, that would include our Hidden Bench, our Tarpon fields, a portion of our Cassandra field, and then going east over into at least part of Sanish. So we see the second bench potential as you pick it on Page 12 there in perspective, it Sanish as well. So the central part of the basin is going to have good second bench potential, that's a lot of what we've added in here this year. We see opportunity there. As far as the extremities of the basin, it will be less perspective as you get towards the margins.

The next question is from the line of Hsulin Peng from Robert Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Just 2 quick questions. One is based on the results that you've seen in Niobrara, I was wondering if you can talk about if there's a difference between results from B versus A wells, if you can, kind of, shed some color on that?

So the information we have on that right now comes primarily from our Razor 27K pilot, which is depicted there on Slide 16. And the early results we're really positively impressed with the fact that 2 of those wells that were drilled in the A zone look just as good as the B zone wells. So it gives us great confidence. That was one of the reasons we did that pattern was to try and compare it to the 27L pad, which is just adjacent to that, trying to figure out which is the best pattern. And I would say, while the jury is not completely in on this, we're definitely leaning now towards doing this alternating A B A B pattern, because the results of those 2 A wells have been very positive compared to by any standards. So they're just as good as the B well, so I think that's the pattern we're going to converge on. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, that sounds good. And then my follow-up is I was -- can you tell us the EUR for Niobrara and also for the Bakken that's currently reflected in your 2013 year end reserves? I just wanted to understand how that compares when you -- hopefully give us the new EUR later on with the performance.

What we're going to say is 400,000 plus in the Niobrara. In the Bakken, we've given the range for years of 500,000 to 600,000, we're not going to comment beyond that.

Yes, the typical range, I mean.

Just typical range, yes.

If there was a new completion activities, I think it's going to be common that we have some wells that are in the 800,000 and 900,000 BOE range. So we want to be able to continue to book those based upon performance rather than just slap them in there. I think if we do it in that manner, hopefully, the industry observers, people like you, will get an idea that this is -- when we say something about our reserves they're based upon solid long-term performance. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: That sounds great and then...

And our location count -- I want to add on that, our location count, you, for example, we think some analysts and even some companies give a location count just based on acreage map. Every location in that table has [indiscernible] case. And we've done all the work to see that we have title to it and all of that, so these are real drillable things, not just what someone made up on a piece of paper. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, now, that's great. And then lastly, a broader macro question, just wanted to -- can you comment on rail giving that we have seen some, unfortunately, accidents recently? Can you comment on this potentially additional regulatory scrutiny and how you see that unfold kind of going forward?

This is Jim Volker, I guess I'll take a stab at that. First of all, 100% of our crude coming out of the Williston has been sampled. And it's a packing group 1 or packing group 2. The number 2, 100% of the purchasers that we used are equipped to handle that crude. So that means by rail or by truck, however it goes out, and of course, by pipeline. So we've not seen nor have we ever experienced any limits on our ability to sell our crude. And I don't anticipate seeing any going forward. I really believe the only thing that you're going to see is that somewhere in the range of around 3% to 5% of the trucks and rail cars that didn't meet the standards necessary to carry packing group 1 and packing group 2 will be replaced by those that do meet the standards to carry packing group 1 and packing group 2. So I think the transportation industry and the producers have all done a good job of not only labeling, by that, I mean, we all have to file paperwork with our purchasers that designates what kind of crude it is. And we've done that and that designation has been accurate. And then the purchasers and transporters, because remember, Whiting and in 90% of the cases, this is accurate for other producers, we do not transport it. If we sell it on our lease, title changes hands there and somebody else takes it into interstate commerce, not us. And those people, in my opinion, have done a great job of getting their trucks and rail cars prepared for the Bakken crude and that's why 97% of the trucks and rail cars meet the specifications necessary to handle Bakken crude.

Next question is from the line of Gail Nicholson from KLR Group.

I'm just curious, on the 14 recent wells in Redtail that you have on the presentation, what's the average lateral length on those?

I think broken down, there's how many -- Randy, do you have that handy? 9 or 960, that's about a 7,000-foot lateral. And the remainder are 640. So 4,000 to 4,500-foot lateral.

And then looking at the drilling plan in '14, and I'm looking at the next 5 years, what's the split between the 960 and 640-acre location, do you guys know?

Probably about the same as what you see there in terms of ratio, very similar to that.

I think you can get a pretty rough idea just looking at our development map, the number of 640 versus 960 there, it's all shown there on Page 15. So each of the well bores that we have that could be drilled is shown on here. You can see we really have relatively few 640s, almost all of this is 960s.

Next question is from the line of Biju Perincheril from Jefferies.

So looking at the Niobrara wells and the decline [indiscernible] I think you've sort of alluded to earlier that initially you're doing pressure management. But even if I look at sort of several months out, it looks like the declines are fairly flat. And I was just wondering if that is still the pressure management at that point, or is that something inherent to the reservoir?

I mean we think that's inherent in the reservoir. You can just see on that curve, I mean, that line is pretty linear on there, which you can infer from that, that we're at pretty stable, pretty constant production rate. So we just see these things as we get them on production. In numerous cases, our 90 day -- like our 90 day -- our production rate at 90 days will be higher than the 30 or 60. So these wells just continue to clean up, just continue to hang in there. And then also usually, about that point, some time around the 90 days in there, is when we put this on lift even with gas lift. We've used gas lift, jet pumps and also beam pumps. Looks like we're probably going to land on gas lift out here.

Okay. You answered my second question there. And then on the some of the liners, is that something that you're going to test in the Niobrara as well?

Yes, we've -- currently in those 14 wells we have on one slide, 4 of those are cemented liners. Just to give you a hint, we're still -- the jury is still out a little bit, we're still evaluating, but we have gone 100% to cemented liners in the Niobrara.

Next question, Jeffrey Campbell, Tuohy Brothers.

I just want to confirm the 16 well B pad test, is that the same spacing that you're going to use when you do the 32 well test in the A and B later on?

Well, no, there were 2 16 well pads, one was in A B A B staggers, so 16 wells. 8 A 8 B. The other one was 16 wells spacing pattern just in the B, the 27L. And the 30F is going to be basically 8 A 16 B 8 C is what it -- and that's all depicted on Slide #16, the diagram. Of course, we're not drilling 32 wells, we're drilling a portion of the spacing unit on that spacing pattern.

And my other question was just now that we're starting to talk about the C, or more specifically, do you have a preliminary estimate at this time as to what percentage of your acreage is exposed to the C?

Looks to me like all of it, I think the C is going to be present throughout our acreage position. So as Jim mentioned earlier, we've got well logs that go back to the '50s and '60s that show the presence of the C. Our -- the information is coming out of our core facility here. We take our core thorough, I think, 3 C intervals now, and it looks pretty good in all of a -- we have a previous slide here, I think we've taken it out this quarter, but if you go back to our last quarter, or perhaps maybe 2 quarters ago, there's a log in there that shows the A, B and C that shows how the oil saturation in the C and that's pretty representative, I would say, for all of our Redtail acreage positions.

Our final question is from the line of Gil Yang from DISCERN.

Can you talk about what the better well results in the Bakken that you seem to be having, yet you're taking down your capital allocation in the area. And obviously, you have a lot of wells drilled in Redtail, and so it's natural you ramp up spending there. But can you talk about that capital allocation decision, why you're coming down in the Bakken, is it just to sort of keep overall capital spending flat, is that sort of the goal?

Yes, Gil, that's our goal, we want to stay within our budget. In both places, in both the Niobrara and in the Bakken, with the -- I mean with each plays, the efficiency is improved on our rigs. So we're drilling more with fewer rigs. So we can -- we're trimming back the Bakken a little bit to try to stay within our capital budget. And we're also able to drill more wells with fewer rigs up there. So it's a little bit capital balancing and rig efficiency.

Right, and I didn't want -- I did not want to leave you with the impression that we're saying the dollar volume of our capital budget is going to remain flat. It should grow with production. My point was that as we grow, we'll try to keep the amount of capital that we invest and our discretionary cash flow equal or pretty close to one another, so that we're not outspending while we grow.

Great. And related to that is you say that you haven't at least fully incorporated a better well results into either bookings or guidance. But aren't the better well results fully baked into the slide that shows the ultimate density spacing that you're anticipating? Slide...

I'm not sure I understand because the better -- we're talking about 2 different things of well density versus increased productivity. We have, for example, Uran pilot was a high-density pilot in Sanish where we experienced success drilling on higher density. And also, because we used the new completion method had a significant uptick in the productivity of the wells, so I'm not -- does that answer your question or?

Well, yes partially. But my meaning is more that as the well get better, you can put them closer together presumably. So is there upside -- to Slide 12, is there upside that density if the wells are better or are you already incorporating the better well results in placing those wells at those distances?

We talked a little bit about that before, the answer -- there's 2 things here, one is reserve bookings, the other one is what we're counting in this well count summary on Page 8. And if you look at Page 12, what the reserve bookings, the effect of the cemented liners and the high-density infills are not yet ground into our reserve bookings. But they are selectively ground into our -- slide on Page 8 that shows our net well count. So as we recognized positive results from doing high-density infills and from our cemented liners, we started to include those in our gross and net well counts and specifically in the primary locations category, which as you can see has gone up by the numbers that we mentioned there earlier in the call.

I hope that's helpful. Earlier, I answered the question that there's probably about 1,000 well uptick in our well count that could happen as we move forward. It's not in there now. So we've selectively put some in, but with improved performance and some of these new zone potentials that we've shown you in white. Probably about another 1,000 or 1100 in there, something in that range.

We have no further questions in the queue at the moment.

Thank you, very kindly. We really appreciate all the questions that come in. In the future, if you have further questions, please feel free to contact Eric Hagen. With that, I'd like to thank all Whiting employees and directors for their contributions to a successful 2013 and our exciting plans going forward into 2014. Eric?

Jim Volker will be presenting at the Raymond James Institutional Investors Conference in Orlando on March 3 next week. Jim Brown and Pete Hagist will be presenting at the Howard Weil Energy Conference in New Orleans on March 26. Jim Volker will be the keynote luncheon speaker at the IPAA Oil & Gas Investment Symposium in New York City on April 7, and we look forward to seeing you at all those events.

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

Ladies and gentlemen, that concludes your call for today. Thank you for joining. You may now disconnect.