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Whiting Petroleum (NYSE:WLL)

Q3 2012 Earnings Call

October 25, 2012 11:00 am ET

Executives

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

Analysts

John Freeman - Raymond James & Associates, Inc., Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Will Green - Stephens Inc., Research Division

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2012 Whiting Petroleum Corporation's Earnings Conference Call. My name is Karen, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And I would like to turn the call over to Mr. Eric Hagen, Vice President of Investor Relations. Please proceed.

Eric Hagen

Thanks, Karen. Good Morning, and welcome to Whiting Petroleum Corporation's Third 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 third 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 September 30, 2012, is expected to be filed later today. 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.

James J. Volker

Good morning, everyone, and thanks for joining us. We're pleased to report that our active drilling program is on track for 20% to 23% production growth in 2012. Our production in the third quarter averaged 82,615 BOEs per day, a 17% increase over the third quarter of 2011. We exited the month of September at an even higher rate, producing 84,550 BOEs per day.

Our production in the first 9 months of 2012 averaged 81,360 BOEs per day, a 22% increase over the first 9 months of 2011. Including the 4,500 BOEs per day of production that we conveyed to the Whiting USA Trust II in the first quarter of this year, our production in the first 9 months of 2012 reflected a 28% increase over the first 9 months of 2011.

Several wells highlighted our third quarter. At our Redtail prospect in the DJ Basin, we completed the Wildhorse 04-0414H well in the Niobrara B zone, flowing 1,170 BOEs per day. At our Hidden Bench prospect in McKenzie County, North Dakota, our Timber Creek 21-27 well has shown exceptional performance to date. The well was completed in the Middle Bakken, flowing 2,839 BOEs per day on October 11.

Now moving to the slides. Slide 3 is a breakdown of our production by region. Please note 73% of our total production is coming from our core Rocky Mountain region and more than 60% is coming from the Bakken and Three Forks in the Williston Basin.

Moving to Slide 4. We provide an overview of our plays in the Williston Basin where we control 715,000 net acres. We've highlighted some of our recent well results on this slide, including the Timber Creek well at Hidden Bench in the center of the slide. Other highlights include the Kannianen 22-32XH well, a cross-unit Bakken well in our Sanish Field that flowed nearly 3,500 BOEs per day.

We are also generating exceptional results from our recent Three Forks drilling operations as we continue development of our Sanish Field. Highlighting recent results was the completion of the Mildred Roggenbuck 41-24TFX well. This cross-unit well was drilled on the western side of the Sanish and was completed flowing 1,695 BOEs per day. We expect our development at Sanish to extend at least through 2014.

At our Pronghorn prospect, we show a sampling of our typical strong well results. The Solberg 14-11H flowed 1,825 BOEs per day. Two pad wells, the Buckman 34-9PH and the Buckman 44-9PH, flowed 1,964 BOEs per day and 1,545 BOEs per day, respectively. All 3 wells were completed in the Pronghorn Sand.

Moving to Slide 5. You can see that our Big Island Red River play, we've identified more than 50 vertical Red River prospects using 3-D seismic interpretations and porosity anomalies. Estimated ultimate recoveries range from 200,000 to 300,000 BOEs per well, with an estimated completed well cost of only $3 million to $3.5 million per well.

Our most recent completion at Big Island, the Ross 13-2, flowed 306 BOEs per day from the upper Red River D zone. We currently plan to test the lower Red River D with a horizontal well in mid-2013.

Slide 6 shows that, according to the North Dakota Industrial Commission, Whiting's average well flowed in the Williston Basin and remains the most productive during the first 12 months of production of all operators in the basin. I'd like to point out that the majority of our wells over the past 18 months have been drilled outside of the Sanish Field, and we continue to maintain this ranking.

Moving to Slide 7. Let's talk about productivity of as our drilling shifts from the Sanish Field to new areas. As you can see from this slide, in 2012, our 30-, 60- and 90-day rates in our new development areas of Pronghorn, Lewis & Clark and Hidden Bench have actually exceeded our average well in the Sanish Field. In other words, our productivity is increasing.

On Slide 8 are some facilities updates. Construction of our Watford City operation center is currently 90% complete and is scheduled for completion in early November 2012. The center will handle operations for our Hidden Bench, Tarpon, Missouri Breaks and Starbuck areas. The Robinson Lake Plant inlet gas rate increased by 10% to 69 million cubic feet of gas per day in the third quarter. At the Belfield gas plant, the average inlet gas rate increased by 33% for the quarter to 12 million cubic feet of gas per day. The plant also reached a new record inlet gas rate of 15 million cubic feet of gas per day in July. We kicked off 2 key Belfield gas plant projects: the fractionation unit for the Belfield gas plant and the addition of inlet compressors 4 and 5.

The scheduled in-date service for the Belfield oil terminal, shown on this slide, is late November, which remains ahead of the Bakken link oil pipeline connection. So we will be ready.

Volumes on the oil gathering system and oil pipeline are up more than 50% at 7,000 BOEs per day. Jim Brown will now highlight our exploration results outside of the Bakken and our 2 EOR projects. Jim?

James T. Brown

Let's start on Slide #9 with our Big Tex prospect. Two horizontal Wolfcamp wells are currently waiting on completion. As you can see on this map, one of these wells, the May 2502H, offsets the May 2501, which is a vertical Wolfcamp well that was completed in the month of May of 2012, flowing over 320 BOE per day from the upper Wolfcamp formation. The results of the May 2502H will provide us with a good gauge of the uptick we get from horizontal wells in this area.

Slide 10 shows our Redtail prospect in Weld County, Colorado, where we target the Niobrara Formation. As Jim mentioned, we completed the Wildhorse 04-0414H, flowing 1,170 BOE per day from the Niobrara B zone on October 15.

In addition, another operator drilled the well that produced an average of 534 BOE per day in the month of July within the boundaries of our Redtail field. This play is looking better every day and we now have over 118,000 gross and 88,000 net acres.

While all of our wells at Redtail have been completed in the Niobrara B zone, we are currently completing our first 2 wells in the A zone. You can see these wells on the northern and western sides of our acreage.

Now I will turn to our EOR projects, the Postle and North Ward Estes fields. Combined, they represent 39% of Whiting's total proved reserves and 20% of our current production. Third quarter production from Postle and North Ward Estes totaled 16,630 BOE per day. Both fields continue to be strong performers for us.

Mike Stevens, our CFO, will now discuss our financial results in the third quarter of 2012.

Michael J. Stevens

Before I get started, I'd like to mention that there was an erroneous report on Reuters that Whiting reported an unrealized derivative loss of $1 billion. That is incorrect. Our actual pretax unrealized derivative loss for the third quarter was only $1.6 million. Next, I'd like to mention that effective October 19, we entered into an amendment to our existing credit agreement that increased our borrowing base from $1.5 billion to $2.5 billion and increased our commitments to $2 billion. All other terms of the credit agreement remain unchanged.

Our third quarter 2012 adjusted net income available to common shareholders was $86.9 million, or $0.73 per diluted share. Our discretionary cash flow in the third quarter totaled $343.4 million. This total represented an 8% increase over the $316.5 million in the third quarter of 2011 and an 11% increase over the second quarter of 2012.

On Slides 20 and 21, we show reconciliations to these non-GAAP measures.

Our guidance for the fourth quarter and full year 2012 is detailed on Slide 13. We've adjusted our differential guidance downward to reflect the recent narrowing of differential in the Northern Rockies and adjusted our DDNA guidance to be more in line with our third quarter results.

On Slide 14, primarily because of the narrowing in differentials, our third quarter EBITDA margin increased 2 percentage points to 67% of our blended realized price per BOE.

On Slide 15, you can see that we continue to maintain a strong balance sheet with total long-term debt of $1.6 billion and a total debt to total capitalization ratio of 32%.

Slide 16 shows that our 2 senior sub notes are trading above par. It also shows that we're well within all the covenants in our credit agreement and our bond indentures.

Slide 17 shows the new 3-way oil collars that we put on for 2013. We are now 61% hedged on 2013 oil production.

On Slide 18, you will see our current gas hedge positions and strong fixed price contracts that continue to net us over $5 per Mcf.

I'll turn the call back over to Jim Volker.

James J. Volker

In summary, Whiting is a high-margin oil company, and our production is on track to go 20% to 23% in 2012. We're very encouraged by the continuing results of all of our Williston Basin acreage, and we estimate that we have at least 10 years of future drilling inventory in our Williston Basin plays alone. Outside of the Williston, we are experiencing strong results in our DJ-Niobrara play and are building significant acreage positions in exciting new areas.

Operator, please open up the conference call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] First question comes from the line of John Freeman of Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

I'm just trying to think about -- just generally make sure that I'm thinking about kind of 2013 and 2014 the correct way. You basically, you've got the 20 rigs in the Williston Basin and you've got, obviously, the 7 rigs in Sanish where you're getting very good efficiency, some around like 15 wells per year per rig. And the other areas in the Williston as we start to move towards pad development, that sort of gap starts to narrow with the rigs being outside of Williston, kind of narrowing the efficiency gap with Sanish. And if my number's right, I think you've got like close to about 50% of your rigs in Williston will be sort of pad capable by year end. And I guess what I'm trying to think about is when we're looking at next year, you still can look like you could draw 20% next year and not necessarily have to increase the Williston rig count just because of those efficiencies. Am I thinking about that right?

James J. Volker

Well, I think your answer to your own question there is probably accurate, John. And we haven't provided official guidance and likely won't do so until January or February of 2013 because we want to see what continues to happen to oil prices. And fortunately for us, we have the flexibility with our rig fleet to adjust accordingly, either upward or downward. So I guess to cut to the chase for you, if our budget was about the same, I would say, yes, is the answer to your question. If our budget was a little less, say, we cut it back to something like $1.7 billion. Then we would prefer that you kind of start your growth estimate lower at around 10% and let us grow into it as we see what happens, both to oil and gas prices, as well as, I think, as you correctly anticipate, our continuing finding cost efficiencies.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay, that's very helpful. And then just looking at the drilling CapEx for this year, is there anything in particular that would drive the CapEx lower here in the fourth quarter? It looks like we're sort of implied by the full year CapEx budget.

James J. Volker

There's a couple of things happening. Yes, we're on a more rapid pace than that, but we're dropping 3 rigs and they probably won't be replaced until the first quarter of 2013. Second, we have also basically drilled about 10 more wells in 2012 than we originally estimated. So that's sort of the reason for the higher cost to date and the reason why we expect things to come in a bit in the fourth quarter.

Operator

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

So the Niobrara seems to be -- appears to be your top focused area outside of the Williston Basin right now. And -- so it sounds like you've started test, the A bench. Can you give us your view of where do you think you'd go on this play over the next year or 2 and what the down-spacing in multiple bench potential could look like?

James J. Volker

Go ahead, Mark.

Mark R. Williams

So you're right, Scott. The Niobrara is taking on very accrete significance for us. We have had good success in our acreage position in the B so far. We've just completed the first 2 Niobrara A wells, one sort of up on the northeast side where we map the sort of the sweet spot of the A. And so we're actually, this week, in the process of completing that well so we don't have any results on it yet. But I think the most important takeaway from all this is the Niobrara has -- our focus here is on oil plays. We figured if the oil play is there, we'll figure out a way to get it out. The Niobrara has tremendous oil plays, and our recovery efficiencies based on the wells we drill suggest that 4 wells per spacing unit is probably a little bit light. We think that it could go above that to 6, possibly even 8. You'll see our competitors are out there with similar numbers. So I think those are the 2 big changes for us: Niobrara A, which we think is going to work, don't have the results yet; and increased density.

James J. Volker

Just to comment a little bit further for you, Scott. The average IP for all of our wells, excluding the first 3 science wells is 517 BOEs per day. And they're averaging, for the first 30 days, about 250 BOEs per day.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And when you look at your relative activity, I think you're running a couple of rigs there now. Would you likely ramp that into the next year, assuming, say, flat -- flattish kind of oil prices? Is the JV an option to help you kind of accelerate activity there?

James J. Volker

Yes, to both of your questions, Scott. So with or without the JV, the answer is yes. And with the JV, the answer is sort of an empathic yes.

Operator

The next question comes from Mike Scialla of Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Had a couple more questions on Niobrara. Jim, you mentioned the first 3 wells there were science wells, more or less. Anything you've seen from any of the drilling you've done so far that would suggest that any parts of the acreage are better than in the others? It seems like you're getting some real good success in this Wildhorse area and that all the way over to the Horsetail. I'm just wondering if you can get any sense on the variability you're seeing in terms of any geologic attributes at this point.

James J. Volker

Well, we continue to be positively surprised by the results of wells being drilled by us and by others. So whereas -- where we originally thought there'd be sort of a long hot dog basically running Northeast, Southwest, in the sort of down the center of our acreage position, we now see that having extended substantially to the South. And as a result of what we now know from the science we have done about the A zone on the north, we're very positively impacted, I think, by that thought that a greater portion of our acreage is going to be in the sweet spot, either for the A or the B. So if I had to guess at this time, I would say that somewhere between 100% and 67% is going to be good acreage and productive for us. And we'll try to continue to refine that. We think the whole thing is going to be productive, but I'm going to say if you want to say what areas would be up there in the 3:1 or better on our money, then I'm going to say at this point, our best guess would probably be about 67%.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. Any structure issues that you're facing there? And do you plan to put your own gas plant in? Or how does the infrastructure look?

James T. Brown

Yes, Mike, it's Jim Brown. Currently, one of the acreage acquisitions we made out there came with a small gas plant, so our guys have upgraded that. And all of the wells we've drilled to date, we've got either hooked up to that gas plant or to a third-party line out there. We are looking at installing our own gas plant out there, and we're going to be making that decision here very soon. But I think it's more than likely that we will be building our own plant out there.

Operator

Next question comes from the line of David Tameron of Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

I'm going to go back to the Bakken. In Sanish, and I've gotten some questions about it, it looked like production was flattish quarter-over-quarter. Can you talk about what current production is and how you guys -- kind of what the outlook is? I know you talked about through 2014, but can you talk about what your volume profile will be over the next couple of years?

James T. Brown

Yes, as we've mentioned that, we're doing pad drilling. We're well into pad drilling in Sanish and so that production is going to be kind of lumpy up there. So for the third quarter, it looked flat. If you looked at our exit rate from Sanish, we were up considerably. We -- our exit rate out of Sanish as of September was 33,350 BOE per day. So it just depends on what time period you look at and what's going on recently in there. So both Sanish and Pronghorn are going to be kind of lumpy just because of this pad drilling that we are employing right now.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And Jim or -- Jim or Jim, whoever wants to take it. If I extend this out the next couple years, can you give us any -- just a breakdown in where production profile, where it should be coming from, like what the major regions are going to be? Is Niobrara going to be 1/3 of the growth and Bakken 2/3. Or how, with EOR in there, can we -- any framework you can give around that.

James J. Volker

I'll try to give you more color that as we get close -- as we come out with our Q4 results. And the reason I say that is that we basically are evaluating exactly what's happening just as, I'm going to say, question indicates. And we'd like a little more time to take a look at what's happening there in the Niobrara and decide how far to push the accelerator pedal down. And we've got several wells that are in the process of being completed right now, including our 2 A zone wells. So we'll kind of make that determination between now and the time that we come out with our Q4 results. The only thing I can tell you is that as we look forward to 2014, even with, I would say, prices lower than we see today. And I'm not saying that will happen, I'm just saying that we're making sure that, in the event that it does happen, we're putting our capital to work in the most capital-efficient, highest rate of return areas for us. And I think we've done actually a very good job with that. And I'd call your attention to Slide 7, which I know you -- is not lost on you at all, to show that actually we are becoming more efficient, more effective and actually more productive as a result of where we are applying our capital. And one of the interesting things about that, as we look at 2011 and compare it to 2012, and I'll just talk about 90-day rates here, if we were to compare Sanish-Bakken -- the Sanish-Bakken 90-day rates 2011 to 2012, they went from an average of 528 to 582. So things got better in the Bakken and Sanish. Things also got better in the Three Forks of Sanish. Our 90-day rate was about 288 in 2011 and it's 306 in 2012. And so the only thing that's happened is we're drilling -- we obviously are drilling more Three Forks wells. The Three Forks wells are somewhat less productive than the Bakken wells. On the other hand, the good news is that outside of Sanish, wells that we are drilling in Pronghorn and Lewis & Clark and Hidden Bench, when we combine those, have the results that are shown for you there on Page 7.

Operator

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

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

A question on what you call the Lewis & Clark area outside of Pronghorn. Has there been any recent drilling there? Have you de-risked any more of that acreage from what you said, I think, going back a few quarters ago?

James J. Volker

Well, first of all, I'd like to comment on the de-risking. What's happened here in the last year is that, as a result of drilling by others, the whole area is really de-risked. We know it's all productive, and the primary reason that we can drill faster, for example at Pronghorn than greater -- than Lewis & Clark, simply has to do with the permitting time on some federal acreage that's over there at Lewis & Clark.

Mark R. Williams

The thing that happened there is that at Lewis & Clark, we have a pretty vast acreage position there. And because of the permitting issue, it's slow getting to drill out all of those units. What we've seen though in general, or in terms of results over the last year, is that the Western, Southwestern margin, we pushed it right up to the edge of our acreage position there. We've got good product --a new good productive well there on the southwestern part of our acreage that gives us confidence. We can drill right up to the, essentially, the pitchout of the Middle Bakken there. The northeastern side of our acreage, we have expanded as well. We drilled a couple of new wells and so we're -- the core where we've been developing or expanding concentrically out from Lewis & Clark, is still getting good results.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. So when can we expect -- why aren't we starting that program?

Mark R. Williams

Well, we are starting it. But what's really slowing us down -- unlike most of the Williston, this is almost all federal acreage in this area. So that's the thing that's really kept us from getting out there and getting more rigs after this project.

Michael J. Stevens

We've had 2 to 3 rigs running there this year as compared to 5 or 6 in Pronghorn. And the main reason, as the guys have commented, is just that the permitting is a little slower there. And also, the Pronghorn is a higher rates of return, as we've said in the past.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it, okay. And then the CapEx in the third quarter was a little heavier than I was modeling. And I was wondering if there were any acreage component in there compared to the previous quarters. And if there is, if you could comment where that is?

James J. Volker

No, just basically faster drilling.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then -- so the 3 rigs that you're dropping, can you comment -- I don't know if you mentioned where that is. Is that Bakken?

James T. Brown

Those are -- they are scattered across all the -- I think there's one in Missouri Breaks, one in Hidden Bench, one in Pronghorn, but those rigs are all going to be replaced sometime in early 2013 with newer more efficient rigs.

Michael J. Stevens

I'll comment, Biju, on our capital. When we hit a peak rig count during the quarter, and as Jim alluded to earlier, that meant we drilled a few more wells than we had anticipated during the quarter and that shows up in our strong exit rate for the quarter.

Operator

Your next question comes from Will Green of Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we could follow on to that last one. You mentioned you're dropping 3 rigs, one in Missouri Breaks, one Pronghorn and one in Hidden Bench. You're adding 3 more to replace those in '13. Do they go to the same areas, whenever they come back?

James T. Brown

Yes, we're going to do a little bit of shuffling with rigs. But I mean, simply, they're going to go back into the same area.

Will Green - Stephens Inc., Research Division

Got you. And then, I don't think we've touch on it yet, but Belfields, you guys noted you're hooking up other operators in November. Where do you see utilization for that plant, say, by spring time?

James T. Brown

Well, we're in the mid-teens right now for inlet and I'm just trying -- I'm trying to think of the latent capacity we've got out there, but we should be in the mid-20s sometime -- by the time we get into the third quarter -- or into the first, second quarter next year.

Will Green - Stephens Inc., Research Division

That's great. That's been a great project. And then the last one I had was North Ward Estes. Production declined a little bit sequentially. Could you guys just maybe provide a little bit of color around that?

James J. Volker

They're reservoir. Basically, the phase that we're in right now is one that is -- when we talk about phases, as you know, we have 8 different development phases there. And essentially, one of the phases that we're most active in right now is taking a little longer to pressure up and fill up. The good -- so that means the response is slightly delayed. However, I can tell you that we're now very pleased because we are getting initial response and that's putting us back on an uptrend at North Ward Estes. So what it really means is there was more porosity there to fill up and pressure up, which means ultimately greater recoveries.

Will Green - Stephens Inc., Research Division

Great. So we should see that uptick again in the fourth quarter then.

James J. Volker

Yes, I think we'll see an uptick there and, if you don't mind me commenting on Postle, Postle has been above its forecast all year long. In addition, we now see the ability to drill beyond the existing patterns that we've already installed, basically between the edge of our existing pattern and our -- the edge of our leasehold. So essentially, there's some great banked up, exceptionally low-risk oil to go after out there and I think that's going to bode well for our Postle reserves at year end.

Operator

Next question is from Brian Velie of Capital One.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

I just wanted to ask about progress or anything you might be able to share on the Schaal well, the first horizontal there in the Red River?

James J. Volker

Okay. Well, the Schaal well is, again, a well that we drilled horizontally, essentially between the Red-- the upper Red River D bumps. So this was a concept to see if we could get some of that matrix in there to produce and also an attempt to determine whether the fractures that we saw there were water-bearing or oil-bearing. So the answer is they're predominantly water-bearing. We don't think, therefore, this particular concept of going horizontal in an attempt to cross those fractures is a great idea. On the other hand, it is still a good idea, we think, to go horizontal. And rather than stay, I'm going to say, between and away from the porosity zones that we see in the bumps, the second thing we can do there, and will attempt at some point next year, is connecting the 2 porosity zones in the upper Red River D from one bump to another. Separately, there is the concept of a resource play in the lower Red River D, which was tighter and look and we think may react a bit like the Bakken. It's got a lot of oil trapped in it, but it's tight. And so early in 2014, we'll do -- that is in the first half of 2014, we'll drill a well for that concept -- I'm sorry, 2013.

Operator

Next question is from Pearce Hammond of Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

All right. Can you provide on update on any targeted divestitures? And if you are able to divest some assets, what are your thoughts on how the proceeds would be allocated?

James J. Volker

Okay, well, first of all, as you know, we've talked about royalty trusting, Postle. There's also been, frankly, a high interest generated from third parties on some of our assets. I don't want to be too specific on that. But at any rate, there's been strong interest there. There's been strong interest in JV-ing with us. We're fielding those inquiries and responses and so I don't have anything in particular to announce. But moving onto the second part of your question, how might the proceeds be used, and without picking a dollar amount, I would say half of it would go to pay down debt and half of it would go to accelerate drilling in the Williston Basin.

Pearce W. Hammond - Simmons & Company International, Research Division

Great, that's very helpful. And then just one other question. As you're going to your budget planning for next year before you announce your guidance in, say, January or February of next year, what are you seeing on service cost? Are you expecting a decent amount of service cost deflation in '13 relative to '12?

James J. Volker

Yes, we are, and we're also expecting some efficiency improvements. We've talked a little bit about that. Moving in an even better equipment. I mean, the great thing is that both the drilling contractors and the pumping service providers have both really -- they get it. They're bringing in more equipment and more crews. And the quality of what they have up there is producing both in terms -- is increasing both in terms of the equipment, new equipment, stronger equipment, better equipment and better crews. And we, by the way, are responding by making the facilities that Whiting has up there to house those crews and make a good environment for them available to them. So we have a good relationship with, I'm going to say, all 3 of the pumping companies and half a dozen different drilling contractors up there, both on drilling rig side, as well as the work-over rig side. And so I'm very optimistic about the availability of services. We're working closely with the state to essentially continue our program of hooking up our wells ASAP to our oil and gas gathering system that reduces the number of trucks on the road. So we're just becoming more efficient overall up there. I think we're a bit ahead of the curve in the sense that at our current rate of drilling, we really have all of the services, and in my opinion, some of the top quality services available to us. That's what's making, I'm going to say, one of the reasons that you see these productivity gains that we've talked about here today.

Operator

Next question comes from Jason Wangler of Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just had a question on the differentials there. Obviously, you've seen them coming in pretty nicely and obviously, your guidance is kind of ratchets them down a bit. Do you think that there's a steady state we're going to kind of get to with all the real capacity and everything? And what are your thoughts, just in the general, as we move forward there?

James T. Brown

Yes, I mean, I still think that we should start to see the crude at Clearbrook trade at something that's going to be like a landed brand or an LLS-type price minus the transportation to get you back to Clearbrook. I think that's the price we're going to move to. So we're still -- there's still a little gap in there right now, if you do the math to get back there. But that's what my expectation is. Naturally, there's going to be the interruption that occurs that is unplanned, but I think that's where we're headed long term.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. And just maybe -- just so I have the number handy, what is that transportation cost looking right now and even maybe going forward?

James J. Volker

We're saying that you can get a barrel down to the St. James market for about $15.

James J. Volker

Yes, just to further comment on that. We basically got the gathering and transportation cost on Page 2 of our news release for you, at least as it was in the middle of the month. And it was $6.34 of gathering and transportation, so that's where it is now.

James T. Brown

Right. And that's going to Clearbrook.

Operator

Next question comes from Mike Scialla of Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Just want to follow up a couple of more on the Niobrara. I think you said in the past that you thought you could drain all 3 benches from the B Bench and now you have couple of wells tested in A. Just wondering what changed the thinking there or as -- yes, I guess, basically that. Did something change your thinking? And is the -- are all 3 benches present over all of your acreage?

Mark R. Williams

Well, Mike, they're -- actually, there's 4 benches altogether. And the way we map it right now, the B is by far the dominant one. The A also looks very good on the northern part of our acreage. We really don't think right now, or at least we haven't gotten any reason to believe that the C and D are going to be productive. We did try well down there, but the B and the A are really where all of this is. And there's a fair -- the section between the B and the A contains quite a bit of what's called bentonite clay in there. And the good news is, is that provides a good frac barrier, keeps our fracs isolated between those 2 zones. But it really means that we can't process the A and B together with a single well. They're going to be separate objective wells. So our -- what we're doing right now is trying to prove up the A both on the north side of our lease where we see a really nice sweet spot, as well as the area that we're drilling in the B more on the west side of the acreage.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And in terms of your well cost, it looked maybe a little bit higher than some of the other operators in the play. You guys have been known for very low well cost. Can you address that at all?

Mark R. Williams

The main thing that's happening there is that we have a large acreage position. We continue to do a fair bit of science, both coring as well as putting on different-sized fracs and so forth. And so there's a fair number of science wells. Incorporated with what now are development wells. And so we're getting our cost down to right around $3.5 million for Coffey [ph]. We think that going forward, our development cost is going to be sort of in that range. I think we've been averaging closer to $4 million prior to this point. But as we go into development phase and start to drill out our spacing units here, we think we're going to be right around $3.5 million.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, and that's quite a bit lower than what I'd thought, but I was under the impression you were drilling for $4 million to $5.5 million but...

Mark R. Williams

Those are for the 6 40s, we're also doing 9 60s out there. And you can pretty much add about $1 million to each those -- to the 9 60s relative to the 6 40s.

Operator

Next question comes from Mike Kelly of Global Hunter.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Slide 7, I think is a great slide that benchmarks the Pronghorn and the Hidden Bench and Lewis & Clark against the Sanish. And you made the comment that you see 10 years of drilling inventory out in the Bakken. And I'm just wondering, if we just took the acreage that's applicable to go into this slide alone, so kind of the de-risk portion so that the portions of these fields on this slide that you feel that you're going to be able to replicate these results from this slide. How many years of drilling inventory would you say you have under those assumptions?

James J. Volker

Well, the answer is still 10 years and that's because we really have been positively, I'll say, surprised and pleased by what we see as we think -- I'm going to say, you are now starting to see through our reporting and our results, for example, at Pronghorn and Hidden Bench. So in summary, I would simply say that our wells at Pronghorn and Hidden Bench seem to be basically replacing our Bakken wells at Sanish. That's really what's happening and -- in terms of productive capability and pretty much overall performance. Separately, we are -- we're drilling a few more -- we're drilling more. Typically, the ratio's probably around 2/3, 1/3 Three Forks wells at Sanish. But that's been the story really for 2 years now. So -- and we've said for 3 years now that we think that the reserves are somewhat lower in the Three Folks than they are in the Bakken. So really what some people sort of are writing about actually happened over the last 2 years and the case going forward is basically what you're seeing on Page 7, that the productivity of what we're drilling now, and have for the last year, is actually better than what we're currently drilling, and have been, for the last year at Sanish. So we don't see any degradation in our productivity. If we did, we wouldn't be producing a 20% year-over-year production increase in 2012, spending essentially the same amount of money that we did in 2011. So it's time for people to kind of get that, and we put the slide out so that, hopefully, that sinks in a bit.

Eric Hagen

And then just to follow up on inventory, Mike, last year, we put out the de-risk slides and so on. The assumptions in there were extremely conservative. So for example, at Hidden Bench, we were saying we would drill 2 wells in the Bakken and Three Forks, and our current estimate is 4 and 3. So if you were just to revise that slide alone, you would more than double your well count there. So if you do simple math on our acreage, you'll see that just between Pronghorn, Lewis & Clark and Hidden Bench alone, we have somewhere around that 10 years' inventory. And that doesn't exclude -- or include Missouri Breaks where we have drilled successful wells west, east and we actually have our first well -- I'm sorry, west, south and have our first well on the eastern half of the field flowing back and that looks like it's going to be a good well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay, great. That's really good color. One other question for me real quick. If you have success with your horizontal in Big Island, how many potential wells do you think you could drill there from the horizontal perspective?

Mark R. Williams

Well, we haven't really laid it out with horizontals just yet because we're still testing that Schaal well. I can tell you about our vertical wells, we've identified up to 50 different opportunities to drill our vertical wells there and we think that we have opportunity to drill up to 2 wells on each of those. So at any rate, we're still trying to figure out whether the vertical approach or the horizontal approach is going to work best. But either way, I can tell you the vertical wells are among the most economic of everything in our drilling inventory right now. We're trying to get our horizontals so that they can match that.

Eric Hagen

And the lower Red River D, as Mark has commented in the past, is fairly continuous across our acreage. So if there's a resource play there, it's likely in the lower Red River D and that would be the kind of more repeatable play we're drilling in other areas in the Williston Basin.

Operator

Next question is from Ray Deacon of Brean Capital.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

My question was about the differential and maybe one further question on that. The investments that you talked about making in the Bakken, does that affect the crude price you receive looking out to next year, I guess?

James J. Volker

Well, yes, it does in 2 senses. A, when we put in these gathering systems, basically, we're saving around $3 a barrel on trucking. And then second, it helps us by virtue of being connected to a good market. And as I think everybody's aware, that the easiest and best market out of the Bakken is the Enbridge system that goes into the Minneapolis and Chicago market. However, the good news there is that because of the planning we did almost 5 years ago now where we built a line capable of handling 65,000 barrels a day up to the Enbridge line, when the Enbridge line only had a capacity of 65,000 barrels a day and now has a capacity of over...

James T. Brown

300,000.

James J. Volker

300,000 barrels a day, we are ready to service the expansion of that market. And for those of you who have sort of been following what's been going on with the transfer of ownership of the Philadelphia area refining complex, that is a great market. I'm going to say, it loves light sweet crude. It used to refine Brent and now it wants to refine Bakken. And so the great thing is that I think, in addition to all the reasons that Jim Brown cited, that demand, as it comes on stream and gets stronger, is going to continue to narrow the differentials that you see in the Bakken. That is a great market, and in my opinion, everything as you go east, all the way out to Philadelphia, should become a market for Bakken crude, and frankly is. I mean, we're working on deals right now to basically -- we have offers from people who want to get a commitment for us to -- for roughly at least 10,000 barrels a day at a very favorable meaning around the current differentials that we're seeing, if we will commit our crude to them for a period of time. So we're not there with them yet because, as I said, I think things are going to narrow and I want their bid to reflect that narrowing. But nevertheless, that market is there and it's getting stronger. What I could tell you is that market continues to rise as more crude gets refined there. I really expect that to be a voracious market for the Bakken crude.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Right, right. And any update on testing of the residual oils on the Ross or...

James J. Volker

Well, yes, visual results appear to be good and there are some adjacent zones. And I would say that in terms of the resource potential there, we've always said it'll be somewhere between, I'm going to say, 100 million and 150 million BOEs and I think it's still definitely in that range. Some of the zones that we're looking at there, like the Glorieta and some of the adjacent zones, have gotten bigger. Some have gotten smaller. But overall, the potential still stays in the 100 million to 150 million BOE range.

Operator

Your next question is from Hsulin Peng of Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

I have a follow-up question to the asset divesture question earlier. Just in general, how do you think about balancing your long-term sustainable growth rate and also your capital resources available to you? Because it seems like you guys have a lot of options for cash sources, whether it's joint -- potential joint venture or if you charge for Postle and your [indiscernible] assets. I'm just trying to get a better understanding for how you think about that and I'll leave it at that.

James J. Volker

Okay. Great question, Hsulin, as always. Well first of all, of course, what we're thinking about is using those assets in order to enhance our net asset value per share. And what we're really doing there is we're releasing assets that, as you know, in round numbers are valued at around $20 per BOE within Whiting, and we're getting them sold for cash at around $30 per BOE. And so then we're deploying some of that cash to pay down debt, which of course has an immediate positive effect. And using, as I said earlier in my comments, roughly half of it to accelerate the drilling in our lowest FND cost areas, i.e. in the Bakken and perhaps now in the Niobrara. So that's how we do it, that's how we think about it. And you hit all the options, whether that be a royalty trust or an outright sale or a joint venture with some people who enter and reimburse/pay us for our acreage cost, as well as pay a slightly greater amount of drilling completion cost in comparison to the working interest that they would acquire. All of those things accomplish that end of raising our net asset value per share because it makes -- it puts our capital, the work in the most efficient manner. I will say that, historically, we have liked the royalty trust approach because it keeps us as masters of our own fate in regard to that asset. We get to continue to operate it. We get to continue to see that it is developed in the most efficient manner. And then ultimately, after we produced the amount of barrels that we have sold to the public, then we get that asset back. So the only difference really between the royalty trust and an outright sale is that we would expect that somebody would pay up for the tail out there beyond that 10-year period if they want to buy the whole asset, you follow me? So -- and that's why there's a difference. I'm going to say, in the total amount of funds we bring in, typically in these royalty trusts, we basically sell a 10-year period of production and we typically retain during that 10-year period around 10% of the asset. So that's why you don't bring in quite as much cash as you would in an outright sale. I hope that's helpful.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Yes, no, very helpful. And then just a follow-up that as well. In terms of -- you say if you pay down 50% of the proceeds to pay down debt, so generally, is there a particular debt metric that you would target or want to stay sort of within the range of?

James J. Volker

Yes, well, historically, we've run between roughly a 25% and a 40% debt to total cap. So there've been times when we run it up toward the 40% level and there have been times when we've had it at the 25% level. We're about in the middle there now and we're comfortable in that range, and I would expect that we'll continue to stay there through the same methods that, I'm going to say, your question just drew my answers out on. And I don't see any change in that. And basically, it's a philosophy that tells you, a; maximize where you're putting your capital. Drive that NAV up. Never be afraid to take a profit. Nobody ever went broke taking a nice profit, right? And second, I would say that I hope, in this time, when oil prices have come in, people realize that there are some companies, Whiting included, that are basically running themselves right around their discretionary cash flow and still growing. So we're not out there spending 1.8x or 2x our discretionary cash flow because, essentially, we think we would rather grow not, let's say, at 50% growth year-over-year but we'd be happier in the 10% to, I will say, 20% range without having to vastly outspend our cash flow and then waiting for an appropriate time when prices are even higher to accelerate our growth. And I think, and I hope, that this conference call today has shown that we certainly have the ability to do that on all of our acreage across the Williston Basin because, basically, it's all in the productive window. And we're doing it very efficiently and effectively, as we have now shown you we have been able to do quite clearly with Slide 7 in 2012 compared to 2011. Things are actually getting better.

Operator

Next question comes from the line of Jason Stocks [ph] with Hallet Advisors [ph].

Unknown Analyst

I was just following up on the last question. So then you were explaining that you can sell your assets into a trust at $30 a barrel and that you're trading at about $20 a barrel. It's very unusual for a growth-oriented E&P company to buy back stock. And I was wondering, is the reason that you wouldn't buy back stock the fact that you actually had reserves at a discount to the $20 a barrel that you are currently valued at?

James J. Volker

In short, the answer is, yes, and the most efficient areas, of course, for us are the areas that we're currently developing, the Middle Bakken and the Three Forks and the Niobrara. So they all have the potential to be in that range, let's say, at $18 or so per BOE.

Unknown Analyst

So that's where you think the defining cost is for those projects, is around $18 and you're trading at about $20?

James J. Volker

Yes.

Unknown Analyst

So do you think that if your company was trading below your finding cost, that you would consider using part of the proceeds to buy back stock? It would be unusual.

James J. Volker

Yes, I think if that happened, we might consider it. That's not -- I mean, we're still trading above our finding cost, so that's not the case that we have to deal with it. What we are concerned with, of course, is basically proving to the market that our growth can continue at this pace, and I think the market is starting to realize that as a result of, what I would say, some of the more correct research that's being done on us.

Operator

That's all the time we have for questions. I'd now like to turn the call over to Jim Volker for closing remarks.

James J. Volker

Well, thank you so much, operator. I'd like to thank all the Whiting employees and directors for a job well done in 2012 and for the exciting plans we have for the remainder of the year. Eric?

Eric Hagen

Jim Brown will be presenting at the Bank of America Merrill Lynch Global Energy Conference in Miami on November 13. Mike Stevens will be presenting at the Capital One Energy Conference in New Orleans on December 4. Jim Volker will be presenting at Hart Energy Conference in Denver on December 6. And Jim Brown will be presenting at the Wells Fargo Energy Conference in New York City on December 7. We look forward to seeing you all at these events.

James J. Volker

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

Operator

Thank you for joining today's conference. That concludes this presentation. You may now disconnect. Have a good day.

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