Eric K. Hagen - Vice President-Investor Relations James J. Volker - Chairman, President & Chief Executive Officer Michael J. Stevens - Chief Financial Officer & Senior Vice President Rick A. Ross - Senior Vice President-Operations Mark R. Williams - Senior Vice President-Exploration & Development.

Scott Hanold - RBC Capital Markets LLC Neil E. Wiese - SunTrust Robinson Humphrey, Inc. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. David A. Deckelbaum - KeyBanc Capital Markets, Inc. Ryan Oatman - Cowen & Co. LLC Brian Michael Corales - Howard Weil David R. Tameron - Wells Fargo Securities LLC Timothy A.

Rezvan - Sterne Agee CRT Jason Smith - Bank of America Merrill Lynch Tarek Hamid - JPMorgan Securities LLC Mike Kelly - Seaport Global Securities LLC Paul Grigel - Macquarie Capital (USA), Inc. John Nelson - Goldman Sachs & Co. Michael Scialla - Stifel, Nicolaus & Co., Inc. Kevin Douglas Andrus - GMT Capital Corp..

Good morning. My name is Keith, and I will be your conference facilitator today. Welcome everyone to the Whiting Petroleum Corporation Third Quarter 2015 Financial and Operating Results Conference Call. The call will be limited to one hour, including Q&A. All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer period. Please limit your questions to one question and a follow-up. I will now turn the call over to Eric Hagen, the company's Vice President of Investor Relations..

Thank you, Keith. Good morning and welcome to Whiting Petroleum Corporation's Third Quarter 2015 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 2015 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 presentation slides, please click on the Investor Relations box on the menu and then click on the Presentations & Events link.

Please note that our remarks and the 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 number one in our earnings release.

Reconciliations of non-GAAP measures we refer to and the GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-Q for the three months ended September 30, 2015 is expected to be filed later today. With that, I'll turn the call over to Jim Volker..

Thanks, Eric. Hello, everyone, and thanks for joining us. We're going to get to your questions just as soon as possible. So we'll be brief with our comments. Production at Whiting averaged 160,600 BOEs a day; that's net after 8,700 BOEs a day of property sales.

Our new completion designs in the Williston Basin are delivering 44% production increases over second quarter 2015 on a per well basis. We reported outstanding results at our Johnson pad in our large Cassandra area, which tested an average rate per well of 5,224 BOEs per day.

Year-to-date, we've sold approximately $400 million of assets, an increase of $100 million over the third quarter. We anticipate further timely non-core asset sales by year-end. After our redetermination with our banks, our credit agreements from our bank group remain unchanged with commitments at $3.5 billion.

This demonstrates the confidence our banking group has in the quality of our assets, and in our strategic plan. On slide number three, you can see our strong capital structure. We have $38 million in cash on hand, and nothing drawn on our $3.5 billion of commitments, on our $4 billion borrowing base.

We are well positioned from a liquidity and debt maturity perspective to deal with lower oil prices. With a focus on the Bakken and the Niobrara, our total net production averaged 160,600 BOEs per day, after the sale of 8,700 BOEs per day in the second quarter.

As you can see on slide number four, 93% of our total production in the third quarter came from our Rocky Mountain region. Within that region, 131,000 BOEs per day, the Bakken/Three Forks represented 82% of our total production. We continue to be a focused company.

On slide number five, we provide an overview of our plays in the Williston Basin where we control 668,000 net acres. We control the sweet spots in the Central, Eastern and Southern Williston Basin and continue to increase productivity with new completion technology.

During the third quarter, we completed wells with average frac/sand volumes of 5 million pounds versus 3.5 million pounds in the second quarter. The third quarter wells achieved 30 day average rates, 44% better than the second quarter. Turning to our Redtail field, we completed 15 net wells in the quarter.

Slide number eight shows the infrastructure at Redtail. We're pleased to report the construction at phase 2 of our Redtail plant was completed a bit early during the third quarter. This expands plant inlet capacity to 50 million cubic feet of gas per day from 20 million cubic feet of gas per day.

I'll now turn it over to Mike Stevens, our CFO, who will discuss our financial results in the third quarter..

On slide number nine, you can see our third quarter 2015 financial results. Our net income reflects non-cash charges on non-core assets. The majority of the charge is at our North Ward Estes CO2 field and was related to the decrease in oil and gas prices at quarter end. We also wrote down the goodwill associated with the Kodiak acquisition.

Our discretionary cash flow in the third quarter totaled $280 million. Our unit costs in the third quarter of 2015 have improved significantly from the third quarter of 2014. Our DD&A rate per BOE has dropped 20% to $21.40. LOE per BOE has decreased 26% to $8.50 and G&A per BOE is down 12% to $3.03.

Our guidance for the fourth quarter and full year 2015 is detailed on slide number 11. We left our fourth quarter production guidance unchanged at 153,000 BOEs per day. Here is detailed the quarter's CapEx illustrating the path to our 2016 approximate $1 billion all-in CapEx budget.

We spent $266 million in development capital in the Bakken and Redtail and $137 million on non-op drilling, facilities, EUR, exploration and land. We anticipate that CapEx on these items will decline significantly in the fourth quarter.

In combination with the impact of dropping three rigs late in the third quarter, we anticipate all-in fourth quarter CapEx under $300 million. On slide number 12, you can see we maintain a strong balance sheet with $38 million of cash on hand and nothing drawn on our $4 billion borrowing base.

Slide number 13, shows our outstanding bonds as of September 30, 2015. It also shows that we are well within all of the covenants in our credit agreement and our bond indentures. Slide number 14 shows our crude oil hedge positions as of October 1. We're 52% hedged for the fourth quarter 2015 and 45% hedged for 2016.

With that, I'll turn the call back over to Jim..

Thanks, Mike. Ladies and gentlemen, to summarize, in the third quarter, we decreased our capital spending 46% and, as planned, still maintained a flat production profile after asset sales. We achieved this while keeping our balance sheet strong, with $38 million of cash on hand and an undrawn $4 billion borrowing base.

We remain committed to our goal of maintaining a strong balance sheet, while positioning the company to run well in a $40 to $50 oil price environment.

With that, Keith, would you please open up the conference call for questions?.

Yes, thank you. And the first question comes from Scott Hanold from RBC Capital Markets..

Morning, Scott..

Hey, how're you doing?.

Great..

So, maybe let me start first and, Jim, you kind of ended the comments by saying you're positioned to obviously for this $40 to $50 environment.

Is your current level of activity or where you think you're going to be by the end of this year sort of that optimal level to be at if this is a kind of lower for longer range?.

Yes..

Okay. And then, with respect to obviously the focus is – really high focus on CapEx levels, and they did come in a little bit above expectations this quarter.

Could you give a little color on some of the major items and how that certainly starts to improve as we kind of migrate toward the end of this year?.

Yes, we will. We anticipated that question. Mike's going to try to answer the first part of it, and I'm sort of going to answer the second part..

So, the main reasons that third quarter was elevated was due to facilities and non-operated drilling. On the non-operated drilling side, the AFEs that we approved back in 2014, many of them are just now being drilled, completed and then it takes awhile for them to bill us.

So, it's a little bit surprising on some of the delay that's went on; the schedule's not very predictable. If you look at the non-operated, the trend so far this year, it's went from $133 million in the first quarter down to $78 million the second quarter and it stayed up a little higher than we thought at $58 million in the third quarter.

We just don't have complete visibility in all that spending. On the facilities side, the expansion, basically a lot of the facility costs at Redtail came a little quicker than we thought. We did complete the plant – moving that up to $50 million a day. We got the Redtail water systems and the electrical systems finished quicker than we thought.

And all of those items are going to have a positive impact on LOE, which is why you can see me guiding the LOE down a little bit when we move into the fourth quarter. So, we do expect these items to normalize, and CapEx to come in under $300 million in the fourth quarter.

The other item that has a lot of impact on CapEx is how many rigs you're running. We're running 11 rigs. We dropped three of those in September, so late in the third quarter. So the impact of that will benefit the fourth quarter, but the completion activity will still be going on for those wells drilled.

So the ultimate benefit of dropping those three rigs will really happen in the first quarter of 2016..

And then to talk in general about non-op going forward, we've dealt with the non-op by, as we mentioned in the second quarter press release, packaging up a large number of our non-op Williston Basin on a wellbore-only sale basis, wherein we achieved to-date over $11 million of cash payments and achieved a non-cost bearing overriding royalty interest going forward.

So it'll be easier to predict the non-op level as it declines, and second of course, as we concentrate therefore on our operated drilling. I hope that helps you..

Yeah, yeah.

Thanks, it does, but – and could you give us a sense in that sort of under $300 million number then what is the expectation for non-op in 4Q, so we can kind of look at the progression of $133 million, $78 million, $52 million? What is that planned number for the fourth quarter for non-op?.

$15 million to $20 million..

$15 million to $20 million. Okay.

And is that net of any kind of package – your wellbore package that you put together?.

Yes..

Okay. Appreciate it. Thank you..

You're welcome, Scott..

Thank you. And the next question comes from Neal Dingmann from SunTrust..

This is actually....

Morning, Neal..

Hi. How are you? This is actually Neil Wiese in for Neal Dingmann....

Okay..

Just a quick question on Cassandra, you guys had a lot of strong results there after some strong results in Dunn County last quarter.

Just curious on where you guys see that well design going after upping the profit levels? And again a follow-up to that; if you guys see any upside to that Williston type curve, if we could see a revision there by year end? Thanks..

The answer is we're in the process of looking at that type curve right now. And as you know, we've already announced that we've been seeing, really across the board in the Williston Basin, over a 40% and in many cases up to a 50% increase in the first 30 day rates, 60 day rates, et cetera.

So the longer we have in order to come up with an adjustment in that type curve to ultimately predict EUR, the better we'll be at it. But, we do anticipate some uplift in our EUR.

I'm not going to give you a number yet, but it should be significant as we move forward with this current completion design, and, I might say, improvement in our economics as we concentrate on, as you know, keeping our costs down. Our costs basically have come down from $8.5 million last year to $6.5 million or less this year in the Bakken.

And they've gone from $6.5 million at Redtail to $4.5 million. So, we are very pleased with what we've been able to accomplish. We're very pleased with the really great cooperation we've received from the service companies. And we, frankly, anticipate that the improvement in design and the reduction in cost will allow us to prosper at even $40 oil.

Thank you..

Perfect. Thanks, guys..

You bet..

Thank you. And the next question comes from Jeffrey Campbell with Tuohy Brothers..

Hi, Jeffrey..

Hi, good morning. First question I wanted to ask you just with regard to thinking about 2016 spend. I think you've talked pretty specifically about trying to stay near or within cash flow and that can be tricky because of commodity price swings.

So I was just wondering, A) is there a level of overspend that would be tolerable and, B) will you perhaps increase your hedging in 2016 to help manage staying within cash flow?.

So one thing you'll note is that our level of hedging is going to go up as we sell these properties. And so we've sold a few more here, another 2,600 – 2,500 barrels of oil a day that will close in November. That was the sale that was in the press release at $52 million.

And so the percentage will rise with those sales and, yes, we will look to opportunistically put on more hedges..

Thank you..

Did you want to go back and maybe restate the first part of that question in case I didn't get....

That was pretty helpful.

I just wondered if there's some level of – just due to the vagaries of commodities, if there's some level of overspend above cash flow that you would consider tolerable?.

Well, as you know, we've got a $3.5 billion undrawn commitment from our banks and therefore we certainly have the ability to sustain some amount of overspending, but that is not, I'll repeat, not our plan.

If there were some exceptionally good results, and we elected to I guess I'd say speed up drilling in a particular area, as a result of exceptional results even at let's say $40 oil, if it really made good sense there, wouldn't be afraid to do that. But that's not, repeat not currently the plan..

Okay. Well, I think that was pretty explicit. Thank you....

You're welcome..

For my other question, I just wanted to refer to the press release which said the completions in Redtail we're going to pick up in the first quarter of 2016.

Could you tell me how many uncompleted wells you have in your current Redtail inventory coming into the new year?.

Rick Ross will answer that one..

Yeah, I would say, we've got a small inventory right now of uncompleted wells and that's really because we are drilling a larger pads. We're drilling 16-well pads, and two eight-well pads. And what's remained to be completed are just the wells that have been drilled on those pads prior to getting the drilling rig off.

And as we mentioned, those will be -completions will start in the first quarter of next year and probably be coming on production towards the end of the first part of the second quarter..

Okay, great. Thanks very much..

You're welcome..

Thank you. And the next question comes from David Deckelbaum with KeyBanc..

Hi, David..

Hey, Jim.

How are you?.

Good..

Thanks. Thanks for taking my questions. I was just wondering – either you or Mark could add some color to this.

Someone had asked before, but how many more tests do you have coming up with increased sand loading? Can you talk about specific pilots that you have ongoing right now that might stretch some of the completion techniques that we're seeing right now?.

Sure. Mark wants to answer that one..

Sure. I'll just say in general with regard to our completion program, we've made pretty much a wholesale switch now to larger sand volumes and along with that, really focusing on distributing that sand, which means more entry points. So, we've employed some other techniques to really help in that.

So, we were last year at 3.5 million pounds per well and now we're up pretty consistently up very close to 7 million pounds. It varies just a little bit. We have a few that are higher, few that are a little bit lower, but across the board we've increased sand volumes.

We're seeing exceptional results in the areas that we talked about, pretty much in the Central Basin. We're very concentrated there in Cassandra, in Hidden Bench, especially in Tarpon and that's really we've seen a pretty dramatic uplift in our initial rates.

We don't have tremendous amount of history behind those wells yet, but the last two or three months, we've been employing a lot of techniques to try and increase our number of entry points, converter technology, et cetera, and that's where we're really seeing the big productivity gains right now. And again, our rigs are fairly focused in that area.

We have rigs in all of our good areas, but that Central Basin area is a little bit gassier is really where we're seeing the best results right now..

Got it. I appreciate the color on that.

And then, Jim, could you give us some color just on – we saw the incremental $100 million of non-core asset sales, could you sort of give us like a lay of the land that where you guys are right now with sort of remaining packages and sort of expected timelines there?.

So the focus now – early on we focused on the sale of the higher LOE, older producing properties, conventional properties, basically in our inventory that typically had LOE around $20 a barrel. And so we sold 400 million of those and that's about 8,700 BOEs a day.

It's about 400 additional barrels there that we reported here since the previous release. So, going forward, we're going to be concentrating on the midstream and that includes the sale of our water distribution system at Redtail.

Water distribution and, even more importantly, our produced water, gathering and disposal system, which is now as a result of the money we put into it in the second and third quarter, pretty much complete and should serve our needs for the foreseeable future.

So, it's basically time to harvest that particular asset as well as perhaps some of our plants. But I want to underscore that we have strong interest, very strong interest in all of our midstream assets that I'd mentioned previously.

But we want to sell them for a good price and, most importantly, actually we want a good partner in there, someone who we believe will be a good operator of plants and put in the necessary capital. And I'm optimistic that we'll get both, based upon the strong interest we've received to-date..

Okay. Thanks, Jim..

You're welcome..

Thank you. And the next question comes from Ryan Oatman with Cowen..

Hi, Ryan..

Morning. The latest Williston results demonstrate initial 30 day rates that are about 30% above the type curve comparable cost.

Just want to see if you could speak to the Williston results that underpin that 2016 color you previously provided about 147,000 barrels of oil equivalent per day?.

And I think as we said – it's an Eric Hagen, Ryan. I think as we said before, those get risk credit for increased sand enhanced completions. So the 147,000 BOE per day guidance we gave didn't include the full impact of that. So there could be upside to that from the enhanced completions..

Got you. That's helpful. And then maybe a question for Mike here, looking at the 4Q guidance, you're definitely calling for narrowed differentials, lower per unit operating expense.

As we look into 2016, I just want to see if you can maybe speak to the sustainability of both of those items?.

Well. On differentials, first of all, we did finally see a nice step-down from around $9 to $7 companywide and that's really pretty close to where it's out in both the Redtail area and the Bakken. I've guided fourth quarter to be between $7 to $8. Right now, it's still trending towards the $7 number, it hasn't improved, but it hasn't gotten any worse.

So as we look out the next year, I mean, historically differentials run about 10% of NYMEX. That would mean differentials should be down around $5. We don't see that happening yet. We're certainly hoping for that. So I'd say right now $7 is a good number as you look forward.

And then on LOE, I've guided that down a little bit, given some of the systems we got running now at Redtail that's going to help our LOE a little bit out there. And our Redtail rate has come down substantially this year.

We've really made some nice progress down to around a little under $7 right now for BOE at Redtail and the Bakken has always been in that range. So we've done good. We've got this last package that we've mentioned we're going to sell. That's going to help LOE a little bit as well.

And so I think going forward, I've guided the midpoint at $8.25; probably can improve on that a little bit as we move into 2016. I think we'll be able to improve it somewhere down to around $8..

Good questions, Ryan. Thank you..

Thank you. And the next question comes from Brian Corales with Howard Weil..

Hi, Brian..

Hey, guys.

How are you Jim?.

Good..

Just a great job on enhanced completions and it seems like it was quick step-change that y'all have seen.

Is that all just enhanced completions or is some of that kind of where the rigs are located?.

We did a fair bit of high-grading early in this year, in the first quarter, stretching a little bit into the second quarter. So we've got our rigs and have had for the last couple of quarters pretty much where we want them.

The results that you're seeing here really have – are reflecting the two things we talked about before and that's increased sand volume, so essentially we're doubling the amount of sand we're putting into our completions.

And then the other one is more entry points, which we're achieving by a variety of different methods, but one of the more interesting ones is the use of diverter technology. And we're getting really good results.

The wells that we've used that on are primarily here in the last three months, and those are ones that really standout from the pack in terms of the initial rates.

Still a little early to say how they're going to do in the long run, but we're getting very good initial rates on those, over 3,000 barrels a day on average for the ones that we're using that technology on..

And then, Mark, maybe just one more on the same topic is are y'all also trying to go even more sand than, call it, 7 million pounds? I mean, closer to 10 million pounds, because I think already heard some other operators doing that as well?.

Yes, we are selectively testing that in a few places. We see really good results going up to 7 million pounds, but we're selectively testing even more than that in places where we think it makes sense. I personally think that we're going to get good results as we continue to bump up the amount of sand.

And the other thing that is happening is we're getting very good cooperation as Rick will tell you here from the service providers that are pumping those jobs for us. They've been very good about getting the cost for wells at equal to or in some cases even less than what we were spending previously. So, that's all working very much in our favor..

All right, guys. Thank you..

You're welcome..

Thank you. And the next question comes from David Tameron with Wells Fargo..

Morning, Dave..

Morning.

Niobrara, can you guys just talk a little more about kind of how you think about 2016 out there? And maybe some of the recent thoughts around the Codell, and just give us a little more of an update there?.

I'll let Mark, comment on that..

So, right now, we have two rigs out there. The plan is to keep those two rigs. They're very much engaged in our development program and we're getting very good results out of there. The Codell, so far we drilled four Codell wells, a couple of them been a little bit better than our typical Niobrara wells, a couple of them just a little bit worse.

On average they're about equal. So, we're seeing good consistent results. The problem is we don't have enough production data out there to really predict what the EURs are going to be. So, the Codell is now very much part of our development mix and we're drilling Codell's right along with the Niobrara wells. And so far we're getting good results.

We just don't have quite enough production history to be able to forecast the fleet results there..

Okay....

Yeah, Dave, this is Jim. I'll just follow up with that a little bit in the sense that we've recently completed pretty much a eastern portion of the basin study that of course encompasses all of our acreage. And so, it takes advantage of the old wells – I know you're aware of this because of your history here in Denver.

As you know, that area out there is pin cushioned with old wells that went through the Niobrara and the Codell on down to the D and the J sand.

So, we have been able across our acreage position now, as a result of that old drilling, our own drilling, our own coring, and our own 3D seismic, our own proprietary 3D seismic, to isolate those thick areas of the A, the B, the C and the Codell that have the highest resistivity and – to parenthetically comment here – that I'll say, was difficult for others to comprehend because they looked only at the old logs and what the old logs were telling them.

They didn't ask what made the old logs read that way. So, I want to underscore that the resistivity and the oil in place out there is a lot higher than folks originally thought, us included.

As we did our core and we could analyze what was happening to those old logs, essentially the marrow (31:25) that is in those zones, some of them, masked the great amount of oil in place by showing lower resistivity than is actually the case.

That, in combination with the 3-D seismic that allows us to see the sweet spot of the Colorado mineral belt and the areas of high fracturing or fracture swarms, tells us that the entirety of our acreage position is good in multiple zones. Sometimes it's best in the A and the B, sometimes its best in the Codell.

And so, I really believe more strongly than ever that this area out there, which as you know is unchallenged by a high population.

In fact, it's a very low population of only about one person per square mile, and it's in an energy corridor with not only oil and gas, but wind energy out there is a perfect place for this large scale development that we're planning to occur out there.

And I continue to believe that over time, that the Redtail area can be as big for us, to get us up into that, let's say, 100,000 barrels a day, just like the Bakken does for us.

So anyway, I just want to kind of underscore that the drilling out there being done by us and, from what we can tell, the other large acreage owner out there, is underscoring our belief and their belief in this area as warranting a large scale development..

No, that's very – that's great color. Thank you..

You're welcome..

And then just along those same lines, I know you're never done with the completion design; I guess, it's always being tweaked.

But are you doing anything different or new out there than say what you talked about two months, three months ago as far as completing those wells?.

Yeah. Rick would like to talk about that..

Yeah. This is Rick Ross. Current completion design there are, on a 960 basis, about 5 million to 5.5 million pounds of sand. We are doing cemented liner completions. We've been doing that for some time. And we have moved to slickwater completions, so that's kind of the current approach.

One of the other things we'll be experimenting with is the diverter that Mark talked about that we've been successful in, in North Dakota. So, continuing to try and evolve those completions and improve as we go.

A major thing we've done is getting our cost down very significantly, working with our service providers, allowing us to get our cost down to $4.5 million per well and still pump quite substantial jobs..

Okay. Thanks, Rick. Thanks. Thanks for the questions – the answers..

Thank you, Dave. You're welcome..

Thank you. And the next question comes from Tim Rezvan with Sterne Agee CRT..

Hi. Good morning, folks. Thank you for taking my question. One theme that hasn't been hit on yet is a pretty impressive reduction in LOE that's come over the last six or so quarters. I know you talked about some of the infrastructure work in the Niobrara.

But I guess the question is how much of that reduction is going to stick if oil does rally a bit? And I guess what are you doing now to sort of continue to grind that down to $8 or below?.

Well, in terms of grinding it down, the most recent property sale that we mentioned will have some impact on that, probably help us about $0.25 – the systems out at Redtail that we mentioned already.

We continue to work our vendors for more concessions, and we continue to work the Kodiak properties to gain more efficiencies on them, although we've done pretty good on all those different aspects. So that's why – I've already talked about LOE probably churning down to around $8.

If the price of crude moves back up, I imagine there will be some increase in LOE because a good chunk of the LOE, 25% to 30%, is based on energy cost. Higher energy prices will flow through to our LOE. But we believe most of it is sustainable..

Okay. Thanks. It's pretty helpful. And then I think your comments were interesting before talking about getting the Redtail salt water disposal system completed earlier than planned. And then it was the kind of first asset that you mentioned on the 4Q kind of asset sale list on midstream.

Is that a fair conclusion to draw, kind of the early build might help on monetization of that, or? And I guess, yeah, maybe that is a justification for that incremental 3Q CapEx that surprised some folks.

I guess kind of what – is that a right inference to make?.

Yeah. That and the plant and the water disposal system did get done a little early and that contributed to the little higher CapEx there in Q3. That's true.

And then if I can just comment for you on a general nature of what we're doing now with these asset sales or the high LOE properties, and basically concentrating on drilling our Niobrara and our Williston Basin properties is that really selling off those things that don't do as well, have a thinner margin at lower oil prices.

And we're concentrating on those things that have the highest margin that we own at lower oil and gas prices. So – and at the same time basically we're targeting enough of those sales that we hope to reduce some of our debt out there with the proceeds of those sales.

So, then what you'll have as a company that as we go forward and begins to grow from that base, which is net of our production sales, will be a company that has excellent metrics. And our goal is to be among the very best in these metrics of LOE per BOE; G&A per BOE, et cetera; DD&A per BOE here in the lower 48..

Okay.

Then if I could just sneak one last one in, is it safe to say that the LOE on your North Ward Estes property is probably markedly higher than across your conventional properties?.

Right. It is. I'd like to comment on North Ward Estes because I would say, we – I have liked that particular property for a long period of time. And I'll explain briefly what we've done out there at North Ward Estes, so that we can sell it if we get a reasonable offer or retain it if we don't get a reasonable offer.

And that is we basically have adjusted – as you do in these secondary and tertiary recovery projects when prices decline, to put the thing basically into a situation where we're not spending anymore CapEx, and that's pretty easy to do, you just basically stop expanding the flood, so you don't have CapEx for further expansion.

And to comment where we were on that, we had five phases done of eight phases out there. We've taken the production from about 2,500 barrels of oil a day, up to just under 10,000 BOEs a day.

And so now what we're doing is we've reduced the CapEx and we basically have reduced our LOE by putting in the minimum contractual amount under our CO2 contracts and essentially putting it into a harvest mode where we can positively cash flow that property at $40, $45, $50 oil.

So, really it does two things when we do that, it helps our LOE per BOE out there; it has come down. And it also makes it a more attractive property. So, I think we've accomplished two things out there, which makes it possible for us to either retain it or sell it, but in either case, it will improve our metrics. I hope that's helpful to you..

It was. Thank you for that response..

You're welcome..

Thank you. And, the next question comes from Jason Smith of Bank of America Merrill Lynch..

Hey, morning, everyone. Good morning, Jim. So, I was just coming back to the earlier question on the allocation of your CapEx. You talked a little bit about 4Q.

Can you just give some color around the $1 billion for next year and basically what you've assumed to the breakdown of D&C versus facilities and non-op in that number?.

It's going to be similar to 4Q, Jason. I mean, I think Mike gave a pretty good breakout of D&C going to around $200 million. And....

It's roughly 90% D&C, 10% other..

Got it. Okay. Thanks. And then in your acreage in the Bakken and Redtail it looks like it's down about 10% from last quarter.

Can you just talk about what drove that and if there was any of your defined inventory associated with that?.

No, it really wasn't. The number of our kind of drilling locations that we've been counting, which is about 13,000, hasn't really declined. All we did there was primarily let some acreage in Starbuck and Big Island go. Remember, Starbuck that was on the far west side, the thinner portion of the Bakken.

And then our Big Island is basically – was a Red River play where we essentially have stopped drilling. We had some good wells developed what we thought were the primary prospects out there, and so we let those two go, that was the bulk of the acreage, Starbuck and Big Island..

Is there anything more at this point that you think you'll allow to expire in the next few quarters?.

Not very much..

Got it.

If I could just throw in a very, very quick one, just as you guys have talked about the water gathering and distribution rates, can you just remind us what the investment was there?.

I don't want to go into that right now since we're in the process of selling it..

Fair enough. I figured it's worth a try. Thanks, Jim..

It was a loss. Thanks, Jason..

Thank you..

The next question comes from Tarek Hamid with JPMorgan..

Good morning. Thanks for taking my question..

You are welcome..

Just a quick one on what you're seeing in terms of working interest partners and non-consents and sort of how you're thinking about that as you work your capital budget through for 2016?.

I'm sorry, could you repeat that again?.

Sort of just what you are seeing from working interest partners in terms of non-consents and how you're thinking about that as you sort of build the CapEx budget for 2016?.

We have virtually no non-consents in what we're drilling; no non-consents..

So it's not an issue for you guys at all?.

No..

And then secondly, you sort of touched on this earlier, but I think you've talked in the past about sort of repaying debt being one of the more NAV accretive things you could do with cash flow or asset sale proceeds at this point.

Sort of any change to that view or you still think that way?.

Still think that way, but I was – and my comments have basically been on since you don't know where – you never know where oil prices or natural gas prices are headed, you do know that if you payoff blank million dollars worth of debt, you do know how much that makes your NAV go up. That's what I was trying to say..

There is certainty of outcome. That is true..

Yep..

All right. That's all for me. Thank you, very much..

All the best. Thank you, Tarek..

Thank you. And the next question from Mike Kelly with Seaport Global..

Hi, Mike..

Hey, Jim. I've got two questions for you; give you the quick easy one first.

What's the commodity split on the 2,500 BOE that you're going to sell here?.

Let's see, I think it was about 50%-50%. It was about 50%-50%....

Okay..

On that one..

(45:12)....

The packages in total were heavier on the oil side. The three packages that we've sold were heavier on the oil side, Mike. Overall, I think they were probably more like 60%-40%..

Okay. Great. And then a second question here, I was hoping to kind of revisit the question on what's baked into guidance as it pertains to productivity improvements on your wells here. And if you just look at Q3, you saw a massive uptick in the 30-day rates in the Bakken, up 44% sequentially.

Yet it didn't translate into a production bead versus the midpoint of your guidance. And just hoping to get some color around that, we're you baking in 1,000 barrel a day 30-day rates? Or is there some sort of other offsetting kind of negative there that we really haven't discussed yet? Thanks..

Mike, I'll take that. We already answered the first question. In regards to 2016, we've given a risked amount of credit for the improved completions. And for this quarter, really production, the timing of bringing on production and frac protect was really more of an impact on our forecast than anything this quarter, so..

Got it. Fair enough. Thanks, guys..

You bet..

Thank you. And the next question comes from Paul Grigel with Macquarie..

Hi, Paul..

if prices remain well below $50, where would the next cut in activity come from, given your comments on not wanting to outspend in the current plan?.

Mike, will answer the first part..

First of all, the budget next year is equal. We're running 8 rigs. Like I said before, we dropped three rigs late in September, completion activity at the 11-rig pace still falls into the fourth quarter. And then by the first quarter, we're at the new 8-rig program rate, around $250 million per quarter, but it should say pretty flat..

And in response to your question about what would happen if prices fell further? While we do have the ability to drop two more rigs, the rig drops essentially since the economics in our two plays are pretty comparable as a result of the improvements in cost versus EUR we've made in both places.

So it doesn't – it's really not a comment on which play is better than the other, just that we happened to have two rigs in the Williston that would be droppable with only somewhere around $10 million of an early term payments. So we could drop two of them and it wouldn't cost us more than $10 million..

Okay. And then just a quick follow-up on that.

And the other six rigs, what's the average term on those contracts?.

Well, they run through 2016, but not too far after that..

Okay. That's all I had. Thank you..

Thank you..

And the next question comes from John Nelson with Goldman Sachs..

Good morning and congratulations on the quarter..

Thank you, John..

You guys hit on asset divesture, I just want to come back to that. You previously set the $500 million to $1 billion target for 2015.

And I'm just wondering if that range and, even more specifically, timeline still remains the base plan, given that you have ample liquidity? Is there the potential for some of those sales to slip into 2016 to ensure you think you get the best valuations for those assets?.

At this point, I would say that there's no change in the estimate and it's not very – obviously, there's not much. We wouldn't have to sell too many assets in order to get to that $500 million level from the $400 million level. And there is nothing that I can see that would make me see that it would slip very far.

If it did slip, as I've already said, I'm optimistic about the sale of midstream assets in Q4..

And have you seen – given those potential buyers, have you seen weakness in their stock prices? Have you seen any degradation in kind of their appetite overall for midstream assets? Or does appetite still seem fairly strong for the midstream assets you guys have on the market?.

As you would imagine, I think, people's ability varies company to company, just as it varies within the E&P space from folks who are, I'm going to say, continuing to spend above their cash flow, if they, for example, did a stock or a bond offering or whatever prior to today. If they're sitting on some cash they might be continuing to spend.

And I think in general that's the case within the midstream space and, fortunately, there seems to be quite a bit of midstream money out there still from folks who timing-wise have capital still. So, I realize what you're talking about with regard to the decline in the unit prices of a number of midstream players.

On the other hand, it's a bigger universe than just that, if you follow me. There's private as well as public and, essentially, there are backers and there are buyers, if follow me, that are still well financed and have a lot of capital to spend. And again, I think the real key isn't so much the price as I think values are pretty easily established.

In this game, it's volume times fee or POP, whatever. And our plants have a good mix of both fixed fee and POP contracts, so it's not all one or the other. So, we have a healthy mix there, I would say. And so, I think that's attractive because it has both stability as well as upside.

So, I think it's basically just – it's your revenue, less your expenses, present valued. And fortunately for us, our two plants that we have in the Williston Basin have a lot of PDP reserves behind them, our own and third party. So, while I would say there has been some – as oil prices have come down, NGL prices have come down.

On the other hand, volumes are up and our contracts have a good mix of fixed fee and POP. So from that standpoint, I think it's a healthy asset to sell and really, I don't think we're going to see a price degradation. I think what we're going to see is selectivity by who's the right partner..

Just want to add one thing, John, to that. The plant is located in a very attractive area, Montreal County, the core of the Bakken. You continue to see a lot of activity there. You even continue to see on the E&P side some good asset purchases, some high value acreage. So there's still a lot of activity there to backstop that plant..

That's very helpful color. I'll let somebody else hop on. Thanks, guys..

Thanks, John..

Thank you. And the next question comes from Mike Scialla with Stifel..

Hi, Mike..

Morning, Jim. You gave some really good detail on the Niobrara. I wanted to follow up on that. Last quarter, you gave some rates on the Horsetail 30F pad, which was testing I think 32-well equivalent per your DSU of – your 960 DSU.

Just want to see if there is any update on longer-term rates there and what you're thinking on ultimate spacing for the play?.

Go ahead, Mark..

So the 30F pad is now behind us. And I would say the results have been very encouraging. Going to put that in the context; when we started that, we were testing much higher densities than even at the time we felt like were desirable. The 32-well density is going to end up being a little bit high. That's one of things we've learned.

We also tested a variety of different completion technologies in there and tried to get a feel for communication between wellbores, those type of things. So it's been invaluable to us in terms of trying to understand that and help us fine-tune our completion designs In terms of the overall performance of the 30F pad, it's been great.

It's been right at their comparable, most what we're dealing with there in Razor, which has been where we focused most of our development activity. So, it does extend what we believe is a good, developable area out to the east a little bit.

So overall, it was really designed to try out a lot of different technologies in the Niobrara and it's been successful in helping us understand the best way to go ahead and complete those wells and what density you drill them on. So, I think one of the main things is, is we've come off of that estimate of 32-wells per DSU..

Yeah, but....

But....

...not very far off. I think you can go ahead and tell them what our plans are here, which – or we can go ahead. It's – right now, if we said what's the optimum, it's probably 28 [wells]. It's probably three eight's and a four. Eight [wells] in each of the Niobrara zones and four [wells] in the Codell.

That's what we believe and basically that's what we're permitting out there. I admit that does give us flexibility to, for example, drill somewhat less than that.

But right now, based upon everything we know about our oil in place out there and the recovery rates that we're seeing, which we think in total will – on average will be about 15% with a 28-well drilling spacing unit. That will give us close to 0.5 million barrels per well; that's what it looks like..

Okay. Great. Wanted to ask you one more too on – you've talked a lot about potential divestitures; sounds like midstream is the near-term focus. North Ward Estes has been mentioned in the past.

Sounds like you're pretty making a lot of progress on the midstream, is that enough do you think where you would really feel like you wouldn't want to seriously consider other things? Or wondered about is Parshall really – I know it's a great asset, but it's non-op, is that a potential candidate down the road as well?.

The answer to be blunt is no, on Parshall. It is a good asset. And we wish we owned more of it. As I'd said before, I had a chance to buy it all, turned it down. And then it came back to us with a chance to buy 20%, and we did. So, yeah, we like it.

We think our own Sanish acreage is somewhat better because our own Sanish acreage has the Three Forks underneath it, whereas over there that's not the case at Parshall, at least not in our opinion, good Three Forks. So, it's thinner as you get near the pinch out of the basin. But the Bakken is good and the well results are good.

The initial spacing that was done over there was really not very intense, meaning the wells were a great deal – a great distance apart. There was only two or three wells per drilling spacing unit. And now there's a great opportunity to go back in and with longer laterals really kick up the economics there.

So, wouldn't want to sell that one, my friend..

Good, my, I like blunt answers. Thanks, Jim..

All right. You're welcome..

Thank you. And this morning's last question comes from Kevin Andrus with GMT Capital..

Hi, Kevin..

Hey, Jim.

Hey, you guys have laid out a plan for 2016 at $50 oil, but how would your plan change if we happen to see higher commodity prices at the $60 level or the $65 level? Would you put that into the drill bit, or would you put it towards debt repayments?.

Yes. I think we'd do a little of both, my friend. I think we'd do a little of both..

Well then, I guess, how would that change your – I guess, how would you expect to change your production profile? Would maintaining a certain production level become more of a priority? Or maybe if you could expand on that a little bit?.

Well, without – I don't want to change our guidance right now because none of that has happened. But I can tell you that our drilling department here has been very proactive, such that when we've laid down these rigs. And I'll just kind of state in case people have kind of lost count, last year at mid-year, the company had 24 rigs running.

So, this year with eight, we're down to a third of that. So, I'm going to say that we do have the opportunity to bring back those rigs pretty quickly with those same drilling contractors and get some credit for the early termination fees that we've paid. So, I think that's one good thing that would allow us to ramp up pretty quick..

It's at about – rigs at about four or five rigs that we can flex back pretty quickly if we needed to. So, Kevin, about – it's Eric Hagen. About four or five rigs we can flex back pretty quickly if we saw higher prices. And we would get some credit for the early termination fees..

Yeah. Thank you..

Thank you..

Yeah, thanks, Kevin..

And as that was the last question, I would like to turn the call back to Jim Volker for any closing comments..

I'd like to thank all of the Whiting employees and directors for their contributions to a solid third quarter. Eric..

Mike Stevens and Pete Hagist will be presenting at the Bank of America Merrill Lynch Global Energy Conference, Tuesday November 10 at 9 a.m. Eastern Standard Time. And Mark Williams will be presenting at the Goldman Sachs Global Energy Conference the week of January 4, 2016..

In closing, we thank you all for your interest in Whiting Petroleum Corporation and we look forward to meeting with you soon..

Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect..