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

David A. Deckelbaum - KeyBanc Capital Markets, Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Tarek Hamid - JPMorgan Securities LLC Timothy A. Rezvan - Sterne Agee CRT Paul Grigel - Macquarie Capital (USA), Inc. Ryan Oatman - Cowen & Co. LLC Brad Carpenter - Cantor Fitzgerald Securities Stephen F. Berman - Canaccord Genuity, Inc.

Michael Anthony Hall - Heikkinen Energy Advisors LLC John Nelson - Goldman Sachs & Co. Bob Bakanauskas - GMP Securities LLC.

Good morning. My name is Keith, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Fourth Quarter and Full Year 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 one 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 Fourth Quarter and Full Year 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 fourth quarter of 2015 and then discuss the outlook for the first quarter and full year 2016.

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 and Events link.

Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on slide number one and in our earnings release.

Reconciliations of non-GAAP measures we refer to and the GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-K for the year ended December 31, 2015 is expected to be filed later today. And with that, I'll turn the call over to Jim Volker..

Good morning, everyone, and thank you for joining us. We'll get to your questions as soon as possible. I call your attention to slide number two. Production averaged 155,210 BOEs per day in the fourth quarter, at the high end of guidance despite selling 3,300 BOEs a day as a result of property sales in Q4 and 12,400 BOEs a day across 2015.

Driving our performance was our enhanced completion designs in the Williston Basin that delivered 22% production increases quarter-over-quarter on a per well basis.

Despite the sharp drop in commodity prices, our proved reserves increased 5% to 821 million barrels of oil equivalent, even after 53 million barrels of oil equivalent of asset sales which equated to almost 7% of our year-end 2014 reserves. In 2015, we reached our goal and sold $512 million of assets, which leaves us financially well-positioned.

We ended the year with $2.7 billion of liquidity and no major bond maturities until 2019. Our 2016 plan is designed to maximize current and future returns and preserve balance sheet strength.

We're decreasing CapEx by 80% from 2015 levels and adjusting our activity levels to four rigs versus our monthly average of 11 in 2015 and our high of 25 rigs in 2014.

We are also building a robust inventory of approximately 73 drilled and uncompleted wells, aka DUCs, in the Williston Basin, and 95 DUCs in the Niobrara that can drive highly effective and efficient growth and high returns upon any moderate rebound in oil prices. On slide number three, you can see our liquidity and debt covenants.

We have $2.7 billion of liquidity and no major debt maturities until 2019. With our reduced capital spend and availability on our revolver, we believe we are well positioned from a liquidity and debt maturity perspective to deal with lower oil prices. At year end 2015, we were well within all of our debt covenants.

On slide number four, you can see our better liquidity position versus most of our peers. We have $2.7 billion of liquidity, which places us at the top end of our peer group. On slide five, with a focus on the Bakken and the Niobrara, our total net production averaged 155,210 BOEs per day in the fourth quarter.

As you can see on slide number five, 92% of our total production came from our Rocky Mountain region. At 128,600 BOEs per day, the Bakken/Three Forks represented 83% of our total production.

On slide six you can see that, according to Wall Street analysts, our Bakken and Niobrara plays are top tier in terms of net present value created per rig on an annual basis. On slide number seven we provide an overview of the Williston Basin, where we control approximately 500,000 net acres, of which 99% is held by production.

We control the sweet spots of the Williston Basin and have continued to increase productivity within the Basin with new completion technology. Note that although we continue to drill, we plan to defer completions in this depressed price environment.

You can see on slide eight that during the fourth quarter we completed wells with average frac sand volumes of 6.7 million pounds versus 5.2 million pounds in the third quarter. The fourth quarter wells achieved 30-day average rates 22% better than the third quarter.

On slide number nine, you will note that our Redtail Field continues to produce strong results from all zones. We're currently completing a 16-well pad, after which we'll defer completions. Mike Stevens, our CFO, will now discuss our financial results in the fourth quarter..

On slide number 10, you can see our fourth quarter and full year 2015 financial results. On slide number 11, you can see our unit costs for the full year of 2015 decrease significantly from the full year 2014. Our DD&A rate per BOE has dropped 20%, LOE per BOE has decreased 22%, and G&A per BOE is down 32%.

Our 2016 capital budget is outlined on slide number 12. Please note that 88% is going for development. Our 2016 capital budget is 80% lower than our 2015 CapEx and close to cash flow at current strip prices. Our guidance for the first quarter and full year 2016 is detailed on slide number 13.

We anticipate that our capital spending rate will drop to $80 million per quarter in the second half of 2016. On slide number 14, you can see our balance sheet, with $16 million of cash on hand and $800 million drawn on our $4 billion borrowing base. As Jim indicated, we're in compliance with all of our debt covenants at year end 2015.

At current strip prices, Whiting expects to be in compliance with all debt covenants in 2016 as well. Slide number 15 shows our crude oil hedge positions as of January 1. We're 45% hedged for 2016. With that, I'll turn the call back over to Jim..

To summarize, we took decisive action in 2015 to position our company for a lower for longer price scenario. We have a premier core acreage position in the Bakken and the Niobrara. Additionally, we have $2.7 billion of liquidity and no large maturities until 2019.

We have a better 2016 crude hedging position than many of our peers, and we have taken prudent steps to adapt a conservative strategy to maintain strong liquidity and leave us well-positioned to capitalize on a rebound in oil prices. Keith, please open up the conference call for questions..

Yes. Thank you. We will now begin the question-and-answer session. And the first question comes from David Deckelbaum with KeyBanc..

Hey, David..

Hey, Jim. Thanks for taking my questions. And I appreciate the decision to go down to the four rigs and preserve some cash here.

Was hoping you could give a little bit of color just on the program this year of how many wells you actually intend to complete in conjunction with the guidance that you have, and if there would be any sort of incremental change that would change the way that you're thinking about building up this DUC inventory?.

Sure. Well, in terms of the drilled and completed wells in 2016, 10 in the Bakken, 16 in the Niobrara, to answer that question. To answer the second part of the question, yeah, probably if oil prices recover back into the $40 to $45 price range, then we would consider completing some of these wells..

Is there a lower bound if – I mean, if oil prices – should we assume that this budget is basically set for a low $30s world?.

Yes. That's right..

And then, in terms of the – you've done almost over $0.5 billion of asset sales in 2015 and part of 2016.

Can you give a bit more color on what's still being actively marketed, and what your outlook is for getting anything done incrementally going forward?.

Well obviously, we're still working on some asset sales. I don't want to give any specific dollar amounts or timetable for that. But you're all aware that we have highly sought-after assets and, if and when we sell some, we'll make the announcement. That's the best I could tell you at this point.

To be honest, I got a little worn out last year when people said we weren't going to make our goal of $500 million when in fact we did. So I'm just not going to put out a number out there, or a timetable, but we'll let you know when we do..

Got it. Thanks for that color. And then, this is a question for Mark. Sand loading has increased every single quarter now.

Can you give us an idea of the average amount of sand that you're loading in the first quarter of 2016 here, in the remaining Bakken completions?.

Sure. I think most folks know we've gone up, during 2015, from a average size of about 3.5 up to about 7. (12:25) And that's about where we're remaining right now.

We found that pretty much optimal with regard to keeping our cost at a manageable level, but we've also seen very significant performance improvements with essentially doubling of sand volume, as well as other elements of our enhanced completion. There's also some of our performance gain. Frankly, a lot of it comes from high grading, too.

So all of those elements combined, as you've seen, quarter-over-quarter we've done very well with those things. But sand loading is definitely the highest component..

That's a great point. Thank you for asking. And essentially, those improved results are one of the reasons why we were able to grow about 7% year-over-year our production in 2015 over 2014, even though we sold 12,400 BOEs a day..

Great. Well, thanks for the answers, guys. I'll let someone ask some questions and maybe re-queue later. Thank you..

Great. Thanks..

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

Good morning, guys..

Good morning, Neal..

[audio gap] (14:05-14:18) Can you hear me, Jim? [audio gap] (14:20-14:28).

One moment, please..

Hello?.

Yes. One moment, please. (14:34-15:14).

Hello? (15:14-16:15).

Please continue to hold the line. We will re-establish the connection shortly. Please continue to hold the line. (16:20-17:21)..

Operator? (17:22-18:43).

Pardon me. This is the operator. I have reconnected the speakers..

Neal?.

Yes, sir.

Can you hear me, Jim?.

Thanks for hanging in there.

Did you hear my answer?.

No. I got off cut off before. I mean, basically my question was just as your finances improve, your thoughts on capital allocation between completions, additional drilling and financial matters..

Yes. So, as things get back into the $40 to $45 range, then we would start completing the DUCs..

What about looking at your bonds out there, Jim? With the situation, would you consider repurchasing some of those?.

So, I don't want to speculate on any kind of capital decisions of any type at this point, let's just stick to operations..

Okay. And then just lastly, certainly I know you don't want to go as far as putting any 2017 guidance.

But I think is it fair to say, Jim, you can really control your destiny as far as when you look at 2017 production, given all the DUC inventory you'll have towards the end of the year?.

Absolutely. Good conclusion..

All right..

That's exactly the way we feel about it..

Got it. Okay. Thank you very much, Jim..

Thank you..

Thank you. And the next question comes from Tarek Hamid with JPMorgan..

Hi, Tarek..

How are you?.

Good..

On the borrowing base, any recent discussions with the banks so you could update us how those conversations are going, what your expectations are?.

In general, we think that the borrowing base, like other companies have seen, will be down between 20% and 30%..

Okay. That's helpful..

But that still gives us lots of liquidity. Lots of liquidity..

And then as you think about and sort of similar to the last question, in terms of capital allocation as you look at bonds versus drilling and completion, have you also thought about (20:41) as a potential option?.

It's Eric Hagen. Jim already answered that. As a policy, we never have and we're not going to speculate about capital market transactions. So let's just try to keep our questions to operations..

Fair enough. Thank you very much..

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

Hey. I guess I'll keep to the operations side. So I had a question on the DUC count you had given. You look at 168 into year end. That's kind of a high DUC count, even if you were running a 15-rig, 20-rig program.

How did you land on that number? And what would the thoughts be about being maybe free cash flow positive and having half that DUC count, or maybe two-thirds that amount, which would still give you firepower? I'm just curious how you ended up there..

Well, basically that's the number of wells that we can drill in 2016 with a four-rig program. That's how you get there. And as you'd pointed out, in terms of gross wells on the DUCs, it's 73 in the Bakken, 95 in the Niobrara and then 10 completed wells in the Bakken and 16 completed wells in the Niobrara.

So in total, you're talking about 83 wells in the Bakken and 111 in the Niobrara..

Okay..

That's what the two rigs in each location do for you..

Okay. Okay.

And then if we see a move down to, let's call it, $20 to $25 oil, do you have the ability to lay down those extra rigs? Is there a meaningful penalty there?.

We do have the ability to lay that down and we do have the ability to spread that out. It's just under about a $50 million penalty there and we could spread that out over the remaining term of the contract on a monthly basis..

Okay.

Was that $50 million or $15 million?.

$50 million..

$50 million, yeah..

$49 million to be exact I think..

All right. I'll leave it there. Thank you..

You're welcome..

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

Good morning..

Hi, Paul..

Hi, Jim. Thanks for taking my question here. Looking at the latest presentation, it looks like the Bakken acreage is down to 455,000 net acres, a couple hundred thousand acres down from the last time.

Can you go into what the change is there and what drove that?.

Sure. Basically we sold off some of our western, which is the far west edge of the Williston Basin where the results in the Bakken out there for other operators has not been all that great. So we let that go. And then we sold part of the old Lewis & Clark, which was only about 1,000 barrels a day, but got a great price for it.

Got about $41 million for it for people who wanted to go in there and do some other types of drilling as well. So, yeah, we basically sold off a part of the Bakken that we didn't think made it in a $30 long-term price environment.

But we kept roughly 0.5 million acres, as you just pointed out, that's 99% HBP and that we consider to be, as we say in that slide, 700 MBOE-plus type acreage. So we've got a lot of acreage left to develop.

When you look at our whole sort of across-the-board inventory of things that we have to drill, we're up there to close to 4 billion barrels with all reserve categories, including resources and everything. So, lots of future net revenue out there that we can develop even if price is in the, I'm going to say, the $45 or less, down to $30-type category.

And we're just kind of cutting back on spending here until we hopefully can see at least a little bounce up in the price of oil..

Okay.

And all those asset sales are included in the roughly $500 million from last year, correct?.

Yes, sir..

Okay. And then just maybe for Mark here, kind of following up on the same concentrations. Certainly, good at the start here, and impressive on the uplift.

What do you need to see in terms of a longer runway, to know that the roughly 20% uplift is consistent, or is it just a pull forward of production, potentially?.

Well, I'd say the answer to that is, if you just go – and you can easily do this, just pull public data, and see exactly what that uplift is to the sand volume. So, we're very comfortable that that uplift in sand volume, relative to what we were doing previously, is real.

Yet the interesting part about this is, we think that there's still room for increased sand volume, there's still opportunity to do yet better. So you may actually see us go up, if we can get reduction in the cost of sand and at least keep our well costs normal. But obviously, in this price environment, we're not completing wells at all.

So as we go forward and, as Jim mentioned, if prices get up in the sort of $40, $45 range, we believe it may be possible to increase sand volumes and increase our well productivity above those amounts and still keep our well costs at the same levels, so there (26:33)..

I think you should look at this as really a timing decision here on when to complete wells and when to start spending heavier again. We're very pleased with the results of what we see from our greater fracs. As we said here, we think we're in 700-plus MBOE territory with all of our acreage.

A lot of it, we think, is in the very close to 1 million BOE-type acreage, in the better parts of the acreage.

So, if you were to just run a typical Bakken well at our now cost of $6.5 million CapEx, and say you looked at the higher end of that range of around 950 MBOEs, apply the five-year strip and hold it flat at the end of five years, your IRRs are up at around 60%. So it's a timing decision.

And, like a lot of folks from the Permian Basin into the Bakken and the Niobrara, things are getting better with bigger fracs. Like everybody, we'd like to spend that money when prices are a little higher..

Understood. Thanks for the time, guys..

Thanks..

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

Hi, Ryan..

Hi. Good morning. You guys have already answered a lot on the borrowing base.

Just wanted to see if you could speak to the amount that you have currently drawn on the revolver, and how you expect that to look at year-end, at strip pricing?.

Well, at year-end we had $800 million drawn. And at current strip pricing, we expect to be very close to $800 million drawn by the end of the year. Right now, there is a little bit of outspend in Q1 as our CapEx continues to come down, where if the strip holds true, by the end of the year, we'll be generating extra cash above CapEx..

And that assumes no asset sales..

Got you. That's helpful. And then, any scenario analysis that you can provide – obviously we have the base plan here.

If oil prices do rebound and you're able to spend, pick a number, $750 million this year, do you have any sense as to what production could look like in such a scenario?.

Well, we're not going to guide to that until prices go up, but we'll be the first ones to tell you when prices do go up..

Fair enough.

And then on the operations front, just thinking about flexibility here, have you guys thought about re-fracs, especially on some of that eastern acreage that's older? Can you speak to how you're thinking about refracs in the current environment and how those do or don't compete for capital versus new drills at this point?.

Well, I suppose I'm going to let Mark answer part of that, but I'd like to say that there's been a lot of work done. Thankfully, our friends at Halliburton have been doing a great job on that, as have Schlumberger and a couple of others who have what I would call great new diverter materials, and so we see a lot of promise in that.

And I'll let Mark go on and say that. But I'd like to say that I think our partnerships with large pumping companies, pumping service companies that we use, has been great in keeping us up-to-date on that, I'll call it refracking and recompletion technology, and we're excited about that because we have a lot of places to use it..

I'll just follow that a little bit by saying one of the great things about Whiting is our operated well inventory. We've got 1,400 wells up in the Bakken right now. And so the great thing about that is it presents us with a very large variety, both geologically and from a pure numbers standpoint, opportunities to go in and look at stimulating wells.

And we've really taken a deep dive technically, we're in the process of doing that right now to identify which of those 1,400 wells has the best opportunity. And so when you think about the opportunity cost there, what we have to do is compare that to our DUCs. We've got a lot of DUCs out there that we've been talking about, as well as new drills.

And right now new drills aren't the best bang for the buck. The DUCs obviously are because you're only spending, round numbers, two-thirds of the cost on completion. You've already drilled the well, but the refracs can be actually quite good. They, we think, have economics that are comparable to our DUCs, and we have a tremendous number of them.

So we're in the process right now of high-grading those, sorting through them, figuring out which ones are the very best. You'll see us I think here towards the end of the spring or in summer start to execute and test a few of those. We think some of them can actually be done at relatively modest cost.

And so, they, just a like new completion, are very much dependent on sand volume. And the bang for the buck may actually be going in and just cleaning out those wells. So we think there's two buckets out there of opportunities for these re-fracs and we're going to pick the one that makes the most economic sense..

Great question. Thank you..

That's great. And then one maybe is a little bit more sensitive here. We have seen the board take a number of actions, most recently letting the rights agreement expire, implementing proxy access.

I just want to see if you could speak to the broader goals and strategies behind these moves and any way you just want to shape the narrative as to what those moves do or don't mean, Jim?.

Well, I'll simply say, look, Whiting has been for good corporate governance from day one and we're simply making the changes necessary to be seen as one of the companies that has, I'm going to say, exactly what our shareholders are looking for in terms of corporate governance.

And those are two things that we think the shareholders want and so we (32:50)..

Great. I'll turn it back. Thanks..

You bet..

Thank you. And the next question comes from Brad Carpenter with Cantor Fitzgerald..

Hey. Good morning, everyone.

Jim or maybe Mark, in the Niobrara, while I believe the rig count is unchanged, with the reduced capital program for 2016, has there been any change in your focus on either the mix of Niobrara versus Codell, the locations you're drilling from an aerial extent, or any other changes on how you are thinking of developing the asset?.

Well, I would say this, that at lower prices you might not have the same number of wells drilled within each spacing unit. Just something we're looking at right now. But essentially what we're thinking is in the range of between – and I'll give you kind of by zone here, you get about roughly eight wells in the A, the B, the C, and four in the Codell.

And if prices stay low for an extended period of time, you might just go about four fours, in other words, 16 versus 28..

Got you. Okay. That's helpful. And then I think you had some new Codells come on line this quarter. I might be mistaken on that, but at last check, I had you guys with four Codells.

If there were any new wells that came online, do you have sufficient production now to be able to start talking about how the EURs might stack up against the Niobrara wells?.

This is Mark. I'll just say that we continue to include the Codells in our development program. And as we go further north from our core acreage position, Codell is actually improving. So if you look at the economics of those, they are comparable with I'd say about 90% of the A and B-type wells that we're drilling.

The C also is up there with the Codell. So the Codell and the C behave pretty similarly. So we're looking at a variety of different options as we move north away from where we've been drilling in the last year, but among those is a way to actually get the Codell and the C with a single well rather than drilling two wells for that.

So that's just one of the things we're working on. But still very much a part of our program. The thing we've got to do is make sure that we're developing right along with our A and B, and we expect to see improved results, especially in the Codell moving north..

I'll just try to add to that. Basically, the more we learn and know about the Niobrara and the Codell, the more we think whenever possible we will drill them on 1280s essentially because you're getting that roughly 33% increase in reserves for only a fraction of that in terms of your increase in cost.

And so a combination of drilling 1280s along with the current completion techniques we think has taken the typical Niobrara well from somewhere around 400 MBOE up to around 500 MBOE in our very most recent completions, and those have resulted in better wells.

And you start taking 1.33 times that for the extended reach of a 1280 and you're getting up there into the 670 MBOE range as an EUR. And if you run that at today's strip, basically the five-year strip, and just hold it flat, you're looking at a rates of return up there into the mid-20%s, IRRs in the mid-20%s. So we love the Niobrara.

We love what it's doing for us out there. We love the cost structure that we have been able to come up with out there as our drilling and completion come down. And frankly, we love the area that we're in because we're not constrained by what I would call the Front Range issues.

Where we're developing out there, there's about one person per square mile..

Got you. Okay. Yeah, that's helpful. Thanks, Jim. And thanks, Mark..

You're welcome. Thank you..

Thank you. And the next question comes from Steve Berman with Canaccord..

Hi, Steve..

Hi. Good morning. Thank you. The Q4 mix was a little less oily than it's been, at 76% if I did my math right. I assume at least some of that is because the Niobrara is gassier. But my question is in the 2016 guidance.

Can you give us some thoughts on what you think the oil NGL gas mix will look like?.

It's going to be very similar to what you saw in the fourth quarter. We've gotten a lot of gas on, done a good job of hooking up more of our wells, and then the completion of ONEOK's Lonesome Creek facility also helped us out. So I think we are where are..

Okay. Great.

And then my follow-up is, can you tell us what the PV-10 was on the year-end proved reserves, or do I have to wait for the 10-K to come out?.

Well, it was just under $5 billion. $4.6 billion or $4.7 billion as I recall. But try to keep in mind that when you look across Whiting and all of our reserve categories, using that same year-end pricing case, the PV-10 can double pretty easily when you throw in all of our reserve categories..

Got it. All right. Thanks, everyone..

Thanks..

Thank you. And the next question comes from Michael Hall with Heikkinen..

Thanks. Good morning..

Hi, Michael..

Just wondering, can you provide a little bit of thought around cycle times that are expected to bring the DUC inventory to sales when you get the price signal you're looking for? How long between seeing that price signal and bringing volumes to market? I'm just curious..

It will vary a little bit between the – I'm sorry, this is Rick Ross, Senior VP of Operations. For completion in the Williston, from the time we start on the completions, an individual well or a pad will be a 30-day cycle time in order to complete and bring those on production.

Obviously, the larger inventory we build up, the longer it's going to take to work that off. But that's what I'd say on cycle time. A little bit longer cycle time in Redtail, just because they can be larger pads, more wells on a pad. So that's kind of what we're looking at..

And how many wells per pad was that in the Williston versus DJ, as you have the DUCs oriented?.

Williston, typically we're somewhere between, let's say, three wells and five wells on a pad right now, and up to eight wells at times. In the Redtail area, we would be generally about 16 wells to as many as 28 wells per pad..

And have you had any discussions with completion services providers around maybe getting some one-off incremental discounts as you build up packs of DUCs, if you will? Any thoughts around that? Or do you think that might be a feature in the back half that could entice you to bring some of those wells to sales?.

We have worked with, continued to work with the service provider and the pressure pumping services, and have continued to secure price decreases on our completions. And really those are in place right now. I think that should translate to those savings when we start coming back up in the future.

We're seeing, recently, another 20% off pressure pumping service pricing..

Okay. That's helpful color. Thanks. And then, I wanted to make sure I got some of the numbers earlier correct.

You're backing into 83 Bakken wells, is that 83 Bakken wells and 111 Niobrara wells, is that how many are drilled?.

Correct..

Okay..

Total, yeah..

That implies, I think, about nine days and seven days, respectively, spud to release..

Yes, that's correct..

Are you running 24-hour operations still on those wells? Just trying to think through the sustainability of that sort of time. It's pretty impressive (42:42)..

Yes, it's 24-hour operations..

Okay.

And is there any ability to take that down to a daylight-only hour, or has that been discussed?.

I don't think that would be very efficient to do it that way, on a cost basis..

Okay. Fair enough.

And last one on my end is, are there any additional expectations around losing leasehold in the back half of the year with the reduced plan?.

No..

Very good. Thanks..

None. Thank you..

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

Hi, John..

Good morning. Thank you for taking my questions..

You're welcome..

I just wanted to clarify, on the drilled but uncompleted wells, is that a gross number or a net number?.

Gross..

And how should we be thinking about that on a net basis?.

Typical working interest in the Niobrara is like 90%. Typical working interest in the Bakken is between 60% and 70%..

That's helpful. Thank you.

And then, can you help us out in just thinking about the production declines the back half of the year, what 4Q 2016 volumes would look like relative to 4Q 2015?.

No, we don't really guide on a quarter-by-quarter basis. And, frankly, who knows where prices will be at that time. So we may be completing some wells that we're not currently planning to complete right now.

I guess I'd say, in response to that vein of questioning, I think we did a great job in 2015 basically being able to essentially have a 7% year-over-year from 2014 to 2015 production increase, while at the same time selling off more than a couple thousand BOEs a day (44:58) and at the same time cutting from a run rate of $4 billion to $2.3 billion in terms of CapEx.

And I have a lot of confidence in our ability here to essentially do the same thing. The only thing we're doing a little differently this year is of course the DUCs, as has already been pointed out. We can quickly come back and complete those DUCs when prices bounce back a bit..

I appreciate those comments. And the team obviously had strong execution in 2015. I guess I'm just more thinking in regards to what's baked into guidance.

Is that something in the ballpark of sort of a 20% to 30% decline?.

Well, the guidance is (45:49). It just it is what it is. I mean, what's baked in there is deferring wells basically after the middle of the second quarter. That's what's baked in. And we already gave the numbers in prior comments, but in addition to the DUCs, we'll drill and complete about 10 wells in the Bakken and 16 in the Niobrara.

So those really should be all the numbers you need for your modeling..

Thanks so much..

I'll try to be as helpful as I can for you. We're talking about a midpoint of guidance of about 133,000 BOEs a day. And if you compare that to the fourth quarter, which was 155,000 BOEs a day, less the 3,000 BOEs a day that we sold, that's 152,000 BOEs a day.

So that's basically a 12% decrease between the average across 2016 and the fourth quarter of 2015..

Great. Thanks for that..

You're welcome..

Thank you. And the next question comes from Bob Bakanauskas with GMP..

Hi. Good morning, guys..

Hi, Bob..

Just a quick one for me.

The two rigs in the Bakken, what specific areas will those be running in?.

Basically Polar and Tarpon..

And Dunn County..

And Dunn County. Three areas..

Then maybe just one more.

In terms of the high sand intensity completions, have you used these across all your core areas at this point? Are there any areas that you haven't used them? And are there any meaningful differences between the areas in terms of the results you're getting?.

I'd just say that's because our standard design – the 7 million-pound design that we talked about, is pretty standard. It does vary slightly between areas. We see broad uplift in all of the areas. The other thing that comes out of the data is that the better the area to begin with, the better the uplift with enhanced sand.

So there's a clear relationship there as well. So the combination of us high-grading the three areas that Jim just mentioned and increase sand is what's really driven our well performance.

Again, I'll just reiterate the easy way to get at that is to just go out and pull 30-day average rates versus sand volumes, which is all public data, you can sort of see what that looks like. Of course, 2015 is a pretty impressive number..

Okay. Great..

Thanks, Bob. Great question..

Thank you. And as there are no more questions, I would like to turn the call back over to Jim Volker for any closing comments..

Thanks very much, Keith. I'd like to thank all Whiting employees and directors for their contributions to a very solid fourth quarter.

Eric?.

Jim Volker will be presenting at the Raymond James Institutional Investors Conference on Tuesday, March 8 at 8:05 A.M. Eastern Standard Time. Pete Hagist will be presenting at the Howard Weil Energy Conference in New Orleans on Wednesday, March 23, 9:40 A.M.

Central Standard Time, and Jim Volker will be presenting the IPAA OGIS New York Conference the week of April 11..

So in closing, I'd like to thank all of you for your interest in Whiting Petroleum Corporation. We look forward to meeting with you very soon..

Thank you. The conference is now concluded. Thank you for attending today's presentation. Have a nice day..

Thanks, Keith..