Good morning. My name is Keith, and I'll be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Third Quarter 2016 Financial and Operating Results Conference Call. This call will be limited to one hour including Q&A. I now would like to turn the conference over to Eric Hagen, the company's Vice President of Investor Relations.

Well, thank you, Keith. Good morning, and welcome to Whiting Petroleum Corporation's third quarter 2016 earnings conference call. On the call for Whiting for this morning is the Whiting management team. During this call, we'll review our results for the third quarter of 2016 and then discuss the outlook for the fourth 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 & 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 1 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-Q for the quarter ended September 30, 2016 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 quickly as possible. Let's begin on Slide 2. Operating cash flow of $151 million exceeded CapEx by $66 million. This is the second quarter in a row in which we have generated cash flow above CapEx in a low oil price environment. Third quarter production came in at the high end of guidance and averaged 119,890 BOEs per day. On the operating side, we continue to achieve cost savings with third quarter LOE below the low end of guidance at $7.98 per BOE. Well performance continues to be excellent with our previously disclosed set of 48 wells tracking a 900 MBOE type curve and our leading-edge completions tracking a 1.5 million barrel of oil equivalent type curve. We're ramping up in the Williston Basin with four rigs running. That's up from two last quarter. A recently completed set of pads in the Central Williston Basin delivered outstanding results with 13 wells testing at an average rate of 3,727 BOEs per day. As you can see on slide three, with the focus on the Bakken and the Niobrara, our total net production averaged 119,890 BOEs per day in the third quarter. 97% of our total production in the third quarter came from our Rocky Mountain region. At a 105,645 BOEs per day, the Bakken/Three Forks represented 88% of our total production. On Slide number 4, we provide an overview of the Williston Basin where we control approximately 443,000 net acres, of which 99% is held by production. You can see the new Rolla Federal Unit with 13 wells that averaged 3,727 BOEs per day. The three wells producing from the Bakken formation averaged 3,445 BOEs per day, and the 10 wells producing from the Three Forks…

On Slide number 14, we show our third quarter 2016 financial results. Our operating cash flow was $151 million, and our discretionary cash flow was $163 million, both were significantly above our CapEx of $85 million. Our adjusted earnings were impacted by approximately $0.09 due to non-cash interest and non-cash income tax charges associated with the debt exchange. On Slide number 15, you can see our liquidity and debt covenants. Our commitments of $2.5 billion were reaffirmed by our banks last week. We have $1.8 billion of liquidity and no major debt maturities until 2019. We remain well within all of our covenants and strongly positioned from a liquidity and debt maturity perspective to deal with lower oil prices. On Slide number 16, you can see the actions we have taken to reduce debt. Starting from a base of $5.65 billion as of March 31, 2016 which consisted of $4.65 billion of bonds and $1 billion of bank debt, we have constructed a plan to reduce our debt to $3.73 billion. In addition to $300 million of debt pay-down, using proceeds from the North Ward Estes sales, we also paid down $50 million from free cash flow during the quarter. Our guidance for the fourth quarter and full year 2016 is detailed on Slide number 17. We increased our full year production guidance and project Q4 production of 10.4 million BOEs to 10.8 million BOEs, which at the high end is equal to our third quarter rate when adjusted for the sale of North Ward Estes. Slide number 18 shows our crude oil hedge positions as of October 1. We are 68% hedged for the remainder of 2016 and 49% hedged for 2017. With that, I'll turn the call back over to Jim.

Thanks, Mike. Great job. Ladies and gentlemen, with our strengthened balance sheet and increased hedge position, we have the financial base to realize the full value of our world-class asset base. Our enhanced completions in the Williston Basin are tracking between 900,000 barrels of oil equivalent and 1.5 million barrels of oil equivalent based on type curves. We're getting those done for an average cost of only $7 million. We believe this makes core Bakken one of the highest return plays in North America, and we look forward to delivering more stand-out results in future quarters. In summary, Whiting is well positioned with a premier asset base, a strong hedge position, an enhanced balance sheet, and a highly efficient capital plan. Keith, please open up the conference call for questions.

Okay. Thank you. We will now begin the question-and-answer session. And today's first question comes from John Freeman with Raymond James. John A. Freeman - Raymond James & Associates, Inc.: Good morning, guys. Nice quarter.

Thank you, John. John A. Freeman - Raymond James & Associates, Inc.: On these – the big results we're seeing from these kind of super completions, how much production history do you feel like you need to see on this before you basically make the decision that that's sort of the direction you need to go on all future completions?

Hi. This is Rick Ross. I guess, the way we look at it is we're going to continue to try some additional completions in the fourth quarter. The larger ones, we'll probably do about 10 of those and continue to watch those. We'd like to see a quarter to two quarters of production to really understand the EUR picture on them. But the results we're seeing gives us enough encouragement to continue to do more of these, not our full complement, but to do probably 30% to 40% of our fourth quarter completions that way. John A. Freeman - Raymond James & Associates, Inc.: And then, my follow-up question is, is there any kind of read-through we could do on your Niobrara, at least, on those 10,000 foot laterals, the ability to do something similar with sort of the even bigger kind of sand jobs and what you all are doing there?

I'll address that. Mark Williams. So, the answer is, yes, we – the difference between the Bakken and the Niobrara is we were getting a lot of feedback and incremental improvement. In the Niobrara, we've got over 100 DUCs planned to complete in 2017. So, we will have plenty of opportunity to improve completions there as well, and several of those are in 1,280-acreage based units. It's important to mention here that most of the remainder of our acreage position has the ability to space our 1,280s, which has a tremendous upside to – but it really is much as the 33% upside on the existing 960s that we've been drilling. So, we think that's going to be a big asset. John A. Freeman - Raymond James & Associates, Inc.: Well done, guys. Thanks a lot.

Thank you, John.

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

Good morning, guys. And a great turnaround, Jim. Say...

Thank you.

Hey, Jim, just curious for you are the guys there, you mentioned in the press release, talking about the 1,280-spaced wells and it certainly seems – I'm just sort of shocked that, at 2.75 days, you're able to get something down. Can you talk about just the opportunities for that going forward? It seems like – I think you mentioned there about a 12.5% cost. I guess my question is, will that change dramatically if service cost go up? Or again, what is the opportunities for that going forward?

Well, I'd like to say two things. We have a new design out there. I won't go too far into the weeds. But essentially, after setting about 2,000 feet to cover all the water zones, then we're able to basically run one string of casing all the way to total depth, and that's really improved our times. It's really cut our cost. And so, even I would say if there turned out to be pressure on the prices, which frankly – I will say this. I'd like not to see that happen until oil prices get at $60 or better. And I think, based upon, I would say, both the interest that we have from the major pumping companies as well as what I consider to be a great history of coordination with them and partnering with them, I don't expect to see much pressure on pricing really in the Bakken or out there in the Niobrara until and unless we get $60. So, I feel good about that, and I do feel that these improvements that we've made in the time it takes to drill and complete a well out there actually gives us an opportunity to maybe even drop our cost from what we report here to you today.

Wow, great opportunity there, Jim. And then, on – just lastly on DUCs, you talked about sort of knocking some of those out depending on, is it still price dependent. Maybe if you could just talk about sort of the current DUC situation, how you see that going into 2017?

Well, I'm just kind of stepping on Mark's answer here. But I'll say we're going to begin completing them in the first quarter of 2017, and we expect to complete about half of them by yearend.

Very good. Thanks, guys. Great turnaround.

All the best.

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

Good morning, guys. Great quarter.

Thanks, Brian.

Looking at those super completions, the Carscallen well, I guess, had even more proppant and is seeing better results. Are you all still testing the limits of this, potentially even adding more proppant?

So, we have a range of 10 million pounds to 13 million pounds and we vary it depending upon the area that we're in. So, I would say, yes, there is upside there by increasing the amount of sand that we use. Sand, as you know, is in essentially an oversupply situation right now frankly so is some of other proppants that we can use. It's also in an oversupply situation. So, I think, as I said just a minute ago, I think we can continue to see enhanced completions by, yes, adding more sand and perhaps some more entry points. Mark Williams has a program that he's working on with Rick to give us even more entry points than we have today. So, yes, I'm optimistic that we can see some uplift not only from more sand, but also more entry points.

Mark, do we have a 15 million pound job plan next year? Is that the largest one we have planned?

I think the largest one right now is 13 million pounds.

13 million pounds, okay. I'm sorry.

And then, you mentioned you're going – you're at full rigs in the Bakken. I mean, can we assume that that's going to maintain throughout 2017?

Well, we'll watch it. I would say, if oil prices were to get back to $60, you'd see us add some more rigs.

All right. Thanks, guys, and good quarter.

Thanks.

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

Hi. Good morning, everyone, and again, congrats on a strong quarter.

Thank you, Jason.

So, just sticking with the DUCs and upping the rig count. Jim, has anything changed? I think, previously, you talked about $600 million or so to hold flat from exit next year. Has that changed with the improvement in completions along with where you guys stand on the DUC backlog?

It's probably a little early. I'd like to watch prices here, see how volatile they are before I provide much guidance as to the amount of our 2017 CapEx. But however, I will try to help you by saying that, I think, assuming the current 2017 strip price for oil, which is approximately $53 per barrel, I believe, we could easily return to double-digit production growth based on looking at 2016 to 2017 exit rates and do that by spending near cash flow. But we'll give more specific guidance as to the total CapEx amount as well as growth with our fourth quarter results.

Thanks for that. And then, one for Mike, I think. Just on the share count, Mike, can you just maybe update us on where you are today and, I guess, how we should think about it going forward, given you have the mandatory conversions and you also have the voluntary conversions? Just an update on where the share count stands.

Okay. No problem. We're around, if you fully diluted all the shares that could be issued, it's around 290 million today. We still have 721 million of the mandatorily convertible debt that's outstanding, and it will convert into 77.6 million shares. So, if you put that all together, you'd get to 367 million and it will convert once our stock price rise above $8.75 for 20 out of 30 consecutive trading days.

I think the important point about that is that when we convert that – in other words, when the stock is at $8.75, we actually get a benefit because we convert that at an average price of about $9.25.

Okay. Thanks.

That's due to the premium that was built into the deal.

Got it. Thanks, guys. Congrats again.

Yeah. So, frankly, every time we convert the share, we're converting at a price in excess of the current stock price. So, there is an accretion that occurs. Thank you.

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

Good morning.

Good morning.

What's the incremental cost on the large completions versus the 5 million pound there? Are you going to be testing these big completions in the Three Forks as well as in Bakken?

This is Rick Ross. The cost for, let's say, the 10 million pound frac jobs total well cost are about $7.5 million to $7.6 million is what they're coming in at. Primarily, we've been testing the larger jobs in the Bakken because that's the inventory we've been completing right now. I think we've got one that we've done in the Three Forks. But going forward, we'll be testing in both zones.

Okay. Great. And my other question is, can you bring us up to-date on where you stand in the two participation agreements, how many wells you've done, et cetera?

Yes, we can. So, we have the two joint ventures, a 44-well joint venture. In that one, we have completed 27 of the 44 wells. And then, we also had a second 30-well joint venture in Stark County, and we've completed four of those so far. That's one that we added a rig, and that rig will continue drilling into next year and we'll complete as we go.

Great. Okay. Thank you, guys.

You're welcome.

Thank you. And the next question comes from Jeanine Wai with Citigroup.

Hi. Good morning, everyone.

Hi, Jeanine.

Hi. Maybe a question for Mike. Just walking through some of the numbers in the press release, it looks like the 2Q 2016 long-term debt was $4.96 billion. And then, the 3Q was $4.09 billion. So, it implies a reduction of $875 million. And after accounting for the North Ward proceeds and the $372 million in converts and then the free cash flow, we're not quite getting the $875 million. We see that there's maybe a $140 million of debt reduction that we haven't accounted for. So, I'm just wondering if we're thinking about that right and if you could bridge that gap for us.

Yeah. Jeanine, what that is, is a debt discount that we had to book when we did the exchange. So, when we do the exchange, we had to take the debt down to fair market value at that time. So, for instance, if they're trading at $0.90 from $1, we'd write it down. So, that's – well, it's kind of a financial accounting maneuver, not a true debt pay-down.

Okay. That's really helpful. Thanks. And then, just following up on Jason's prior question. I think, previously, you guys said that the maintenance CapEx of $600 million and to keep production flat versus 2H. And I'm just wondering if that estimate incorporates some of these higher sand loadings and, if not, any color on what that $600 million could potentially move to for next year?

It's inclusive.

Okay. Great. Thank you for taking my call.

Thank you.

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

Good morning, Jim, and everyone. Thanks for taking my questions. Pretty encouraging to see the uplift from the enhanced completions. I guess, we've seen the preliminary testing in sort of the Polar, Koala, I guess, Cassandra and Tarpon areas. Do you have any initiatives next year to test other areas of the Bakken? And are there any areas in your portfolio right now that we should think aren't amendable to these enhanced completions?

So, there are basically three of us here who hoped that you would ask that question. Thank you, David. We all believe that, virtually, all of our Bakken acreage is amenable to these bigger fracs. And so, we really believe that, across our acreage position, that it'll benefit. Now, there may be some areas that have slightly less DURs just because, in some cases, there may be differences in the rock. But we believe, in all cases, they will be incremental to rate of return and return to investment ratio.

Thanks for making me the token softball, Jim. I guess I'll follow up on that and – but just specifically, are you intending to move any rigs east and west in 2017 to test that concept?

Well, that's a great question. And certainly, I commend you for both of your questions. I know they weren't softballs. So, I'll say that we have the flexibility to do all of the planning that is necessary to stay, I'm going to say, on track for what I previously mentioned is what I hope and think will be double-digit growth next year. So, plenty of flexibility across our acreage position permitting-wise, and I'm going to say from a logistics standpoint as well. So, we've got now what I think is a number of great rigs up there really built for purpose, and they're manned by a number of great crews and frankly overseen by, as you can tell from – for example, our – I'm switching on you now from the Bakken down to the Niobrara. But as you can tell, we have what I think – there are some great engineers out there not only doing the drilling, but also the completion operations for us and overseeing that part of it. So, I'm very optimistic about seeing the length and breadth of our acreage react positively to this bigger fracs.

I appreciate all the answers. If I can just slide in one – quick other one, guys, just...

(27:43)

You talked – yeah?

One thing, just to be clear, we're not – our rigs actually drill wells with Missouri Breaks. They have drilled wells across almost all of the prior operating areas you talked about. The 30 wells that are in that dataset, there's 1,000 BOEs a day or range from Missouri Breaks, some wells and former smoky. There's wells in Pronghorn there. And the only area they don't – there aren't a lot of incremental wells will be Sanish, and we plan on drilling there again first or second quarter of next year. Is that right, Mark? So, yeah, that's why I don't want you to get the impression that our rigs are just drilling in one or two areas so...

(28:19) Thank you.

Thank you, David

Thank you. And the next question comes from Brian Velie with Capital One.

Good morning, everyone Thanks for taking my call. I have one question. I think you may have addressed this, but I'm not if I heard it correctly. Just to ensure, the Redtail drilled on completed wells, did you say that those are going to begin being worked off in 1Q 2017 with half expected to be done by year-end 2017?

Precisely.

Okay. All right. Thank you for that. And then, also on Redtail, a completion crew is out there. How many completions – or how many wells can be completed in a given month for a crew out there?

One – this is Rick Ross. One crew can complete four to six wells in a month.

Okay. And then, from the time of completion until they get turned online is that typically – or is there a timeframe that we could use to model?

Yeah. Obviously, it will depend on the number of wells on the pad that we're drilling if it's a 4, 8, 16-well pad. But you can just plan that out from, if it's an eight-well pad, take that timing that I've given you to complete them all and then they'd be on production...

Okay.

About the timing.

Okay. Great. Thank you very much. That's all I've got.

Thank you. Great questions.

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

Good morning, and congratulations on the strong Williston Basin results.

Thank you.

I'm going to concentrate my questions on the Redtail as a result. Slide 12, concerning the difference in completion intensity and the Redtail 1,280-acre versus 960-acre wells, is there any concern on negative well interference in 960 acres if you tried the larger completions there?

The short answer is no. We've drilled 1,500 wells up there. We have a great idea with respect to, let's say, each area's porosity and permeability. And so, our current spacing plan up there, which relies upon our current completion techniques, is designed to avoid which you would call interference from well to well with respect to production. Now, you'll probably hear us and other operators talk about frac protect from time to time, and that's simply because you do shut in some wells due to the higher pressure created during fracking operations. But we don't really see that as something that's then going to cause depletion of one well's drainage area by another well. We really are planning our spacing appropriately for the applicable porosity, permeability and oil in place in every drilling spacing unit. So, it's very detailed. It's down to that level of thinking. We've taken more core in the Williston Basin than any other company. So, we have an excellent idea of porosity, permeability and oil in place in each one of our acreage positions so...

Right.

The same thing is true at Redtail. We've done the same thing there. We've taken core. We feel that, currently, spacing – the appropriate spacing pattern there that will not have any effect on us is probably 16 wells per drilling spacing unit to as many as 8 in some areas per zone. So, it can be four, four, four and four. Four in the A, four in the B, four in the C and four in the Codell. And in some cases, in the B or the A, we may have as many as eight. I hope that's helpful to you.

Yeah, it's very helpful. Thank you. Following on at whatever commodity assumptions you like, can you ballpark the wellhead IRR uplift and spacing it 1,280 versus 960? You've put out the EUR, so that's very clear. I was wondering if we have an IRR guess.

I would guesstimate that the IRR would go up proportionally with EUR. So, as we see – as we go from a 960 which is 7,500 feet to 1,280 which is 10,000 feet, you'd expect to see essentially a 33% uplift.

Okay. Great. And then, my last question is, are there any opportunities or appetite to increase acreage in Redtail at this time?

Well, the answer is we're always acquiring more acreage out there because there are a number of leases that come up on state lease sales. And so, we've been successful here since the beginning of the year participating in those lease sales and acquiring additional acreage. So, we're always acquiring more, filling in our acreage position and adding to the size of our working interest, therefore, within our drilling spacing units. To answer your question on a broader scale there in terms of whether or not there are other big acreage positions owned by someone else that we may acquire, we're always open to looking at that and we have had a few proposed to us. We have not acted on any of those because we didn't think it – they were as good as the acreage that we currently own. I hope that's helpful.

Yeah. That's very clear. Thank you. I appreciate it.

You're welcome.

Thank you. And the next question comes from Scott Hanold with RBC.

Thanks. Good morning, guys.

Hi, Scott.

Hey. So, a question for you. You obviously – you gave a lot of color over the enhanced completions and the uplift they could provide. And could you just give us a sense that at your current pace in the Williston right now, roughly four rigs in which you've got the Niobrara in terms of plan completions, is that an adequate level based on what you're looking at to grow production next year by that double-digits rate that you mentioned?

Yes. When comparing exit rate 2016 to exit rate 2017, to be clear on that point, yes.

Okay. And then, what is – when you step back and look at, obviously, there is a little bit of uncertainty around commodity prices right now, but you all have locked some of that in. Would you envision, I guess, meaningfully outspending cash flow at some point if commodity prices are higher? Or is there a goal with bringing debt into a certain level that you'd feel more comfortable with at this point?

Okay. There's a couple of questions embedded there in that statement, so let me just say that I think that, in 2017, we can spend as I said at or near cash flow and still grow double digits, so I hope that's as pretty direct as in terms of answering your question. From time-to-time, I think you might see us sell off some assets or something like that, some non-core stuff. And if we did, we might use that to fund, if you will, what otherwise might have been deducted as debt. So, I hope that sort of gives you an idea of the flexibility that we have to ramp up to an even greater pace if, A, oil prices are there and we continue to be satisfied with our results, which frankly I think we've been very pleased with what you see happening here well result-wise throughout 2016 and don't anticipate any divergence from that in 2017.

Yeah. I mean, that's great color. And it's interesting I think right now in the market, there is obviously a lot of interest in what's happening in the Permian Basin and the desire to see capital go to that area to grow production. Can you discuss how returns for Whiting right now compete versus, say, the Permian Basin? And actually, considering there's really very few companies that are very focused on the Bakken like you all are, what is the opportunity set in front of you that you think investors might be missing?

I would only say this that you may remember that, not too long ago, we sold a fairly large acreage position that we had in the Permian Basin and we were very happy with the price we got at the time. And we felt that the – at least, with respect to the acreage position that we have and I won't be trying to characterize what other people have, but we felt that the results we were seeing and, at least, area results from others indicated some variability that caused us to prefer to spend our capital in the calmer, meaning more consistent Williston Basin. So, we sold out down there. We still have some acreage down there that we'll get back when one of our trust that we sold comes back to us in about four years. But I would say that if I had to pick right now as to whether or not I want to go down there and pay those kinds of prices that have been necessary to buy a large acreage block from someone who already owns it, I'd much rather be in the Bakken or the Niobrara as we are. So, I'm not mocking what other people are doing. Some of them are having great results and more power to them. I just think that, for us, we're very happy with our Bakken results and think that they compare for us anyway more favorably than what we were doing down there in the Permian.

All right. That's great. I appreciate it. Thanks.

You're welcome.

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

Thanks.

You're welcome.

Just curious, as you look at the kind of trailing results on those 900 MBOE wells that are tracking to 900 MBOE curve, what sort of return do you think those would get on a prospective basis given current cost and current strip?

Those would be in the 30% to 40% IRR range.

Okay. That's helpful. Certainly competitive. And then, of the – I know you guys have had the sorts of results across a wide number of counties that you guys highlight. You talked about having just shy of 5,500 potential gross drilling locations in all those counties. How many of those locations did you say would support that sort of 900 MBOE type curve?

Well, I've tried to indicate to you that, by customizing the size of the fracs that we use, we think all of our acreage is susceptible to uplift. So, I guess, let's say, maybe the best way to think about that might be that we would be in the sort of 25% to roughly 60% IRR range on all across our acreage north, south, east to west by using these larger fracs.

Okay. Yeah. I guess, I was trying to think through, I guess, if there was an existing core within that 5,500...

Michael, it's Eric Hagen. And just to make a point, some analysts and commentators were questioning Pronghorn because the wells don't come on at the rates that you see in the Central Basin. And yet, we entered into a JV, where our partners are earning excellent returns in Pronghorn, and we entered into that JV when oil was closer to $40 than $50. So, I think that's indicative of the quality of our acreage in general. So, we don't think – what we call the core is the core. And as Jim said, we're earning – I mean, believe me, these partners want to earn 20-plus-percent IRRs, something in that range. So, we're earning those kind of IRRs across those locations.

And there's further proof of what Eric is indicating to you there. I'd simply point out the results that we detailed for you here in the second bench at the Three Forks. So, we're very optimistic about having years and years of excellent drilling up here that we can get those kinds of rates of returns on at $50 oil.

Great. Yeah. I guess, what I was trying to highlight was, on a trailing basis, the perception of the core seems like one thing. But if you start applying new technology, that perception of the core expands but...

Yeah...

I think we are on a similar page. Anyhow, then the only question I had is on spacing assumptions. You talked a little bit about it in some of the prior remarks, but I just want to revisit it a little. In the context of these enhanced completions, my understanding is that like it's not just increased proppant loading but also, like you said, increased entry points. How, if at all, do you think that has the potential to change legacy assumptions around spacing? And to what extent are any new pilots going on with new completion technology, testing, spacing and design in the Williston?

I'll address that. So, with regard to spacing, two ways to look at it. The 1,280s that we're drilling on, those are pretty well set except for areas, for example, Montana and North Dakota. The vast majority of the basin was already at 1,280s, and the question becomes the number of wells that we can put into each of those...

Right.

Zones, and we become a lot more optimistic, especially about the Three Forks. The results here of this Rolla Federal pad really show that. We think that's going to extend over a good portion of our acreage position. So, we see increased number of well bores by expanding into the second branch here in the Central Basin. As oil prices continue to rise, then the number of wells per ESU also increase. So, it's very much tied to commodity prices, but that table that we showed there on a slide here is pretty good indication of what we think we have as the number of potential locations and we referred to that. Now, to sort of tie this into a previous question there on page five, as far as, what part of acreage is perspective, it's really I think important to see where historically wells have 50 MBOE or higher, all those black dots on there, if you just take that area and apply the sort of uplift that we've seen just from the last two quarters, that area also expands. And so, it really shows that, in aggregate, virtually, all of our acreage is economic. The 50 MBOE in 90 days, that's sort of what we consider to be economic at $50. And so...

Okay.

And so, I think that's the important thing there. We get more – very much tied to commodity prices. But even at $50, the vast majority of our acreage...

Yeah, it's susceptible with better completions. And as we show there on Page 6, we think it encompasses 92% of our acreage.

That's helpful. I appreciate the color, guys.

You're welcome.

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

Good morning.

Good morning.

So, just given the broader impact of enhanced completions across the portfolio, could you maybe just update us a bit on how you think about allocating capital, sort of, in 2017 between Redtail and the Williston and sort of how that has changed with the enhanced completion designs?

Right now, our plan is to continue on with the four rigs that we have in 2017. That could change. As Jim mentioned, we are not ready to give guidance on that. But we – if you take that and add to it the number of DUCs that we plan to complete, which we addressed already and that's pretty much what we're planning on right now. There's opportunity for us to increase that with increased oil prices with currently four rigs in the Bakken. We got one rig drilling in Redtail right now (46:42)

Got it. And then, yeah, I think you touched on it a little bit. But on the balance sheet, that's incredibly successful in reducing debt so far in 2016. Is there a target in terms of gross quantum of that, that you're comfortable with or do you think that just relates directly to the commodity price environment we're in?

Obviously, yeah, that's true. But I will say, at this time, we do not have plans to do anything other than what is currently in the works, i.e. that's $721 million that can convert. We don't have any plans to do exchanges beyond that.

Got it. That's very helpful. Thank you very much.

You're welcome.

Thank you. And the next question comes from Sean Sneeden with Oppenheimer. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Hey, guys. Thank you for taking the question. Maybe as a follow-up to Tarek's question there. But how are you guys thinking about your 2018, 2019 maturities at this point? Any plans to address that? Are you pretty comfortable?

Very comfortable, obviously. Plenty of places to put that if we wanted to just pay it down using our existing borrowing base and then work it down once it's on the borrowing base. Basically switching from 6% debt to 2% debt helps on the amount of interest that we pay. And then, as we would reduce that either with cash flow or, I would say, well-timed strategic non-core asset sales, we feel very good about our ability to either pay it off or if necessary. Our bonds are trading at $98 to $99 right now, so there is no worry on our part that, if we wanted to refinance some of it, we could do that. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Okay. That's helpful. Just one other one on oil differentials. Can you remind us, I guess, A, what the breakout of that kind of $8 to $9 diff is between the Niobrara and the Bakken; and, I guess, B, how much of that differential is fixed versus variable?

Well, the differentials between the two plays are very similar. So, there's really no particular or big difference in the true differential. And then, as far as fixed and variable are, honestly it's all pretty much variable, they make deals each month, we don't have any real long term contracts there for any of our oil sales. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Okay. That's helpful. Thank you very much.

You're welcome.

Thank you. And the next question comes from Gary Stromberg with Barclays.

Hi. Good morning.

Good morning.

Any update on the possible monetizations of the Robinson Lake and Belfield gas plants?

So, we have a number of parties who are very interested from where we were, say, a little over a year ago. I'll commend our staff for switching virtually all the contracts we have at those two plants from percent of proceeds contracts to fixed fees. So, that's immensely helped what I would consider to be the consistency of earnings of those plants. And so, I'm optimistic that we will see some very competitive bids there and get excellent value in terms of multiples of cash flow, if and when we elect to sell. So, we're actively pursuing that, a lot of interested parties and don't really want to say much more than that right now. We'll probably keep control even if we would like to sell those assets. We'd probably keep control of the oil gathering system there at Sanish as that's a fairly big piece of our net daily production. And so, we'll probably keep that, if we elect to see other assets.

Okay. So, no firm timing on a potential sale of those two plants?

No, I don't want to do that at this time.

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

Great. Thanks.

Thank you. And the next question comes from Gail Nicholson with KLR Group.

Good morning. I'm just looking on Page 8. The 13.6 million pound proppant well growth above that 1,500 MBOE type curve just before the 60-day mark. And I was just curious, was that does the well behavior or was there any facility constraint on that well in the prior – first 60 days?

I think that was just production behavior on that one. I don't think there were any restrictions.

Okay. And then, just from a curiosity standpoint, when you look between rail and pipe, are you guys agnostic between how you transfer the oil?

Obviously, the pipe for us is the better – we're going to get the better differential on that. We don't actually determine whether it moves on pipe or rail. We sell prior to that, and the folks that are marketing make that decision. But better economics are on pipe.

And just a higher level question, do you have any concerns from a political standpoint with future pipeline build-out in the region?

Well, I think there is – the Bakken had plenty of capacity to move the oil that we would produce now or even in the future between rail and pipeline. We think that the pipeline in question right now ultimately will be built, and we think that's a good thing for the Bakken infrastructure. It may be on a little bit delayed path but we think it will happen, and that's a good thing.

Okay. Great. Thank you.

You're welcome.

Thank you. And the next question comes from James Spicer with Wells Fargo.

Hi. Good morning. I think you've covered mostly everything. But I did have one more of an accounting question probably for Mike. It looks like you took a large write-down of deferred tax assets during the quarter as a result of your notes exchange. Just wondering what effect that might have on the – how much you're going to be paying in cash taxes going forward?

That's a good question. We still have significant NOLs, and we will again be generating more NOLs in the future, at least, the way the current projections look. So, we don't think, we're going to be paying any cash taxes for the foreseeable future. That's at least three to five years out there.

Okay. Perfect. Thank you.

You're welcome.

Thank you. And that concludes the question-and-answer session. So, I would now like to turn the call back over to Jim Volker for any closing comments.

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

Mike Stevens will be presenting at the Bank of America Global Energy Conference in Miami on Thursday, November 17, at 10:30 A.M. Eastern Standard Time. And Pete Hagist will be presenting at the Capital One Energy Conference in New Orleans on Thursday, December 8, at 9:00 A.M. Central Standard Time. In closing, we thank all of you for your interest in Whiting Petroleum Corporation, and we look forward to visiting with you soon.

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