Good morning. My name is Keith, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Third Quarter 2017 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 note this event is being recorded. 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 2017 earnings conference call. During this call, we'll review our results for the third quarter and then discuss the outlook for the fourth quarter and full year 2017. 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 results to differ materially from those in the forward-looking statements. Additional information concerning these risks are set forth forward in 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, 2017 is expected to be filed later today. And with that, I'll turn the call over to Jim Volker.

Thanks, Eric, and good morning and thank you for joining us, everyone. Before turning to the quarterly results, I want to take a moment to discuss the exciting announcement we made earlier this week. On Tuesday, we announced that Brad Holly will be joining Whiting Petroleum as President and Chief Executive Officer effective November 1. Brad Holly joins us from Anadarko Petroleum Corporation, where he most recently served as Executive Vice President, U.S. Onshore Exploration and Production. He was promoted to that position in May of 2017. He brings more than 20 years of experience in the energy industry. He will be a terrific addition to and leader for Whiting Petroleum Corporation. As part of a thorough search and a comprehensive succession planning process, we did extensive due diligence and considered many candidates. Brad brings the right mix of deep industry experience, expertise, proven operational and executive capabilities. His extensive leadership experience will allow him to hit the ground running to advance the company's strategic initiatives. Moreover, he embodies our core values of integrity, teamwork, and innovation. After more than 30 years at Whiting, including more than a decade as President and CEO, I believe that now is the right time to transition leadership responsibilities. Our company is in a strong financial position with a world-class asset base, and I am confident that Brad is the right person to lead Whiting in its next phase of growth and drive value for our shareholders. I know Brad shares my enthusiasm for what is ahead at Whiting. I'll remain in my role as Executive Chairman of the Whiting Board until the end of the year and will serve as Non-Executive Chairman until the May 1, 2018 Annual Meeting when Brad will assume the Chairman of the Board position. I look forward to…

On slide number 16, we show our third quarter 2017 financial results including our discretionary cash flow of $148 million. On slide number 17, you can see our liquidity and debt covenants. We remain well within all of our covenants and strongly positioned from a liquidity and debt maturity perspective. On slide number 18, you'll see our guidance for the fourth quarter and full year 2017. We forecast production to grow to an average of 126,000 BOEs a day in the fourth quarter. This represents a 10% increase from third quarter 2017 levels. During the quarter, we had a very small decrease in our oil mix from 67.4% to 67%, due to the sale of the Dunn County properties which had a lower GOR due to a lower gas capture rate. Also, to clarify further, the gas processing outage caused us to curtail significant oil production on our new Koala pad. So, not only gas volumes were curtailed, but also significant oil volumes. Slide number 19 shows our crude oil hedge positions as of October 11, 2017. We added to our hedges and are now 62% hedged for the remainder of 2017 and 52% hedged in 2018 at attractive prices. We will consider moving this percentage in 2018 up to 60% or greater, if oil prices remain strong. With that, I'll turn the call back over to Jim.

Thanks, Mike. Ladies and gentlemen, during the quarter, we continued to execute on our 2017 plan and further improved our strong balance sheet with the sale of our Fort Berthold Indian Reservation assets. We believe Whiting remains a very attractive investment for all the reasons detailed on slide number 20. 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 Neal Dingmann with SunTrust.

Good morning, Neal.

Good morning, Jim, and wish everything the best for you on the retirement.

Thank you.

First question, just real quick on the 8 million pounds, I think is on that slide that you referenced showing all those 55 wells now at 8 million pounds plus. Do you think you've sort of hit the diminishing returns or what – maybe just if you could comment you or Mark or one of the guys as far as now, when you see it for wells into 2018, what you could potentially see on an average size for some of these frac jobs?

Thanks. Great question. Rick's been waiting to answer to that one.

Hi, Neal. This is Rick Ross.

Hi, Rick.

Regarding our Williston Basin completions, we think, probably 9 million pounds to 10 million pounds is our optimum right now. So, that's kind of our standard job. You'll see some larger jobs on the slides that Jim talked about earlier that in specific cases we may bump it up a little bit. But in general, we think the optimum is in that 9 million pound to 10 million pound range.

Got it. And then, Jim, you mentioned in Koala, a little bit of that gas curtailment. If you address that for the remainder of the year and just if you could just talk about any potential outages that you see going forward?

Well, Rick's been ready to jump on that one, too, so I'll turn that one over to him.

Neal, that was a – the curtailment was a midstream operator from McKenzie County that had some equipment problems that took about a month to replace and get the plant back up and running. So, we're back to normal at this point. And I'd say going forward, it should be business as usual from what we can see.

Got it. And then lastly, Jim, just you still contain obviously very asset heavy, a lot of potential assets on strategy for further potential divestitures. Will you just go ahead and wait until that's passed to Brad or if you could just talk anything about potential investors for the rest of the year or into 2018?

So, I'm not going to say we're going to sell anything. I will say that the candidates that we have are the properties that are listed at about – in our non-core areas slide, minor amount of acreage there, some non-op. And of course, once we further load up our gas plant at Redtail, the Redtail Gas Plant.

Very good. And congrats again, Jim.

Thanks.

Thank you. And the next question comes from John Freeman with Raymond James.

Hi, John. John A. Freeman - Raymond James & Associates, Inc.: Hey. Good morning. Congratulations and all the best to retirement, Jim.

Thank you. John A. Freeman - Raymond James & Associates, Inc.: First question I had was on Redtail. We had those 15 wells that were completed back in 2Q on those two Razor pads. And now that those have been online for about 90 days, I'm just wondering if we could have some sort of an update, maybe how those are tracking relative to kind of the original EUR range?

Yes. This is Rick again. Yes. As you mentioned, we did do a couple of completion experiments in Redtail and those wells are on production and have been flowing back. And as you mentioned that usually takes 60 days to even 90 days to hit a peak. I guess what we would say at this point is we experimented both with additional stages and with additional proppant and we believe that additional stages add value. And at this point we think 5 million pounds of proppant is probably the optimum amount of sand. John A. Freeman - Raymond James & Associates, Inc.: Okay. And then just a follow-up on a little bit on the earlier question for the optimal amount of proppant to use on the Williston Basin wells and you mentioned the 9 million pounds to 10 million pounds range. So, when I sort of think about 2018 kind of completed well costs, if we look at the 9 million pounds to 10 million pounds that would put you on the higher end of that kind of completed well cost range that you all previously given of 7 million pounds to 7.6 million pounds. And then, how do I think about the fact that you've had the big advances, big improvements on the drilling days, but then in 2018 maybe we have some service cost inflation. Just sort of how you all would think about as your planning your 2018 budget, how we should sort of think about completed well costs in 2018? Thank you.

Yes. Obviously, we can't see all the way out through 2018 at this point, but what we can see in the pricing commitments we have from our vendors cost appear to be flat on the completion side and we're continuing to see gains in efficiency. So, my prediction would be flat on cost- overall well cost. John A. Freeman - Raymond James & Associates, Inc.: Great. Thanks, guys. Appreciate it.

Thanks, John.

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

Hey, guys. And I'll echo everybody else, Jim, congrats on the great career and well deserved retirement.

Thank you, Brian.

The Bakken results have been extremely impressive. I mean, going forward, are you all going to – what would it take to put a rig back in the Niobrara? Is it just commodity price or are you going to plan to keep one there every once in a while?

Well, in short, I would say looking at our results there and planning for 2018, we basically plan to just complete the remaining DUCs and we'll have about 39 of those at year-end 2017 to complete in the first half of 2018. Beyond that, whether or not we put a rig back there would be essentially oil-price related, so we'll wait and see. To try to be specific to you, probably something in the $55 range would make us start thinking about it. But with the results that we're having in the Williston, we really, at this time, due to the higher IRRs, higher ROI and of course the huge acreage position that we have up there, prefer to spend the capital and get the rates of return available to us in the Williston.

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

You're welcome.

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

Good morning, Jim...

Good morning, David.

...and I'll get on the congratulations train as well, congrats on the retirement.

Thanks.

I wanted to ask you I guess to get a little bit more color on the calculus around the $650 million to keep that 126,000 BOEs a day flat or so at the end of the year. I know that that numbers walked down from the $850 million level or so in the beginning of the year and granted I know there's been some sales. But how do you think about what contributes to that $650 million, is it all – I guess it sounds like it's all Bakken driven with the benefit of some of those DUCs at Redtail. Is that using sort of a 1.2 to 1.5 thousands – or million (21:05) type curve? And just describe a little bit more about how you think about that?

Well, I would say it's just based upon the results that we have seen over the year, really from January on here in 2017. Efficiencies have continued to improve our results. We're confident about the areas in which we're drilling through the end of the year and really through the end of 2018. And we're concentrating, as you've said, in the Williston Basin. So, those things really contribute to what we view as contracting maintenance capital.

Appreciate that. And you mentioned with the asset sales outside of non-core, potentially the Redtail Gas Plant. But with the remaining DUCs that you have on schedule to complete, does it fill the plant to a level that you feel like you could market it for a competitive bid?

So, the answer is we'll have to see on that market. It's an interesting market and in general, I would say that it seems to be a reasonably strong market out there and I would harken back to the price we received for the Robinson Lake Gas Plant. There seems to be continued interest out there, what you all would call reverse inquiries, people calling us about that. So, I sort of like to get everything on production out there and then we'll see how much interest is piqued.

Okay. I appreciate the color, Jim, and then congrats again.

Thanks again.

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

Hi, Gail.

Good morning and, Jim, congratulations on the retirement. Looking at the Nelson pad in Williams County, those are Three Forks wells, but very impressive that's tracking that 1.5 million barrel curve [BOE type curve]. Did you see anything differently how the wells performed in the Three Forks versus the Middle Bakken or is that an area where the Three Forks is just better than other areas in the wells, just kind of your thoughts there?

Yes. Mark Williams here. That area is in the deepest part of the basin, it's just north of the basin center and that's a great area with regard to the lower Bakken Shale, which sources both the Middle Bakken as well as the Three Forks. So, we get very good results there and to the south of there across the river, in our Three Forks wells, as you can see both by the Nelson as well as the Koala pad, so that will roughly a two township area there that really have some outstanding Three Folks. Fortunately, we got a lot of acreage in it.

Great. And then just looking at the Brent pricing and the spread between Brent and WTI these days. Have you guys thought about trying to get more crude out to maybe the East Coast, take benefit of the stronger pricing on the Brent standpoint?

We look at all the different outlets but the best place to send our crude lately has been Dakota Access. That's where a lot of it is ending up right now. It takes it all the way down into Texas and gets to the LLS markets which of course trades close to Brent. So, that's been the big game changer up there, definitely has tightened up our differentials and we saw some good results there in Q3 and even a little bit tighter results so far in Q4.

Great. Thank you.

All the best. Thanks.

Thank you. And the next question comes from Michael Glick with JPMorgan.

Hey, Michael.

Good morning, guys. I guess just to start, could you talk a little bit more about the CEO selection process and what drew you to Brad?

We liked him the best. Brad has a great history here in Denver, Colorado having run the local office of Anadarko. He is skilled in management. I think he did great job in handling some challenges that Anadarko faced and everyone we interviewed with respect to Brad, the recommendations were all AAA. And he has, in my opinion, an excellent energy level and an ability to, my opinion, drive value. So, I think he really just can't wait to get his hands on our asset base. So, from that standpoint, I think he evidenced probably the – overall, the strongest showing from the many candidates that we did review and interview, and he was unanimously picked by our board. So, I hope that's helpful.

Got you. Yes. Thank you. And maybe jump into in a more technical question, one topic that's getting a lot of play lately has been the potential for a degradation between parent and infill wells. Could you talk about your experience in the Williston and whether you've seen any impacts on that front? And maybe could larger fracs mitigate some of that impact?

Mark Williams here. I'll just mention a couple of things. There are certain parts of the basin especially where there are earlier wells that were completed in the 2010 to 2012 timeframe where we've had pretty good success of going in and doing infill drilling. For the most part, most of the drilling that we're doing here has been more in the central part of the basin, and we're doing a good job of making sure that we get all the wells necessary to completely develop those DSUs, put online with our current development program. But some of the more – I'd say the more oil prone areas out on the east side in the Sanish area, for example, have very good infill potential.

Yes, and I'd point out Michael – it's Eric Hagen – if you look at our assumptions for well density we've released periodically, they're really on the conservative side compared to a lot of our peers. Development on 12 wells or maybe at most 14 wells per DSU versus some of the peers are 18 wells or more. So, we've always been conservative in our development plan.

Got it. And just if I could sneak one more in, that was good call on the Koala pad, just kind of reading between the lines, it doesn't sound like we should expect much variability in your oil mix in 4Q, is that a fair assumption?

That's correct.

Okay. Thank you. And Jim, we do wish you all the best. One of the classier people I've met in the industry. Thank you.

Thanks so much.

Thank you. And the next question comes from Will Green with Stephens.

Hi, Will.

Thank you. Congrats, Jim, on a successful career and good luck in retirement.

Thank you so much.

I wanted to follow on that last question and just talk about the 85 wells over 1 million [BOE] that you guys are seeing on the type curve. Can you talk to us a little bit about what's the tightest those have been spaced? Are you seeing any degradation in older wells when you put those newer wells on? Just any kind of additional color on those bigger fracs and how they're competing with existing wells that are in those units?

This is Mark again. One thing I'll say is we have sort of the standard wine rack now typically tends to be five to six wells in the Bakken, depending on the leased line configurations, whether we own the adjacent DSUs or not. And so, that's become sort of a standard for us. But what we've tried to do in our development program over last few years is make sure that the development we're doing is on that pattern. It may only be on one side of the DSU, but that leaves us a very large area to come back in where we need to do infills and do that. So, that's been the hallmark of our program here for about three or four years. And so, that's really what's giving us the opportunity to come in and do additional drilling in some of our core areas.

Great. Thanks. And then, you guys obviously completed a lot of wells in the third quarter, it does appear that a lot of those Redtail wells were back-end loaded to the quarter. First of all, is that a fair statement. And then kind of secondly to that is can you guys give us some color on whether or not the Williston Basin wells were back-end loaded in the quarter as well?

Yes. I would agree with you both on Redtail and up in the Williston Basin. In Redtail, we were very back-end loaded and continue to put the rest of the wells on in the fourth quarter there. All of those are on in Redtail right now so we've made real good progress. And we were back-end loaded in the Williston as well with a number of the wells coming on in mid-August to the end of September. So, I would agree with you.

Great. That's all had. Thanks again and, Jim, congrats.

All the best. Thank you

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

Good morning.

Good morning.

And Jim, of course, congratulations on your great career and your leadership. You're handing a very nice asset and organization off to Brad. I'm sure he appreciates it.

Thank you.

Regarding the Evitt 14-12 and the Evitt 34-12, the well results in some of the earlier displays that I looked at seemed to suggest that it was tracking in excess of a 1 million BOE type curve, but this quarter it looks much closer to the 1.5 million BOE EUR. Can you talk a little bit about how these wells have performed? Have they declined more slowly than the norm or did they take a long time to reach peak rates or just anything relevant that gives some explanation for this improvement or seeming improvement over the last 40 or so days?

Thank you for asking that one. Rick's been waiting for that one.

I'm happy to oblige.

That was obviously two pads there, each with three well pads and it was, on the total, it was about half Three Forks, half Bakken wells. And I would say really nothing out of the ordinary in terms of performance or that have happened. They just continue to produce and track that type curve. So, I think they're performing well, but nothing out of the ordinary that I can point to.

Yes, we're glad you noticed that and the one thing that we like about it is, therefore, we think the repeatability of that particular completion style.

Okay. That's a good point. And quickly going back to the business of the backend loading in the third quarter. Can you speak about the cadence of completions for the fourth quarter of 2017? Will they tend to be earlier in the quarter or how's it going to shape up?

Mark Williams here. The completions for the fourth quarter are really probably going to increase just a little bit up towards the end of the year, but for the most part we're staying relatively stable. We've got a couple of frac crews working up right up to the end of the year.

Okay. And if I can ask one last one, my last Jim Volker era question, regarding the 9 million pound to 10 million pound completions you were talking about. I noticed that Koala was 9.8 million pounds and I think Nelson was 10 million pounds. Is this 9 million pounds to 10 million pound intensity, is this your standard completion now? And if so, when might you start showing a broader dataset of the results of those sand loadings.

That is our standard completion right now, 9 million pounds to 10 million pounds as I mentioned. Periodically, we'll see maybe a leased line well or some data in an area where we'd ramp it up a little bit from there. And I think all the data is publicly available to look at.

Thanks, Jeff, you just made more work for me – another slide.

Well, I mean the 7 is becoming irrelevant, so you just drop that one off and put the ten up.

Yes. I think we're getting in a critical mass, would be next quarter.

Okay. Great. Thanks again, Jim.

You're welcome. Thank you.

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

Hi, Jeanine.

Good morning, everyone, and congratulations, Jim.

Thank you.

You now have I think about 4,500 gross locations in your core Williston according to your slides. And you just mentioned previously that you may be conservative on your spacing versus peers but less any additional locations, with downspacing or new zones or anything, which seems a little less likely, how are you specifically thinking about the right level of Williston inventory years for Whiting or for investors? Based on just our math depending on your rig ramp-up assumptions and capital allocation, your current Williston location implies an inventory of arguably over 15 years.

Well, I'll start out on that and then I'll let Mark Williams chime in. I'm going to say like every independent oil company, we've watched – or every independent that's active in the Williston Basin, we've watched our inventory of good drillable locations improve with technology and expand with technology. So, we're very optimistic about essentially all of what we call our core area there, that 90% of our acreage being good long-lived assets for us to continue to develop. And one of the things that I'd like to point to is not only this improvement as we've essentially gone to the roughly 9 million pound job, but also the opportunity that Mike or that Mark and others have alluded to here in that we really haven't heavily drilled our inventory so far and there is an opportunity even for some downspacing as we go forward. And we've tested that, and we're very happy with the testing that we've done so far in that we see improvement not only in our total volumes of production from the new wells that we've drilled, but also from the offset wells that improve when we frac the new wells. So, that tells us that we got a great reservoir there, we got a lot of oil in place, and our opportunities both from new technology in new areas, meaning undrilled areas as well as areas where we may have some downspacing opportunity are both good, they're both good. Mark?

I think Jim hit the high points so there's just only really one other thing I'd add on there. We talk about sand loading being a driver for our completion, that's very much true but there's another part of that and that's trying to make sure that you get the sand distributed properly in the wellbore. So, more sand in more places, more entry points essentially. So, that's one of the big things that we've been doing – increase sand loading now for the better part of two years. But we continue to improve the number of entry points. That means more stages, use of diverter, all of these things to distribute that sand better and that's really what's driven our performance in the Evitt pad, and we think what's going to be driving our performance going forward. So, as we see that uplift going from essentially 1 million pounds to 1.5 million pounds in the same areas, that's kind of a rising tide for all of our wells across, especially the core areas of our acreage position. So, that brings what would otherwise, say, last year have been a marginally economic well to be an economic well now.

I'll just add to what Mark said because Mark and our geological team, we think is one of best in the industry. And they even have some ideas for some of the areas that we label non-core in our presentation. They think using a different completion approach could bring those into the core category. So, we think there is even upside to the locations you cited, Jeanine.

Okay.

But we don't think we're the only ones thinking about this, most of the other operators there are, in my opinion, both finding the same thing and saying the same thing we are. I bet you'll find that on their calls that they are going to be raising their type curves and talking about greater efficiencies all across the Bakken.

Okay. So, I guess it sounds like there is opportunity to do more with less and things are going well. So, I guess on that point then, how do you think about revisiting the value proposition trade on accelerating some of the Williston acreage value through divestitures, but you're trimming the inventory which sounds like there is upside in inventory versus managing the balance sheet. So, maybe with the new results, the value proposition is just a little bit.

Yes. Well, what we think about of course is maximizing rates of return, ROIs, of course, are part of that. If we do sell something and I said what they would be, they would be what we currently label non-core. Although as Mark has just pointed out and Eric has pointed out, we're finding that that non-core acreage, as a result of the way in which we're currently completing these wells especially with respect to the, if you will, way we distribute it out there, is making those look even better. So, I would say when people come to us and make us offers for non-core assets or non-operated assets, I would say they'll have to distinguish themselves from the crowd and make sure that they're looking at the current results, the more recent results which, frankly, are being realized by numerous operators across our acreage positions.

Okay. Thank you for taking my questions.

You're welcome.

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

Hi, Mike. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Hi, Jim. I'd like to offer my congratulations on your career and retirement as well.

Thank you so much. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: You said that next year, you could spend cash flow and grow. And you also said you're probably going to complete DUCs in the DJ. As you look at preliminary 2018 plan, would that imply that you're going to continue to kind of run the four-rig program in the Bakken at this point?

Yes, sir. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Got it. Okay. And then I think it was Jeff that asked you on the Nelson pad, seeing that performance kind of improve over time as the wells jump from that 1 million BOE to 1.5 million BOE type curve. I thought Rick's answer would include maybe something on choke management but that didn't sound like the case. I'm just wondering is there any need to choke these wells back or do you see any potential benefit from that or is that anything you've even tried at this point?

On our flowbacks, I would say we're generally moderate on the chokes. We don't choke them back heavily, but a little bit. And you can see in the curve, there's generally a transition from flowing to sub-pump and then later on to a rod pump and a little bit at the inflection point you see there relates to that transition from one lift mechanism to another which is currently a sub-pump. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Got it. Great. That's all I had. Thank you.

(42:05) Thanks.

Thank you. And the next question comes from Paul Grigel with Macquarie Capital. Paul Grigel - Macquarie Capital (USA), Inc.: Hi. Good morning. On the improvement in maintenance CapEx and the idea of growing, if cash flow comes in better than expected due to higher oil prices or there is the potential to have above maintenance CapEx, is the focus still on growth? Is there a thought or consideration on using any of the excess free cash flow to either pay down the revolver or address near term maturities?

Yes. Well, the new maintenance CapEx around $46 oil price will allow us to achieve that kind of cash flow. So, prices above that will give us opportunity to decide what to do with it, which could be adding another rig, but probably not till prices got closer to $55 would we do that. So, in the mean time, we would use the excess cash flow to pay down some debt. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. Thank you. And then on the operations front, it looks like you guys have three fewer completions and five less DUCs in the Bakken during the second half of 2017. What would impact – is that an impact of lower spending in fourth quarter 2017? And what impact does that have on production momentum into at least the start of 2018, especially considering potential winter weather issues?

Just with regard to the DUCs, we build up a pretty significant number of DUCs towards the end of the year in Northern Rockies. So, really what we're going to be doing, that sort of reaches the peak right there at year-end, and so we'll be working those off in the first half of 2018. So, I think that really relates more to sort of a seasonal thing. We don't complete quite as many wells over the Christmas holidays and early in the year, so pretty natural for us as well as other operators. Paul Grigel - Macquarie Capital (USA), Inc.: And is part of that related to any change in the outlook on spending in fourth quarter and the scale back on CapEx?

No. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. Thank you.

You're welcome.

Thank you. And the next question comes from Kashy Harrison with Simmons Piper Jaffray.

Good morning, everyone, and thanks for taking my questions.

You're welcome.

And so, with respect to the two Redtail contracts to deliver crude, I was just wondering what the opportunities are available to maybe restructure those agreements into more of a win-win situation where the counterparties could get more duration and visibility in longer term volumes but in a PV-neutral fashion, and then that would place Whiting in a situation where you've eliminated – you can eliminate those deficiency payments through the end of the decade.

Well, the answer is yes, those opportunities do exist. However, at this time, I would say that the best time to do that would be, if you will, within about the last 12 months, you have a little more leverage then than we do right now.

Okay. Got it. And then one for Rick, just reverting to an earlier question. So, the Redtail Well, I believe the Razor wells from early in the year, are they tracking the 465 EURs and 655 EURs highlighted in page 15 of the presentation?

The flowback on those is early – as you remember, it takes 60 to 90 days to clean up and to even get peak rate and we're not at that point so it's difficult to assess where we are in the type curve right now. It's too early to make that call.

If you pull all the wells, you'll see some wells that are well over 600,000 barrels and some that are below 465,000 barrels. It's just we're going to need to get the wells on and flow them back for probably three to six months before we establish type curves.

Got it. That's it for me. Thanks again.

You're welcome.

Thank you. And the next question comes from Biju Perincheril from Susquehanna Financial Group.

Thanks. Congratulations, Jim.

You're welcome. Thank you.

I had a question, I think Rick mentioned in the Redtail that you're seeing an uplift in production just by increasing stages. Have you tested that in the Williston, either in Middle Bakken or Three Forks. I'm wondering if there is an opportunity to lower well cost. The reason I ask is looking through some of your peers' data, it looks like there is some evidence that, particularly in the Three Forks, you do get an uplift just by increasing stages.

I think that's true and I think that's the – we talked a little bit about this earlier. In addition to the increased sand loading that we've been doing, the number of entry points is – you need to do both at the same time and increasing stages is one way to do that. We've also been very successful using diverter to make sure that the perf clusters within each stage are efficient. And so, we do typically three or four perf clusters per stage, and we want to make sure that each and every one of those takes. But the long and short of it is we're doing – that's been a key to success at Redtail and both the sand loading and the increased entry points have been the key to success in the Bakken, so, you got to do both.

Okay. And maybe, can you talk a little bit about the results you've seen in the Williston, like is there a potential that you could walk back some of the sand loading?

No. I think we're probably at what we see the optimum right now on sand loading. And as Mark mentioned, as far as adding additional stages, you can increase your sand distribution either adding additional stages or increasing perf clusters within the existing stages, and then use diverter to spread the sand around better, and that's really the direction we've gone and our results drive us to, more so than adding stages, it leads us towards adding perf clusters and then using diverter to distribute the sand. That seems to be the more economical way to go about it.

And I would just add, Rick, that we're still optimizing by area. And so, there still may be some efficiency gains by area, maybe go a little higher in some area, a little lower in some area as to optimize economics.

One thing I'd add into that, if you look at the overall section of the Bakken, and how much of it is hydrocarbon bearing the deepest part of the basin so the area around the river in the Walleye and Tarpon Prospects, west of the Nesson anticline, the whole hydrocarbon column there is quite a bit thicker than it is if you get out towards the marginal – at the very extreme peripheries of the basin. And so, we have the opportunity then to do larger fracs because we're not as worried about frac height growth and those type of things. And so, that's the areas where we had the best success going to larger sand volumes and fortunately that's where most of our acreage is.

Got it. Thank you, guys. That's very helpful.

You're welcome. Thanks, Biju.

Thank you. And the next question comes from Sean Sneeden with Guggenheim.

Hi. Good morning. Thank you for taking the questions.

Good morning, Sean.

Jim, maybe just a point of clarification on the maintenance capital. I know it's come down pretty nicely over the course of the year. I guess one, does that contemplate you drawing down and completing all the DUCs or how should we think about that in the context of maintenance capital?

Sean, why don't I jump in on that one because we've already kind of addressed it and early next year, we're going to have sort of minimal DUCs. We're going to have about 40 DUCs at Redtail and that compares to – we had over 100 DUCs this year. So, really the improvement in maintenance capital just reflects the improving efficiency, primarily out of our Williston Basin wells whereas you've seen throughout the year, our type curves have moved up and our productivity has moved up.

Yes, we're definitely going to spend most of the money next year definitely in the Williston Basin and that's where we've seen some major increases in EURs on the wells. So, that's where we're putting the money.

Okay. I think that's helpful. And so, we should really be thinking about as you spend $650 million that it's really causing kind of Bakken to grow and you'd have perhaps a slight decline and that keeps the corporate, overall, flat versus kind of Q4 numbers. Is that how you guys are thinking about it?

Is that on the maintenance capital or?

Yes, yes, on maintenance, yes.

Yes, there's going to be some growth at Redtail early in the year as we complete those DUCs. But yes throughout the year, the Bakken will probably take over and there may be some decline by the end of the year at Redtail.

Okay. And then just lastly, your 5 to 19 I guess, current, at the beginning of next year, how are you guys thinking about addressing that maturity? Do you think it's a refinancing or is it a combination of asset sales and other kind of capital market activities?

We'll keep you posted on that one.

Yes, we can't really comment on that. We've got lots of ideas, lots of plans. We will take care of it in time, but I can't really tell you right now what we're going to do.

That's a no problem.

Okay. And then just lastly, and I guess conceptually around that same point – I know you guys talked about deleveraging. Is that really primarily driven by growth as you kind of grow EBITDA? Or is that a function of just kind of lowering the quantum of debt that's on the balance sheet?

It could be both.

Okay. Thank you very much.

Thank you.

You're welcome.

Thank you. And that does conclude the question-and-answer session. So, I would like to return the call to Eric Hagen for additional comments.

Thanks, Keith. Whiting will be participating at the Raymond James one-on-one conference on Tuesday November 14, in Boston. And we'll also be presenting at the Bank of America Merrill Lynch Global Energy Conference on Thursday, November 16. Our presentation is 1:20 PM Eastern Time. We'll also be presenting at the Capital One Energy Conference on Thursday, December 7 at 8:30 AM Central Time. And with that, I'll turn the call over to Jim Volker for closing remarks.

Thank you, Eric, and ladies and gentlemen, in closing I'd like to once again thank Whiting's investors, employees, and board for their contributions during my career here at Whiting and their contributions to a solid third quarter. Serving as the CEO of Whiting has been the greatest privilege of my career. I've also enjoyed my association with all of the analysts on the call, and I wish you the very best.

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