Good morning. My name is Andrea, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Third Quarter 2018 Financial and Operating Results Conference Call. The call will be limited to 45 minutes including question-and-answers. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. I will now turn the call over to Eric Hagen, the company's Vice President of Investor Relations. Please go ahead.

Thank you. Thank you, Andrea. Good morning, and welcome to Whiting Petroleum Corporation's third quarter 2018 earnings conference call. On the call today with me is Whiting's Chairman, President and CEO, Brad Holly; Senior Vice President and CFO, Mike Stevens; Chief Corporate Development and Strategy Officer, Tim Sulser; Senior Vice President of Operations, Rick Ross; and Senior Vice President of Planning and Reservoir Engineering, Pete Hagist. During this call, we'll review our results for the third quarter and then discuss the outlook for the remainder of 2018. 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 2 and in our earnings release. Our Form 10-Q for the quarter ended September 30, 2018 is expected to be filed later this week. And with that, I'll turn the call over to our Chairman, President, and Chief Executive Officer, Brad Holly.

Thank you, Eric. I want to start off by welcoming, Tim Sulser, to our executive team. Tim has a strong background in reservoir engineering which complements our focus on being the best at understanding the subsurface. He also has a strong track record in banking, and running private equity backed E&Ps with a focus on the Bakken. As Chief Development and Strategy Officer, Tim will ensure our near-term planning efforts are integrated with our long-term strategic goals. Some of you have already met Tim as we recently had him on the road. He is on the call today and excited to help answer your questions. Before we get started, I would like to review our scorecard year-to-date. Starting off with CapEx, we are maintaining our capital discipline and sticking with our $750 million budget. As Mike will detail, fourth quarter CapEx should decrease significantly because we pre-spent to prepare large pads that will come on in the fourth quarter. Production continues to grow within the range of our guidance, and we forecast a strong increase in the fourth quarter. Free cash flow is exceeding expectations because we continue to drive down our cash cost and improved realizations. Since 2014, we have reduced cash costs by 30%, and price realizations have improved by 70%. In summary, we continue to deliver on our value proposition of growing production while generating strong free cash flow. Moving on to third quarter results, production grew 2% quarter-over-quarter despite a tank battery incident that deferred production. Production has accelerated and in the fourth quarter we forecast a 5% increase over the third quarter. The teams maintained a laser focus on cost control and delivered exceptional results that underpinned our strong margins this quarter. DD&A per BOE came in below guidance, and LOE and G&A per BOE…

We generated positive adjusted earnings per diluted share of $0.92 and discretionary cash flow of $297 million, which exceeded CapEx by $90 million. Per Brad's comments, fourth quarter should be a strong quarter in terms of free cash flow generation. Capital spending is forecast to drop-off in the fourth quarter to between $150 million and $160 million versus a run rate of around $200 million in the past few quarters. This is because we completed fracing operations on several large pads in the third quarter, where production will commence in the fourth quarter. You will note that we have reduced risk by adding to our 2019 hedges and now have approximately 31% of our 2019 crude volumes hedged. Given the improvement in our balance sheet, we're using wider collars that range from $50 to $80 per barrel. This protects the downside, but leaves a lot of upside on the table for our investors. In the fourth quarter, we anticipate a temporary increase in our differentials due to pad 2 refining turnarounds. Looking into 2019, we have reduced our differential risk by entering into 10,000 barrel per day of rail marketing contracts that lock in an average weighted price of $2 per barrel off NYMEX. Operator, please open up the conference call for Q&A.

We will now begin the question-and-answer session. Our first question will come from Neal Dingmann of SunTrust. Please go ahead.

Morning, gentlemen, and congrats on a good, a great quarter. But, Brad, what an amazing first year. You've done an outstanding job. My first question, Brad, when you did come on, you talked about really digging in all the processes, everything from how you all lease things all the way through to the marketing process and everything in between. I'm wondering now when you go back and now look at those things, are there still a lot of changes to be made or maybe just any color you could talk about that and any improvements we're still going to see?

Sure, Neal, appreciate the comments, and thanks for the question. I'm really proud of the organization this year (00:11:02). They have embraced change. They have driven cost out of our system. They have gotten very, very excited about the potential to be the best in the Bakken and to really work on everything from the top-line to the bottom-line. So, I think we've made significant progress that you will see, but there's more to go. And 2018 had a lot of change. I'm really looking forward to taking the next step in that process improvement and really driving that into our business in 2019. There's more that we can do, and I'm excited about getting after that.

Great answer. And then, just lastly, looking at slide 8, for – Brad, for you or Peter or one of the guys. When you look at the potential locations, not only – I know you mentioned about the additional potential, if you go to WildHorse and some of these others, could you talk a little bit – I'm just curious like when you look at those potential well locations that are on the right, 1,122, what type of spacing and potential for just additional even on those Tier 1s by more downspacing?

Yeah. Hey, Neal. It's Eric. Most of – I think, we think the spacing is generally appropriate there. We're somewhere around – on the lower-end, around 5 to 6 wells per DSU; and on the higher, 10 to 11. And the higher spacing is generally in the center of the basin where you have multiple benches in the Three Forks. We have talked about infill spacing in Sanish and the potential to add some locations, but we think that's largely already reflected in the number.

And, well – some of these, you talked about WildHorse and some of this – Eric, what you're talking about there, does that depend on – I guess my question is more on leading into to the processing situation in 2019. Is that going to drive where you're going to be going after these or I guess just a broader question in the processing situation going into 2019?

Yeah, let me answer the first part and I'll hand off the second part to Rick or Pete. But Wildrose and Cassandra collectively are over 200 locations potentially added to our inventory. Currently, we haven't classified as Tier 1. So we see that as big upside. And also, obviously, Foreman Butte, as we noted, could be over 100 locations. So we're looking at potentially around 300 locations that could be upgraded next year. But in terms of the how we're allocating resources, I'll hand that over to Rick.

Yeah, Neal. Rick Ross here. As we put together our 2019 plan and are working on that, we are certainly factoring in where we know we have gas capture and gas takeaway into our development plans. For example, Brad talked about Sanish field where we do have a good, very high gas capture. We are expanding our Red (00:13:56) gas plant as well. So, yeah, you'll see some overprint of that in our development plans, but certainly, we're looking at the highest return on investment as the first criteria.

Very good. Thanks, guys.

Neal, this is Brad. A final comment. We're focused on inventory development and as hopefully you can see we've got our internal teams charged up to give us additional inventory on our existing acreage as well as looking at stuff like the bolt-on acquisition that we did earlier this year. So, all focus is generating new inventory for the company at very attractive prices.

So, it certainly sounds that way. Thanks, guys.

Our next question comes from John Freeman of Raymond James. Please go ahead. John A. Freeman - Raymond James & Associates, Inc.: Good morning, guys.

Good morning, John. John A. Freeman - Raymond James & Associates, Inc.: When I look at, obviously, the last 12 months, you have generated peer-leading cash flow, and I guess on a go-forward basis as you're pretty soon going to reach all the kind of leverage target you all set out, just kind of how you all think about the preferences for that free cash flow and when you're sort of trying to balance add-on kind of deals like the Foreman Butte transaction versus whether it's dividends or share buybacks, just sort of the thought process as we get kind of the balance sheet stuff behind us going forward.

Yeah. John, good points. We certainly are generating a lot of free cash flow. It's a nice place to be in. This year, we've kind of used a balanced approach between paying down some debt and we did the Foreman Butte bolt-on as well. When we look forward into 2019 and what price to use, but it looks like there's going to be as much or more free cash flow and still growing at moderate rates. So, I think it will be more the same. We still got $2.8 billion of debt. We'd like to get that down a little bit. So, some of that will go that way. We find more attractive bolt-ons, we'll be steering some towards those. And then you can never take share buybacks out of the picture. And if we see softness in our share price, I think it's something we definitely got to consider. So, kind of a three-pronged approach there. John A. Freeman - Raymond James & Associates, Inc.: Great. And then my follow-up question, on slide 28, you all show rail exports versus rail takeaway indicating there's a good bit of capacity there. And there's just – there's been some comments kind of in the industry on the rail side that rail logistics are pretty tight at the moment just due to some lack of kind of compliant rail cars. Just any comments you can make on the rail situation at the moment.

Yeah. Hi, John. This is Pete Hagist. You need to remember that in the past, the primary takeaway in the Bakken was rail and at one point reached almost 1.5 million barrels per day. And a lot of that capacity has been repositioned as a result of the pipeline starting up. So, we think that is going to come back into play. Our latest intelligence is that a significant portion of that rail capacity is compliant and can be brought to bear. And the issue has been accruing those trains which will take a little bit of time. But I'll also make note that there are other areas in the country, in particular, the Permian and the Marcellus out on the East Coast, which with the start-up of a new pipeline out there for NGL should free up some rail capacity. So, I think at this point, a lot of that rail capacity is repositioning, and we do think there will be sufficient rail capacity in the future to take crude away. John A. Freeman - Raymond James & Associates, Inc.: Thanks. I appreciate the comments. Nice quarter, guys.

Thanks, John.

Our next question comes from Asit Sen of Bank of America Merrill Lynch. Please go ahead.

Thanks and good morning. So, just following up on your commentary on the macro and I appreciate the near-term guidance on oil diffs. Just wondering if you could share with us your outlook for Bakken diffs over the next two to three quarters.

Yeah, again, Pete Hagist. First, we did make some additional – earn in (00:18:13) additional long-term or longer-term contracts. Just recently, we added about 20,000 barrels of oil per day, an average differential of NYMEX minus $1.88. And then in addition to that, we've got about 15,000 barrels a day on DAPL at a fixed differential. So, when you put all those together, we do see differentials increasing up to an average in December of around $7, but we do expect that to moderate next year.

Great. Thank you. And my follow-up is on drilling and completion cost per well. With the Gen 4.0 completion attraction across the acreage position, could you update us on what D&C per well should look like going forward?

Yeah. I would. This is Rick Ross again. Our slide on page 20, where our well costs are between $6.5 million and $7.1 million. I think we'll hold that. We are not seeing any upward pressure on the pressure pumping side, which is the largest cost. We're actually seeing some reductions on the commodity or the sand. We continue to move our drilling or reduce our drilling time. So, I think we can hold those numbers or maybe slightly reduce them next year is what I expect.

Great. Thank you.

Our next question comes from Mike Scialla of Stifel. Please go ahead. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Yeah. Good morning, everybody. Just want to get your sense on some higher level thoughts on 2019. I know you've talked in the past about maybe adding a rig mid-year, any update there?

Yeah, Mike, thanks for the question. I think we've continued to talk about it's an efficiency game and it's a margin game for us. And so, we're truly focused on driving cost out of the equation and improving our margin. So, we only look to add activity at the point in which we think we can do that at or below the margins that we're currently generating. And so, we look at that closely. I wouldn't expect any large movements in either direction from us. Today, we're pretty happy with a five-rig program. I think we're getting cost efficiency and savings by allowing our team to really focus and to drive into that program. And so, we will look at maybe up one rig scenario, just depending on how our teams perform, how inventory looks, and takeaway capacity. But right now, we're at the five-rig program and we are not guiding or forecasting anything more than that at this point. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Okay. And then, is there any potential for Redtail to be part of the 2019 plan?

Yeah, Mike, that's a great question. We have economic wells to drill at Redtail. The last wells that we drilled out there are performing very nicely. We're encouraged by what we're seeing there, and it's something that will compete in our portfolio. Our commitment is to put our dollars to work at the highest investment opportunities that we have. And we do have some attractive opportunities at Redtail, and we'll be looking at how that mixes in with our North Dakota portfolio moving forward. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Very good. Thanks, Brad.

Our next question comes from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.

Good morning and congratulations on the continued great results. First question I wanted to ask was just if the Wildrose and the Cassandra tests prove successful, will the science behind these optimized completions enhance Whiting's ability to produce better wells in other Tier 2 areas or is it very specific to Wildrose and Cassandra?

Yeah. No, Jeffrey, this is Tim Sulser. That's a great question. And the short answer is yes, particularly in the context of right-sizing completions for the area, right? The Foreman Butte area, we have six wells we're drilling in that area and another 11 next year. And we're really excited about what we're seeing in offsets and how the completion evolution continues to evolve. So, it's, again, right-size for the right area and very much encouraged that some of those learnings can be applied elsewhere.

Okay, great. Thank you. And, Brad, you mentioned I think 3-mile completions upcoming. I was just wondering. What's the longest well that you've completed to-date?

This is Rick Ross. In the range of 2.5 miles is the longest we've done so far, but we feel real confident about the 3 miles that we've got the technology and ability to do it.

Okay. Fine. Thank you. Appreciate it.

(23:14), Jeffrey.

Our next question comes from Joe Allman of Baird. Please go ahead. Joseph Allman - Robert W. Baird & Co., Inc.: Thank you. Hi, everybody.

Good morning, Joe. Joseph Allman - Robert W. Baird & Co., Inc.: Good morning. Mike, question on the tax situation, could you give us some color on the 0% tax rate you had the past couple quarters and what we should think about going forward?

Sure. No problem. Right now, we're in a net deferred tax asset position. And what we did is we decided not to recognize that asset, so we don't even have that on the balance sheet. We put a reserve against it. As we generate taxable income going forward, we kind of eat into that reserve. So, what you should think about for 2019 is probably somewhere in the second quarter, we'll start recognizing deferred taxes again. Just to be very clear, we don't anticipate being a cash taxpayer for any time in the foreseeable future. But we will start recognizing deferred taxes, I would say, around Q2 and the effective rate would probably be just a little under 24%. Joseph Allman - Robert W. Baird & Co., Inc.: Great. Very helpful. Thanks, Mike.

Sure.

Our next question comes from Mike Kelly of Seaport Global. Please go ahead.

Hi. Thanks. Good morning, guys. I wanted to go back to the differentials real quick. Slide 23 shows that things have been kind of moving in your favor now for a few quarters. I think you just said you expect to see $7 diffs in December but then for that to come back down. Given everything you said about pipeline capacity, rail capacity, having some excess capacity, maybe could you just talk about, in your eyes, what the driver has been to see the diffs step back up to $7? And maybe give us a sense if people are looking at the Clearbrook hub as a potential proxy, if that's really kind of an applicable hub for us to really be kind of gauging where differentials could be up for you guys. Thanks.

Sure. Yeah, again, this is Pete Hagist. Yeah, we believe the differential expansion is primarily driven by the unusually high refinery maintenance. At peak, that was about 1.2 million barrels per day in pad 2 versus about 450,000 barrels a day at the same time last year. So it has been a very unusual usually high maintenance period, and there's still 850,000 barrels a day offline. So we do think the differentials will contract once that capacity comes online. So we think that's the primary driver here. In periods when you have an abrupt change like that, Clearbrook tends to be a clearing price. But as that moderates, then other pricing points become more relevant. So, differential – Clearbrook is not always the main pricing point.

Okay. Fair enough. Appreciate that. And then just a question for you on some of these newer concepts that you rattled off whether it's the 3-mile laterals or 500-foot spacing, so kind of dual Three Forks, Bakken wells, in your opinion, what should we really be having our eyes on? What do you think is kind of the most impactful for you? What are you most excited about? Thanks.

Yeah, Mike. Great question. I think I'll answer and I'll let Tim give a little perspective from his standpoint. But I think what we think about, Mike, is there's more oil in place in Sanish than anywhere else in the basin. And we realized that we're not getting at – we realized in place like the McNamara, we were only getting maybe 10% to 12% of the oil in place out of the ground. We think we can do much better than that. We think we can approach 20%. And so we're going back into the heart of the basin and looking how it was originally developed. And we're seeing some really nice surprises because the oil is in place there. And frankly, the Generation 1 and Generation 2 completions in there that were done a decade ago were not optimized. And so, we're finding – we're contacting new rock we believe that has not been stimulated before and that we're being able to get after that with new technology and that's just opening our eyes to a lot opportunities in both the Bakken and the Three Forks in that area and we're very excited about Sanish.

Yeah. This is...

Great. Appreciate that.

...Tim, and I'd just add to that, I think with Sanish (27:39) obviously, the way the wellbores were oriented originally, we're seeing a lot of unswept reservoir area that are leading to some of these 3-mile laterals just given the logistics of the original development. And as Brad mentioned, the oil in place there is better than anywhere in the basin and really just trying to capitalize that and manage that reservoir effectively and get the most out of it.

Great, guys. Great quarter.

Mike, I had one quick follow-up just to give you an idea, a little more clarity on your question. So, in November, we sold forward most of our volumes, and we sold about 2,000 barrels a day at Clearbrook out of our total volumes in the Bakken. So, as you can see, we're not selling them – we're selling a small portion of our volumes into Clearbrook at any given period.

Thanks, Eric.

Yes.

Our next question comes from Noel Parks of Coker & Palmer. Please go ahead. Noel Parks - Coker & Palmer, Inc.: Good morning.

Good morning, Noel. Noel Parks - Coker & Palmer, Inc.: I was interested in, at Foreman Butte, the outlook as you plan to start testing in early 2019 for the improved completion. I just wonder if you could talk a little bit more about what's the first priority in terms of changing those completions and just a little bit about how you plan to go about it, what your expectations are.

Yeah. Noel, this is Tim Sulser. It's a great question, and I think the first thing to keep in mind that those original wells and all of those drilling and spacing units that hold the acreage were effectively Generation 1 completions, right? So, we're really, really excited about getting in there and taking all the learnings that we've had over the last several years of optimizing that and just getting in there and see what we can do. So, we feel like we've got a really good design and we're going to get some wells. Like I said, 6 wells drilled this year and completed an additional 11 next year. And that is, again, offset operators have had some really good results in that area that we're excited about. Noel Parks - Coker & Palmer, Inc.: And just to follow-up, and so essentially pretty similar application of all the different changes in the Foreman Butte area as opposed to what you do in Gen 4.0 in the other areas?

This is Rick Ross. We're certainly going to stick with what we've been talking about, and that is that we're going to custom design the frac jobs for each application considering rock properties geology. So, in general, yes, with the Gen 4.0 design. We will be using some of our thoughts on rate. We'll be using our diverter strategies that we think have been very positive. In general, we're going to not pump the huge jobs of probably be in 7 million to 9 million pound range, which we think is applicable to that area and we're excited about the results that we're seeing. We've shown it in the Hidden Bench. We've shown you some numbers in Sanish and what we're doing with that new completion. So, we're very positive about it. Noel Parks - Coker & Palmer, Inc.: Great. And then, just my other question, you're talking about all the things you could do at Sanish trying out new concepts. I was curious about – further to the West with new completions and certainly higher oil prices than we've had in a couple of years. I was wondering about the lower Three Forks like how and kind of out to the, if memory serves me, the southern and western extent of the position. Any of those coming back into play in this price environment, or is that even something that you're – is on the agenda for tackling near-term?

Noel, just one clarification. This is Eric. When you say lower Three Forks, do you mean like third bench, fourth bench, or are you talking... Noel Parks - Coker & Palmer, Inc.: Right.

... about the second? Noel Parks - Coker & Palmer, Inc.: Well, second also.

Okay, so I think in this, we've always been a big proponent of the second and never really built third and fourth much into our inventory. With that, I'll hand off to Tim. Any new thoughts on the third or fourth? Or Rick, Rick's going to take that one.

Yeah, I would say certainly on the west side of Sanish field and the southwest side, the Three Forks is quite strong. And we have about – we are looking at the second bench. But as Eric mentioned, that's as far as it would go. We really see first and second bench targets.

And we have second bench producers in the greater Hidden Bench area as well that we've produced in the past and continue to get contributions to that. And you better understand the reservoir dynamics but absolutely get contribution in Hidden Bench there. Noel Parks - Coker & Palmer, Inc.: Great. Thanks. Oh, sorry.

Noel, just a huge advantage that we have as we've had a geologic staff that has completely mapped the entire basin over the last eight years and incorporated every bit of log and core data that's out there. And so we've never just looked at our postage stamp of the acreage we've owned. We've always mapped the entire basin, and so really good understanding in-house here at Whiting of what the opportunities are across the entire basin. Noel Parks - Coker & Palmer, Inc.: Great. Thanks a lot.

Our next question comes from Tim Rezvan of Oppenheimer. Please go ahead. Timothy Rezvan - Oppenheimer & Co. Inc.: Hi. Good morning, folks. Thanks for taking my call. Brad, there are a few oily peers out there making a value proposition based on perpetual free cash flow generation and low leverage. Is that the longer-term model you think is possible for Whiting or should we think about this free cash flow generation as a medium-term initiative designed to right-size the balance sheet?

Tim, great question. And no, I don't think that's the case. I mean, we've talked about always running a great business here and we think that's a part of it. So, with the Tier 1 position, we have the opportunity to have production volume growth and continue to make (34:03) free cash flow generation. So, I would (34:09) say that free cash flow generation is a short-term objective here at Whiting. It's how we think you ought to run the business. Timothy Rezvan - Oppenheimer & Co. Inc.: Okay. Thank you.

Our next question comes from Ray Deacon of HS Energy Advisors. Please go ahead.

Yeah. Hey. Good morning. I was wondering if you could talk a little bit about your gas dedication on any new pipelines that are being built and when you kind of expect to see some relief there in pricing.

Yeah. This is Pete Hagist. Currently, about 2.3 Bcf a day of production, about 2.6 by the end of the year capacity, so it's fairly tight. But there's announced about 1.2 Bcf of expansion capacity and we're in very close communication with all midstream providers. We've got a lot of confidence that that's going to come to fruition. Probably starting early next year and certainly by the end of next year, a lot of that will be in service. So, as we look out, we think there's going to be plenty of gas takeaway capacity. But in general, we are selling – most of our gas is dedicated to those midstream providers. So, we can't move that gas around a lot. So, we really have to work closely with those providers.

Got it. Got it. I guess I assume some players in the basin are at the point where they need to look at flaring, maybe aren't able to get permits. I guess, could that potentially drive some M&A where you could add some acreage at a good cost or...?

It certainly could. And every operator's in a different situation. We have been aware of the tightening gas takeaway situation for some time now and have been planning for it. And we've got various strategies in place. So I think Whiting is well-positioned for it. We've had a very, very high gas capture rate with the excellent operations we've had. So, I think we're well-positioned. I can't really speak for others. So we'll see how that plays out.

Got it.

Rick, we were over 90%, right, last quarter – last month?

We have and we've always been in compliance with the capture.

Yeah. So...

We're well over 90%.

Yeah. We're well over 90% too, Ray. So just to speak to your point, we definitely have a competitive advantage in that regard.

Got it. Great. Thank you.

Our next question comes from Jeoffrey Lambujon of Tudor, Pickering & Holt. Please go ahead. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning. Thanks for taking my questions. First one is on crude marketing, but from a pipeline standpoint. What's the house view there in terms of the outlook for potential newbuilds? And is there an appetite to dedicate volumes towards getting anything built?

Well, we know that there is quite a bit of talk about some future pipeline expansions and there's a number of those on the drawing boards. We're certainly aware of all those. We've been involved in discussions about those, so. But as I said earlier, there has been historically a lot of takeaway capacity out of the Bakken via rail, so we want to see how the refinery turnarounds. We want to see that concluded first and we do think that some of that rail capacity will be repositioned. And then we'll also be cognizant of these planned pipeline expansions.

Yeah. Jeoff, just to be frank, we have signed CAs on some of those things. And so, we really can't discuss them that much in the call. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Understood. Appreciate that. Second one is just a follow-up to the capital allocation and free cash flow questions from earlier. Thinking about the balance sheet as a priority still, can you just expand or remind us on where you'd like that to be before return of capital starts to potentially enter the mix?

Well, like I said, we're at $2.8 billion of debt. We've already stated our intention to want to get that down to $2 billion over time. I think as you get closer to that, as we get down to $2.4 billion and $2.3 billion, I think return on capital talk really starts to heat up at that point. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you.

Our next question comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.

Yes. Thank you. At Redtail, any updates on the expected exit rate there?

Yeah. This is Rick Ross. I think we were guiding or maybe I've talked earlier about 15,000 BOEs per day. We continue to really focus on our base decline really closely. And we've made good progress there, and I would say the new wells that we brought on over the last year are performing well. So, we're going to exit about 17,500.

Okay. That's good. And a question on hedging into next year, do you have a percent hedged goal, or is it – are you hedging more opportunistically based on price?

Yeah. We have a goal. We have a goal. We want to be 50% to 60% hedged. I kind of say if we – once we get to 50%, we'll see where the market's at and see where we want to take it. This year, we took our hedges all the way up into the 70% and prices are where we like them, what we think is a good attractive value proposition to put the hedges on. We'll take it up above 50%, maybe as high as 70%. But we'll just have to wait and see where the market's at but 50% is the bottom goal.

And one more if I could. In terms of – you're drilling now primarily in the core, what would the oil cut be of the wells that you're currently drilling versus your legacy production?

Depends what part of the basin we're drilling and there are certainly areas that have higher GOR such as Tarpon area. But in general, we got a 60% oil rate, 83% total liquids, and on average that's where we're going to come out with a new drilling as well, and staying pretty consistent we've got right around 67% all year.

Yeah. Marshall, I don't see any big shift in the oil rate depending on where we put the rigs, for example, Sanish has a bit higher oil cut, Tarpon a bit lower. As we go into the expanding areas, they're probably a little bit lower than in the Tarpon area. So, you may actually get a little bit of an uptick in the oil rate there.

All right. Thank you very much.

Thanks, Marshall.

There are no further questions and I will now turn the call over to Mr. Eric Hagen.

Thanks, Andrea. Whiting will be participating in the Bank of America Energy Conference, November 14 through 16; and we'll also be participating in the Capital One Energy Conference, December 4 through 6. And now, I'll turn the call over to Brad Holly for closing remarks.

Thank you, Eric. In closing, I would like to thank Whiting employees for making this one of the most remarkable years in Whiting's history. We are rowing together to rebuild Whiting into an industry leader in capital efficiency and to pioneer a fresh business model that can thrive at all points in the commodity cycle. I also want to thank our shareholders. As you know, we truly value our interaction with you and are active listeners to your thoughts and suggestions. We will continue to create value by delivering on our balanced strategy of free cash flow with disciplined growth.

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