Good morning. My name is Keith, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Fourth Quarter and Full Year 2016 Financial and Operating Results Conference Call. The call will be limited to one hour, including Q&A. 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.

Well, thank you, Keith. Good morning, everyone, and welcome to Whiting Petroleum Corporation's fourth quarter and full year 2016 earnings conference call. During this call, we'll review our results for the fourth quarter and full year 2016, and then discuss the outlook for the first 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 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-K for the full year ended December 31, 2016 is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

Thank you, Eric. And good morning, everyone. Let's get right to slide number 2, which shows it was a great quarter for Whiting. Production exceeded the high end of our guidance with capital spending on target. Earnings per share and cash flow per share exceeded consensus estimates. In the fourth quarter, operating cash flow of $237 million exceeded CapEx by $115 million. This is the third quarter in a row we've generated cash flow above CapEx. Also, CapEx was on target again this quarter. Fourth quarter production came in above the high-end of guidance, and averaged 118,890 BOEs per day, despite severe weather in December. Adjusted for asset sales, our production increased from the third quarter, driven by our Bakken/Three Forks play, which grew 3% quarter-over-quarter. This reflects the quality of our wells, where productivity is measured by 90-day rates has increased 84%, since 2014 to an average of 1,057 BOEs per day over that 90-day period in 2016. We continued to see strong results in the fourth quarter with 30-day average rates of 1,754 BOEs per day. On the operating side, we continue to achieve cost savings with fourth quarter LOE at the low end of guidance at $8.01 per BOE. Subsequent to the quarter end, we received $375 million from our North Dakota midstream sale, and used $275 million of the proceeds to redeem all of our outstanding 2018 notes. The additional $100 million was used to pay down the revolver. As Mike Stevens will detail later in the presentation, we have reduced debt by $2.4 billion or 42%, since March of 2016. In 2017, we project a capital budget of $1.1 billion, and forecast strong production growth of 23% from Q1 to Q4 of 2017. This also sets us up for strong double-digit growth in 2018, and…

On slide number 13, we show our fourth quarter 2016 financial results. Our operating cash flow was $237 million, which was significantly above our CapEx of $122 million. On slide number 14, you can see the debt reduction we achieved since March 2016. Starting from a base of $5.65 billion, which consisted a $4.65 billion of bonds and $1 billion of bank debt, we have reduced our debt to $3.3 billion. This represents a 42% decrease since March 31, 2016. On slide number 15, you can see our liquidity and debt covenants. We had $500 million drawn on our $2.5 billion borrowing base as of February 2, 2017. We have no debt maturities until 2019 as we redeemed all of the outstanding 2018 notes on February 2 with the proceeds from the North Dakota midstream sale. We remain well within all of our covenants and strongly positioned from a liquidity and debt maturity perspective. Our guidance for the first quarter and full year 2017 is detailed on slide number 16. We project 23% production growth from the first quarter to the fourth quarter of 2017 based on our $1.1 billion budget. We will put on production 70 gross wells in the first half of the year, and 163 gross wells in the last half of the year. At current NYMEX strip prices, the additional cash flow from this growth will result in continued improvement in our debt-to-EBITDAX metric. Slide number 17 provides a breakdown of our capital budget in 2017. 96% of the budget is allocated to development activities that drive production growth. Slide number 18 shows our crude oil hedge positions as of January 3, 2017. We are 53% hedged at attractive prices. With that, I'll turn the call back over to Jim.

Thanks, Mike. Ladies and gentlemen, in 2016, our efforts to position the company for growth in a $50-oil price environment came to fruition. Through innovative capital markets transactions and asset sales, we reinvigorated our balance sheet. Through innovative technology leadership, we created a step-change in Bakken well productivity and profitability. We believe these achievements position us for multi-year growth while maintaining a strong balance sheet. We thank our investors for their support as we delivered on our 2016 initiatives. These achievements set the stage for the rewards from strong growth in 2017 and the years ahead. Keith, please open up the conference call for questions.

Yes. Thank you. And the first question today comes from John Freeman with Raymond James.

Hi, John. John A. Freeman - Raymond James & Associates, Inc.: Hey. Good morning, guys.

Thanks. John A. Freeman - Raymond James & Associates, Inc.: Jim, you mentioned that if you just sort of flat line that 4Q 2017 production, you get like 13% growth in 2018. And you've mentioned you'd look to kind of grow on top of that. I'm wondering could you just sort of give maybe a ballpark kind of estimate of what the maintenance CapEx would like at the end of 2017.

Sure. Mike's been waiting to answer that one. So I'll let him do it.

We think to hold the results flat around 140,000 BOEs a day would take about $900 million in 2018. John A. Freeman - Raymond James & Associates, Inc.: Perfect. Thank you. And then, my follow-up, when I'm looking at the completion cadence, it's obviously driving the big second half 2017 production ramp. Any color we could get on either just the total kind of completion cadence or even just specifically on those 105 Redtail DUCs would be helpful.

Well, as Mike said, we intend to put on, in the first half of the year, about 70 wells on production, and 163 in the second half of the year. John A. Freeman - Raymond James & Associates, Inc.: And then, of that – I'm sorry, but on just the Redtail DUCs?

Go ahead, Mike.

Yeah. So, we're pretty heavily weighted towards the second half of the year on Redtail. So we have 15 in the first half, but 95 coming on in the second half. It comes on pretty strong right at the end of the summer there, and then continues to stay pretty strong. So, in total, 110 wells that we are putting on production at the Redtail.

So, you're right, John. 15 in the first half and 95 in the second half. John A. Freeman - Raymond James & Associates, Inc.: That's perfect. Thanks, guys. Look forward to seeing you all soon.

Great. Same here.

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

Hi, Brian.

Good quarter, guys. How are you?

Thank you. Great.

Great job on the Bakken, wells look fantastic. I had one question on those, the 25 wells you brought on in the fourth quarter, were those spread out through your acreage? Or was it concentrated in one area because the rates were fantastic?

It was really spread out across our acreage. That's the great thing about our acreage position. And Mark you can add to that if you like.

Yeah, really, it's across the basin. We have rigs working both in Dunn, they're in McKenzie County and Williams County along the river, or what we call our Polar area and Tarpon, some of the better completions are in Tarpon. And we've also got a rig working on the Pronghorn. So, pretty much across our acreage.

Okay.

Great question.

And then, when I look at the Niobrara, you're going to test the bigger completions there. When do you think you're going to have some of those results?

This is Rick Ross. The larger completions will come on right at the end of the second quarter, first part of the third quarter.

Okay. All right, guys. Thank you.

You're welcome. Thanks for your questions.

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

Hi, Neal.

Hi, Jim. Say, Jim, of that – you put out the $580 million of the five rigs that you're planning for the Bakken this year, are most of those going to be tackled into the larger volume completions that you so pointed out on that slide 9, that are outperforming? I mean, how much is going for those enhanced completions?

I'll let Mark answer that one, and Rick too. They have been waiting to kind of answer that.

All right. Basically, at this point, everything we're doing is enhanced completion where our sand volumes are between 7 million pounds and 10 million pounds as a rule. Some of them get up to about 11 million pounds. But as we continue to ramp up sand volumes, the other thing that we're paying lot of attention to is, as we bring the sand volumes up, adding more entry points, so that we're actually distributing that sand better. So that's – so we did a lot of ramp up to essentially 7 million pounds to 8 million pounds over the course of the last year. We're now going up to 10 million pounds or 11 million pounds. The second thing that we're doing I think is really important, is we're customizing the design that each of those completions to the different areas of geology vary subtly across our acreage position. So, essentially, customized completions of the well.

Got it. And then, just one follow-up, if I could, guys. Mark, you've mentioned in the past about the refrac opportunities. Do you still see just as many? And what type of upside could that produce either this year or next year?

So we have started on our refracs. We were about four wells into that program right now, and have had some very good initial results. Essentially, what we're doing is we're grinding in all our refracs with our development. So, as we put rigs out into any one of our areas, we've already catalogued now and prioritized all the refrac opportunities. We are working on those right in with the completion of our new wells, it's sort of seamless. But in total, we figure that we've got somewhere in the neighborhood of 200 pretty good opportunities for refracs, but you'll see those as just a regular part of our development program.

Great. Thanks so much, guys. Jim, nice turnaround.

All the best. Thanks.

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

Good morning.

Good morning, Steve.

You've obviously done a fantastic job of bringing your debt down over 40% in a relative short period time. Are we done with non-core assets sales, I know never say never, but what's your thinking there, Jim?

Yeah. We don't have any non-core assets lined up right now. We do continue to talk to some folks who have approached us about joint ventures, and the net result of those joint ventures could be continued balance sheet improvement.

Okay. And in terms of the – just staying on the balance sheet, 2019 is not that far away. Any thoughts on maybe refinancing those bonds or the just the 2019 or even 2020, based on (18:03)

Yeah. We're looking at ideas for that right now, but honestly, there's still out there quite a way. So we have plenty of availability on the borrowing base. It's one way to go. So we're just looking at ideas right now, but no plans in the near-term to do anything with them.

Yeah, I'm sure you're aware all of our bonds are currently trading above par.

I am. All right. Great. Thanks, guys.

Thank you. Great questions.

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

Hi, Will.

Good morning. I may have just missed this, but I wondered if you guys could remind me on where you guys are currently at or where you've been Redtail completions on maybe a pounds per foot and where you guys expect to get to or where you guys are layering in these higher intensity jobs?

Yeah. This is Rick Ross. Our current completion I'll say on a 960 would amount to about 700 pounds per foot and a 30-stage job. What we're ramping up to in a test mode would be 50 stages and about 1,100 pounds per foot.

Now, I'll add to that. Will, you may have seen that one of our peers that operates at the East Pony field, which is basically contiguous with the Redtail field (19:21) larger completions with excellent results, nearly 600,000 BOE wells on a 7,500 foot lateral. So we are very optimistic about the potential at Redtail for enhanced completions.

So, you guys are kind of just taking a more gradual approach to that, and seeing how they respond and ultimately that's still, I guess, potential like to go out further with those?

We're ramping up to a similar amount to our peers and we'll see how that comes in.

Just to mention one thing about Redtail there, we have a tremendous amount of oil in place. And we feel like, there is an opportunity to get better production given the high oil in place there is there we don't really have a ceiling. So as we test our larger sand volumes that we're talking about here, we think our recovery efficiencies going to getting started to get in line with the Bakken. So, a plenty of headroom, I would say, on those completions.

That's right. All Redtail needs is more wells.

That's great to hear. And then, on 2017, I know you guys noted you're targeting kind of a 900,000 to 1.5 million barrel EUR for all the wells you guys drilled in Williston this year. I wanted to ask because you've really cored up and high-graded your acreage up there over the years, so I realize that all of the acreage is pretty high quality now. But do you think that that range is now kind of reflective of all of the wells you have going forward or you just kind of drilling some of your best areas this year? How do I think about that long-term EUR (20:59)

I think you've stated it very well. I think it's a reflective of all of our acreage going forward, certainly everything that we'll be drilling over the next three or four years and we feel very good about that.

Great. That's all I had. Thanks, guys.

You're welcome.

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

Hi, David.

Good morning, Jim and everyone. Hi. how are you, Jim? Thanks for taking my questions.

Good.

I was thinking, you guys provided a helpful sort of a maintenance CapEx on the fourth quarter 2017 exit into 2018. I guess to square that with your comments earlier about growing on a healthy balance sheet, there is some outspend in the 2017. I guess as you guys reinitiate the DUC program and Redtail, et cetera, do you view more of a free cash neutral profile beyond 2017, while still being able to grow there?

I would say our growth in 2017 will improve our debt-to-EBITDAX metrics very significantly over the course of the year. Plus, we protected a large portion of the cash flow from this growth through a robust hedging program. Also, in our own mines, we earmarked $100 million from our North Dakota asset sale to reinvest for growth, which we don't consider to be outspend.

Got it. That's helpful. And then, just on the, I guess, geography of the Redtail DUCs, can you give us a sense of maybe percentage-wise, how many of them are sort of in that Razor area versus Horsetail, and some of the other areas there?

Let's say that everything we have lined up for 2017, the DUCs as well as the new drills are in the core part of Redtail, which is Razor and the west part of Horsetail. It's all one contiguous accumulation through there and that's our entire program for 2017.

Yeah. It's very high quality, David. It's where we released a lot of well results in 2015 that were showing wells approaching 500,000 barrels.

I appreciate that. And just one last one, if I may. And, Jim, you discussed maybe the potential for looking at JV opportunities, is that being considered across the entire asset base or in more specific areas? And I think in the past, you've kind of framed JVs versus kind of going in the loan based on commodity prices, is that still kind of the framework or you now kind of feel like with the balance sheet right sized, there might be just be some opportunities out there maybe in some less capitalized areas to pull some of that value forward?

My comments currently are directed only at Redtail.

Okay.

Yeah. And that would be outside of that area that Mark and I just talked about, David.

That's helpful. Thank you.

You are welcome.

Thank you. And the next question comes from Paul Grigel with Macquarie Capital. Paul Grigel - Macquarie Capital (USA), Inc.: Hi. Good morning. Just wanted to touch on the Williston Basin, and do you guys have the (24:09) potential desire to increase completion sizes larger than even the 10 million pound or 12 million pound? Some of the peers are well into the teens, and pushing 20 million pound. I guess could you guys walk through the strategy of going on a more measured pace versus maybe jumping on and testing something towards the outer edge?

Yeah. I will say, our plan for 2017 is to look at the 10 million pound to 15 million pound jobs. We're going to look at probably 10% to 15% of our completion inventory going that way, and we're just trying to ensure that we're getting a good return on our incremental investment. I think we're seeing some good results that we're showing you there. So that's our plan. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. And within that plan, just as a follow-up there, for the assumptions on the guidance that you've given, is it based off of $900,000 for each of the wells or is it more targeted specific that some are maybe $900,000, some are $1 million and some are $1.5 million?

Paul, it's more complicated than that. It varies. We model it by area And I would say some of the recent results are partially reflected in there. So... Paul Grigel - Macquarie Capital (USA), Inc.: It's okay.

It's same as we've said in the past. That's conservatively modeled. We look back at results in those various areas over the past six months to a year, and that's what gets factored into our production forecast. So, I'd say, you can say some of the recent results are partially factored in there. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. No, that's helpful. Let me just...

I want to clarify one thing about the capital efficiency and spend too just in case it wasn't clear what Mike had said earlier that our maintenance CapEx was $900 million. Now, I want to ensure everyone understood, that was to keep 140,000 barrels a day flat, that's not referring to our 2016 average. That's $900 million for 140,000 barrels a day. All right? Paul Grigel - Macquarie Capital (USA), Inc.: Okay. Thanks. And then, one just one last one on service costs, you guys are obviously baking in some. What is the thought on potentially in the Bakken or in the DJ relative to other basins in the U.S.? Should it be higher, lower, in line? Just curious to get your thoughts there.

I'll just say that we've built in about 20% increase in pressure pumping services for our activity in 2017. But for full disclosure – well, and I'll say that that amounts to about 4% of the total well cost, when you really work it out in that way. For full disclosure, we did build in some significant efficiencies that we've gotten in other areas as well and we're pushing down our drilling cost. So, 20% on the service company pressure pumping volume (26:48). Paul Grigel - Macquarie Capital (USA), Inc.: And are those service costs or service efficiencies that you've already realized to-date, or they assuming going forward there, Eric?

These are efficiencies that we've been able to achieve over the last quarter. Paul Grigel - Macquarie Capital (USA), Inc.: Thank you.

You're welcome.

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

Hi. Good morning, everyone.

Jeanine, hi.

Hi. Just going back to the 2017 plan, can you talk a little bit about the capital allocation process between the Williston and the Redtail? Maybe specifically in terms of adding incremental activity to the Redtail, just want to understand – understanding that it's DUCs that you also started the rig running, but was that solely rate of return driven or were there other considerations like – it sounds like there's more optimism in new completion designs in Redtail, et cetera?

Well, of course, we look at all the data, and we use that to determine where we're going to drill. And you can say therefore that it is rate of return driven, that's for sure.

Yeah. I mean, I'll add to that, Jeanine – it's Eric – that it's underpinned – earnings underpinned by rate of return and NPV. And when you look at a Redtail DUC, you're spending about $3 million to get a well around 500,000 barrels. That's about a $6 million of finding cost. You look at 1 million barrel well in the Bakken for $7.3 million, that's about a $7 finding cost. The Bakken wells do have a little bit more production upfront, but the Redtail DUCs have a shorter cycle time, they're already drilled. So we think the returns are pretty competitive. That's why we kind of had a balance in the program this year. As we go into 2018, probably, you'll see more activity shift into the Bakken, as we drill through the DUCs there.

Okay. Great. That's really helpful. Thanks. And then, just my follow-up is, is there anything, logistically speaking, that would maybe prevent you from adding more 10 million pound fracs to the plan? I know you said they are all kind of at that level, but maybe adding higher sand volumes to that or just more well, should you see commodity prices increase or if you're completing things ahead of schedule for anything logistically that prevents you from adding more of those bigger frac to the schedule?

We don't see that now.

Okay. Great. Thanks for taking my questions.

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

Thanks. Good morning, guys. Sorry, if it's been hit and I missed it, but just to be clear what exact sort of EUR you're assuming in the 2017 guide?

Can you repeat that?

What you're as being assuming within the 2017 guide (29:38)?

900,000 barrels to 1 million barrels.

Okay. And how much of the capital program will be directed towards, call it, 10 million pound plus type completions?

10% to 15% of our completions in the Bakken.

Okay.

Yeah. That's testing things (29:59) in the range of like 12 million pound to 15 million pound jobs, Michael.

Okay. Great. I appreciate clearing that up for me. And then, on the productivity front, the step-up from 2014 to 2015 to 2016, how much of that would you say it's completions-driven versus high grading and/or just location-driven?

I would say, if you look across the completions we've actually done, here as reported by the NDAC, you can see where all of our wells have been completed, where we drill and where we complete wells. And you'll see it's across our acreage spread. So what we were talking about earlier is it's pretty broad representation of Whiting's acreage, especially in the Williston. So that increase in production is driven primarily by increases in our completion technology, which again is a sand volumes plus more entry points plus customized completions, designed completions specific to the geology of each those seven areas.

Okay. Great. So with the larger – it sounded like then with the larger program in 2017, you wouldn't expect a much of a headwind from that. It would be probably a tailwind from the higher completion loading year-on-year. (31:33) statement?

I think you judged much better of what we do. And I think, those gains once, you realize that technology, those are locked in.

Got it. Appreciate it. Thanks for the questions, guys.

You're welcome.

Thank you. And the next question comes from Mike Scialla from Stifel. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Yeah. Good morning, guys. Most of my questions have been answered. But just one on Redtail, wondering where you are in terms of HPP acreage. Does one rig fill all the need there? And same thing for any minimum volume commitments that you may have there, does the completion schedule where does put you relative to any MVCs you may have?

Well, we're in good shape on acreage. We've scattered our drilling around enough out there previously that, we're in good shape in terms of the HPP-ing our acreage. And as we have commented before, the bulk of the budgets going into the Bakken, 60% roughly and 40% at Redtail. The wells are cheaper at Redtail. So we can basically drill a few more. And of course, really the reason that as much as 40% of the budget is in Redtail currently is, because of, as Eric just explained, the good bang for your buck you get by completing these 100-plus DUCs that we have there. So Redtail is good, I would say. If you want to me to rate something for you, I'd say, I'd rate our Redtail as an A, and I'd rate our Bakken as an A-plus. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Fair enough. And just to clarify, Eric, you put up those numbers on well costs, I think $3 million for – and Jim, you just mentioned that. That is, I assume that is the larger frac size and same thing with the Bakken, the $7.3 million, is that for your – I guess, what size completions is the $7.3 million referred to?

In the Bakken, 10 million pound job at $7.6 million. If you are down around $7.8, it will be around just over $7 million. And in Redtail, DUC would be $3 million to probably $3.5 million with a larger completion, somewhere in that range. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Got it. Thank you.

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

Hi, Tarek (34:16).

Hi. It's actually Kevin (34:17) calling in for Tarek, and thanks for taking my question.

Okay.

Just real quick on the 2017 spend, and I know you mentioned free cash a little bit earlier, and this is more to kind of lay the groundwork for 2018 growth. But just wanted to see what near-term free cash flow looks like or lack thereof also what you might expect for the spring redetermination?

Well, I'll handle the redetermination part. There were $2.5 billion of commitments in borrowing base right now. We'll have our bank meeting coming up here in March – later in March, and we expect that from all the signs so far to stay right at $2.5 billion. Could you repeat your other question?

Sure. I was just looking what kind of your near-term cash flow outlook looks like. I know it's going to be a little tougher to spend with the higher spend and to keep it within cash flow in 2017, but just wanted to see kind of what your near-term outlook is, what your revolver draw might look like?

Well, like we said, we really believe that in 2017, there is a limited amount of outspend, because we basically earmarked about $100 million of that sale for growth in 2017. And I as mentioned, there are other balance sheet improvements that we can do simply by perhaps JVing a few more wells in Redtail. What that means is production growth there which helps your debt-to-EBITDAX ratio without spending much, if any, additional capital. So that would be the reason for doing some of those is twofold, more production and improvement of the balance sheet, as a result of that ratio.

Okay. That's helpful. And my follow-up is just on any color on the M&A environment in the Bakken and Redtail, given more recent transactions focused on the Permian and in the Mid-Con?

We are vigilant. That's all I can say. We are vigilant, but we don't have – if we had an acquisition there, we would have announced it. So, haven't seen anything that I would say would knock my socks off right now.

All right. Fair enough. Thanks very much.

You bet.

Thank you. And the next question comes from Jeff Robertson with Barclays.

Thanks. A couple of follow-up questions on Redtail. The largest stimulations that you all planned, are those applicable in all four of the prospective zones you have or are they more suitable to one bench than the others?

Let's say they are going to be applicable to all four of the zones. We haven't seen a tremendous need to change the design between zones. The exception of that might be the C, which is a little bit thicker than the A and B or the Codell but pretty applicable to all four zones.

So, those zones won't communicate with each other at Redtail?

If they do, not for long.

Right, exactly. There is a quite a bit of, what we call, Bentonite or play in between those zones. So during the frac, sometimes there is some pressure communication but those are pretty good frackers. So during the production phase, there is little or no communication.

Okay. And, Jim, can you remind me are there any marketing issues or processing issues in the Redtail area that will be addressed that allow you to go a little bit faster towards the second half of the year?

No, there is no limit there. We've got great takeaway capacity, and frankly, adding more production there reduces the differential.

Okay. Thank you.

Thank you.

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

Hi, Gail.

Hi. Just in regards to the $900 million CapEx to keep the 140,000 BOE/d flat, how should we think of the allocated, like 70% towards Williston, 30% towards the Niobrara?

Yeah, that would be good.

And then, looking at the 105 Redtail completions, how many of those at this point in time are doing the enhanced completion?

I would say that what we're going to be doing is we're testing out some different completion designs here during the first quarter that will drive a lot of the completion designs for the second half of the year. But, in general, we're ramping up, sand volumes as well as stage. We're getting up to 50 stages. So our real focus there is to distribute that sand better, it's not just the sand volumes, but it is distributing the sand along the wellbore better. So, we're doing a lot of experimentation on how to best achieve that right now. But, I think, in general, you will see us up in the sort of 7 million pound range is where I think we are going to have the settling for the year for the Niobrara, maybe a little more.

And then, based on the performance, it's plausible that they could be more productive than the average recovery that you are assuming currently in guidance, correct?

Absolutely.

Great. Thank you.

Thank you.

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

Hi, Sean. Sean M. Sneeden - Oppenheimer & Co., Inc.: Hi. Thank you for taking the questions.

You bet. Sean M. Sneeden - Oppenheimer & Co., Inc.: Maybe just on the reserve side, have you guys run what year-end would like on a strip basis or kind of $55 flat environment versus the SEC deck? I'm just kind of trying to think about or wondering how that might factor into your may redetermination with the banks?

Well, the banks are going to use their own bank case pricing, which is lower than the current strip. So, we know what those prices are and that's why I think that the redetermination will stick at $2.5 billion. And in terms of the reserves, I guess, a higher SEC price, they were higher at December 31, 2015. They were in the low $50s then, cutting back to a low-$40s, we moved 120 million of reserves this year. So we'll probably get most of those back when we go back into the low $50s.

And, Sean, I'd point out, we gave the case in the press release, which said that at a $50 and $2.58 oil/gas price, reserves would have been $850 million, and adding back divestitures would have been $851 million versus the actual prices were $42 and $2.49. So, we kind of gave that case in the press release to show that adjusted reserves actually grew year-over-year. Sean M. Sneeden - Oppenheimer & Co., Inc.: Okay. That's helpful. I might have missed that. And then, just lastly on the balance sheet. Jim, did you say, under your current plans that 2018 leverage would be under 3 times or was that a 2017 number?

Yes. I said that. Sean M. Sneeden - Oppenheimer & Co., Inc.: Okay. So, 2018?

Yes. Sean M. Sneeden - Oppenheimer & Co., Inc.: Okay. Perfect. Thank you very much.

All the best. Great questions. Thank you.

Thank you. And the next question comes from Tyler Garrioch (41:47) from Coker & Palmer.

Hi, Tyler (41:50). Ray Deacon - Coker & Palmer, Inc.: Yeah. Hi. It' Ray Deacon. Thanks for letting me ask my question.

Oh, hi, Ray. Ray Deacon - Coker & Palmer, Inc.: How are you?

Good. Ray Deacon - Coker & Palmer, Inc.: Congrats on the results in the Bakken. It sounds great. And I was wondering, it seems like as you kind of go through the DUCs in 2017, and you get to 2018, people might assume you become less efficient. And I was wondering do you think the potential with the XRL laterals that you've talked about some, could offset some of that as you go into 2018?

Well, every year, we become more efficient. So I would agree with you that, as we move into 2018, we'll be more efficient than we were in 2017, and the things that both Mark and Rick have said here about the testing of these, I'll just go beyond testing and say, the implementation of our plan to spread more sand across more entry points is exactly what will drive that growth in 2018.

And I'll point our Ray, we think about capital efficiency between 2017 and 2018, as I enumerated, Redtail DUC, in terms of returns and whatnot is similar to a Bakken drill and complete. So as we shift from Redtail DUCs to Bakken to more Bakken drill and completes in 2018, you shouldn't see any change in the capital efficiency. Ray Deacon - Coker & Palmer, Inc.: Okay. Got it.

If anything (43:23)

It shouldn't be a concern. Ray Deacon - Coker & Palmer, Inc.: Right. Got it. And I guess just, could you talk a little bit about your thoughts on differentials from here, given some of the projects moving forward in the Bakken, I mean, sorry?

In the Bakken? Ray Deacon - Coker & Palmer, Inc.: Right.

Thank you for asking. Well, we do think, we'll see $1 or $2 as a result of DAPL. And I might say increased takeaway capability as it now looks like there is chances for a number of parties, us included, to market perhaps not only in what I would call the Upper Midwest, down the Enbridge line, but in the key driving portion market of the Midwest where DAPL will end up in Illinois. And then, also the ability to take more crude to some of the markets in Wyoming, which have been pretty strong off late. So in general, I see a declining differential, and the longer the period you're talking about, in another words, if you were asking me where you think we'd be 36 months from now as opposed to 12 months from now, I'd say it would be even lower 36 months from now. Ray Deacon - Coker & Palmer, Inc.: Great. Thanks very much.

You're welcome.

Thank you. And the next question comes from Jacob Gomolinski-Ekel with Morgan Stanley.

Hi, guys.

Okay. Hi, Jacob.

Hi. Just a quick follow-up to Sean's question. Did you have available like sort of – I know that you provided the number of reserves, but a value of those reserves for assuming the 2015 price deck for the current reserve book and adjusted for the new cost structure?

That will all be in the K.

Including on – I'm assuming the K will be on SEC 2016 pricing. But did you have one on either strip or $50, $2.50 gas?

No, we don't have that right here.

Okay. And then, on hedging, just – I know you've got 50%.

The other thing we said regarding that is we thought we would add back over 100 million barrels as a result of having what looks like strip pricing, the current strip pricing for year-end 2017. Mike gave you an estimate of about...

120 million barrels, thereabout?

Right there. Right at 120 million barrels.

Okay. And then, just wanted to get your thoughts on hedging. Is sort of 50% for current year, how is (46:30) the right way to think about your philosophy on hedging going forward in terms of the right amount have hedged, call it, maybe for beginning of 2018, also looking at 50%? Or is it something else? Just trying to get your thoughts on how you think about hedging.

Yeah. Generally, we want to be 50% to 60% hedged, probably likely closer to 60%. Right now, we're 53% hedged based on December's production. But as we go through the year, we'll become less as a percent hedged because of the growth we're going to have in our oil volumes. So although we layer on more hedges here for 2017 as we move through 2017 in the last half of the year and that on 2018 as well 50% to 60% with a leaning towards a 60% range.

Okay, great. That's it from me. Thanks very much.

Great.

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

Thank you, Keith. I'd like to thank all of the Whiting employees and Directors for their contributions to a very solid third quarter at Whiting. Eric?

So, Pete Hagist will be presenting at the EnerCom Dallas Conference on Wednesday, March 1 at 10:55 AM Central Standard Time. Jim Volker will be presenting at the Raymond James Institutional Investors Conference in Orlando on Tuesday, March 7 at 8:05 AM Eastern Time. And Pete Hagist will also be presenting at the Howard Weil Energy Conference in New Orleans on Wednesday, March 29 at 9:40 AM Central Daylight Time. In closing, everyone, we thank all of you for your interest in Whiting Petroleum Corporation, and we look forward to speaking with you soon.

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