Good morning. My name is Keith, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation Second Quarter 2017 Financial and Operating Results Conference Call. The call will be limited to one hour, including Q&A. I would now turn the call over to Eric Hagen, the company's Vice President of Investor Relations.

Well, thank you, Keith. Good morning, and welcome to Whiting Petroleum Corporation's second quarter 2017 earnings conference call. During this call, we'll review our results for the second quarter 2017 and then discuss the outlook for the third 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 and Events link. Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks are set forward in slide number 1 and in our earnings release. Reconciliations of non-GAAP measures to 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 June 30, 2017, is expected to be filed later today. And with that, I'll turn the call over to Jim Volker.

Thanks, Eric, and thank you, ladies and gentlemen, for joining us. Let's begin on slide 2. Our second quarter production came in within guidance at 112,660 BOEs per day. This reflects the timing of wells put on production during the quarter, with several large pads coming on in June. Our new budget of $950 million represents a 14% reduction in our budget in 2017, but is still projected to generate 14% production growth from Q1 to Q4 of 2017. New enhanced completion wells in Williams County are producing above a 1 million BOE type curve. We now have 69 enhanced completion wells that bracket our acreage position from North to South and East to West across the basin, and are producing above a 1 million BOE type curve. DD&A per BOE came in below the low-end of guidance, benefiting from strong reserve bookings in the Williston Basin area. All other metrics were within guidance. Proved reserves grew 23% from year-end 2016 levels. Approximately 60 million BOEs of the increase was attributed to upward performance revisions for wells in the Williston Basin area. In addition, Whiting received a $35 million cash payment that finalized the contingent oil price payment associated with our prior sale of the North Ward Estes asset. On July 19, when Whiting received the $35 million, the contract settle amount would've been only $4.2 million based on the NYMEX forward strip pricing on that day. As you can see on slide number 3, our total net production was within guidance and averaged 112,660 BOEs per day in the second quarter. At 105,475 BOEs per day, the Bakken/Three Forks represented 94% of our total production. On slide number 4, we provide an overview of the Williston Basin, where we control approximately 450,000 net acres. You can see in the…

On slide number 14, we show our second quarter 2017 financial results including our discretionary cash flow of $139 million. On slide number 15, you can see our liquidity and debt covenants. We had $550 million drawn at quarter-end on our $2.5 billion borrowing base. We remain well within all of our covenants and strongly positioned from a liquidity and debt maturity perspective. Our revised 2017 capital budget is detailed on slide number 16. The new budget of $950 million allocates 96% to development activity: $518 million to the Williston Basin; $332 million in the DJ Basin; and $62 million to non-operated drilling. On slide number 17, you'll see our guidance for the third quarter and full-year 2017. We forecast production to grow to an average of 133,500 BOEs per day in the fourth quarter. This represents a 14% increase from first quarter levels. Slide number 18 shows our crude oil hedge positions as of July 19. We've added to our hedges and are 64% hedged at attractive prices for this year, and we expect to continue to build our hedge book towards that level in 2018. With that, I'll turn the call back over to Jim.

Thanks again, Mike. On slide number 19, you can see that even though our wells earned good returns at and below current prices, we believe in disciplined capital allocation. We have been able to reduce our capital spending by 14% for 2017 and still plan to deliver 14% production growth. This reflects our commitment to generating high returns and maintaining a strong balance sheet. Keith, please open up the conference call for questions.

Thank you. We will now begin the question-and-answer session. And the first question comes from Neal Dingmann with SunTrust.

Hi, Neal.

Good morning. Hey, Jim. How are you doing? Quick question. You certainly have a lot of financial and operationally flexibility maybe that you once did not have. And so, you talked about reducing the plan a little bit for the remainder of the year. Could you address the Redtail, the DUCs, how you see that factored in, not only with that plan, but potentially next year, depending on how you scale up or scale down the plan?

Right. Well, I guess I'll let Mark answer the question because we've disclosed in the press release how many wells we're going to complete in each area. And then, I'll go on and answer the second part of your question and say that, yes, in 2018, we'll have fewer DUCs in Redtail. And, consequently, the concentration of activity in 2018 will be more in the Williston Basin.

So we started out the year with 105 DUCs at Redtail. We've been working off that DUC inventory right up until the present. We're continuing to do that. We expect to end the year with about 38 DUCs. And we are following through we've done, but we also scaled back our drilling a little bit, about 17% roughly in Redtail. But we'll continue completing our DUC inventory into 2018, and we should work most of that off by the end of the first quarter.

Thank you, guys. And then one last one. Just looking at that slide 4 where you really break out some of your stimulation and type curves. Definitely noticeable in McKenzie where despite using some of the lower stimulation around 8 million or 9 million pounds, you're still talking about now – or you are talking about now 1.5 million barrel type curve. Jim, for you, or Mark, is there kind of how you envision the potential there if you do step up the stimulation there like you have in other areas if you bring it up to 10 million or 11 million or 12 million or something like that. What potential you could see?

Well, Rick's here, and he's been sort of waiting for somebody to ask a question like that. So I'm going to let him answer that one.

Hey, Neal. This is Rick.

Hi, Rick.

To answer your question, we're really getting very good results in McKenzie County with our current completion of 9 million pounds. We've mentioned in the last couple of quarters, we continue to test some larger jobs well above that, and we'll watch those. But I think we're in a pretty good spot right now from what we see with performance.

Thanks, Rick. Thanks, Jim.

You're welcome.

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

Good morning, Brian.

Good morning, guys. How are you?

Great.

You talked about the outperformance of those enhanced completion, the 8 million pound pad in Redtail. Any chance you can give us a little bit more details on the production side of things?

Sure.

Yeah. This is Rick again. I would say the Razor 12-H pad that Jim mentioned, it's only been on a couple of weeks at this point. So we don't have a lot to go on. The early performance looks good and we're just going to watch it very closely. And as soon as we feel comfortable that is the right step to take, we'll apply that to future completions. But I'd just say, it's pretty early. We generally would like to have 90 days performance, but we'll make a decision as soon as we feel comfortable.

So far, everything is very encouraging. Really good.

And should we assume that with the completion of the DUCs, are you only going to use 8 million pounds going forward or are you going to continue to do both and see if you get the benefit?

Right now, we're with our standard completion of 5 million pounds. As soon as we feel comfortable with the performance on the Razor 12-H, I'd anticipate we could make that change immediately.

Okay. And one kind of simple one. How many completion crews are you all in the Bakken? And do you expect to maintain that kind of through going into 2018?

Right now, generally, we've been running three frac crews. Right now, we happen to have four running. I would say, going forward, we'd be in the probably three range.

Okay. Very helpful. Thanks, guys.

You're welcome.

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

Hey, David.

Hey, Jim. Thanks for taking my questions.

You bet.

I know that you've been asked this probably recently since one of your peers in neighboring areas sold some acreage. As you look to kind of rationalize some spending going into next year, you moved down to the four-rig program exclusively in the Bakken. How motivated are you right now to prune some of maybe your Bakken inventory with some prevailing decent asset prices, particularly as you highlight the 4,500 locations that you have now. Is that something that you're explicitly exploring right now? And do you have any intentions to start a process there?

Well, I'll make it clear that we don't have anything signed up currently. I will say that there is strong interest. And I would say that the acreage that we have – and I'll just refer you back to the amount of acreage that's there on our acreage table that's non-core, is certainly in high demand by other operators, and I would say investors, both operated and non-operated. So I would say that our decision will depend upon how much these people who are interested distinguish themselves from the crowd; meaning, how much they're willing to pay. And I would say, from what I can tell, the market is strong and it's also well populated based upon the inquiries we get.

I appreciate the color on that.

Thank you.

The other question I had is, as you move to this program now exclusively on the Bakken, I think you had also said previously that you thought you could basically spend within cash flow in 2018. I suppose with the four-rig program, can you give us an update on how you're thinking about that? And if you're focusing on the Bakken exclusively, does that capital look more efficient than, say, the $800 million or so that you've kind of put some brackets around previously for holding that exit rate flat?

Yeah. You kind of asked two good questions there. And I think Mike's been waiting to answer that question. So I'm going to let him answer it. Go ahead, Michael.

Sure. As we reduced our Capex budget this year by $150 million, we reduced our exit rate from 140,000 a day down to 133,500. I think everybody's clear on that. And in the past, we've said in order to hold that 140,000 a day flat, we need to spend $800 million. So to hold on 133,500 flat, we think we'd have to spend around $750 million. And we think also that at $50 NYMEX, we'd generate about that much cash. So cash flow neutral, holding production flat, $750 million at $50 NYMEX.

All right. Thanks for the answers, guys. I'll let somebody else ask some questions.

Great. Thank you.

Thank you. And next question comes from Graham Price with Raymond James.

Hi, Graham.

Hey. Good morning, and thanks for taking my call. We're just wondering kind of what crude price range the new budget was set for, and maybe if that's the right way to look at it?

Yeah. $45.

Okay. Perfect. And then, for a quick follow-up. We've seen a pretty good recent rebound in crude prices over the past month. And I was just wondering if that continued, how long it would potentially take to bring a rig or two back into the mix?

To be honest, that wouldn't take very long. Although, what we might do first is add back a completion crew.

Okay. Got it. Thanks, guys.

Yes.

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

Hi, Jeanine.

Hi. Good morning, everyone. Thanks. Just two quick questions for me. How did you decide on the level of activity in the second half of 2017? You forecast that you'll still have a meaningful amount of DUCs at year-end, but on our model we also see you still having a meaningful outspend.

Well, of course, your outspend is dependent upon your price deck, and Michael has already answered the question about 2018. And essentially being able to hold the production there at about 133,000 at under $800 million, $760 million. So I think we're pretty clear on that with you. And in terms of how we made our decision, it had to do with, I would say, giving ourselves some room that if prices were to deteriorate, we could still cut some more. And on the other hand, keep in mind, we're making these decisions when oil was about $3 a barrel or so less than it is today. And so, we left ourselves some flexibility to cut further if oil prices decline. And if we were to get a jump in prices, we could add back some, initially anyway, a completion crew and, I would say, still have a very nominal amount of outspend in 2017.

Okay, great. That's really helpful. And then my follow-up, in the press release, you mentioned that one of your priorities is to maintain a strong balance sheet while delivering high returns and sustainable growth. Can you just talk about how you're thinking about sustainable growth? For example, whether your primary consideration is simply absolute year-over-year or exit-to-exit growth. I know you guys mentioned the maintenance CapEx. Or is it to achieve more of a ratable kind of multi-year growth that could be lower, but more consistent?

Well, I'm going to say, essentially, what we try to do here, and I think we've been successful at it, is, especially currently, trying to get these wells that have the rates of return likely put in this table here at between $45 and $50 a barrel that are approaching 100% IRRs. So how do you do that? Well, frankly, you continue to find good places to drill on acreage that you already own so that you're not paying $25,000 to $50,000 an acre. And we've been successful at doing that. We essentially have, this year, I think done an excellent job of that in the Williston Basin while we spend some money to complete the DUCs at Redtail. Next year, we'll be able to, in my opinion, enhance our growth potential by drilling these high rate of return wells that we have in the Williston Basin and not having to, if you will, go out and acquire a lot of extra acreage at exceptionally high prices. So I think that's our plan. That's how we intend to grow bigger. It basically leverages off of our exploration work that we've done over the years so that we still have 5,000 drilling locations in the Williston Basin and over 5,000 drilling locations in the DJ Basin. And we've been able to acquire those at acreage costs in the hundreds of dollars per acre rather than the multiple thousands of dollars per acre.

Okay, great. Thank you for taking my questions.

All the best. Thank you.

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

Good morning.

Good morning, Jeffrey.

A kind of couple of quick ones for me. On slide 7, where you detailed the 1 million BOE type curve and the 1.5 million BOE type curve. I was just wondering, is there an average lateral length that's assumed for each of these type curves?

Our average lateral length's about 9,500 feet in a 1,280 acre spacing unit.

Okay, great. Thank you. And then on slide 10. The chart that shows the various oil prices and rates of return correlated to those two type curves. I was just wondering, is there any assumed basis differential embedded in these calculations?

Absolutely.

$6 a barrel, which is actually a little bit above where the differentia is in the Bakken today.

All right. And I guess just a quick follow-on on that. Since we've seen the new pipeline completed in the Bakken, have you seen a significant improvement in – or at least a meaningful improvement in your basis differentials? And does that look like it's pretty durable going forward?

Absolutely, yes. We've seen about $3 a barrel due to the pipeline coming on and all the competition for barrels, and it looks very sustainable.

Yeah. I'd like to follow up on that, Jeff. I think for some of the analysts, they're still using a much wider differential in their net asset values. And on the Bakken, we're down closer to $5 and in the Redtail around $4. So I think there's a lot of value that still is to be captured in some of these models out there.

Yeah. I think that's a fair assertion. Thanks very much for answering my questions.

Thank you, Jeff.

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

Hi, Mike. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Good morning, Jim. You had some nice reserve growth. Can you say what kind of EURs your reserve auditor has given you for the 2017 Bakken wells?

Yeah. They're in the same 1 million to 1.5 million BOEs per well. And, really, they were largely responsible for that 60 million barrel increase. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Got you, okay. And then, I know, Rick, you had mentioned it was too early to talk production numbers on the new pads for the Niobrara wells. I guess, we've seen some of your competitors do some larger fracs there and with mid and long laterals in the DJ, it looks like their wells are taking a long time to reach production or peak production. Can you say what kind of timeframe you're expecting to see peak production out of those wells?

Sure. I think we would be similar in Redtail. Generally, it's 60 days to 90 days to reach peak production. But again, I think as we watch performance, we may be able to make a call earlier than that if the performance holds up. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Got it. And then, last one for me. You had mentioned that you are looking at hedging for 2018. Have you done anything – or based on the current strip, would you be willing to hedge there right now?

If we do more hedging, I think you'll see us using three-way collars. And so, the answer is yes. And, today, I think basically we're knocking on the door of something like a 35%, 45% and 56% ceiling. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Great. Thank you.

You're welcome.

Thank you. And the next question comes from Asit Sen with Bank of America.

Thanks. Good morning.

Good morning.

So I have two unrelated questions. First, on oil as a percent of total production, came down somewhat sequentially. So my question is, how should we think about the oil cut trajectory in back half of the year and potentially into 2018? And on that, impressive reserve books in the first six months. Could you share with us the split, oil, gas and NGL mix and those incremental bowels?

I'll take the first part of your question. Right now, and actually in the future, we're drilling in areas of the basin that have a higher gas to oil ratio. That's why we dropped about 1.5% in the quarter. So we expect it to stay where it's at, around 67%, through crude oil as we move forward. And I'll let someone else answer the reserve part.

And the same thing is true with respect to how those increases came about. It was about a one-third, two-third split with respect to the oil, gas mix on the reserve increases.

Okay. And thanks for the color on CapEx and your maintenance CapEx, which essentially you're keeping at $750 million to keep production flat. But looking at the back half of the year and you kind of addressed that on your hedging philosophy. Could you share with us your philosophy as it relates to underwriting the 2018 CapEx program?

Well, I would say, per our comments, the idea here is to grow production a bit while staying right at or perhaps only slightly above our discretionary cash flow. And we'll be measuring that, of course, as we watch what's happening to oil prices. So we're very much attune. Our models take into consideration, of course, the increase in margin as oil price rises and it gives us, therefore, a nice bump in discretionary cash flow. As I might say, this recent $3 increase in the price of oil is done.

Okay. And a last quick one. Yesterday, Hess highlighted 60-stage fracs as their standard. Could you share with us your standard completion designs again?

Yeah. In the Bakken, our standard completion design is a 40-stage frac, 9 million pounds of proppant plus. And, generally, we're using a diverter agent to better distribute our frac material across each of the stages and I think we're having pretty good luck with that. In Redtail, our standard design right now is a 50-stage job with 5 million pounds. But as we mentioned, we're evaluating a step up to 8 million pounds potentially.

Right. We're seeing good initial and very encouraging results from what we did with the 8 million pound jobs.

Thanks a lot, guys. Very helpful.

You're welcome.

Thank you. And the next question comes from Geoff Jacques with IBERIA Capital.

Good morning, guys. Thanks for the questions. Just looking at those Bakken wells, the Evitt wells, was the only difference between those two proppant load?

Yes. Yes, it was.

Okay. Okay. And then, the two-well pad I think you mentioned after that that was using 11.6 million pounds. In terms of performance relative to the 5 million pound or the 8 million pound, how does that one look relative to those?

Certainly, good performance on those. And as we mentioned, we're continuing to test a handful of larger jobs. I think we said we're going to do about 15% of our completions this year would be above 9 million pounds. And I think the results we're seeing so far is the 9 million pounds is a pretty good number to be at in terms of our performance, although we continue to test the larger jumps.

Excellent. Thanks, guys.

You're welcome.

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

Hi, Jeff.

Hi. Good morning Jim. Just a quick question on the reserve adds. Can you talk about how much of that was proved developed versus PUD reserves? And are you getting any credit on the PUDs that you carry for some of the performance you're seeing as you consider the way you'll complete those wells?

So the answer to your question is, it would've been about two-thirds, one-third. I think about two-thirds proved developed producing and about one-third on PUDs.

Okay. On the PUDs, Jim, are the engineers giving you all any credit for improved completion designs?

Yes.

Okay.

Yes.

On the completion designs, it looks like very early days. Those wells flow produced a little bit under your type curves. Is that just because of the way that you recover the load?

Yes.

And are you doing anything around the flowback procedures?

No. We haven't changed anything in terms of our flowback procedures. The jobs are a little bit larger that were pumping the 9 million pounds. So it takes just a little bit longer to clean it up. But we certainly catch up, as you can see, on the type curves.

And then, last question. Do you use a different recipe if you're thinking about $45 oil versus something above $50 in terms of how you space and drill and complete these wells in the Bakken?

No. We really haven't. That's not much enough of a spread to really make a different decision. I think our current jobs fit both environments.

Okay. Thank you very much.

You're welcome.

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

Hi, Michael.

Thanks. Hello. Good morning.

Good morning.

Couple of questions on my end, a bunch have been answered. But I guess while we're talking, on the completion side, can you remind me what your average completion loading was in 2016? I'm asking in the context of that slide 11. and just trying to think about if, I guess, the implication is we've kind of maxed out rate of change in terms of completion tailwinds?

6 million to 7 million pounds.

Yeah.

Michael, was the average. And this year, we're going to be closer to 9 million.

And so, was there some carryover in terms of like wells completed thus far year-to-date that are still on the old design? Or is there a mix shift from a regional perspective that's driving that flat year-on-year IP 90?

Our smallest jobs this year are probably 7 million, 7.5 million, and those are in maybe some areas where we have a little bit less oil in place, like maybe Pronghorn. But our average job is still around that 9 million.

Yeah. I think that's the key to that slide we have with all the stars on it, in that 9 million pounds in that range seems to be working from north, south, east to west across our acreage position.

Yeah. And we're testing up to 12 million in those areas as well, and it will take a while to get all the results back.

Okay.

I'd just -

Is it fair to say – sorry, go ahead, Jim.

I was just going to say, I think you ask a good question which is are we peaking or is there more yet more to come. And I would say that we're learning a lot more about the benefits from the diverter technology and the ability to really break up the near wellbore rock. So we still think that there is a good upside by making sure that we have the ability to perhaps even get more entry points and more break up in that near wellbore rock. And we're working very closely with our – I consider them our partners in the service industry to make sure we can take that next step.

This is Rick. One of the things we're evaluating is multiple diverter drops in our terminology. In other words, in a stage, rather than dropping diverter once, possibly dropping diverter 2 or 3 times to get better distribution across the state. So we still have tricks up our sleeves that we're evaluating.

Okay, great. That's all good color. I appreciate it. And then I guess the other I was curious on is just in Redtail, can you just give us any sort of estimates around your expected deficiency payments in the back half and how that plays out with the new outlook in Redtail?

Well, the extra production will certainly help us. In the last quarter here, we paid around $19 million of deficiency payments. So to the extent we can get our production up, we can start bringing that down. That's having about a $2.80 effect on our company-wide differential. We net those payments against our oil sales. So, therefore oil impacts our differential. So we think that will come down. Our differential price still have an impact of greater than $2 though as we get into the last half of 2017.

Well, that's not the greatest news. I would say the good news is that particular arrangement really only has, once we get to the end of this year, about 24 months you have to run. And as we get to the end of that, with that in sight, I'm pretty sure that the people who will want our crude oil will want to renegotiate that deal if they want to keep our crude. So I'm optimistic that we won't have to wait until the end of the term. But if we do, we do. And if we do, why, I'm pretty sure we'll be having more than one opportunity to really improve on the differential there at Redtail. It wouldn't surprise me to see that thing come down to only about the $3 range.

Yeah. Certainly, it can have a big impact. Okay. And then, last one of mine will just be on the gross and net completions in the quarter, how many were in Redtail?

As per the press release, there's really none that were recorded in Redtail. Those pads have just started to flow back and hadn't even really reached stabilized oil cuts until July. So the 22 wells you see in the press release are all – the 22 gross, 10 net wells are Bakken wells.

Okay. Thanks. Appreciate it, Eric.

You're welcome.

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

Hi. Thank you for taking the questions. Maybe just as a follow-up on differentials. I guess, one, just I think you talked a little bit about this. But as you're thinking about just the corporate guidance you have out there, roughly dollars on oil side, are you guys just kind of being conservative with where Bakken and Nio diffs are today or is there other stuff that we should be thinking about for the second half?

No. There's nothing else to think about. The midpoint is 8, as you say. And we just talked about Redtail being $2.80 in the current quarter and going down, but probably not below $2. And Bakken differential's around $5 right now. So somewhere, I think that's pretty good guidance. Hopefully, we land on the low side of that.

Okay, that's helpful. And then just on the NGL realization. Obviously, winding down a little bit versus Q1. How should we be thinking about that going forward?

Well, Q1 was a bit of a pop compared to what we saw all of last year. Even the most recent quarter was better than anything we saw in 2016. So it did come down. 90% of our NGLs are propane and butane, and those prices just came down from where they were in the first quarter. I personally, will model it right where it's at right now. As I look to the rest the year, I don't see a reason for them to necessarily go up. So I'm keeping them flat with where we were in Q2.

Okay. That's helpful. And then maybe just last one in terms of a bigger picture question on the balance sheet. And I recognize this is early, but your 5% notes, is that something that you're looking at as part of your near-term deleveraging plans or how are you kind of thinking about that from a holistic standpoint?

Well, we have plenty of time to deal with that note. We obviously have the ability to easily put the roughly $960 million that's out there on to our borrowing base if we should choose. And in answer to prior questions, I've said we have numerous opportunities of non-core assets where we could use to pay it off.

Okay. Fair enough. Thank you very much.

Thank you.

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

Good morning. It looks like your location count in Mountrail ticked up about 80-plus locations from March 31 to June 30. I was just curious as to where those incremental locations came from?

I'll take a swing at that. The Mountrail County is mostly Sanish field. And the one thing that we've seen as we've gone forward is our performance of our wells has actually been better than had been forecast. And we believe one of the reasons for that is we have exceptionally high oil in place in the Sanish-Parshall area. And so, our ceiling for what those wells can recover is pretty high. So the big gap between recovery and what's out there capable of being recovered. So this is just a realization in that.

Okay. Great. And then looking at the enhanced completions. When you look at the behavior of those wells from a longer term dataset, are you seeing a shallower decline in those wells versus the 3 million, 4 million pound jobs that were historically done?

We're seeing a higher rate – initial rate. And I think we do see a little bit shallower decline in those as well. And you can see as it can compares to the type curves that Jim had presented earlier, at least in the near term. Some of those go out a year. So I think you can see that performance there.

Is that improvement and decline baked in at all into the ability to hold the 133.5 MBOE per day flat at $750 million? Or is that you're assuming the current PDP decline rate on that?

The $750 million is really a preliminary estimate, and it's extrapolating from the $800 million down to $750 million. We'll give you a detailed estimate early next year. We think it's a very conservative estimate that is consistent with what we said last quarter.

Okay. Great. Thank you.

So, no, it doesn't necessarily bake in all these performance uplifts.

Thank you.

You're welcome.

And the next question comes from Mike Kelly with Seaport Global.

Hi, guys. Good morning. Thanks for taking my questions.

Good morning, Mike.

Good morning. Jim, Page 9, you've got enhanced completion pad that is, I'd say, outside of the core of the core essential McKenzie County. I was hoping you could maybe talk about the results you've seen here and just kind of general thoughts on what the impact will be on bringing these enhanced completions outside of the core.?

So I think the one that you're referring to is the one that's a little bit further west there in McKenzie County, is that right??

Yeah. It looks like the ones kind of closer to Dunn. Well, if you can maybe talk about the one that's out west, too. But this really just kind of applies to, okay, outside of the core of the core, can ultimately kind of elevate inventory to a point that's 1 million barrel-plus potential like you've done thus far?

Yeah. I'd say that all of our McKenzie County completions in there are in areas of exceptional oil in place and good performance. So if you look at everything in McKenzie County, you're going to see comparable rates with all of that stuff. So I would argue that really that is core.

Okay. Okay, fair enough. Jim, just from a longer term strategic perspective, I can't imagine, you're too terribly excited about just kind of swapping dollars between cash flow and CapEx to stay flat with production growth in a $50 world, especially if your IRRs in these enhanced completions are over 100% now. So just kind of wanted to get your sense on what's the most logical course of action for you if we do stay at $50 long-term to kind of free up to get more aggressive on the growth side? Thanks.

Yeah. The history of Whiting is being efficient. So as I talked to earlier, one of the things that I think that we're pretty good at is finding oil and gas in places where we already have leases. Leases that cost us a couple of hundred bucks an acre, not $25,000 to $50,000 an acre. So I'm optimistic about our ability to continue to do that, bring cost down and continue to find, if you will, million barrel wells that get us 100% rates of return and at $50 oil. So we're going to do that in the Bakken, we're going to do that really on across our acreage position. And then, I think you'll find us from time to time spending some money on new exploration plays. And with a little luck there, those will also mature and give us a chance to get additional growth, good incremental growth in areas that we picked up for $200 an acre or less.

Okay. Just following up on that. If we are at $50, are you comfortable outspending given those sorts of returns? How should we think about that if we are at a $50 world, how you approach the budget?

Well, like I said, at $50, and as Mike said, at $50, we're projecting some growth into 2018 and staying right around our discretionary cash flow. My comment was directed toward potentially getting further growth above that for approximately the same amount of dollars by being very efficient where we are in the Bakken. I hesitate to use the word hydrating. I really prefer to use the term improvement and efficiency. As Rick has described, we have a number of tricks up our sleeve to get us even higher EURs without spending much more money. So I'm confident of being able to have the potential for growth, both in the areas where I'm going to say you're somewhat familiar, the Bakken for example. Second, further improving our results at Redtail. And we've talked about how we're doing that with the larger 8 million pound jobs. And like I said, coming up with some new zones to complete in that are in acreage in areas where we own acreage at well under $1,000 an acre. So that's how you grow an independent oil company without having to go out and right now, frankly, pay up in the Permian.

Understood. Thank you.

You're welcome.

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

Hi, John. John Nelson - Goldman Sachs & Co. LLC: Hi, Jim. Good morning, and thank you for taking my questions.

Welcome. John Nelson - Goldman Sachs & Co. LLC: First, I was just hoping to get a clarification on your earlier comments about the strength of the asset sale market. Are you guys looking to that similar to last year in more of the JV-type structure where it was kind of a drill to earn, or are you instead looking to kind of outright divest some of the non-core acreage?

So both of those opportunities are offered to us and I would like to say we'll evaluate them. And when someone distinguishes themself from the crowd, why then, we'll take advantage. John Nelson - Goldman Sachs & Co. LLC: Okay, fair enough. And then, just as I think about the balance sheet, I think you guys have put in context before being happy with kind of where you were when debt levels come down about 40% since the beginning of 2016. Is that still the case or has the kind of flattening of the forward curve caused you to rethink or want to have a incremental debt paydown?

So I think that's an excellent question, and I'm not too sure that – I mean, I think it's good to say and it's correct to say the flattening of the forward curve. I would say if history has taught us anything, it may not be a black swan. It may look more like a gray duck. But I think there's a change coming out there. You can't have things happening that are happening in Venezuela and elsewhere without having an effect overall on the supply of crude oil worldwide. So I'm actually optimistic that we will see higher prices by year-end. I think certainly, $50 to $55 is definitely achievable. And I would say that that will be reflected in the forward curve. And I'll buy you a Starbucks if I'm wrong about that. But the point I'm trying to make is that I really believe that as we think about our debt level, we have to think about it in relation to our cash flow. And as our margins increase, and I think you understand they increase markedly, with just a $3 or so increase in the price of crude. So it has such a marked effect on our cash flow that your debt to EBITDAX or debt to EBITDA or debt to discretionary cash flow, however you prefer to look at it, really improves and you can come down a whole turn or so on that number with just a $5 or so reduction or increase in the price of oil. So I thought your question was well structured, but I'm also trying to make a point that I really think we got plenty of flexibility such that whether it's debt paydown through one of the methods that you mentioned or an increase in our cash flow, making that existing debt that we have look more like a 3 or a 2 times, that we have good options available to us and nothing pressing us until we have that answer. Sorry to be long-winded, but I just wanted to just kind of take a look at the whole picture. John Nelson - Goldman Sachs & Co. LLC: No, I agree. That's helpful. Until you know kind of what that long-term price is, you would do kind of a razor's edge there on how much that debt that level can come down.

Thank you. John Nelson - Goldman Sachs & Co. LLC: I guess maybe speaking one high-level. If I could sneak one more in, Jim. You've been in this business kind of a long time. Can you maybe take a step back and speak for the broader industry. Do you see the potential for maybe greater consolidation over the next 12 or 18 months? Kind of leave it open-ended like that.

Well, I certainly can't speak for anybody else. I don't know their plans. And all I can say is that there has been a positive influence out there and it's been the arrival of capital from the non-traditional sources. I'm talking about people who essentially have put together large pools of capital to buy operated and non-operated properties and spawn new companies. I think that is essentially filling in for some of the M&A activity, the traditional M&A activity that we've seen in the past, in that companies' operators do have the ability to sell assets or rather than being acquired, I guess, in whole. So I look at it as a very healthy situation right now in that there's all sorts of solutions to the questions that you are poking at there, which is how to maintain a good, strong balance sheet and how to have good growth. And does that mean that there's going to be, by necessity, some M&A activity? I'm going to say, yes, there's going to be some more M&A activity. But I think part of it will be more A than M because of this availability in new capital. I hope that's clear. John Nelson - Goldman Sachs & Co. LLC: That was very clear and very helpful. I'll let somebody else hop on. Thanks again.

Thank you. You're welcome.

Thank you. Actually, that does conclude the question-and-answer session. So I would like to return the call to Jim Volker for any closing comments.

Well, thank you very much. I'd like to thank all the Whiting employees and directors for their contributions to a solid quarter. Eric?

So Jim Volker will be presenting at the EnerCom Oil and Gas Conference on Monday, August 14 at 10:05 a.m. Mountain Time. Thank you.

And, in closing, we thank all of you for your interest in Whiting Petroleum Corporation and we look forward to meeting with you soon.

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