Good morning. My name is Keith, and I will be your conference facilitator today. Welcome everyone to the Whiting Petroleum Corporation's Second Quarter 2018 Financial and Operating Results Conference Call. This call will be limited to 45 minutes including Q&A. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. I now will 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 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; 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 second quarter 2018 and discuss the outlook for the remainder of the year. 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. Digital information concerning these risks is set forth on slide number 2 and in our earnings release. Our form 10-Q for the quarter ended June 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 updating you on Redtail consistent with our prior timeline. We have completed a thorough process. The bids received did not achieve our expectations or reflect the cash flow power of the asset. With the company investment to date, the asset will generate $250 million after deficiencies in calendar year 2018 and will continue to turn out hundreds of millions of dollars over the next couple of years. It is hard to relinquish a high oil yield production stream and a backward dated forward oil curve. We have elected to keep the asset and run it to maximize free cash flow. We do not plan to invest additional capital in Redtail at this time, but we'll continue to operate the asset to maximize cash flow and continue to optimize the asset for returns. Now, let's move on to the quarter. I would like to thank all Whiting employees for another great quarter. Despite challenging wet weather this spring, second quarter production came in at the high end of the guidance and we continued to generate robust free cash flow. We have adjusted our production guidance upward to reflect the strong performance. Our efforts to build a learning based organization are paying off through teamwork and enhanced communication. I would like to start off by celebrating the achievements of our industry-leading drilling team. The average spud to TD times have decreased from 23 days in 2011 to 8.9 days in the second quarter including a company record of 6.7 days. Our second quarter average performance represents an 11% decrease quarter-over-quarter as our team innovates with drilling bits and downhole mud motors. Not to be outdone on the completion side, our engineers have pioneered right-sized completions. As mentioned in our press release and detailed…

Thanks, Brad. We generated positive adjusted earnings per share of $0.62 during the quarter. Operating cash flow exceeded CapEx by $107 million. Over the past three quarters, we have generated $269 million of operating cash flow in excess of CapEx. In addition, G&A was at the low end of guidance and LOE was significantly below the low end of guidance. Operator, please open up the conference call for Q&A.

Yes. Thank you. We will now begin the question-and-answer session. Please also note this event is being recorded. Please hold while we assemble our roster. And this morning's first question comes from Neal Dingmann with SunTrust.

Good morning. Brad, looking at that slide 7, it shows entire position there now including the bolt-on, your thoughts about moving rigs around. I see where you've got the rigs positioned there, could you talk about will they stay in generally the same area or do you see those moving throughout the year?

Thanks, Neal, and great question. As you can see our rigs are spread out over our Tier 1 acreage position and a lot of the reason we're doing that is to really maximize our returns by putting the rigs in areas that we have gas takeaway capacity and we can fully move our volumes. We're very excited to get over into the East Breaks and Hidden Bench area and both test our stuff there as well as test this new acreage. And so, we are moving that up in our priority list and plan to be – in the first quarter of 2019, we plan to be out on the new acquisition acreage drilling our first well.

And then, just lastly, just your wells like number of other offset operators are very notable here in the last several months. Your thoughts about type curves as these wells continue to outperform the type curve, any thoughts of boosting those, or if you could just talk about sort of well performance you've seen here recently versus, I guess, that which was set – would set the type curves?

Yeah. I think that's also a great question, Neal. We're certainly looking at that. It's early on in the process of looking at these new wells. But we continue to update the curves and we continue to see just great performance. The Mallow well in our Hidden Bench area, as you see on slide 9, we are almost 90 days in. So, we're still early. We're three months in, but we've almost got a significant 30%, 40% more production – cum production at this point in the first 90 days. And so, we are not seeing the wells fall off. We're seeing nice pressure behind the wells' performance, and we're certainly looking at our 2019 program through the lens of an updated type curve situation.

Very good. Nice operations, Brad.

Thanks, Neal.

Thank you. And the next question comes from Drew Venker with Morgan Stanley. Drew Venker - Morgan Stanley & Co. LLC: Morning, everyone.

Morning, Drew. Drew Venker - Morgan Stanley & Co. LLC: Brad, I just wanted to follow up on that. The asset sale, it seems like with the bids on Redtail coming in below your expectations, maybe you're taking the opposite end of that and taking advantage of weak bids in the market for assets. So, curious to hear how much additional appetite you have to acquire other bolt-on properties and what you'd be looking at is similar to this halo area as you've described it, or other parts, maybe it's bolt-on core in the Bakken, or what's of particular interest to you?

Yes, Drew. That's a great question. We think that we should be looking at other Bakken acquisitions. We think it fits in our strategy of being the best in the Bakken. We believe that we should be looking at all the packages out there. One, it helps us to better understand the basin and our competition. But consistent with our acquisition announced today, we'll consider transacting if we feel the package fits well with our current acreage position, has the potential to compete in our current drilling program inventory and we can apply the Whiting stock completion and operations to that. And so, we do feel like that we're getting much better performance with the Gen 4.0 completions and we think there's more acreage out there to be prosecuted that way. Based on our really detailed geologic mapping, we see substantial oil in place across a large area of the Bakken and it's an incumbent upon us to apply the right completion technique to be able to get that out. Drew Venker - Morgan Stanley & Co. LLC: Thanks for the color, Brad. And just a follow-up there on the completions you mentioned. Do you have data to confirm you're actually seeing shorter frac lengths with the Gen 4.0 completions than with the bigger 10 million pound completion?

Yeah, I'll let Rick Ross comment on that.

Yeah. Good question as well. We certainly model all of our completions. We've got calibrated models for each of our development areas. So, we do have a good feel for frac length and we really design that based on each specific well situation, well spacing and try and design that appropriately. So, I don't know if I'm answering your question directly but I think the answer is yes on frac length that we understand that. Drew Venker - Morgan Stanley & Co. LLC: And they're a bit shorter?

That's correct. Drew Venker - Morgan Stanley & Co. LLC: Okay. Thanks, Rick.

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

Good morning. The Polar wells are showing most specifically meaningful positive effect from diverters that I've encountered recently. So, wanted to ask a couple of questions there. One, do you imagine this is going to be a one size fits all solution or does the diverter chemistry have to be altered in different portions of the Bakken? And second, will this completion be appropriate for the Three Forks?

I'll take the second question first regarding the Three Forks. We believe it applies to both the Bakken and the Three Forks. We think using the diverter to create more complexity to get our stimulation distributed better across the zone will be beneficial in either zone that we're completing. And I think in terms of the chemistry, we actually are trying two or three different types from different vendors' approaches and evaluating each of them. They're similar but there are material differences and we'll continue to evaluate and obviously apply the one that we think gives us the maximum bang for the buck.

Okay. Great. That's helpful. Brad, I just want to make sure I understood. It sounds like you plan to operate Redtail as a managed decline that throws off free cash. I mean is that an accurate characterization and do you have kind of a target decline rate over the next year or two in mind?

I think that's fair. We are going to invest in the highest return projects that we have on our portfolio and I think we've consistently said that currently, while our last round of Redtail wells were encouraging and we got better results, they're still not competing today with our Bakken inventory. And so, we'll continue to focus our CapEx investment in the Bakken. And, we are going to go to work with the team on Redtail to optimize our existing wells to flatten that decline as much as we can. We've said before that our fourth quarter exit rate at Redtail is about 15,000 barrels of oil equivalent per day and we are challenging ourselves to do better than that and see if current well performance can – we'll be working very hard to channel that decline as much as possible and to keep those oil rates high.

Great. Great. Thank you. Appreciate it.

Thank you. And the next question comes from Brian Corales with Johnson Rice. Brian Corales - Johnson Rice & Co. LLC: Good morning guys. I just wanted to get in, the drill times look pretty impressive. Does that – because you're drilling so fast, does that kind of preclude you from adding a sixth rigs down the road or what are your thoughts there?

That's a great question, Brian. As you can certainly – as you've accurately identified, the cycle time certainly speeds up the process and speeds up the CapEx. And so, we're looking at getting more wells into the program this year than was originally forecast and we're working very hard to keep our cost down and so do that under the same budget. But as we look forward, we certainly believe that these cycle times we can get more wells with the same amount of current activity that we have. And so, that's going to go into our calculation on how many rigs we need and what our activity will be moving forward into 2019. Brian Corales - Johnson Rice & Co. LLC: Okay. And one just on the acquisition. I know it's early but can you all maybe give us a ballpark on what kind of inventory that could add?

Sure. Brian, this is Peter Hagist. As Brad mentioned, we really like the acreage. It's on trend with our Mallow well. It's relatively lightly drilled, 35 wells on 55,000 acres, and we think the East Missouri Breaks is a good proxy for the acreage. And in that area, we're currently carrying about six wells per DSU. Brian Corales - Johnson Rice & Co. LLC: Thanks. Okay. Okay. Thanks guys.

Thank you. And the next question comes from Asit Sen with Bank of America Merrill Lynch. Asit Sen - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Thanks. Good morning guys. I have two quick ones, first on micro. Can you provide any thoughts on at what oil price does Redtail come into play or it doesn't?

So Asit, I would tell you on our last post appraisal of our NIO A and B wells there, we're getting positive economics there, very positive economics. And just is a relative competition within our portfolio. And right now, we feel like we have plenty of our Bakken in inventory that generates higher returns. And so we're going to stick to that program and to continue to invest in our Bakken assets at this time, so I wouldn't say that there is a particular commodity price that makes us go back to work on Redtail. We'll continue to optimize and high grade it inside our portfolio and put our CapEx to work on the highest returns possible. Asit Sen - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Great, Brad. And on the macro, just wondering if you could provide us your updated thoughts on flaring caps falling in November and how do you think the industry is set up for processing plants planned expansions and indicative constraints?

Yeah. This is Rick. I'll answer that one. I would say, I'm not going to comment on all of the industry but the capture rate current requirement is 85%. It will go up to 88% in November. Whiting enjoys one of the highest capture rates in the Williston Basin. We've continued to work real closely with our midstream providers to communicate our needs and we planned ahead to make sure that we're going to meet those capture rates and we are currently meeting or exceeding the capture rates. Asit Sen - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Great. Thank you.

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

Hey, guys. Good morning. Going back to Redtail, I was hoping you could quantify, Brad, you mentioned that you would look to optimize for free cash flow here. If you could give us a sense of what that free cash flow could look like the next couple years. And also curious if this is an asset that's really kind of perpetually held for sale if somebody will come along and pay the appropriate price for it? Thanks.

Sure, Mike. Thanks for the question. As you've accurately mentioned, the true free cash flow from the asset this year is almost $300 million. After deficiencies, it's $250 million in my comments. And we'll generate another – we'll generate over $100 million in the last two quarters of this year from Redtail. And so, if we can hold that decline high and price – oil prices stay up, it's a nice cash flow stream moving forward. And our deficiencies fall off fairly quickly here in the next couple of years. And so, it's an asset that we think we can generate significantly free cash flow, trying to – continuing to try to paydown our debt as we've stated. And so, we're still very intent on paying down debt and reducing leverage. We'll use the asset for that. But as you say, Mike, it is a non-core asset for us and it's certainly available if – if we get the right price for it sometime in the future, we'd certainly be willing to move that out of the portfolio.

Okay. Great. And circling back to the acquisition, just wanted to get a sense on the consistency of this acreage and if we could really expect kind of Mallow lookalike wells across the entire acreage position which would be outstanding. Thanks.

Yeah. This is Pete Hagist. Again, we've got an extensive geologic database covering all of the Williston. So, we think we have a good understanding of the geology up there. It is on trend with the Mallow well and we think the majority of the acreage will be high quality acreage. And of course we think we could benefit it with our customized completions.

Got it. Appreciate it, guys.

Sorry, Mike. I'll just add there. If you look at page 9, I think what we're trying to show here is that we had a 1 million barrel type curve, and the red line on there the Hidden Bench historical performance is 27 wells in the area, and so that's not just one well. I mean that's really what I would say our Gen 3 completions were. We're giving up with the same amount of rock. And so, I think what's so impressive is the rock's the same. We're just one DSU over from some of those wells and we're seeing substantially better performance. And we've not only seeing that in Hidden Bench, but we've seen that in other places across our acreage position as well. And so, we continue to be very encouraged by the Gen 4.0 completions and the significant uplift that we're seeing over past performance. And we think that applies more than a localized area. We think that's going to apply across a larger part of the Bakken. And the real question, as you accurately ask, is how far does that extend out and how far can we carry that out. But we're encouraged by the results we've seen to date, and we're looking forward to trying that in more areas on our own existing acreage this year as well, as well as into 2019.

Very good. Thank you.

Thank you. And the next question comes from Mike Scialla with Stifel. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Hey. Good morning, Brad. Just looking at the CapEx for the quarter, it looked like a little higher than the run rate expected for the year. Anything that was significant for the quarter that led to that?

Yeah. There's really nothing out of the ordinary. That's actually where we really expected our CapEx to come in at towards the $200 million and probably closer to that in the third quarter as well, and then drop off a little in the fourth quarter.

Yeah. I think we talked a little bit on the last call is, we had about 40 wells coming online in the first half of the year. We've got over 80 wells coming on in the back half of the year. And so, a lot of that second quarter spend was getting wells that, a lot of those are getting turned on in July and August here. And so we had some big pads, 14 well pads that we primary did all of our completion work in the second quarter. And you're seeing that reflected in the CapEx. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Got you. So, some of that CapEx for the second quarter is really going to benefit production for third quarter. Is that the right way to think about it?

Correct. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Looking at the – your outlook for the Williston Basin differentials over the next 12 to 18 months, I want to get your thoughts there as well.

Yeah. The differentials in the first quarter were low because of some lingering effects from actually hurricanes in the fourth quarter of last year. So, the current guidance we think is more normalized and what we should expect going forward. But we've discussed before, the Bakken is really well-positioned for takeaway. We can take crude North, East, South, West and right now there's almost 3 million barrels a day of takeaway capacity between pipeline and rail. And total production is 1.2 million barrels a day. So, there's lots of excess capacity. So, we expect differentials to stay positive for the foreseeable future. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Okay. Wanted to follow up just one last one on the acquisition. Apologize for maybe hitting this in more detail than you intended, but you mentioned it is on trend with those Mallow wells. It is a fair bit to the West. My understanding was water was an issue – formation water was an issue going to the West. Is that not going to be a concern in the area of the acquisition?

No. We're not really that concerned about water. Again, when we look at the geology, as you extrapolate out from the core of the play, we see very similar reservoir properties really along the Southern boundary that's on trend with Mallow, so we would expect similar reservoir characteristics in this area as the Mallow area. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Okay. Thank you.

Thank you. And the next question comes from John Freeman with Raymond James. John A. Freeman - Raymond James & Associates, Inc.: Hi guys.

Morning, John. John A. Freeman - Raymond James & Associates, Inc.: First, on the strong – the Polar wells. You all talked previously about considering experimenting with the pump rate to try and keep more of your frac fluids and proppant in zone. I'm just curious if that was actually done on those Polar wells?

This is Rick. We are doing that. We are experimenting with that and we'll continue to. So, the answer is yes. John A. Freeman - Raymond James & Associates, Inc.: Okay. And then just my last question. On Redtail, just given how – completely understand the decision not to sell it given the cash flow it's generating. And as you try to kind of manage the decline on the asset, does it I guess in any way kind of materially change how you all think about your 2019 growth with that in the fold?

Good question, John. It's a little early for us to come out with the 2019 guidance. So, we have seen better performance in our Redtail wells. They've stayed flatter longer. Actually, some of them haven't went on decline yet. And so we continue – as you saw maybe in the quarter, we averaged over 22,000 barrels oil equivalent for the quarter. We're going to continue to watch those wells and try to optimize them through the third quarter here and we'll be providing that 2019 guidance a little bit further down the road. John A. Freeman - Raymond James & Associates, Inc.: Thanks, guys. Appreciate it.

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

Good morning. I wanted to talk about the infill project at Sanish, really high quality results there and when you talked about even further improvements on returns in regards to reduced frac percent cost and CapEx. I was just wondering if you could provide a little bit of more incremental clarity on that and what you learned from the project?

Sure. Thanks, Gail, for the question. This is Rick. So, the comments that we had of being more efficient in future development really center around how far away from our development we would frac protect. I would say we're probably fairly cautious in the first go around and capture data to understand that better. So I think we're fairly grounded in saying that we think we can improve that. And I think the other piece that we learned was the parent wells in the spacing unit, we had a strategy to try and protect those by pumping water into them to charge them up a little bit ahead of time. And I think you can see it from the graph that we feel like we've been successful there. So those are some of the things that we learned that we can use to optimize future activity in Sanish.

Great. And then, looking at the Polar Gen 4.0 completion design and the water reduction that you were able to achieve and the LOE savings, is that unique to the Polar area or is that applicable across the asset base with the utilization of Gen 4.0?

I would say it's applicable across our acreage position. As you know some areas have a higher water cut than others. Some are very low. So, it would have a different effect in each area, but I think it's applicable, and I think it's very positive that we've been able to impact that for the positive.

Great. Thank you.

Thank you. And the next question comes from Raymond Deacon with HS Energy Advisor (sic) [HS Energy Advisors].

Yeah. Hey. Good morning. Thanks for taking the question. I had a question about a little bit of detail on the midstream relationships there and in terms of gathering and transportation. Do you see any potential bottlenecks beyond 2018, and what plans would you like to make, I guess, to ensure that any don't develop?

Sure. I just went over the crude takeaway. So, we really don't see any...

Right.

...issues with the crude takeaway going out. Future gas, gas is tight. It's tightening towards the end of this year. It will be tight early next year. We are well aware of where the constraints are. So, we've put plans to manage that. We're expanding one of our gas plants up there and we're bringing some portable units and some other strategies to manage that. But I think the thing to keep in mind is there's a lot of midstream expansion going on right now, in total about 500 million cubic foot of capacity is being added. So, by year-end 2019, we think the takeaway capacity will be over 3 Bcf a day, and that should address...

Right.

... any kind of tightness that we see right now.

Okay. Great. And in terms of once you achieve your sub-2 times debt to EBITDA, how will you look to balance growth relative to free cash flow?

Well, we see ourselves getting under our target of 2 times somewhere in 2019. So that's step one.

Okay.

After that, it isn't going to hurt to continue to paydown debt if we have free cash flow. It really depend how many opportunities come our way within the Bakken as we continue to bolt-on. We just have to see what's going on at that point in time. But initially, the idea is to get under 2 times. Then we'll be able to worry about that.

Okay. Got it. Great. Thanks very much.

Thank you. And the next question comes from John Nelson with Goldman Sachs. John Nelson - Goldman Sachs & Co. LLC: Good morning and thank you for taking my questions. Regarding Redtail, would you all be interested or potentially entertain DrillCo JV structures, the farming structure (30:17) that you guys have used in Pronghorn before just as a way to still potentially mitigate the decline but maybe partially using some third-party capital?

John, we're not currently looking at anything like that or contemplating that at this time. John Nelson - Goldman Sachs & Co. LLC: Fair enough. And then can you just I guess move into the kind of bolt-on as an allocation of your free cash flow? Can you walk us through the framework you used in that capital allocation decision between bolting on versus potentially thinking about buying back your own stock? I appreciate that it was contiguous. You all think that the market was mispricing the potential for completion optimization there but you also had opportunities to kind of buy back your own portfolio there. So, can you just walk through how internally you all kind of evaluate that capital allocation process?

John, I think that's a great question. And maybe Mike Stevens and I'll both provide some color on that and I'll start. I think the way we looked at it is we've generated about $270 million of free cash flow to date as we detail in our portfolio here. And so, about half of that's going to debt paydown. And about half of that we really saw is we – is we saw an opportunity here, we saw a special opportunity to add something that fits perfectly with our current inventory. And based on the recent results in the area, we really felt like that, that provided some real high quality opportunities for us to best 55,000 acres as you've heard that's been lightly drilled. And so, we kind of felt this was a special bolt-on that really fit nicely to that. We obviously debated that heavily as we still have a really strong desire and a commitment to paydown our debt and reduce the leverage on the organization going forward. And so, we're trying to do both at the same time and we're holding those strong intentions.

I'll add on. With the run that our stock has had, it's not quite as attractive to think about buying that back. There is – where our debts at right now, that's really where the focus is at right now, getting that reduced. John Nelson - Goldman Sachs & Co. LLC: Great. Thank you for taking my questions.

Okay. Thank you. And the next question comes from Joe Allman with Baird. Joseph Allman - Robert W. Baird & Co., Inc.: Thank you. Good morning, everybody. Could you talk about the Williston Basin bolt-on and how competitive was that process? Was there a data room or was it a negotiated deal?

No, Joe. It was a data room process. It was put out there publicly and we competed in a data room process on that. Joseph Allman - Robert W. Baird & Co., Inc.: Got it. Thanks. And then on Redtail, what is it that you think precluded the bidders from making adequate bids?

I think that's a – I mean, that's a hard question to answer, Joe. I don't know what was in other peoples' minds. I think the asset was at a really nice position in that substantial capital had been invested. The plant has been upgraded, and there's a gas plant in the middle of it that runs at 99% runtime. Production is rising into a rising oil market. I do think the backward dated curve. I think your future view on oil price really affects maybe what people could lock-in on a forward strip. And so we had a lot of activity. We had a lot of interest. We did receive some bids, but nothing that we thought was compelling enough to make us move forward. We really felt like we could make more free cash flow moving forward operating it ourselves versus what we received. Joseph Allman - Robert W. Baird & Co., Inc.: Great. That's very helpful. Thank you, Brad.

Thank you. And the next question comes from Noel Parks with Coker Palmer Institutional.

Good morning.

Good morning, Noel.

Yeah. I did have a couple other questions about the bolt-on. I was wondering, did you have any non-operated interest in any of the stuff you acquired?

Yeah. There's a small amount of non-operated interest but the majority of it is operated.

Okay. And I guess what I was trying to get a sense of is since the acreage was fairly lightly drilled, I just was curious sort of over sort of what area or what era of sort of completions they had used. And sorry if you commented on this already but everything already held by production or anything, any lease work to do still?

Right. Noel, actually 94% of the acreage is held by production. There are some older completions in there in some other zones that are holding that acreage. There has not been any new completion test in the area. Most of them are three to four years old.

Great. Got you. And just my last one. Talking about consolidation as a whole in the Bakken region, just wondering with your current footprint, are you aware of anything that's particularly complementary to your position that you have an eye on you think likely could be up for sale? And I'm just trying to get a sense of whether there's other things that you guys might have an advantage over or be able to justify a little bit more of a premium of than other people in the area? And if so, how much stuff fits into that category?

I think, Noel, what we're trying to do is put ourselves in a position as being just – we're trying to drive efficiencies, and hopefully you've seen that in our drilling performance. You see that in our completion performance. You see that on what Rick's group's doing driving down our LOE per BOE. We're very proud that that has dropped below the $8 mark. And so, we're continuing to be – trying to be the most efficient possible on our existing position. And we think that puts us in a great position to look over the fence and look around us, and see where opportunities lie. But we're going to try to run our own business as efficiently as possible and put us in a position or an opportunity to be able to consider those things and see what we might could do with it in our portfolio.

Great. Thanks.

Thank you. And the next question comes from Jason Wangler with Imperial Capital, LLC.

Hey. Good morning. Just wanted to get your opinion on the NGL, pricing in the quarter was maybe a little bit weaker than expected and maybe your outlook as we look forward on that?

Yeah. The NGL pricing was a little bit weaker in the second quarter. Most of our NGLs, probably 60% is propane, and that pricing reduced fairly significantly from February into March and April and on. It has come back a little bit now and so my internal model that I'm using, I've knocked the price of about 10% for the third quarter from where we had in the second quarter.

Okay. Thank you. I'll turn it back.

Thank you. And the next question is a follow-up from Jeffrey Campbell of Tuohy Brothers.

Thanks for letting me back in. I just wanted to return to the Sanish infiill project and just ask you to expand a little bit on the concept or how you define protecting parent wells since lest I'm misreading it. Page 12 appears to show an increase in the parent production after the infills came on line. Thanks.

This is Rick. So, when I talk about protecting the parent wells, it's really during the stimulation of the new wells that are offset to the parent wells. What you've seen in terms of better performance suggests that when we completed the new wells that we also stimulated the drainage area of the parent wells, increasing the production and apparently appears to be ultimate reserves from the parent wells as well. So we protect them during the stimulation by pumping water in and then we believe we're stimulating the drainage area and improving the parent wells as well. So, it's a little bit of landing (38:57) up for us there.

And when you referred to – when you were answering Gail's question, you said you thought you were really conservative about the way that you did those fracs at that time. Does this uplift from the parent well encourage you to think that maybe you could be able a little bit more aggressive with the fracs going forward or you have a little bit more room to frac?

What I was referring to and being conservative was more in how far away from the new wells we did frac protect work. We were a little conservative and we went maybe further than we had to. So, what I was saying is we would have to do frac protect in fewer wells in future pilots or development like this, which would save costs.

Okay. Thanks for the color. I appreciate it.

Thank you. And that was the last one question. We'll return the call to Eric Hagen, please.

Yeah, thank you. Whiting will be participating in the EnerCom Oil and Gas Conference, August 20 and 21, and also in the COGA Rocky Mountain Energy Summit, August 21 and 22. With that, I'll turn the call over to Brad Holly for closing remarks.

In closing, I would like to thank the Whiting employees for their outstanding efforts this quarter. I would also like to thank our shareholders for their continued support. We will continue to deliver on our balanced strategy of disciplined growth and free cash flow.

Thank you. That concludes today's conference call. Thank you for attending today's presentation. You may now disconnect your lines.