Good morning. My name is Keith and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation's First Quarter 2018 Financial and Operating Results Conference Call. The 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 will now turn the call over to Eric Hagen, the company's Vice President of Investor Relations.

Great. Thank you, Keith. Good morning and welcome to Whiting Petroleum Corporation's first quarter 2018 earnings conference call. On the call today with me is Whiting's President and CEO, Brad Holly; Senior Vice President and CFO, Mike Stevens; Senior Vice President of Operations, Rick Ross; Senior Vice President of Planning and Reservoir Engineering, Pete Hagist; and Vice President of Geoscience, Mark Sonnenfeld. During this call, we'll review our results for the first quarter 2018 and then discuss the outlook for the remainder of 2018. This conference call is being recorded. It 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 is set forth on slide number 1 and in our earnings release. Our Form 10-Q for the quarter ended March 31, 2018 is expected to be filed later this week. And with that, I'll turn the call over to our President and Chief Executive Officer, Brad Holly.

Thank you, Eric. I would like to thank all Whiting employees for another great quarter. It was a very harsh winter in the Upper Midwest, but our teams in the field performed exceptionally well to help us meet our goals. Production came in above the midpoint of guidance. In the second quarter, we were building a backlog of wells in the Williston Basin. We plan to drill 32 wells but only put on production or popped 21. For example, we have several large pads being completed in the second quarter that will come on production in the third quarter. This will give us strong momentum in the second half of the year when we plan to pop 83 wells and our production really accelerates. This is in contrast to only 40 wells in the first half of 2018. Our optimized completion strategy has begun to bear fruit in some of our less tested areas. We announced an important new well in our southern Hidden Bench area. The well was completed with our leading edge completion design and tested at a rate of nearly 5,000 barrels of oil equivalent per day. That is over 1.5 times the typical well in the area. This further validates that Whiting has Tier 1 rock across its position and technical expertise to fully exploit it. In addition, during the quarter, we completed our reorganization into asset based teams. Whiting has three new Williston Basin asset teams led by some of our rising stars. Kelly Eisele will be leading our Eastern team. She has been with Whiting since the Kodiak acquisition and was instrumental in the development of our Dunn County assets. Charles Olson has been leading our completions team which has delivered industry-leading results. He will be heading up our Northern team. Mike Stahl, who will be leading our Southern team, has been in charge of the operations at our Redtail asset. His team did an amazing job bringing nearly 100 wells on production at the end of last year. This was the driving force behind our strong production profile in the field. We hope to introduce you to some of these leaders face-to-face in the coming months. We are still rigorously pursuing the strategic vision we rolled out last quarter and have made significant progress on our 2018 strategic initiatives. I'll now turn the call over to Mike Stevens who will briefly review the quarter and then we will take your questions.

Earnings per share and discretionary cash flow both substantially exceeded analysts' estimates. We generated positive adjusted earnings per share of $0.92 versus the analysts' estimate of $0.28. Discretionary cash flow exceeded CapEx by $103 million for the quarter. Over the past two quarters, we have generated approximately $200 million of discretionary cash flow in excess of CapEx. DD&A was significantly below the low end of guidance and oil and natural gas differentials were also below the low end of guidance. In terms of wells put on production we'll have 40 pops in the first half of 2018 and 83 in the second half. Our full year production guidance remains unchanged despite the impact of the Sanish gas plant outage. Whiting projects a relatively stable quarterly CapEx spend between $180 million and $200 million for the remainder of the year. Though activity increases in the second half of the year, this will be balanced by Redtail for all spending occurs in the first half of the year. Additionally, per Brad's comment, we are building and accruing CapEx for a backlog of wells that will contribute to production in the second half of the year. Keith, please open the conference call for questions.

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

Good morning guys and great turnaround, Brad. Brad, the first question, just on Redtail, I think bids were due here in the last couple of days. Any further color you can give on how that process is going?

Sure, Neal. Thanks for the question. We actually have been having a very robust process on Redtail and bids are actually due the first week of May. And so, due to interest and activity, we delayed that slightly. But bids are due next week and we expect to complete the process late second quarter or early third quarter.

And then, just to follow up there, your thoughts, obviously, the free cash flow was quite nice this quarter. Between the continued free cash flow as you step up the pops and you have the potential sale, your thoughts still for free cash, would that still be primary just to pay down debt or any further acceleration or anything you can talk about now that you have this free cash flow to potentially talk about?

Yeah. Great question, Neal. We're working on that really hard. We talk about that a lot. We will likely do a combination of both paying down debt and potentially reinvesting for growth. We're not ruling out but potentially looking at buying back shares if that makes the most sense.

Very good and thanks again. Great quarter.

Thanks, Neal.

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

Morning, Brad, and everyone. Thanks for taking my questions.

Morning, David.

Just curious, Brad, as you sort of look to the back half of the year and bringing on a number of incremental pops, as we look into 2019 and the potential for Whiting to maybe accelerate organically once some of the other priorities are managed, what do you think that the basin can sustain right now in terms of rig additions sort of vis-à-vis the gas processing constraints out there with some of the rising gas processing requirements and how are you all managing through that process and are there any sort of visible chokepoints on Whiting's end?

Hi, David, this is Rick Ross. Good question. I guess I'll comment first on Whiting's gas capture rate and follow-up in the latter half of your question. I'll say that Whiting has one of the higher gas capture rates in the Williston Basin right now. And we work very closely with the midstream providers to make sure they understand our development plans and are building to meet those needs. And I'll say we've done a lot of planning around gas capture. In terms of how many rigs would the basin support, I guess I don't have a great number but, yeah, I'd guess probably 60 to 65, somewhere in that order.

Thanks, Rick. And I guess my other question would be, you had success here on sort of the Southeastern portion of Hidden Bench with some enhanced completions above 8 million pounds. As you see folks kind of marketing some assets in the Bakken right now, are you still seeing opportunities to apply enhanced completions to assets that aren't necessarily asking for that sort of upside credit in their asking price right now?

David, this is Brad. We believe that we should be looking at all of those packages. It helps us to better understand the basin and our competition in the basin. And we would consider transacting if we felt the package fit well within our current acreage position and had the potential to compete in our current drilling program through applying the Whiting-style completions, as well as our operations.

Thanks, Brad. That's it for me, guys, Thank you.

Thanks, David.

Thank you. And the next question comes from Brian Corales with Johnson Rice. Brian Corales - Johnson Rice & Co. LLC: Good morning, guys. Kind of follow on this last question, is there opportunity that you all see from – to move from the Tier 2 inventory? Any of those options to move into Tier 1?

Yeah. David (sic) [Brian] (00:09:55), I'll let Mark Sonnenfeld, our VP of Geoscience, take that question.

Yeah. We are, for example, in the second half of this year are going to be testing enhanced completions in areas called Wildrose and Cassandra which are currently Tier 2 areas listed in the other category of our table. And in those kind of areas, as with our Tier 1, we think the upgrades will come from the standpoint of the job size, entry points, aggressive use of diverters. And additionally, especially in Tier 2, we're considering pump rate experimentation to keep more of our frac energy fluids and proppant in zone. Brian Corales - Johnson Rice & Co. LLC: Okay. If you're a gambling man, is there one area that you're more confident on?

Well, all our Tier 2 areas present different challenges and that's kind of one of our themes of right-sizing our fracs for the different sub-areas of the basin. Brian Corales - Johnson Rice & Co. LLC: All right, guys. Thank you.

I'd bet on all of them, Brian. Brian Corales - Johnson Rice & Co. LLC: Thanks, guys.

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

Hi, guys. Piggybacking on that last question, do you have a net acreage number for Wildrose and Cassandra, ballpark?

They're basically in the – they're the majority of the other category in our presentation. So that would be around....

Thirty...

36,000 net acres, 70,000 gross.

Got it. Appreciate it. And given that you're going to be second half weighted with these pops, I was just hoping you give us a little bit of sense of what this means for organic growth in the Bakken as you head into 2019 if you could maybe kind of frame that a little bit, that would be helpful. Thanks.

Yeah. Mike, I think we're still committed to our 14% operated growth production in our Williston Basin assets.

Okay. All right. Fair enough. Great quarter, guys.

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

Good morning. On slide 13 of the presentation, it illustrates the large frac geometry completions, that mix, both far-reaching and near wellbore fractures. And I thought this is really interesting since the current industry standard is exclusively a near wellbore completion. I was wondering if you could provide some color on what led you to employ the large frac completion and where is it typically most appropriate and what gains does it achieve versus a purely near wellbore completion?

This is Rick again. What we're targeting there with completions on slide 13 is, well we've got maybe a little bit more geometry, a little more space between wells. We're targeting the, what we call large geometry fracs that will be more proppant. We'll still focus on diverter but we're trying to get further from the wellbore to cover the area around the well. And then the high intensity near wellbore completions would be where we've got a little less geometry, a little less area, and we're really working pretty hard with diverters to try and create more complexity in the area that we are stimulating. Diverters that will go further out not just in the perforation tunnel but go out in the formation and create more cracks, more intensity and allow us to better drain the area that we're stimulating.

So, I would add, Jeff, that there's no longer any cookie-cutter completions for us. We are rightsizing every completion that we pump based on where we are in the field and what the offsets look like.

Great. I appreciate that color. Thank you.

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

Good morning, everyone.

Good morning, Will.

Wanted to touch on OpEx a little bit. In 2016 and 2017 you guys really brought down OpEx quite a bit despite production declining, and I realized that some of that may be kind of shedding higher-cost assets. But I also assume that you guys have been working on some additional initiatives going forward to drive that as well. I would fully expect that we get just with greater scale some downward pressure on that front. But can you talk about any additional initiatives you have going forward that can help lower those unit OpEx numbers on a forward basis?

Sure. Some of the things that we're currently focusing on and are continuing to focus on would be getting more of our water on the pipeline and continuing to try and renegotiate and bring our price for saltwater disposal down. That's one of our highest cost categories. So it certainly demands focus. And we've made good headway as you've mentioned over the last few years and I think there's still room to go. And then secondly, the other thing we're working on is just well intervention rate or reliability on our downhole (00:15:14) pumping equipment. And we've made very good headway over that through some advanced data monitoring that we use and design work to try and minimize our failures. And I think in our slide show we show that we had – over a year's period we brought our well intervention rate down by 12%, and we believe there's some more to go there and we continue to focus on that.

Will, I haven't baked any of these potential savings into the forward guidance. You'll see our per BOE number going down as our flush production comes on in the second half of the year. So, hopefully, there's some upside there on the guidance front.

That's a great color. And then, I wonder if we're thinking about a potential Redtail sale, can you guys help me with how to think about how those unit OpEx numbers may change on a go-forward basis after that sale is potentially complete or is there a drastic difference in LOE between the basins?

Well, there's some difference. The Bakken number is probably closer to $7.25 to$ 7.50 whereas Redtail is closer to $10. So, there will be a little bit of improvement there when we sell Redtail.

Great. Thanks for all the color, guys.

Thanks, Will.

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

Good morning, John. John A. Freeman - Raymond James & Associates, Inc.: You've all done a really good job of locking in most of your services for a year as opposed to the past where it was more shorter term type of contracts, and as we sort of shift, as we move into the second half 2018 and attention starts to move more and more to 2019, I'm wondering if we should think about the way that you all have structured the services kind of like what you all have done with hedging where you've increased the hedging a lot more than had been done in the past to sort of kind of de-risk the business plan. Should we think about like when you roll in and you start looking into what you're going to be doing for 2019, should we anticipate that the services would be handled in a similar manner where it's mainly longer term type contracts?

Yeah. That's really our intent. We'll be working on that in Q3 and Q4, lining up services for next year, as well as some of the materials pumping units, casing, tubing, those type of things. So, yes, we will we will be using the same strategy. John A. Freeman - Raymond James & Associates, Inc.: Great. And then just the one follow-up for me, is there anything that would potentially have to change or some scenario you could envision where you all would consider divesting some or all of the non-op Bakken again?

We don't – right now, we don't anticipate selling off any of the non-op. It's thrown off a lot of cash flow, there is a lot more activity going on from the other operators in the area and we're enjoying the additional insight we get from there, drilling and completions. John A. Freeman - Raymond James & Associates, Inc.: Thank you. And nice quarter, guys.

Thanks, John.

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

Thanks. Good morning. Brad, if I could probe a little bit into one of your strategic vision, which is to maximize economic returns at the DSU level as well as the corporate level. My question is, on the corporate level or at the DSU level, could you talk about where you are today and sort of the roadmap going forward and how does that fit into the compensation plans?

Sure. I appreciate the question. What we're really trying to do there is get away from individual well economics. And so, it's easy to say that a certain well cost a certain amount and we get a certain EUR on that well and we generate a rate of return. We're trying to get away from looking at it as an individual well rate of return, but really look at a holistic, what do we have. We have 410,000 net acres in the Bakken and our job is to maximize the returns on all of that. So, we look at a drilling spacing unit and we look at what the current commodity price is, we look at how many wells we could drill in that unit and what style of completions, the style and type of completions. And we'll iterate on rate of return and NPV in that DSU, to get really an optimum economic output or benefit from that. That's how we're looking at that.

And on the corporate level, could you remind us what the road map would be that you have in mind if you can quantify or any additional color that you can provide?

I don't think we're exactly sure what you're asking there on the corporate.

The corporate returns and what would the corporate target return be, and what's your goal – what you're driving the organization towards?

Yeah. I think, Asit, you're asking – we added a drilling rate of return metric to our compensation plan, and the threshold on that we've said before was a 30% rate of return.

Okay. All right. Just a quick follow-up then. At what point, Brad, philosophically does balance sheet become suboptimal? I know you're driving less than 2 times net debt-to-EBITDA.

Yeah. I think we've just said that 2 times is a milestone that we would like to achieve. It's not the end-all. And so what we'd like to do is drive toward being under 2 times and then look at our opportunity set at that point and see what makes the most sense to continue to drive value.

Great. Thank you, guys.

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

You guys have seen a steady improvement in the Williston Basin oil differentials since the 2014 timeframe. I know some of that is just overall improvement in the differential itself but you've also taken an effort to improve your marketing strategies. I'm just kind of curious if you can provide some additional detail on that. And if you think there's more room for improvement on that oil differential if you continue to attack incremental marketing contracts?

Yeah. Thanks. This is Pete Hagist. We've made significant progress on the oil differentials. We think there's adequate takeaway capacity from the basin right now. Total production is roughly 1.2 million barrels per day and the pipeline by itself was 1.4 million barrels per day. About 73% or 100,000 barrels a day is actually leaving via pipe. The rest is via rail. So, there's a lot of capacity there. That's the reason the differentials have decreased. And so at this point, only a small amount, approximately 15,000 barrels a days is committed long-term. So, we're enjoying being able to market it on a short-term basis. But, obviously, very cognizant of what the ultimate takeaway capacity will be and we're always talking to our takeaway providers.

Yeah. Gail, this Brad. Thanks for that question. I'm really proud of Nate and his team and what they're doing there. We're looking at all options there. So with over 100,000 barrels a day of production, we realized where we sit in the basin. And we're certainly not opposed to going a little longer on some of these things that we can lock in good differentials.

Great. And then just in regards – I believe that you guys, in the back half of the year, will be doing the remaining Pronghorn JV wells. Thoughts about completion optimization in the Pronghorn area?

Right. That's something we're looking at Gail. If you notice on our inventory map, we do not have any enhanced completions in Pronghorn. We're excited about the area. We've got a rig headed back down there soon and that we have about eight completions to do this year in Pronghorn, and we'll be trying an enhanced completion strategy on those to try to improve results over what we've seen in the past.

I will sneak in one more. In Sanish, I know you guys are planning to do some infill testing. Does the gas processing plants unscheduled maintenance kind of defer those to the right a little bit, or kind of how should we think about potential news with the downspacing test in Sanish which is the field that just keeps on giving.

Good question. The tests that we're planning won't be affected by the plant downtime. Plant downtime is just in May. And I'll say long term in the Sanish area, we enjoy a 98% gas capture rate. So, we see it as just a one-time event and it shouldn't be an issue going forward, so no change.

Okay. Great. Thank you.

Thank you. And the next question comes from Subash Chandra with Guggenheim Securities.

I was curious on these enhanced completions if any of these qualify, I guess, with the buzzword of as limited entry perforations?

This is Rick again. We are using that technology on a number of our completions, so we have cut back the number of perfs per cluster to try and get better distribution. And from some of the post-frac monitoring tests that we've done so far, we like the results. We're encouraged by what we're seeing.

Is that impact on rates or costs or maybe time to drill and complete?

Really no impact. If anything, the perforating cost would be a little less because fewer holes, but other than that, really no impact.

Okay. Thanks. And then secondly, I'm curious if you're aware or able to talk about some third-party results in the non-core guys like Kraken, maybe some others have been trying to turn the non-core into core. Any update there that you might be aware of?

Subash, I don't think we want to comment on anyone else's process, but I will say that there is a ton of data out there. We mine a lot of that data. We're watching all that. As Mike said, we have a small working interest in a lot of offset operators' activity. And so, I guarantee you, we're watching that. We see a lot of oil in place and we're trying to figure out the proper completion technique to get at that.

Okay. Fair enough. Thank you.

Thank you. And the next question comes from Mike Scialla with Stifel. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: (00:26:04) you said that you are above where you need to be for gas capture. Just wondering if you can make any comments on how the industry looks as a whole in the basin on that issue? And does that maybe create any opportunity as you look to potentially add to your acreage position in the basin?

Well, yeah, this is Pete Hagist. North Dakota requires, at this point, 85% of natural gas to be captured. In November of 2018, that number will increase to 88%. In February of this year, about 88% of the gas produced in North Dakota was captured and Whiting is currently capturing over 90% of its natural gas. So we have actually been doing very well and that's in large part due to our proactive efforts to manage our gas capture. We have some assets. We have a gas plant up there that we're utilizing. So we actually are in pretty good shape.

Mike, what that takes to do that well though is great planning and we have to be 18 to 24 months ahead on our planning cycle to be able to capture that gas. And so, we're doing that today and I'm encouraged by our new integrated asset teams taking a strong two-year look-out to make sure that we maintain that. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Okay. Thank you. And looking at your slide 15 with your optimized completions, just wondering as you – you're looking out over a year, have seen an improvement over your old design, just wondering if you have a sense at this point for how much of that is acceleration versus an EUR uplift or does it even matter to the NPV based on the data that you've seen so far?

I'll let Steve Kranker take that question.

Yeah. We're expecting that to impact both the initial rate, and thus, highly affects our internal rate of return on those wells. After the well phase-out, (00:28:05) it's less impactive on the IRR, but we do expect there would be a significant uplift in the EUR. So, we're planning our DSU optimization appropriately. We plan the frac size for the number of wells going into that DSU so we can optimize all of those things together but both initial rate and EUR are going up in our opinion. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.: Very good. Thank you.

Thank you. And the next question comes from Drew Venker with Morgan Stanley. Drew Venker - Morgan Stanley & Co. LLC: Hi. Good morning, guys.

Good morning, Drew. Drew Venker - Morgan Stanley & Co. LLC: Brad, I just want to follow-up on the response on uses of free cash flow. You said potentially using some of that to reinvest for growth. Can you just elaborate a little bit on how you determine what the right level is and then if you – I'm not sure if reinvesting for growth includes bolt-on acreage or – and whatever extent you can speak to that would be helpful?

Sure. Drew, that's a great question. What I've said internally is we're a margins-based business and we've got to compete on the margin. And so, I'm willing to increase activity when we show that we can do that at or below kind of our current levels. So, that's why we added the fifth rig and we got comfortable with four rigs. We were able to add a fifth rig and have that standing in the field at or below our current cost structure. And so, we'll continue to try that mantra going forward as our teams continue to improve and continue to drive efficiencies. We'll look with our inventory to potentially drive reinvestment in our acreage. As well as we think that we should be looking over the fence. And so, with our strong field operations and we talked about LOE per BOE in the past. We're looking for opportunities where we think we could potentially take a position, we could lower the LOE per BOE, we could shallow decline (00:29:56) and we have opportunity to drill and complete economic wells in that area. And so, we have said that we are totally focused on the Bakken and it is our job to look for any potential opportunities out there that fit into Whiting's portfolio. Drew Venker - Morgan Stanley & Co. LLC: And, Brad, is there much out there that would fit, what opportunities you'd be interested to bolt on?

Today, we think so, Drew. We really like the basin, we think there's more to do out there. I think with our southern Hidden Bench well, it shows you what the capabilities are, both north of the river, south of the river and east of the river. And so, we think we have substantial opportunities in all of our areas to potentially increase the geographic footprint of economic Bakken. Drew Venker - Morgan Stanley & Co. LLC: Okay. That's helpful color, Brad. Just one follow-up on some of the recent organizational changes you all have made. I've heard about, I think, a few, but can you give us some more color on what's been done overall, how it affects the development process? And if – whether there's a potential to name or hire a COO?

I think, Drew, from a – I think from a big standpoint, you just had a discipline-based organization, where everybody reported through their discipline and we went to an asset-based model. And so what we've done is we collocated our engineers, our geologists, our land people, et cetera, all together. Put them on a team, give them P&L responsibility. And so we are moving to a quarterly economic P&L review of each of our areas. And so it really helps to highlight what are the key to the third and fourth quarter, what do we need to be doing in the second quarter to ensure our results down the road, as well as just taking a real holistic look at the areas that we operate. And so we're seeing some good energy and excitement in the teams around doing that. Drew Venker - Morgan Stanley & Co. LLC: And then, Brad, does that – potentially hiring a COO have been a manner of discussion or is it really not something that's been a focus recently?

Yes, Drew. I mean, we're looking at the organization at the top. We're looking at our structure and how we most favorably compete. And so we've been talking about all that, where things report, who needs to sit at the leadership table and all that's under discussion. So.... Drew Venker - Morgan Stanley & Co. LLC: Okay. Thanks for all the color.

Thank you. And the next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning. Thanks for taking my questions. In terms of long-term activity in the Bakken, can you just comment on if there's an optimal rig or well count to keep in mind just from the standpoint of optimally developing the resource?

Yeah. Hey, Jeoff. We had said near-term, I think Rick had said it's somewhere in the 60 to 65 range. I think long-term it's kind of a speculation as to where it can get. Some of the service parties who've said they think that they can get to 80 without any upward inflationary pressures in terms of rig count, that's probably the best view we can give you. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Got it. And then just a quick one on Redtail. Anything new to highlight on spacing completions or laterally? Just wondering if any data from the recent completions had led to any changes in design on those fronts.

Yeah. Go ahead, Pete.

Sure. Yeah. This is Pete Hagist. We did announce that we were trying to enhance completions out there. We had a number of docks that we could do that on. And those wells are performing better than we expected. That's part of the reason that the Redtail production has done so well this quarter. So, we weren't able to replicate all of the advancements that some of our offset operators have been using but the stuff that we were able to test was very promising. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Appreciate the color.

Thank you. And the next question comes from Philip Stuart with Scotia Howard Weil.

Good morning, guys. You all have done a great job on the well costs in the Bakken and I know there aren't many levers to pull. But as you look out to the second half of 2018 and ended 2019 are you all exploring self-procurement of Northern White sand?

Yeah. This is Rick Ross. We did explore and we'll continue to explore that. I would say that the price advantage really wasn't there this year for us. And so we've chosen to stay with the sand provided by the service providers right now.

Okay. So maybe once more of these local sand mines come on the Permian that might be a time when you all could go back and look at self-procuring Northern White yourself.

That's exactly what we're thinking, later this year.

We took a hard look at that, Philip, first quarter as Rick said, it just didn't make sense but everything is open and we'll continuously to rigorously pursue driving our cost structure down.

All right. Thanks, guys. I appreciate the color.

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

Hi.

Hi, Janine.

Hi. I guess dovetailing on Drew's prior question but maybe coming at it from a slightly different perspective. Given the amount of free cash flow that we anticipate Whiting will generate over the next few years, you certainly have a lot of optionality. In terms of the goal of delivering multi-year growth and free cash flow, can you provide some more color on what production growth and free cash flow profile you see is competitive versus your peers in order to help us kind of narrow down what the goalposts are on your multi-year plan and what you view as relatively more shareholder-friendly. We noticed that in the proxy, your peer group was reconfigured and it's pretty diverse including Permian names and some gassy names.

Well first of all, I'll start and say internally, the plan is for double-digit production growth at $55 NYMEX within cash flow. That's the long-term plan. So, when we get out there and we get closer to 2019, we'll put a more definitive plan in place. But on an overall perspective, that's what we're going to do.

Okay. Thank you very much.

Thanks, Janine.

Thank you. And the next question comes from Kashy Harrison with Simmons/Piper Jaffray. Kashy Harrison - Simmons / Piper Jaffray: All right. Good morning, everyone, and thanks for taking my questions. And so last year in an effort to improve the balance sheet, you monetized some assets in the Indian reservation for a pretty decent dollar per acre valuation. I was just wondering if those assets were in your portfolio today, would you consider those assets Tier 1 or Tier 2?

That would be Tier 1 assets, we didn't have a whole lot of development left there. A lot of it was non-operated, but definitely Tier 1 assets. Kashy Harrison - Simmons / Piper Jaffray: Got you. And then just one quick question on the Mallow well, it looked really strong and I was just trying to get a sense of what you think a 24-hour IP of that magnitude could translate to you after six months on line? I'm just trying to get a sense of relative performance or potential relative well performance versus the 1 million barrel type curve?

I think it's a little difficult early on. Certainly, a really strong IP and I would say that was conservative, a conservative IP, by the way we conducted it. A little tough to say long term, but if you look at the type curves we've been showing for our enhanced completions, generally, we're falling above the 1 million barrel type curve. This appears short term to be stronger than what we see as an average for those would be probably as much as I could give you. Kashy Harrison - Simmons / Piper Jaffray: Got you. So, at least in the near term it looks better than the wells that are outperforming the 1 million barrel type curve?

Yes. Kashy Harrison - Simmons / Piper Jaffray: Okay. Got it. All right. Thanks, guys. That's it for me.

Thank you. And the next question comes from John Nelson with Goldman Sachs. John Nelson - Goldman Sachs & Co. LLC: Good morning. Congrats on showing some free cash flow and also to Kelly, Charles and Mike on their appointments. My question mainly had to do with a sentence in the release just where you guys talked about increasing the pace of operations to accelerate your growth profile and I guess I was just trying to reconcile if that's a change versus kind of the plans you already kind of laid out to us and talk about adding that fifth rig? And if that's something that could ultimately lead to you guys taking up that 14% operated Bakken growth rate at some point in the back half of the year.

Hello, John. Thanks for that question and a clarification. We were not signaling anything. We plan to stay with our $750 million of capital in our production growth rates. So, we'd always planned to do that. It's a shift this time of the year from drilling the Redtail docks to moving to more activity in the Bakken. And so, we expect cash flow or we expect CapEx for the quarter to remain fairly consistent and we're still on our initial plan we rolled out. John Nelson - Goldman Sachs & Co. LLC: That's very helpful. And then what was Bakken operated production in the quarter?

93,000, Mike?

Yeah. 92,865. John Nelson - Goldman Sachs & Co. LLC: Perfect. And then last one for me, just on the timing expectations for the remaining Redtail pops?

The remaining Redtail pops will be in the second quarter. There'll be 16 of them. John Nelson - Goldman Sachs & Co. LLC: Perfect. Congrats again on the free cash flow and the turnaround.

Thanks, John.

Thank you. And the next question comes from Paul Grigel with Macquarie Capital. Paul Grigel - Macquarie Capital (USA), Inc.: Thanks. Good morning. A lot of strategic commentary around potentially the Redtail sale, maybe your interest in other Bakken assets getting down below 2 times. Is there an order of operations that those need to occur? And do we need to see a clear path or be at sub-2 times before there's a Bakken transaction? Obviously Redtail involved, I'm just curious how the thoughts line up in terms of order there.

Yeah. Yeah. Paul, that's a great question. Timing doesn't work – always work out perfectly in the real world. And so, we're looking at how to maximize the value to shareholders. And so we've got to evaluate everything at the same time and when those funds become available, we're going to try to make the best decision at that time, with what to do. Any color, Mike?

Yeah. We're trying to get to 2 times, you said it. Internally, it's a $55 in NYMEX, I look at our EBITDAX at $55, we get close to $1.2 billion. Take it times 2, that's $2.4 billion, we're at $2.9 billion today. So, step one is probably to get to that level at some point, if we have the chance. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. No. That's good to know. And then second, would it be possible to get a specific calculation on the drilling rate of return calc in the 2018 plan and the waiting that goes along with that? And then as a tangential follow-up to that, with the new alignment of the teams and the kind of asset-based P&L that you referenced, are they incentivized on the P&L at their asset level as well?

I'll take the first part. So, the calc I'm not going to try to explain that on the call here. I think it's pretty straightforward. And we look at all the costs and wells completed during the year, all costs whether this year or prior year. And look at the future reserves, look at the cash flow, and calculate the rate of return. That's very general how it's done. As far as the second part....

Paul, I'll take the second part. Obviously, if the executives are incentivized by certain parameters, we're going to drive that down into the organization and they'll get aligned. And so that's certainly both return, as well as optimization of our portfolio is directly what we're targeting with our leadership and our employees. Paul Grigel - Macquarie Capital (USA), Inc.: Yes. Great to hear. Thank you.

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

Good morning.

Good morning.

Good morning, Noel.

Pete, my first question was about the other properties that might be available in the Bakken. Not everyone out there is an ideal operator and I'm thinking as you look at what's available or what you might be interested in, do you see opportunity in some of these packages more typically on the productivity side, you've talked about using diverters and other experiments you've been doing or more on the efficiency side as far as how these guys have been running their operations?

Yeah. Noel, we're – I mean, great question and I think that's something that we're striving to do here at Whiting, is to build an enduring great company and be good at both. And so we have taken a really holistic look at the entire basin. We're not trying to just look at what potentially is on the market, but what makes sense in our portfolio. And so, we're looking at it very strategically. But we think the best way to win is have the opportunity to do both. So, we wouldn't shy away from good PDP production, where our operations teams could go in and lower LOE and shallow decline. (00:43:32) And we certainly would like to build Tier 1 inventory in some places where we can pick up that Tier 1 inventory and be able to drill and complete it with our enhanced completion styles with our cost structure. We're looking at opportunities on both sides of that. If we can find those together, I think it gives us multiple ways to win.

Great. Great. And as you continue your process of becoming an all-Bakken focused company, I was just curious if you had any thoughts on secondary EUR production in the basin. I know there have been some pilots that I think have been in a confidential status. But I just wonder if you had any thoughts on that and heard anything on that?

We do. There's been some successful pilots out there. There's been some testing in the Williston Basin. There's been some successful pilots down in the Eagle Ford and we're studying all that. We have some expertise in that area. So that gives us, I think, a little bit of advantage. But, yeah, obviously, there's a big target out there and if we can make some breakthroughs there, there's a big upside.

We know that they know that the Bakken's a tremendous oil resource and we're not getting at a recovery. We think there's more to get out than the recovery factor.

Sure. And just to understand. So, is that the sort of thing that you yourselves might be looking at in like one, two years or maybe not, more like a three, four, five year? I mean, there could be plenty on your plate just from primary production.

Right. We're trying to optimize our DSUs through our primary development program but we have an effort going on right now where we're trying to understand and evaluate those techniques. So, I'd say it's going on in parallel.

Thanks, Noel.

Thanks a lot.

Thank you. And that does ends the question-and-answer session. So, I would like to return the call to Eric Hagen for closing remarks.

Thanks, Keith. Whiting will be participating in the Citi Global Energy Conference May 15 to 16, the Tudor, Pickering & Holt Conference May 15 and 16, Wells Fargo West Coast Energy Conference June 11 and the JPMorgan Energy Conference on June 18. I'll now turn the call over to Brad Holly for closing remarks.

In closing, I would like to thank Whiting's employees for their performance this quarter. Energy is building as our new teams gain momentum and hit the field. Also I'd like to thank our shareholders for their support. We remain committed to delivering on our balanced strategy of disciplined growth and free cash flow.

Thank you. This does conclude the question-and-answer session. Thank you for your participation today. You may now disconnect your lines.