Eric K. Hagen - Vice President-Investor Relations James J. Volker - Chairman, President & Chief Executive Officer Michael J. Stevens - Chief Financial Officer & Senior Vice President Mark R. Williams - Senior Vice President-Exploration & Development Rick A. Ross - Senior Vice President-Operations.

John A. Freeman - Raymond James & Associates, Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Jason Smith - Bank of America Merrill Lynch David R. Tameron - Wells Fargo Securities LLC John Nelson - Goldman Sachs & Co. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Jason A. Wangler - Wunderlich Securities, Inc.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker) Gail Nicholson - KLR Group LLC Michael Anthony Hall - Heikkinen Energy Advisors LLC Pearce Hammond - Piper Jaffray & Co. (Broker) Stephen F. Berman - Canaccord Genuity, Inc..

Good morning. My name is Kate, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation First Quarter 2016 Financial and Operating Results Conference Call. The call will be limited to one hour, 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. Please limit your questions to one question and one follow-up. Please note, this call is being recorded. I will now turn the call over to Eric Hagen, the company's Vice President of Investor Relations..

Thank you, Kate. Good morning and welcome to Whiting Petroleum Corporation's first quarter 2016 earnings conference call. On the call for Whiting this morning is the Whiting management team. During this call, we'll review our results for the first quarter of 2016 and then discuss the outlook for the second quarter and full year 2016.

This conference call is being recorded and will also be available on our website at www.whiting.com. To access the presentation slides, please click on the Investor Relations box on the menu and then click on the Presentations & Events link.

Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on slide number one and in our earnings release.

Reconciliations of non-GAAP measures we refer to and the GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-Q for the quarter ended March 31, 2016 is expected to be filed later today. And with that, I'll turn the call over to Jim Volker..

Good morning, ladies and gentlemen, and thank you for joining us. We'll get to your questions just as quickly as possible. Let's begin on slide two. Production averaged 146,770 BOEs per day in the first quarter, at the midpoint of our guidance.

Driving this was our enhanced completion designs in the Williston Basin, with our more recent completions achieving 60-day rates, more than double offset wells. During the quarter, we also successfully re-determined our bank credit commitments at $2.5 billion. We exchanged $477 million of bond debt into convertible debt on attractive terms.

We also entered into a wellbore only participation agreement in the Williston Basin, where our partner pays 65% of well costs to earn a 50% working interest. As a result, we plan to complete 44 additional wells in our 2016 program and increased our production guidance while keeping CapEx unchanged.

As to CapEx in Q1, our internal estimate was $230 million. The $267 million reported resulted primarily from $34 million of non-op from 2014 and 2015 which we have recently been billed as other operators got around to finally billing us. The good part of that is we, obviously, were able to use their working capital for an extended period of time.

We have recaptured approximately $10 million of this through sales of non-ops on a promoted basis. In addition, our operated Bakken JV brought in $30 million of cash in April. Our focus continues to be spend close to discretionary cash flow, pay down debt and grow production and reserves. Our actions in Q1 advanced these three goals.

On slide number three, you can see our liquidity and debt covenants. We have $1.5 billion of liquidity and no major debt maturities until 2019. We remain well within all of our covenants and are strongly positioned from liquidity and debt maturity perspective to deal with lower oil prices.

Moving to slide number four, with a focus on the Bakken and the Niobrara, our total net production as stated was 146,770 BOE per day in the first quarter. As you can see on slide number four, 93% of our total production in the first quarter came from our Rocky Mountain region.

At 124,900 BOEs per day, the Bakken/Three Forks represented 85% of our production. Because we are concentrated in the Bakken and the Niobrara, we can and truly have concentrated on drilling and completion efficiencies.

On slide number five, you can see that according to Wall Street analysts, our Bakken and Niobrara plays are top tier in terms of net present value created per rig on an annual basis. On slide number six, we provide an overview of the Williston Basin, where we control approximately 446,000 net acres, of which 99% is held by production.

We control the sweet spots of the Bakken in the Williston Basin and continue to increase productivity with new completion technology. Moving to slide number seven, investors have asked how much of our future drilling is located in the core.

We believe that based on NDIC data and numerous industry studies, most observers consider Dunn, McKenzie, Mountrail and Williams Counties to be the core of the Bakken. We also consider our Pronghorn area in the Stark County area to be core. So you can see that 92% of our potential drilling locations are located in these core areas.

Slide number eight shows the performance of all of our enhanced completion wells completed since the beginning of 2015 with over 5 million pounds of sand per frac and 120 days of production. This data covering nearly 50 wells is tracking to a 900 MBOE EUR type curve.

We believe it is representative of our core acreage with these wells spanning the core counties we discussed in the prior slide. This demonstrates the quality of our acreage and the quality of our people, who are using the newest technologies to maximize the productivity of our assets for our shareholders.

On slide number nine, we show our most recent enhanced completion results using diverter agents, which continue to drive higher productivity. During the quarter, we completed two wells in Williams County that both had 60-day production rates that were more than double the rates from direct offset wells drilled by Kodiak with older technology.

These wells were also high volume fracs with nearly 7 million pounds of sand and employed the new diverter agents. Further, the average cost of our Bakken wells remains at only $6.8 million per well. Slide number 10 depicts our Redtail field.

We did not bring on any new wells during the quarter, but we anticipate first production from a 16-well pad during the second quarter. We continue to make productivity gains in the field and have cut our drilling days to total depth by 50% to only 4.4 days with our new wellbore design.

Mike Stevens, our CFO, will now discuss our financial results in the first quarter of 2016..

On slide number 11, you can see our first quarter 2016 financial results. Our discretionary cash flow for the quarter was $102 million. At current oil prices of $45 per barrel, our discretionary cash flow in the first quarter would have been approximately $235 million.

Our guidance for the second quarter and full year 2016 is detailed on slide number 12. We have increased our production guidance without changing our capital expenditure guidance of $500 million. Our CapEx for the second quarter is expected to come in at $110 million.

In April, we received $30 million of reimbursements of capital we reported as CapEx in the first quarter due to the Bakken participation agreement and a smaller non-op sale. As a result, we expect our second quarter net CapEx to come in consistent with the $80 million per quarter we have already guided and reaffirmed for the second half of 2016.

Slide number 13 shows our crude oil hedge positions as of April 26. We are 49% hedged for 2016 and have recently added hedges in 2017. With that, I'll turn the call back over to Jim..

Thank you, Mike. Ladies and gentlemen, as you can see from this quarter's results, we further strengthened our financial position through an innovative exchange of bond debt for convertible debt. In addition, we continue to increase capital productivity through our use of cutting edge technology.

And finally, we secured outside investment on favorable terms through our wellbore only participation agreement, where our partner pays 65% of well cost for a 50% working interest.

In summary, we have a premier asset base recognized by industry partners as profitable at lower oil prices, strong liquidity, a strong hedge position, and we offer investors an attractive value proposition. Kate, please open up the conference call for questions..

We will now begin the question-and-answer session. The first question comes from John Freeman of Raymond James. Please, go ahead..

Hi, guys..

Morning, John..

Hi. Last quarter, you talked about that $45 to $50 price range as sort of when you more aggressively addressed the DUCs. Obviously, the participation agreement takes care of the majority of the Bakken DUCs.

So, I guess now sort of shifting looking at the Niobrara, what you would need to see to where you'd start to work down those, given the big advance that you've got on the drilling side, you're now looking at 100 DUCs at year end there?.

That's correct. So, in general, bringing down that number of DUCs would be one of the first things we would do at higher prices. Yes, $50 is a price where we would move forward on that.

I will say like most folks, at least that I'm aware of, most other companies that I'm aware of, we'd like to see that $50 number stay there for a quarter or so before moving ahead on that. I don't think it can hurt us. I think 2017 will have higher prices, as well.

And so, I think we'd just like to watch that for at least a 90-day period once – if and when $50 is here..

Okay. And then my follow-up question, I know, Mark, last quarter, you talked about you're pretty excited about the potential upside on the refracs, and you all were going to plan on testing a few of those toward the end of the spring. I'm just curious if that's happened yet.

And if so, if there's any color you could provide?.

Yes, John. That's been a pretty major focus for us here in the last quarter. And so, we've gone through our entire 1,400 well inventory up in the Bakken and we're sorting through all those. A number of them have, I'd say, very readily risen to the top of being great candidates.

So, we're working those up right now, focusing pretty much on, specifically, designing the refrac design to match the specific wells. And so, that's a process that we're in. We expect it by sort of mid-summer we'll actually be able to start implementing operations on this.

So, we've identified about 40 candidates so far, and they look like there are going to be good opportunities for us..

Great. Thanks, guys. I appreciate it..

The next question is from Neal Dingmann of SunTrust. Please go ahead..

Morning, gentlemen.

Say, Jim, after that, what I think is certainly a successful JV, just wondering, looking forward, do you have more potential with it, just the wellbore only, obviously given the massive acreage you have both in the Williston and in the Niobrara? Hello?.

Yes, can you hear me?.

Yes, can you hear me all right, Jim?.

Yes, can you hear me?.

Yes, sir. Let me try that again. I'm not sure what happened. My question, Jim, was just on the successful wellbore only JV that you did. I'm just wondering, obviously, given the massive acreage you all have both additionally in the Williston and as well as the Niobrara.

You all identified more – is there more opportunities for that either this year or going forward?.

So, what we'll do there is we'll evaluate as oil prices rise whether we want to drill those or whether we want to JV them. So, in direct answer to your question, yes, there's more opportunity for that. As to whether or not we act on it or not will be dependent upon the terms of those deals, continuing to remain, in my opinion, very positive.

And second, of course, whether we'd rather drill them ourselves as a result of oil prices continuing to go up and having more cash available through our cash flow..

Thanks. Sure. No. Makes sense there, Jim. And then just my follow-up, certainly those enhanced completions you continue to see just outstanding results on those Rennerfeldt wells. I'm just wondering on that, I'm not sure if I saw the lateral length in there.

Is that – Jim, really, I guess, a question for you or Mark, on those enhanced completions now, I'm just trying to get a sense of is it the longer laterals, is the more intense profit, really, what is producing those results? And is there opportunity just going forward do you think that'll become more of the standard for you all?.

Yes, this is Mark. Those are standard length laterals. So, there's really nothing different there. The big difference is we started in late 2015 which continued on for 2016 and two things, increasing our sand volumes. Sand volumes are now ranging between 6 million pounds and 9 million pounds on the wells that we completed this year.

And then the other thing that we talked about a little earlier was the use of diverter agents, which give us effectively more entry points into the formation. That's what that's really all about, so a combination of more sand and then distributing that sand among a lot more entry points is what's creating the difference..

Thanks, Mark. Certainly, impressive results, guys..

Thank you. Thank you, Neal..

The next question is from Jason Smith of Bank of America Merrill Lynch. Please go ahead..

Hey. Good morning, everyone..

Morning, Jason..

Good morning, Jim. Jim, you briefly alluded to this in your prepared remarks. You talked about completing the Redtail DUCs.

But how do you think about allocation of incremental cash flow beyond that? I mean, is the first priority balance sheet right now? Is it adding rigs? Where would you think about adding rigs? And is there kind of a level of leverage that you're managing around?.

Well, there's sort of two combined issues there. And in my comments, I think I prioritized them for you by saying that, first and foremost, of course, we would look to pay down debt. And so, that's always a primary concern to someone like us.

And second after that, as I mentioned, we would watch closely the oil price before determining that we wanted to add any rigs. And we'd like to see it stay at $50 or above. So, again, our focus will be to, number one, stay within discretionary cash flow or spend right around discretionary cash flow.

Obviously, we've now shown you, we have a number of ways to do that, right? We can do that by making sure that we have good cost control on our own operations. Second, we can do that by – on our operated properties, doing these joint ventures.

Third, of course, we can also use some of the increased cash flow that results from higher prices to pay down debt. And as I think you well understand through these promoted joint ventures, we can enhance our metrics, so we can grow production, we can grow reserves without spending more CapEx.

And so, I think our actions in the first quarter, as I said, advanced all three of those goals and all three of those methods of doing it that we accomplished in the first quarter are available to us, obviously, for the rest of the year..

I appreciate that answer, Jim. And just a quick one on the non-op, can you just remind us what's embedded in your $500 million budget for the rest of the year for non-op? And I know that you'd mentioned some of what hit you in the first quarter was catch-up for 2014.

So, just what level of confidence do you have in that trajectory over the remainder of the year?.

Yes. We feel a little better about the rest of the year. We don't think anything is going to come into that level again. We've looked at the AFEs, they look like they're fully funded now. So, we've set the budget for the rest of the year around $2 million per month to $3 million per month. So, over nine months, we have a budget of about $24 million yet..

Okay. Thank you..

The next question is from David Tameron of Wells Fargo Securities. Please, go ahead..

Morning, Dave..

Morning, Jim. Can you talk about some of the – just getting back to the Bakken, I'm thinking about some of the line pressures as it relates to – on the gas side, there's been some vapor pressure type constrictions, if you will, up there.

Can you address that a little bit?.

Well, Rick Ross has been waiting to answer that question for you. So, I'll let him step up here and do that. Thank you..

Hey, Dave. This is Rick Ross..

Hey, Rick..

Your question was about vapor pressure. And I – that was an issue that was discussed several years ago, about vapor pressure falling crude. The majority of our crude leaves the lease by pipeline. So, it hasn't really been a large issue for us. But, probably, to comment further, I think you're talking about line pressures as well.

Our gas capture percentage, I think we talked in the press release about, is way up. We're at about 96% gas capture right now. So, we made huge strides on that. I think the industry right now is about 87% with the target from the NDIC being 80%. So, we're in great shape there. We're capturing virtually all of our gas right now.

And mine pressures in the gathering systems really have not been an issue for us..

Okay. That's helpful. And then, Jim, congrats again on doing the deal. Can you just talk about kind of your thought process as you think about – obviously, you could – as Eric and I talked last night, right, you could complete the DUCs, or you could do this deal. You talked about it a little bit.

Can you just walk us through again your mindset in doing this and your thought process?.

Well, sure. Obviously, when we do a JV, if that's what you mean, in terms of doing the deal....

Yes..

...what we get out of that, of course, is a promote, to speak in terms of the historic way that people in the oil business have thought about it. It's pretty close to the old standard third for a quarter, right? Somebody pays third for the – roughly a third of the cost to earn a quarter of the well..

Yes..

And basically, that's what we've done here. So, for the originator of the idea, what happens is that your metrics improve. And I know you're well versed in this, but, obviously, our F&D cost per BOE, our LOE per BOE produced, benefits from that essentially 15% carry, where we're getting a 50% working interest for paying 35% of the cost.

So, that's what makes that decision, brings that opportunity to the forefront and makes you want to do that first before completing DUCs. But, you're right, that DUC is the second choice, and that will happen predominantly as prices increase.

It's kind of interesting in that as a result of the market increase in oil prices, you can actually on some of the DUCs that we've done, just due to the timing of when we drilled the well and made it a DUC, I think our rate of return will be actually higher because of this roughly $10 a barrel increase that we've seen in oil prices recently.

So, we completed them. We will complete them and put them on production at a time when oil prices are higher, and, frankly, that outweighs what I would call the negative in the IRR calculation of having spent the drilling cost and then had a brief period without revenue. But when you start the revenue, it comes in at a higher price.

So, I believe in this particular instance, it's worked for our benefit such that we will have enhanced our rate of return..

Okay. No, I appreciate the color. Thank you..

Thank you, Dave..

The next question is from John Nelson of Goldman Sachs. Please, go ahead..

Good morning. I guess building a bit on the prior question, there's been a good gas capture up in the Bakken.

But was there anything else noisy that impacted the 1Q oil mix, because this stepped down again, or where do you think we'll ultimately bottom out there?.

No, the real thing that's happening there is we're just putting on to the gas. We're just hooking up some wells that were producing oil, but we were not capturing the gas. So, now we're capturing the gas. We hooked them up, and in that particular quarter, the percentage of gas was a little higher..

Okay.

And if we're at 96% capture, then we should assume that's kind of mostly run its course, and this is probably a good run rate? Is that fair?.

That's fair..

Great.

And then just a question on the 44 gross wells in the participation agreement, are they concentrated in one area, or are they sort of pretty spread throughout your acreage?.

They're spread across our acreage..

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

All the best. Thanks..

The next question is from Jeffrey Campbell of Tuohy Brothers. Please, go ahead..

Good morning..

Hey, Jeff..

And congratulations on the JV..

Thank you..

I wanted to just sort of ask for a little bit of comparative thinking here. On slide eight, it shows the 900,000 EUR type curve performance for the 47 wells, and it calls out 5 million pounds of sand per well. The Rennerfeldt wells that you illustrated on slide nine were identified as 40 stages and 6.8 million pounds of sand.

And I think you mentioned around 7 million earlier in your remarks. So, I had two questions.

One, although it's obviously early, are there indications that the Rennerfeldt wells are outperforming the 900,000 EUR type curve? And, B, how does the performance of the offset wells illustrated on slide 9, the former Kodiak wells, compare to the well averages on slide eight?.

Yes. Hey, Jeff, it's Eric Hagen. I'll answer those..

Hey, Eric..

To answer your first question, the answer is yes, the Rennerfeldt wells are outperforming the 900,000 BOE type curve on slide eight. And we attribute that to using diverter agents in those wells. That's the biggest change from those wells to the prior wells.

And to answer your second part of your question, I'm not certain of the exact EOR associated with the 452 BOE per day and 404 BOE per day rates on the old Kodiak wells. It's something approximately 600,000 BOEs..

Okay. That's helpful. I appreciate that. You just kind of anticipated the second question I was going to ask, so let me ask it anyways, because I'm sure you'll have more color. You're starting to talk more about more sand, more stages and also diverters.

And in the past, Whiting has identified more sand as the most important variable on well outperformance. And it sounds like the diverters are taking out some more importance.

So, could you talk about that a little bit?.

Yes. So, I think, the best way to illustrate that is to look at our well performance from 2015 where we started the year out with less sand and no diverter and really finished the year using much higher sand. So, we went essentially from about 3 million pounds up to 6 million pounds over the course of 2015.

We've actually bumped that a little bit here in 2016. But towards the end of the year, we really started using a lot of diverter with the sand. So, it's really a combination of the two.

The sand is – it's very important to have additional sand, but you're also going to distribute that sand up and down the wellbore, and that's what the diverter does there, so it's a combination of the two.

So, our program this year, 2016, is really taking the results of 2015 and just focus on those two key issues, and we've been able to maintain those higher rates that you saw at the end of the year..

Great. I appreciate it. Thanks for the color..

The next question is from Jason Wangler of Wunderlich. Please go ahead..

Hey, Jason..

Hey, good morning, Jim. Good morning. Just curious, it looks like the participation agreement, obviously, has started off with the cash payment that you guys have started to complete in wells. Is there a timeline for that program? You were kind of mentioning being opportunistic whether it's your DUCs or it may be even in the agreement.

But is there a timeline for that, the 44 wells to be completed?.

So, no. Basically, they're per our schedule of drilling. They're really just participating on that basis in what was our drilling program for the year, and so it extends from now through the end of the year..

Okay..

And it obviously goes from basically day one this year through 12/31 and thus the reason for the fairly large upfront payment cash was to reimburse us for cost we'd incurred to the closing date..

Okay. Perfect. And then just in the Niobrara, obviously being able to cut the drilling days down.

As you look at keeping the CapEx budget the same, will that be something that you're going to focus on getting the same number of wells drilled, and you'd maybe drop a rig or would you maybe look to continue drilling more and adding to that – I guess continue to add to the DUC count as the year would go on?.

We've taken that into consideration to getting to our 100 wells at year end DUC count..

Okay. I appreciate it. Thank you, Jim..

Thank you..

The next question comes from Jeanine Wai of Citigroup. Please, go ahead..

Hi, Jeanine..

Hi. It's Jeanine. Good morning, everyone..

Good morning..

I'm just wondering if we could go back to Jeff's question on slide eight and well performance. I noticed that the wells that are on that type curve for the 900,000 BOE says it's for the wells that have at least 120 days of production. And earlier in your comments, you said the real game changer came late 2015, early 2016.

So, does that imply that the 2016 program would be trending above the 900,000 BOE?.

Yes..

Okay, great.

And then a follow-up to that, in terms of the JV, given the well performance that you've been talking about, do you have any, kind of, general indications on how the extra 44 wells would change either the fourth quarter or the exit rate of this year and kind of the effect on 2017 production?.

So, we've taken the completion of those wells into our guidance for this year. But, yes, you are correct in assuming that there will be a bigger effect upon 2017 production than on 2016 production..

Okay, great. Thank you..

You're welcome..

The next question is from Gail Nicholson of KLR Group. Please go ahead..

Hi, Gail..

Good morning, everyone. I'm just looking at the Niobrara, I think it used to be estimated that an 8-well pad from spud to first production took about 90 days to 120 days.

And I was just curious on – was that based on drill times from 1Q 2015? And how should we now think about an 8-well pad from spud to first production with the improvement in drill time?.

Sure. So, that's been a big change for us. We do have much improved drill time as we'd mentioned in the call. Our spud to TD is now about 4.4 days. But, we really have to look at it on a spud-to-spud. And so, essentially, if you do that, you're still quite around a week, that's a way to think of it.

So, most of the drilling that we're doing now on a go-forward basis is really on what we call a 16 low line rack (33:18). And so, you can really just take that one week times the two rigs that we got and play that out over the course of the year. That's what's built into our budget right now.

It's two rigs drilling one well per week and then actually, we accumulate DUCs here over the course of the year. So, we'll get 100 of those by the end of the year..

Okay.

To follow up, just understanding how long it takes to actually complete a 16-well pad when the completions reengage potentially in 2017 forward?.

Well, the time between when a well is spud and when it's actually completed depends on the size of the pad, of course. So, example, we just completed a 16-well pad. And so, there's a lag in there about four months that can total between the time – on average between the time the well was drilled and the time it was completed.

So, there is a period of shut-in. But during that completion, we have to be down four months. So, you just have to take that into consideration. And so, that's sort of how we're doing it right now is we're – the 16 wells per DSU could be completed essentially all at one time. So, there is a period there of about roughly four months..

Great. Thank you..

You're welcome, Gail..

I'm sorry. The next question is from Michael Hall of Heikkinen Energy. Please, go ahead..

Hey, Michael..

Thanks. Hello.

A lot of mine have been addressed, but just I'm curious, I'll take a shot at, can you provide any sort of view on what your 2016 exit rate might look like, particularly after this new participation agreement?.

You're talking about the 2016 exit rate, and we've given you guidance, of course, for the full year, and that guidance does include the....

Yes..

...44-well participation agreement. And we've given you a guidance for the second quarter. We just haven't given you third quarter and fourth quarter. But I think it's pretty easy for you to get a little close to where we're at if you just take normal decline for those periods..

What sort of normal decline, I guess, are you...?.

Take the difference between the two and divide by two..

That will get you pretty close..

Fair enough. Fair enough. Just was curious on well timing is what I'm asking. And just curious, do you have any sorts of views on the capacity of the services industry in the Williston? From what we hear, a decent amount of capacity has left the basin.

And I'm just wondering what sorts of conversations you've had and what sorts of views you might have around the ability of the service industry to respond to any upticks in activity?.

Sure, this is Rick Ross, Senior VP of Operations. We have had conversations with the service providers, in specific the pressure pumping services. And we will be restarting our completion activity with the 44-well package in a little bit later May.

And there are certainly adequate resources in order to do that with us bringing a couple of frac crews back to work. Some of the service companies have been fairly creative with their crews in ways to make them available quickly in the future. So, we feel like we're in pretty good shape.

Obviously, if price ticks up pretty significantly, there may be a little bit of lag to put folks back to work. But we're going back to work in mid-May for our plan with this JV, and we feel like we're in pretty good shape for services..

Great. Thank you..

Yes. Great questions. Thank you..

The next question is from Pearce Hammond of Simmons Piper Jaffray. Please, go ahead..

Good morning and thanks for taking my calls – questions, sorry..

Morning, Pearce..

On the diverter agents, I thought the commentary earlier was interesting, and I wonder if you can elaborate a little bit about it.

Technically, what is it doing for you, how do you see the advantages of deploying the diverter agents, just any more color on that?.

Sure. The diverter agents really are the – the technology has been around for a while. It's using polylactic acid. And the service companies each have their own mix of that, but the idea here is that when you go in to stimulate a well, what you're trying to do is maximize the number of entry points.

So, within given stage of the well, you can have up to six different perforation clusters. The problem has always been trying to make sure that the frac job gets distributed among all six of those. In the past, maybe only one or two of those was actually receiving any of the frac.

By pumping a diverter, what you do is, you give it a certain amount of time to go into those first one or two stages, then you pump the diverter, and it temporarily plugs up those stages, and the pressure goes up, and another perforation cluster will break.

And so, it essentially doubles, in some cases, triples the number of effective perforation clusters within each stage. So, you just access a lot more of the reservoir that way, and so we're – it's turning out to be a great add-on. It's older technology, but it's just the way we're applying it now with our new completions that's making the difference..

Thank you for that comprehensive answer, Mark. And then my follow-up is on slide nine. I thought it was real interesting, the uptick based on the enhanced completions. The direct offset wells, those were Kodiak wells.

I was just curious what the completion design looked like for those, and then how old were those wells? Were those, like, two years old or...?.

Yes. This is Rick Ross. The older Kodiak completions were generally cemented liners, but they were smaller pounds, number of pounds of sand. They were generally in the maybe 2 million pounds to 3 million pounds of sand, and generally only had one perf cluster or one entry point per stage.

So, those are the big changes that we're making, I think, is more sand, more perf clusters with the diverter resulting in better distribution of the frac load across the reservoir per stage, and we're getting more oil out of the rock per stage..

Great. Thanks for taking my questions..

Great, and all the best..

The next question is from Stephen Berman of Canaccord Genuity. Please, go ahead..

Hi, Stephen..

Thanks. Hi, Jim. You did a nice job last year of raising over $0.5 billion selling non-core assets. With oil having rallied as much as it has from the recent lows, I was just wondering what your current thinking is on further asset monetizations and you've also talked about that possibly including some midstream assets..

Yes, nothing has changed there in our plans. I haven't put a size or a date on it because you kind of wore me out last year, people saying we wouldn't get there. We had a plan, we stuck to it. We had certain number of properties. So, this year we have the same thing and I'm highly confident that we'll execute..

Okay, great. And that's it from me. Thanks, Jim..

Thank you..

There are no additional questions at this time. This concludes our question-and-answer session. I would now like to turn the call back over to Jim Volker for closing remarks..

Thank you, Kate. I'd like to thank all the Whiting employees and the directors for their contributions to a solid first quarter. Eric will now update you on our conference plans..

Mike Stevens will be presenting at the Citi Global Energy Conference in Boston, Tuesday, May 10, 8:45 a.m., Eastern Daylight Time. Pete Hagist will be presenting at the Wells Fargo Conference in San Francisco the week of June 20. And Jim Volker will be presenting at the JPMorgan Energy Conference in New York the week of June 27..

So, in closing, we thank all of you for your interest in Whiting Petroleum Corporation. We look forward to speaking or meeting with you soon..

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