Eric K. Hagen - Vice President-Investor Relations James J.

Volker - Chairman, President & Chief Executive Officer Michael J. Stevens - Vice President and Chief Financial Officer Mark R.

Williams - Senior Vice President-Exploration & Development Rick A. Ross - Senior Vice President-Operations

Jason Smith - Bank of America Merrill Lynch John A. Freeman - Raymond James & Associates, Inc.

Neal D. Dingmann - Suntrust Robinson Humphrey, Inc.

Brian Michael Corales - Scotia Howard Weil David R. Tameron - Wells Fargo Securities LLC Scott Hanold - RBC Capital Markets LLC David A.

Deckelbaum - KeyBanc Capital Markets, Inc. David Martin Heikkinen - Heikkinen Energy Advisors Brian Taylor Velie - Capital One Securities, Inc.

James Sullivan - Alembic Global Advisors LLC Drew E. Venker - Morgan Stanley & Co.

LLC

Thanks, Chad. Good morning and welcome to Whiting Petroleum Corporation's second quarter 2015 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 second quarter of 2015 and then 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. And 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 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 three months ended June 30, 2015 is expected to be filed later today.

And with that, I'll turn the call over to Jim Volker.

Good morning, everyone. And thank you for joining us.

We're going to move through our comments as quickly as possible, so that we can get to your questions. We posted another record quarter of total company production at 170,000 BOEs per day.

We also posted record Bakken/Three Forks production of 136,000 BOEs a day. Our new completion designs in the Williston Basin are delivering 40% to 50% production increases relative to our older offset wells.

We reported a 24-hour rate of 4,300 BOEs a day from an enhanced completion well in Dunn County, one of the very best wells drilled in the county to-date. In the Niobrara, our Redtail production came in at 17,000 BOEs per day in the second quarter, up 31% over the first quarter.

We have two rigs running at Redtail where the Niobrara continues to be a winner for us and where we have exciting new results from the Codell. During the second quarter, we sold an additional non-core properties with high LOE per BOE for $185 million.

Year-to-date, we have completed $300 million of such asset sales. During the second quarter, we continued to deliver strong production growth without adding debt.

This is a testament to the quality of our assets, our commitment to a strong balance sheet and our technical team. We're taking strong measures to preserve our solid financial position while realizing the full potential of our asset base.

With the recent decline in commodity prices, we have elected to drop an additional three rigs in the second half of the year and run an eight-rig program. In 2016, at a $50 NYMEX oil price, our capital budget and cash flow should be equal, with a relatively flat production profile when compared to Q4 2015.

Our 2016 guidance for 147,000 BOEs per day gives only partial credit for our enhanced completions. If we continue to get results consistent with the examples highlighted in our press release, we believe production could average 150,000 BOEs to 155,000 BOEs per day.

In summary, our plan going forward is to operate within cash flow, have property sales of $20 per barrel LOE properties, and drill new properties with LOE of half that for margin improvement; then growing production and reserves from the lower base by getting 40% to 50% increases in the first 12 months production, with well costs only 15% higher. We think our 2016 outlook is attractive relative to analyst estimates as it implies better capital productivity.

Our capital forecast of $1 billion is 40% lower than the consensus estimate, but our production guidance is only modestly lower than their forecast. Also, our budget is flexible.

If oil prices are higher than anticipated later this year, we can ramp up and deliver even greater growth. A simple way to think about modeling this is that for every $100 million of additional spending in 2016, we get approximately an additional 4,000 BOEs to 5,000 BOEs per day of production.

Moving to slide three, you can see our strong capital structure. We have $60 million of cash on hand and nothing drawn on our $4.5 billion borrowing base.

We are well positioned from a liquidity and debt maturity perspective to deal with lower oil prices. We are tooling Whiting to run and grow at $40 to $50 oil.

Moving to slide four, with the focus on the Bakken and the Niobrara, our total net production averaged a record 170,000 BOEs per day, a 2% increase over the first quarter even though we sold 8,300 BOEs per day in the second quarter. As you can see on slide four, 92% of our total production in the second quarter came from our Rocky Mountain region.

At 136,000 BOEs per day, the Bakken/Three Forks represented 80% of our total production. We continue to be a focused company.

On slide five, we provide an overview of our plays in the Williston Basin where we control 737,000 net acres. We control the sweet spots in the Central, Eastern and Southern Williston Basin.

Moving to slide six, we have completed nine higher sand volume wells at our Pronghorn field in Stark County, North Dakota. On average, these wells had 120-day rates of 755,000 BOEs per day, 50% greater than 42 offset wells completed with lower sand volumes.

Moving to slide seven, we've completed two higher sand volume wells at our Walleye field, a subarea of Cassandra, in Williams County, North Dakota. On average, these wells had 60-day rates of 1,095 BOEs per day, 50% greater than three offset wells completed with lower sand volumes.

Moving to slide eight, we've completed two higher sand volume wells at our Polar field in Williams County, North Dakota. On average, these wells had 60-day rates of 935 BOEs per day, 40% greater than 12 offset wells completed with lower sand volumes.

Moving to slide nine, you can see the strong, enhanced completion results from Pronghorn, Walleye and Polar are outperforming our 700 MBOE-type curve. Moving to 10, in our Redtail field, we continue to expand our Codell/Fort Hays drilling program.

The Razor 11G well at the far north end Razor Township was recently completed in the Codell/Fort Hays formation. Early results have been very strong with recent 24-hour production rates in excess of 460 BOEs per day.

Our Horsetail 30F pad was designed to test a 32-well spacing unit drilling pattern in the Niobrara A, B and C zones. This pad has been on production for approximately 80 days with steadily increasing rates.

Recent performance has been in excess of 500 BOEs per day, per well. Slide 11 shows the infrastructure at Redtail.

Construction at Phase 2 of our Redtail gas plant is nearing completion and the plant should be fully commissioned by the end of August 2015. This will expand the plant inlet capacity from 20 million cubic feet of gas per day currently to 50 million cubic feet per day in Q3, and 70 million cubic feet per day in the first half of 2016.

Mike Stevens, our CFO, will now discuss our financial results in the second quarter of 2015.

On slide number 12, you can see our second quarter 2015 financial results. Our discretionary cash flow in the second quarter totaled $381 million, a 53% increase over the first quarter.

Our unit costs in the second quarter of 2015 have decreased significantly from the second quarter of 2014 due in large part to cost control measures and technology-driven productivity increases. Our DD&A rate per BOE has dropped 23% to $20.81.

LOE per BOE has decreased 22% to $9.25. And G&A per BOE is down 19% to $2.90.

Our guidance for the third quarter and full-year 2015 is detailed on slide number 14. We revised our production guidance to 6.5% year-over-year growth despite our recent asset sales.

I'd like to provide a little more color on our CapEx and production trends. With our drop to an eight-rig program, we project capital expenditures of approximately $300 million in the third quarter and $250 million in the fourth quarter.

In the third quarter, we forecast production of 162,000 BOEs per day, adding back asset sales as it's relatively flat with Q2 production. In the fourth quarter, we project production of approximately 153,000 BOEs per day.

The drop occurs because of the new three-rig drop and because the number of new wells completed does not offset newly completed wells from earlier in the year that are declining off (12:43) production. However, for 2016, assuming an eight-rig program, production should flatten out and average approximately 147,000 BOEs per day with a relatively flat profile.

And as Jim mentioned, if we continue to get results consistent with those in our press release, we believe production could average 150,000 BOEs per day to 155,000 BOEs per day. Our all-in capital budget in 2016 of $1 billion should equal discretionary cash flow at $50 NYMEX oil price.

One other note on our 2016 outlook, some analysts seem to have confused discretionary cash flow with EBITDA and are getting much higher implied 2016 multiples than our guidance suggests. The $1 billion of discretionary cash flow we cite equates to about $1.3 billion of EBITDA.

So on a price to cash flow basis, we are trading at under five times cash flow and on an enterprise value to EBITDA basis around 7.5 times. These are far below the 10 times we have seen in a few notes.

On slide number 15, you can see we maintain a strong balance sheet, with $60 million of cash on hand and nothing drawn on our $4.5 billion credit facility. Slide number 16 shows our outstanding bonds as of June 30, 2015.

It also shows that we are well within all the covenants in our credit agreements and our bond indentures. Slide number 17 shows our crude oil hedge positions as of July 1, 2015.

We recently layered in some additional oil hedges and are now 47% hedged for the second half of 2015 and 40% hedged in 2016. With that, I'll turn the call back over to Jim.

Thanks, Mike. To summarize, in the second quarter, we delivered record production growth even though we sold over 8,300 BOEs per day.

We achieved this while keeping a strong balance sheet with $60 million of cash and an undrawn $4.5 billion borrowing base. We remain committed to our goal of maintaining a strong balance sheet while positioning the company to run well and grow in the $40 to $50 oil price environment.

Chad, please open up the conference call for questions.

Good morning, Jason.

Good morning, Jim. Good morning, everyone.

Jim, I just want to touch on in the press release just to get an update on the non-core asset sale program. I know you guys have talked about that you expect to see more by the end of the year.

And what you've done so far this year has been much more focused on the upstream. So can you maybe just talk about what you're seeing right now, what the priorities are between upstream and midstream and the interest levels?

Well, it's strong in all three cases. So I can only say that whether it's from the production side or on the midstream side or as we've done one or two joint ventures wherein we've basically sold off on a wellbore-only basis some of our non-op drilling.

The interest is all strong, and the multiples we've been getting are good, typically somewhere around 100 months at rate in terms of talking what – times current cash flow is. And then really I haven't seen much in the way of anything but strength in terms of the folks who are interested in talking to us about our midstream.

So essentially, we're just looking for those folks who have – because of – for the most part where they're located already, and where they already operate, whether it be midstream or production, can afford to pay a little more than the average, and we'll close with those between now and year-end.

Got it. Okay.

Thank you. And my follow-up is maybe for Mike.

Just I know you guys added hedges in the quarter, but it also looks like, at least from last quarter, you took out some of your, I think, 2016 swaps. And it looks like – at least I don't see the fixed price differentials in the release as well.

Can you maybe talk about if you guys did anything there?

N. Those fixed price contracts are still out there, the ones at Redtail.

We're just not disclosing them the same way as we used to, but they're still out there. So we're getting $5 to $6 off in NYMEX out of Redtail under those contracts and performing quite well.

And on the swaps, like you get $300,000 a month on 2016, it's no longer there?

Those are just part of our – got restructured into our three-way collars, Jason. That's all.

They're still there. Nothing's been taken off.

Got it. Okay.

Thanks, guys.

Thank you, Jason.

Hi, John.

How are you?

Good.

Good. Jim, just to follow up a little bit on what you mentioned where you said that the current 2016 guidance just sort of gives partial credit for the enhanced completion upside you've all been seeing where you're getting kind of 40%, 50% production improvements.

Can you just maybe give a little bit more detail on how much of that upside you did incorporate in 2016?

I think the best way to talk about that, John, if you don't mind, is just to say that, as usual, we've risked it because it's something we've been doing only in the first half of this year. So we try to give you how much – try to give you an idea basically between the 147,000 BOEs and the 155,000 BOEs we think with the continued results of those types our average for 2016 will be.

So it'll be somewhere in that range. We're pretty early on.

We have risked it fairly hard. I have great confidence, I will say, in our technical team out there that's performing these new completion techniques and to do it at no more than about a 16% increase in cost, 15%, 16%.

Basically, John, our well costs out there, we had it down in the Bakken to about $6.5 million, and we're saying we're going to get it done for $7.5 million, and I'm very confident we can do that. In fact, I think with this recent drop in oil prices again to just below $50, we could see up to another 10% reduction in our completed well cost.

So, optimistic about seeing these improvements in first 12 months of production of 40% to 50%, and the number varies. And I'm optimistic about even keeping our well cost down there around $7 million.

So, I feel very good about what's happening going forward and basically, kicking off growth again once it flattens out here, kicking off growth again with the properties that remain which will be our Niobrara, Bakken and Three Forks properties that have much better margins because they've got LOE roughly half of the properties that we've been selling.

I appreciate that color. And then my one follow-up question would be for Mike.

And you had said that, you gave the CapEx numbers for the third and fourth quarter. And on the last call, you kind of articulated the number of wells you're expecting to complete and it was kind of like 39 net wells in 2Q and then around 24 in the third and fourth quarters.

Can you kind of update where the second half of the year looks for, in terms of a well completion run rate?

Just want to be clear on that, John. Those were just, I think Bakken completions that you're referring to.

Yeah. Exactly, yeah.

Okay. So here's the number.

So, I'll say what we did in the first half. We completed approximately 136 net Bakken wells in the first half and 50 net Niobrara wells in the second half.

We plan to complete 40 to 50 net Bakken wells and 25 net Niobrara wells.

That's great. Thanks a lot, guys.

I appreciate it.

Thank you, John.

Good morning, Neal.

Good morning, guys. Say, Jim, just a couple of things here.

First on – I know you guys have talked always on that East side around the Sanish and Parshall about increasing the wells per spacing unit there. Is there – just what kind of opportunity you'll have in some of that Kodiak property as you look up in the Northwest and even down by Missouri Bricks?

Is there a lot of opportunities later to continue to increase the inventory?

This is Mark Williams. I'll address that.

What we're seeing really is essentially no significant change in the way that we're looking at our – what we call our wine racks, which is our development pattern up there. The big change really is with the enhanced completions, we're pumping a lot more sand and getting a lot higher rates, that's why the increase that you're seeing here in our presentation is going up.

So we just think what's happening there is we're doing a much better job of breaking up the reservoir and accessing a lot more of the reservoir upfront, and that's what's responsible for the increase in rates. So early to say what's – exactly how much the EURs are going to go up, but the critically important part of this whole thing is that our near-term rates are going up quite substantially and contribute to much better cash flow.

Makes a lot of sense. Thanks Mark.

And then just secondly, Jim, you guys commented on, and I would agree with you, it seems like that multiple – some folks have that a bit different than I think what it's trading at. Is it fair to say that in addition to maybe the discretionary capital being different than the EBITDA there's just maybe your – what you could comment about potentially debt coming down, as well your spending, obviously, for next year.

Well, it's definitely part of the plan. There's some opportunity to these that we do see to reduce debt out there, and we have the – assuming the asset sales continue to go as they've been, we'll take advantage of that.

Non-core wise, Jim, is there – how big is that portfolio still left that you see?

Well, again, I've said that we'll sell somewhere between $500 million and $1 billion. We've given that advice.

We've sold $300 million so far. The size that remains is about $1.1 billion, I would say, of potential that's out there.

And so if we sold even half of that, we'd come in at around $800 million.

Makes a lot of sense. Thank you, Jim.

Yep. Thanks.

Yeah. Hey, guys.

You have done a good job on the enhanced completions in the Bakken. Are you all taking any of that, the knowledge you gained there, and trying higher sand content or other things in the Niobrara as well?

Yeah. We're continuing to work on that.

We're a little further ahead on the Bakken, that's for sure. With the results of our 30F pilot that we've just completed here recently, we're taking – we're doing a couple of things there.

Really, we're focusing now on cemented liner completions and increasing our sand volumes a little bit beyond what they have been here over the last eight, nine months. So, the jury is still out on exactly how much is going to affect that.

That's a relatively recent change, but we're anticipating similar results. The early results look pretty good.

I'd just like to add to that, that from a CEO perspective, I'm especially impressed and, I would say, appreciative of the work that our folks have been doing in conjunction with the service companies: Halliburton, Baker, Schlumberger and others. But in particular, those three, they've been very good about keeping our costs down as we increase the size of these fracs, keeping our costs down there to, as I said already, only in the range of around 15%.

And I'm hopeful that we'll see another 10% or so increase since oil prices have dropped again. So, it's important for all of us, I think, to keep the capacity of the industry in terms of people and in terms of equipment and therefore in terms of services going in these lower-price environments.

I'm especially pleased to see what I consider to be a concentration of quality out there in the field that we're getting from our service providers. Very pleased with that.

And put me down on record as saying thanks to those folks.

All right. And just one more.

Looking at, I guess, the suppressed oil price here, are you seeing any kind of bolt-on acreage opportunities in either the Bakken or the Niobrara?

Well, I would say, yes, we are. Whether we act on them or not is another question.

It's always cheaper to just lease than it is to buy from somebody else. So, I do see the opportunity to expand our acreage positions, but I don't think we'll have to pay very much for it as our land department has been pretty adept and adroit at finding ways to pick up leases rather than having to, I'm going to say, buy a company or buy out an LLC or something, that was a special purpose deal backed by certain investors.

We've been pretty good at being able to get out there and pretty much pick – either pick it up on the ground or pick it up from, what I would call, the true locals who owned the acreage for sometimes 20 years or 30 years due to production from different zones.

Thank you.

You're welcome.

Good morning, Jim.

Good morning.

A lot has been asked, but let me make sure I got this – the framework right. Just judging by what you said about CapEx next year and cash flow, is the right way to think about it that for 2016, the toggle is just going to be commodity price and for 2016 you're going to spend somewhere close $60 cash flow vice versa for $45, $50, whatever?

Is that the right way to think about it?

Subject to the bump, Dave, the bump being the bump that we get from getting our capital back faster from these improved completion techniques. Basically, we're talking about getting 50% more production in the first 12 months.

So as we expand the application of that, you can kind of add that 50% bump on top of whatever happens to oil prices.

Okay. Okay.

That makes sense. And then a question for whomever.

Just the DD&A rate, it seems like a lot of companies have bumped their DD&A rate a little higher for the full year and you guys did something similar. Can you talk about the mechanics, why that DD&A rate is going up?

Is that a function of reserves? I'm just curious as to why that's going higher.

It's really more of a function of the higher spend in the second quarter than we had initially anticipated, so the extra dollars are coming in. But the calculation moving forward, always try to be a little conservative, but it does depend on – we have lower CapEx, obviously, forecasted.

And it's a matter of how many reserves we add in particular, proved developed reserves for the remainder of the year. So we did a somewhat conservative projection of that and inched the rate up a little bit for the last half of the year.

Everything we're doing here, Dave, I think, as you are perceiving, is to essentially find more oil at lower cost per BOE. So, with these 50% greater first-year production rates, there's plenty of room there to see increases in EURs per well at these improved economics, i.e., greater rates of production, greater rates of – higher EURs at only, let's say, 10% to 15% higher well cost.

That'll help us bring down our DD&A.

Yeah. Yeah.

That's where I was going with that. I just assumed yourselves and others, right, F&D costs should be going lower rather than higher.

All right. Well, thanks.

Appreciate it.

Thanks. Thank you.

Hey, Scott.

Hey, Jim. Thanks for taking my questions here.

I wanted to kind of, I guess, pursue again the 2016 kind of line of comments. And big picture, obviously, you guys are – take a look at a more conservative oil price at this point in time, which I think is reasonable based on what we see today, but at what point in time do you guys step back and get comfortable with a higher price, let's say – and then I think most people are expecting, analysts at least, at this point something on the average of above $60 a barrel.

From a management team perspective, what do you need to see fundamentally change in the oil price outlook to start adding rigs from your eight-rig program?

Well, first, I'll just comment on timing. The good thing I would say about the way in which we've dealt with our contractors has to do with how quick we can get back some of these rigs if prices do go up.

And I think you can see that every $5 increase in the price of oil is somewhere around $200 million of additional cash flow to us. So what we've done with respect to rigs we've laid down is to have arrangements with those folks as to bring them back first before we would add rigs from other contractors.

And so, some of them who have really still very good equipment that's been working well for us should be able to come back quickly and we should be able to respond very timely. In terms of the part of your question about what do we need to see, frankly, I'd like to see prices come up and stay there for about six months, but I'd probably start to add a few rigs if we saw prices come back and be there for maybe four months, something like that.

And I'm talking about getting back into the $60 or thereabouts range.

Okay. I appreciate that.

And then when you think about – obviously, you've seen well costs improve. Some of it is secular, some of it is cyclical, but does that factor in the equation?

If you can see additional efficiencies that reduce that, is that also an impetus where you guys could be a little bit more active?

Yes. And so that's kind of why I'm saying maybe four months rather than six months.

I think we're going to benefit from that efficiency. One of the things that happens as the business contracts is you obviously do – you're concentrating all of your efforts on a fewer number of rigs, a fewer number of pads.

So we really do get a chance to hone in on efficiencies. And again, I'm very pleased and proud of what our technical team and what our field folks have been doing to reduce our well cost and – very proud.

We've basically taken our Bakken well from $8.5 million down to $6.5 million. And then even with the bigger fracs, I think in total we'll able to get her done for about $7 million by – here within the next 90 days or so.

Great. And one last, if I could squeeze it in, have you all seen a difference in price differentials in the Williston with production of the basin likely starting to – I know it's ebbed and flowed over the last several months that we've seen data on, but have you seen differentials relaxing a little bit to your benefit?

Well, in general, the answer to that is yes. We really haven't reflected it too much in our guidance yet, but there is pressure out there now.

And historically anyway, in round numbers, we've seen $5 differentials rather than $8 and $9 differentials when prices fall in the Williston, and I think we'll get there.

Appreciate that. Thanks, guys.

Thanks.

Good morning, Jim. Thanks for taking my questions.

You're welcome, David.

I know we've talked a lot about seeking to be cash flow neutral next year. We also talked about – if you had unrisked the enhanced completions, you'd end with another several thousand barrels a day of production, so obviously it would add to the cash pile there.

If you also completed some of your non-core asset sales particularly on the midstream side. Now how do you think about adding value for shareholders with that sort of roadmap going forward?

Is it to bring the balance sheet down and contract your debt metrics, or if the benefits of the enhanced completions coupled with some dry powder from pending asset sales, you can look to redeploy capital even in sub-$60 world?

Well, that's a great question, I think. It really defines the three-pronged approach here, reduced cost, being more efficient and effective, and then keeping our debt metrics strong.

So to try to give you some guidance on how we might approach that, I would simply say that – look, the one thing that I know you can do in terms of adding, let's say, net asset value per share is to pay down debt, right? That works no matter what the oil price is.

So, that is important to us, and I would say that you'll see some prioritization of that. On the other hand, as perhaps a secondary, but still very close objective is to grow reserves and production.

And so it really kind of depends upon the total amount of our asset sales. And I think as you and the previous questioner discerned, you have, I might say, the ability to do both if asset sales, let's say, are greater than $800 million.

You follow?

Yes.

Okay. And I think as you've discerned, obviously, selling things like midstream assets, water systems, that type of thing, do not have a downward effect on production.

So those are the things that cause themselves to be prioritized as we look at those objectives of paying down debt and growing them from that then-flattened production level to get it turned around and headed up again and doing so with production that is essentially the most effective and efficient that we can get because it's basically got LOEs per BOE of half of the stuff that we sold.

And I think that color is very helpful for what we can expect as you guys get through this process.

Yeah. Thank you.

My second question would be for Mark. We've seen obviously in the Bakken, and I think Brian asked about enhanced completions in the Nio.

Are there any areas within the Bakken that you're currently testing that we haven't seen results from yet or areas that you would like to test that you feel like would be amenable to the enhanced completions that we should look for over the next six months or so outside of Pronghorn, Walleye, Polar, Sanish, et cetera,?

Sure. Well, I would say this, that while we have good coverage – our acreage really covers pretty much the entire basin, and we are experimenting with enhanced completions virtually everywhere.

We also mentioned here in the call the results that we've gotten from Dunn. We got a little bit later start on Dunn, but the early results are very encouraging there at Dunn.

So I mean, if I were to summarize, I would say that I don't see an area within our acreage that isn't going to benefit very significantly from these enhanced completions and I'll go one step further, there's – we're not the only ones doing those. And if you look broadly across the basin at areas that we currently don't – where we don't have acreage, there were also some pretty good results happening elsewhere.

So even quite a ways over on the west side of the basin towards Montana, there is very good uplift in wells that are being done at higher sand volumes over there as well. So I think it's a relatively global thing.

And certainly in the Bakken, I think the Three Forks is going to benefit as well. We're just getting started really in the Niobrara doing higher sand volumes.

But in general, there's a very strong correlation between higher sand volumes and better early churn performance and we think better EURs as well.

And Mark has done – this is Jim again. Mark has done a great job of staying on top of all of these new completion activities.

And I mean, he actually has data that shows that across this broad spectrum, as he has seen and been able to follow, there's typically up to – there's up to an 80% uplift. The difference – the differentiator for us at Whiting is that Ben, Mark and Rick have taken those approaches and applied them to our sweet spots.

So, what I see when I look at the AFEs we – that, A, we put out and, B, we received is that we were getting those – we are getting good results, having driven our costs down to $6.5 million, comparable to what people were getting when some of them were still spending $8.5 million to $9 million. Now, with this enhanced completion technique, I think our well cost is going to be in the $7 million to $7.5 million range.

But we're going to get the benefit of these 40% to 50% and maybe even in some areas 80% uplifts in the first 12 months' production. So, I think that's the differentiator that we're trying to say that we see here at Whiting is that because we've been able to either lease or buy or merge in, as we did with Kodiak, some of the highest OOIP areas, we think that as we show you in that graph of outperforming the 700 MBOE type curve that we're really getting the biggest bang for the buck.

Jim, Mark, thanks for the answers. I appreciate it.

Thank you.

You're welcome.

Good morning, guys. Thanks for taking my question.

Just trying to get into management and the board's thinking of what changed in the last two weeks from the budget of – I guess, two weeks ago, Friday, to today, first?

Well, essentially, we were thinking about reducing it somewhat lower anyway. We hadn't had the board meeting yet, so essentially the decision was made at the board meeting.

Okay. And then, as you think about just the capital efficiency on the first $1 billion of capital versus each incremental $100 million, adding 4,000 barrels a day or 5,000 barrels a day, is there any dramatic difference between that first $1 billion and the next $500 million, or how should we think about that?

Well, I'll tell you how we think about it here is that as we become more efficient and more effective, we hope to continue to improve the efficiency as we go forward by realizing these additional cost reductions. We can do a lot of that by scheduling.

We can do a lot of that by who we work with, meaning, which one of the service companies we work with, and they're willing to adjust price based upon the volume of work they receive. So we actually hope that as we go forward that if you were – you kind of talked about $400 million increments there, you hope you're doing even – coming even more efficient on the fourth $100 million that you invest than you did on the first $100 million.

I guess maybe another way, for $1 billion of capital, do you add 40,000 barrels to 50,000 barrels of production in just rough numbers?

Yeah, I think so. And I think that as we are more efficient, hopefully we'll get a little uplift on that range.

I mean, David, I know you're trying to ask the question, but you know that it's not exactly linear relationship. You know that if we were to add another $1 billion quickly, that we'd be fighting higher declines.

So, it's not going to be an exact linear relationship, you're aware of that. But roughly, if we're going from $1 billion to $1.5 billion or something like that.

Yeah. It's going to be a fairly linear relationship.

But (46:11) at $1 billion quickly, we're obviously going to have higher decline rate wells, so it may not work out exactly that way.

I'm thinking about the incremental 3,000 barrels to 8,000 barrels a day for the enhanced completions and kind of that implication of what that does to your capital efficiency. Just trying to – it's really where I'm aiming.

So, we can talk about it offline, Eric, but...

Yeah. Why don't we talk about it offline.

I think it's a pretty hypothetical question and I can't go into great detail on it here.

Thanks, David.

Hi, Brian.

Good morning, guys. I have a couple quick questions.

It seems that mix of Niobrara and the Bakken completions in the second half of this year is going a little bit heavier towards the Niobrara side. Is there any particular reason for that?

No. It's just that we cut – three rigs we cut were in the Bakken.

And so, we maintained the two there in the Niobrara.

Okay. And then, one other one and maybe it's too soon to go into detail.

But is there any chance you could quantify the bump that you mentioned for the enhanced completions in terms of EUR potential upside off of that 700,000 barrels that you've shown on the curves?

Yeah. Sure.

Certainly, that's what we're focused on. I can tell you that everybody from me to our board, to Mark, Rick, Steve, everyone here, and frankly the folks in our completion team and our reservoir engineering team are watching that very closely.

And at this point, the only thing I can tell you is that there's plenty of room there, what with that 50% – let's call it 40%, 50% increase in first-year production to see a nice increase in EUR. I'm not prepared to quantify that for you yet, but what we're going to do is make sure that from – you're familiar with our wine racks.

You're familiar with the fact that we had some little white spots in there so that in certain areas where porosity and permeability, Mother Nature is sort of good there already. So we might drill some of those wells a little further apart.

We're going to be very, I think, astute in the application of these new completion techniques, so we do get a nice lift in EUR and we don't over-drill. So we maximize the rate of return, maximize the efficiency of that capital that we're putting out there.

So, we're looking for that lift above the 15% increase in well cost to 40% to 50% increase in the first year of production and obviously a nice increase in EUR. I just don't want to give you the number on that yet because, to be honest, we haven't honed in on it ourselves.

We'd like to have at least another six months of production. But right now, it's – the initial results are very good – very good and very encouraging.

Fair enough. Thank you very much for taking my questions.

You're welcome. Thank you.

Hey, guys. Thanks for taking the question.

Sure, James.

I just wanted to zero in a little bit on the second half of the year here. Obviously, you guys are looking at a pretty significant rate of activity decline.

I just wanted to get a little color from you if there's anything out there in the field that's preventing you both – well, I mean, I guess, both in the second quarter, but also looking into the next two, from decelerating as fast as you would like or as you had originally planned. And then kind of in connection to that or connected to that, I think you guys gave a nice piece of guidance for Q3, Q4 in terms of what the CapEx numbers that you're expecting there – $300 million and $250 million I think it was for Q4.

I'm assuming those are accrual numbers and that the cash numbers are going to be higher as you work down your working capital liability. Is there any sense – I'm just trying to – what I'm trying to zero in on is the cash burn in the second half of the year and where you'll be when you approach this kind of plateau level if we are in a longer lower environment.

So a bunch of things in there, but if you could speak to some of those.

Okay. So, Jim will handle the first part; Mike will handle the second part.

The first part of your question being, I believe, are there impediments out there to slowing down in the second half of the year, and the answer to that is no. I'm not aware of anything at this time that would impede our reduction.

And I mentioned earlier in this call that we did a nice deal with a party that took on some of our non-op drilling, which we view as not as quite as effective and efficient as we are being. I suppose every oil company CEO thinks that.

But at any rate, that's the way I view it and that's the way I reacted when an opportunity came up to allow somebody else to take on, on a wellbore-only basis, some of our non-op drilling such that they paid us a fee, a nice cash fee, equal to around 10% of the estimated completed well cost. And then, we were able to get an overriding royalty equal to the difference between 75% and whatever royalty we were enjoying.

So, let's say, for example, it was a 80% net lease and we delivered a 75%, then it was a proportionately reduced 5% overriding royalty interest. So, we have the ability to do that in the remainder of the year, and therefore, that allows us to really control and minimize the amount of non-op CapEx that we have.

And therefore, we can better plan our own CapEx, you follow me, our total CapEx, which is basically then – are dependent upon our rig count and how effective and efficient we are in drilling. And I feel very confident about that aspect.

So, I tried to kind of give you some color as to why I don't see any impediments there. And now I'll turn it over to Mike to answer your questions about the second part.

You're right that the $300 million and $250 million are accrual-basis numbers, but you'll probably also note on our balance sheet how far that accrual for capital expenses has come down, down from $430 million to $190 million. So that $240 million is kind of already flushed through as far as uses of cash, and $190 million accrual probably come down around to $120 million by year-end, which approximately it's about a 30-day lag on pay and invoices.

So there's about another $60 million yet in terms of cash usage there. Of course, we have $60 million in cash on hand, so I still think we end the year with nothing drawn on our credit facility and our CapEx rate way down to $250 million a quarter, which, in the fourth quarter, is a $1 billion annual run rate where we got 2016 at.

Okay. That's great.

Thanks, guys. I appreciate it.

And so just to clarify since I assume this is kind of what you're pointing out with the last piece, the hunker down scenario that you guys are describing of spending $1 billion and generating $1 billion in the mid-140s for volume at 50%/30% for the deck, that is pretty much assuming the same rig count that you guys have now and a kind of rated drilled and completion number that – right about what you'd expect in Q4. Is that what I'm hearing from you?

Yeah. Good point.

Yeah. Good point.

Its eight rigs.

Perfect. Great.

All right. Thanks a lot, guys.

Six and two. Six and two.

Six in Williston, two in the Niobrara.

Perfect. Thanks a lot, guys.

Good morning, everyone. I just want to clarify what you said, Jim, on the asset sales for the midstream.

Were you saying midstream asset sales to close by year-end, at least as part of that asset sale package?

Yeah. I think I just heard the last end of that question; it kind of broke up a little bit on my end, but I think you're asking me, did we – do we expect to have midstream sales around the – in the second half?

Is that...?

That's right, Jim. Yeah.

...Correctly? Okay.

Thank you. Yeah.

The answer is yes. If we have midstream sales, that's when we'll have them.

And some of this is dependent upon – I mean, the market out there continues to be strong for midstream assets and some of this has mostly to do with when people are ready to buy. When they want (55:33).

Do you mean you're sensing increased hesitancy or less enthusiasm to buy right now?

No. I'm sensing more interest.

Okay.

A greater number of people. And as I've said early on, separating those who are active in a particular area, they seem to be the ones who are distinguishing themselves in terms of what they are willing to pay from others.

And that – so when you narrow that down, for those that are pretty active in the area, then some of them are in the mid – have closed transactions and want to close, let's say, I'll pick a date, somebody might want to close in October, some deals might want to close in December or January. That's the only difference I'm seeing right now.

Okay. And somewhat unrelated – I'm sorry, do you have something else, Jim?

No.

On a somewhat unrelated topic. If we go forward and we actually have this oil price environment in which you're kind of – you're thinking about the $40, $50 of oil in the next couple of years, how do you think about spending on a philosophical basis, meaning, are you thinking you'd be spending within cash flow, still if we roll into 2017, you're still in that price environment or trying to hold production flatter?

How do you think about it?

Yeah. We already answered that, Mr.

Venker. We said we'd be spending close to cash flow, and we think we'll start growing even at $50 as we head into 2017.

Okay. And with the pullback in pricing, do have you any different messaging from your service providers that they'd be – want to take additional concessions to keep your business?

Well, the pullback in prices really only occurred over the past few weeks from the past month from $60 to $50. So, I don't think we've had those discussions yet.

Rick, anything to add to that?

No, I agree. We hope to see some concessions in this lower price environment, but it needs to work through.

It can take time.

It takes a little while. We're hoping for another 10% or so.

That's basically what we think. And for and in consideration to that, we're willing to concentrate our business in the hands of the few who are, A, doing a good job for us now; and, B, willing to give us those concessions in order to get the greater volume of work.

Thanks.

That formula has worked for us in the past. Frankly, it's worked for this company with those companies since 1983.

Thanks for the color, Jim.

You're welcome.

Thanks, Drew.

Well, thank you very much, Chad. Again, I'd like to emphasize that Whiting is taking strong measures to preserve our solid financial position while realizing the full potential of our asset base.

With the recent decline in commodity prices, we've elected to drop three additional rigs in the second half of the year and run an eight-rig program in the second half of the year, and we anticipate that eight-rig program into 2016. In 2016, at a $50 NYMEX oil price, our capital budget and cash flow should be approximately equal and relatively flat with Q4 2015.

Our 2016 guidance for 147,000 BOEs per day gives us only partial credit for our enhanced completions. And if we continue to get good results consistent with the examples highlighted in our press release, we do believe production could be higher, perhaps in the 150,000-BOE to 155,000-BOE-per-day range.

And our budget is flexible. If oil prices are higher than anticipated later this year, we can ramp up and deliver even greater growth.

So, in summary, our plan, going forward, is to operate within cash flow, have property sales of our properties that had higher LOE in the range of $20 to $25 per barrel LOE, and drill new properties with LOE of half that, so that our margin improves no matter what the oil price or at whatever oil price you want to assume. Then, growing production and reserves from the lower base by getting 40% to 50% increases in the first 12 months' production and by keeping well costs within only about 15% greater than we had driven the cost down to, i.e., approximately $6.5 million.

And therefore, keeping it in the $7 million to $7.5 million while realizing those uplifts in production and EUR. So, with that, I would like to thank all of the Whiting employees and directors for their contributions to a solid quarter.

Eric?

Jim Volker will be presenting at EnerCom, the Energy Conference in Denver on August 17 and Jim will also be presenting at the Barclays CEO Conference in New York City, the week of September 7 and at IPAA's OGIS West Conference in San Francisco, the week of October 5. And Mark Williams will participate in the Heikkinen Energy Conference in Houston on August 26.

So, thanks to all of you for your interest in Whiting Petroleum Corporation. We look forward to meeting with you soon.

Goodbye.