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

John A. Freeman - Raymond James & Associates, Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Brian M. Corales - Scotia Howard Weil David A. Deckelbaum - KeyBanc Capital Markets, Inc. David R. Tameron - Wells Fargo Securities LLC Michael Scialla - Stifel, Nicolaus & Co., Inc. Jason A. Wangler - Wunderlich Securities, Inc.

Jason Smith - Bank of America Merrill Lynch Jeffrey Robertson - Barclays Capital, Inc. Stephen F. Berman - Canaccord Genuity, Inc. Jeanine Wai - Citigroup Global Markets, Inc. (Broker) Michael A. Glick - JPMorgan Securities LLC Michael A. Hall - Heikkinen Energy Advisors LLC.

Good morning. My name is Mia, and I'll be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation second 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. I will now turn the call over to Eric Hagen, the company's Vice President of Investor Relations..

Thank you, Mia. Good morning, and welcome to Whiting Petroleum Corporation's second quarter 2016 earnings conference call. On the call for Whiting for this morning is the Whiting management team. During this call, we'll review our results for the second quarter of 2016 and then discuss the outlook for the third 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 1 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 June 30, 2016, is expected to be filed later today. And with that, I'll turn the call over to Jim Volker..

Good morning, and thank you for joining us, everyone. We'll get to your questions as quickly as possible after we make a few further comments to help you with your way through our press release and our subsequent 10-Q. Let's begin on slide 2. Second quarter CapEx came in at $79.4 million.

That's a 70% improvement, meaning reduction, from the first quarter. Discretionary cash flow was $151.6 million. Therefore, it exceeded CapEx by $72.2 million despite NYMEX oil price averaging $45 for the quarter.

Production averaged 134,245 BOEs per day in the second quarter despite some frac protect operations on our participation agreement well completions.

As we begin to see the benefit of these new completions, we expect to see Q3 and Q4 production flatten to approximately 115,000 BOEs a day after adjustment, meaning reduction, for the North Ward Estes sale, while spending only about $100 million per quarter in the third and fourth quarter of 2016.

Since the beginning of the year, we have exchanged $1.6 billion of notes for new mandatory convertible notes and, as a result, decreased debt to date by $810 million as of July 27, 2016. Also, on July 27, we closed the sale of our North Ward Estes property for $300 million and a $100 million potential contingency payment.

This further enhances our financial flexibility. Our Williston Basin enhanced completion technique continues to perform well, and our wells are tracking at 900,000 barrels of oil equivalent per well type curve after 200 days. This underscores the high quality of Whiting acreage.

Whiting is adding 16 Williston Basin completions in the second half of 2016. The addition of these DUC wells should lead to a highly capital-efficient production profile. On slide number 3, 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 strongly positioned from a liquidity and debt maturity perspective to deal with lower oil prices. With the focus on the Bakken and the Niobrara, as you can see in slide number 4, total net production was 134,245 BOEs per day in the second quarter.

As you can see on slide number 4, 93% of our total production in the second quarter came from our Rocky Mountain region. And at 114,435 BOEs per day, the Bakken/Three Forks represent 85% of our total production.

On slide number 5, we provide an overview of the Williston Basin, where we control approximately 444,000 net acres, of which 99% is held by production. We control the sweet spots of the Bakken in the Williston Basin, and we continue to increase productivity with new completion technology.

Moving to slide number 6, you can see that 92% of potential drilling locations are located in core areas. Slide number 7 updates the performance of all of our enhanced completion wells completed since the beginning of 2015 that have at least 200 days of production.

This data, covering a broad sample of 50 wells, continues to track a 900 MBOE EUR type curve. We believe it is representative of our core acreage with wells spanning the core counties.

This demonstrates the quality of our acreage over a broad area and the quality of our people who are using the newest technologies to maximize the productivity of our assets for our shareholders. Slide number 8 shows that we are the top performer in the Bakken.

Our 90-day average rate for wells completed between June of 2015 and May of 2016 is 972 BOEs per day. This is based on a truly representative sample of 45 wells that span our acreage position. On slide number 9, you can see that we have driven spud-to-spud drill times down 56% from 39 days in 2012 to only 17 days in 2016.

Slide number 10 shows our second quarter gas capture rate in the Williston Basin was 94%. That's a 5% increase from the first quarter, and it's currently 14% better than the North Dakota capture requirement of 80%. Slide number 11 depicts our Redtail field.

We brought on a 16-well pad at the end of the quarter, and production from this pad continues to ramp up in line with our projections. On slide number 12, you'll see that we have driven drill times down 57% in our Redtail field to only about seven days.

I'll turn the call over now to Mike Stevens, our CFO, to discuss our financial results in the second quarter of 2016..

On slide number 13, you can see our second quarter 2016 financial results. Our discretionary cash flow for the quarter was $151.6 million. On slide number 14, you can see the actions we have taken to reduce debt.

Starting from a base of $5.65 billion, which consisted of $4.65 billion of bonds and $1 billion of bank debt, we have constructed a plan to reduce our debt to $3.78 billion as the $300 million of proceeds from the North Ward Estes sale were used to pay down our bank debt yesterday.

Our guidance for the third quarter and full year 2016 is detailed on slide number 15. Our cash costs for LOE and G&A in the second quarter decreased $20 million from the first quarter, which is reflected in this new guidance. Slide number 16 shows our crude oil hedge position as of July 1.

We're 58% hedged for the remainder of 2016 and 26% hedged now for 2017. With that, I'll turn the call back to Jim..

Ladies and gentlemen, since the beginning of the year, we have significantly enhanced our balance sheet through debt exchanges and asset sales. We have enhanced our capital productivity through advantageous cost sharing, well participation agreements, and by accumulating a robust DUC inventory.

We're taking deliberate steps to position ourselves for a recovery in oil prices by increasing activity in the Williston Basin through these participation agreements and DUC completions. In summary, Whiting is well-positioned with a premier asset base, a strong hedge position, an enhanced balance sheet, and a highly efficient capital plan.

Mia, please open up the conference call for questions..

We will now begin the question and answer session. At this time, we will pause momentarily to assemble our roster. The first question is from the line of John Freeman of Raymond James. Please go ahead..

Hi, John..

Hi, guys. My first question, when you – you mentioned that 16-well pad in Redtail came on at the end of second quarter, so I'm assuming not a meaningful kind of impact for production for the quarter.

The original guidance, was that supposed to come on a little bit sooner?.

Yes, slightly..

Okay. And then on the Redtail DUCs, that went up for year-end from roughly 100 previously to 117 now.

Is that just simply a function that, as you demonstrated, you're just drilling these wells a lot quicker?.

Correct..

Is there anything else going on?.

No, sir..

Okay.

And then is the way that you've talked in kind of the past quarters about – when we think about those DUCs, is it still basically, we get like a $50 oil price for some amount of time, maybe a month or so that that's sort of the – when you would think about starting to draw those down?.

Yes..

Okay. And then just the last one for me, if I could sneak one more in.

Could we get the average conversion price on the debt exchanges up to this point?.

Yes, Mike will give it to you right now..

Thank you..

Sure. The second debt exchange – we converted $333 million after the end of the quarter, and that was at an average price of just over $10, $10.05, so we issued 33.2 million shares..

Got it..

Thanks, John..

Excellent. Thanks, guys..

Thank you..

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

Good morning, Jim..

Good morning..

Jim, it looks to me like just kind of looking now at the enhanced completions and everything you now – you have going on with the improved balance sheet that obviously Mike talked about. Around $50 oil, it looks to me like you guys are pretty close to a free cash flow.

I guess, number one, any color you can add if – when you talk about where you guys are thinking about spend versus your cash flow.

And then number two, looking at sort of prices for next year, is that what's going to dictate activity, or are there certainly many other factors involved?.

I think you've hit on the head. Yeah, it's price-related, predominantly. And as we begin to see the benefit of the new completions, as we've said, we expect to see Q3 and Q4 production flatten.

And after you adjust for the North Ward Estes sale and then begin to rise, assuming our production projections are accurate here as we complete those wells and bring them on in the first half and basically see the best of those results in the second half of 2017. So all we really want to do is watch that oil price.

If it stays up there, let's say, for a quarter or two at $50 or better, why, yes, we'll be back at it. And in my opinion, by the time we get to the end of 2017, again, kind of growing at our historic double-digit rates..

Got it. And then, Jim, you have such a massive inventory out there right now in both obviously the Williston and the Nio.

How do you think about where you added the new participation agreement in Pronghorn? Kind of going forward, how do you think – is it more just based on a return basis, whether you bring out another one of those? I mean, again, it's a nice sort of question to have, given the amount of locations you have.

But I'm just wanting to know how you guys think about when you brought on that second one versus potentially bringing on others?.

Yes. Well, we do think about that in a rate-of-return basis. Another quick way to kind of think about it is how does it affect our metrics, our F&D per BOE, our LOE per BOE, et cetera.

And so, if we're in there cost sharing with someone in the range of – where they pay 65% in order to earn 50%, it helps make our metrics, in my opinion, over time an industry leader. So I do think positively about that because, as you said, we have 5,000 to 6,000 locations in our two core areas.

I think that's one of the very biggest assets of the company. And we can accelerate the development of that at the very best metrics, I think, in the industry for those areas simply by doing some more of these JVs. We happen to have good partner in those JVs. And we're thinking about that all the time.

Should we drill with our own money or should we, as we're doing now, do some of each?.

Makes sense..

So I would think that you can kind of count on us going forward doing some of each. But, as prices rise, we would do a little less of the – we'd do less of the JV. And eventually as oil prices, I would say, get closer to $60, I'm not sure we would be doing any..

And then lastly, Jim, how do you guys think about – you have certainly, besides all these new potential locations out there, a lot of existing locations for potential recompletes.

How do you and Mark and the guys today think about sort of the economics or the incremental cost of adding those versus the obviously the new drills?.

Well, I'll let Mark chime in on this. I would simply say that, while it's true that if you look at some cost on and sort of ignore some cost on a DUC, why, obviously those have some of the best economics, I would say going forward in the year to come, meaning 2017, as we take advantage of those DUCs.

And they have obviously quick production response because you don't have the drilling time.

On the other hand, I would say that we, for our capital, tend to think pretty much that you want to be doing 3:1 or better on your money, and in my opinion, once we get a little bit above $50 a barrel that our new reduced drilling and completion costs we're – both in the Bakken and in the Niobrara, we're doing that 3:1 with our own capital.

So, I sort of think of the joint ventures as being an accelerator, if you follow me, beyond that, something that will help us accelerate the development, make production grow faster, improve our metrics. And so, again, I would say below $60, you'll probably see us trying to do some of these JVs because we have such a large acreage position.

Above that, maybe not so much..

Thanks so much, Jim..

You're welcome. Thanks, Neal..

Next question is from Brian Corales with Howard Weil. Please go ahead..

Hi, Brian..

Good morning, Jim. You had good color on the JV talk in the Bakken and with completing on your own with the JV.

Would you assume the same thing in the Niobrara?.

Yes..

Is this the same consideration? Okay.

Has there been interest from other parties for having a JV in the Niobrara?.

Absolutely, yes..

Okay. And then one more. You all have done a great job improving the balance sheet.

Are you all happy where that sits now? Would you consider more debt swaps, or is it now just asset sales and let's accelerate activity or look to accelerate activity?.

Okay. That's a fair question. I have to give you what I would say is the appropriate answer here, which is that we don't comment on capital going forward, capital potential transactions.

But I want to try to be helpful to you here so you can sort of get our thinking, if you don't mind, which is that I think if you – maybe one simple way to think about this is that if you kind of think that somewhere in that $70 range, and I'll say $65 to $75, and we thought that, if you think of that as the $65 to $75 as at least historically a reasonable range, then at $45 oil, right, that's about $40.

That's about 64% of a $70 number. $45 is about 64% of a $70 number. And so your debt ought to be down there somewhere in that range. And if you look at Mike's plan on slide 14, that's about where we come out. $3.78 billion versus the $5.65 billion is about 66%. So I'm not certainly ruling out any other moves to reduce debt. I'm all in favor of that.

But I think we can do some of that internally without having to turn necessarily to the capital markets unless, well, things improve..

That's helpful. Thank you..

You're welcome..

Next question comes from David Deckelbaum with KeyBanc. Please go ahead..

Hi, David..

Hi. Morning, Jim..

Morning..

Just wondering. A lot of good questions have been asked, but did want to get an update on some of the other things that you're still working on. I mean, I know you guys have been working on a North Ward Estes sale for a while, and your success on kind of putting together a clawback there should we see higher oil prices.

Are you starting to see, I guess more as you consider noncore asset sales, more willingness to kind of leave some upside to the seller there? And what other assets are you working on right now that you could update us on?.

Well, you moved that second part of the question in there pretty well, so I'll try to respond to both parts of it. Yes, I would say that we are seeing strong interest in our noncore assets. Obviously, we've talked about North Ward Estes, and that's been accomplished now.

By the way, my hat's off here to our team, including our land department, our acquisition and divestiture department, our people in that field and who work in that field both in our office right there in Wickett, Texas, as well as Midland, Texas, for making that field an attractive asset even at these prices and having some upside.

So really that asset, like the other assets we've sold, is one that had higher LOE per BOE. So that's really all that's happening there, and we're trying to concentrate on the Bakken and the Niobrara, where we have lower LOE per BOE so that our metrics can continue to improve.

Good asset, but a little bit higher operating expense per BOE than we want to have in the mix right now. So my hat's off. I think we got a good price. I think the buyer got a fair deal, and we're going to do everything we can there during the transition services agreement to make that field continue to perform.

So then moving on to the second part of your question. Yes, I do see people who are willing to give some upside away in order to be able to make an acquisition. And then with respect to the other types of assets, yes, the plants are things that people come to us on. I don't want to comment on a process or anything like that.

We tend to do these ourselves without involving what you and I typically think about as a process run by an investment banker. We like to be able to negotiate and get what we think are essentially as-is, where-is purchase-and-sale agreements. So we don't have to take on longer-term liabilities or have anything that sticks to us after the sale.

We also like to have what we think are good, fair purchase prices and things that – and then with respect to our plants, agreements that are positive for us as we go forward and continue to use those, because we, like all the rest of the producers who are producing into these plants, we have acreage dedications and/or time-period dedications of our productions into those facilities.

So that's kind of the factors that we consider.

And all I can tell you is if we get what we think is an offer that distinguishes itself from the crowd and has perhaps even more importantly than being an absolute top-dollar offer is with some good, professional organization that's what I would say is serious in the case of the plants, midstream organization, yeah, then, sure, we would seriously consider selling those.

I will also say that, with my deal-maker hat on here, I guess I would say that right now, since we've gone back to all of the producers that produce into our Robinson Lake plant and our Belfield plant and renegotiated the contracts there from percent of proceeds to a combination of fixed and flat fee of basically $1.55 to $1.65, depending upon whether the producer brings their gas to us at some central delivery point or not or whether we go out to hook them up – that's basically what that dime represents – to close to $2 over at Belfield.

The plants are very profitable at today's volumes and today's prices. So Whiting and its partners want to make sure that if we do sell – I'm going to say we're under no pressure to sell because it's a good asset to hang on to because it's a good cash flower in and of itself.

So I suppose you can look at that as positioning with potential buyers, but that's exactly the way we and our partners think about those assets. We're just as – pretty much just as happy to keep them as we are to sell them.

If we sell them, we want them to be to somebody who is a good, professional midstream company and who understands that relationship that has to be there between the producers and the midstream company. Sorry for the long-winded answer, but I was trying to give you -.

No, I appreciate all the color, yeah..

Thanks..

No, it's all helpful. If I could just ask one more, the second well participation agreement obviously is a little different than the first in that you're activating a rig.

Should we think when these participation agreements end in 2017, are there any options to extend these on the part of the participant?.

No, no -.

I would assume that on your end. Yeah, good..

Yeah, nothing written there. But they're interested. They're interested in continuing to drill. And I won't belabor what I said before or repeat it, but there's good reason to continue to do it. We do have a good partner there, and – with respect to both of those transactions.

And so, for all the reasons that I mentioned before, it merits a good, strong look. It really is, as I tried to explain before, oil price-dependent as to how much more of that we will do. Nevertheless, to underscore again, it's a good way to grow production at a cost-enhanced method..

Appreciate the answers, Jim. That's all from me..

You're welcome. You're welcome..

Next question comes from David Tameron of Wells Fargo Securities. Please go ahead..

Morning, Jim..

Hey, David..

A couple questions. If I just think about – and you sort of mentioned this, but if – that you'd be growing, I think you said, back to your historical double-digit rate by the end of 2017, and that if we're in the $50-type world.

One, did I hear that right? And, two, is that – if I think about think about third quarter and fourth quarter, are you kind of stabilizing production and setting up for that ramp headed into 2017? Is that the right way to think about it?.

Yes. And I think you did state it correctly that we'd hope to be – assuming, basically, I'll say $55, then I think we can get back to that kind of rate by the time we get out there in the second half to the end of 2017. I think you said it exactly correct..

Okay. And then one quasi-modeling question, I don't know if you can give me detail here or not. But I'm just trying to figure out with the participation plans, and I know on slide 5 – I think it's slide 5 – you talked about completing 60 gross wells and then 22 DUCs that you're going to have at the end of the year.

How should we think about second-half activity in the Bakken as far as with all the participation plans and the DUCs, and how do we think about that number?.

Okay..

Thanks..

Hi. This is Rick Ross. So, for the first JV that you talked about, we've completed eight wells so far. We'll complete another 13 in September. And so we'll have 21 of those done by the end of September, and that one actually carries over a little bit into next year in terms of completions..

Okay..

Timing for the second JV is – four of those wells in the JV are DUCs, and they'll be completed in September. The third drilling rig doesn't come up until October. So the remaining 26 wells will be completed throughout 2017. So hopefully that gives you a little idea on timing..

Yeah, that's helpful. And just one clarification.

So everything you're drilling out there up is under the participation agreements; is that accurate?.

Currently..

Okay. All right. That's all I got. Thanks. Thanks, Jim..

Thanks, Dave..

Thanks, Rick..

Next question comes from Mike Scialla with Stifel. Please go ahead..

Yeah, good morning, Jim..

Hi, Mike..

You gave a lot of good detail on the gas plants. I just wanted to follow up on one question there. Curious as to what the current throughput capacity or throughput is versus capacity and how much third-party gas is going through those.

And have you seen any uptick there in third-party volumes as oil prices moved up to the $50 range – and realize they're back down to $40, but wondering if you saw any increase in activity from third parties there?.

Well, I'll answer that latter part, and then I'll turn it over to Rick for the capacity questions. Yes, we saw pretty quickly around a 15%, 16% increase here recently. And there's still some DUC completion activity going on out there with respect to Robinson Lake. And so the current volumes at Robinson Lake are right around 120 million a day.

It fluctuates between about 117 million and about 120 million a day. And then close to 20 million a day at Belfield. So I think you probably understand that this JV will enhance the amount of gas going to – roughly, pretty quickly another 10 million a day going into Belfield there. So it really does, to be honest, enhance the value of the plants..

And where are you relative to the capacity?.

So Rick will answer that..

Yeah. At Robinson Lake, as Jim said, we're moving 118 million to about 120 million, and capacity on that plant is 130 million cubic feet a day. We've actually seen that increase over time, over the last quarter, to our current rate. So that's a positive.

And then capacity at Belfield is – I think, with compression, we can get up to about 50 million a day. So we've got plenty of capacity there..

Yeah, that was 5-0. So doing about – as we talk to you here today, doing about 120 million, 118 million to 120 million, at Robinson Lake. And without doing anything to the plant at all, we can get that up to 130 million, 135 million. No problem. And then at Belfield, we're at – we're actually close to 22 million today as we're talking.

And then we'll have the joint venture coming in there for about another pretty typical 10 million a day. But that one's good all the way up to 50 million. 5-0 million a day..

So I guess if you were to look at the optimum time to consider selling them, sounds like Robinson Lake is – you're getting pretty close to – or you are pretty close to capacity where you'd hopefully get close to full value for that. Maybe Belfield, you'd want to wait.

Is that a fair way to look at that?.

Well, the short answer is yes because of the facts that you've cited. The longer answer, Mike, is that for modest amounts invested in rental compressors or even compressors that we own, we can kick that capacity up if the volumes become available to us.

So there are folks out there who are connected to Robinson Lake, and if they're listening on this call, come and talk to us with your extra volumes. We'd love to have them. And there'll be no problem to get your gas into the plant..

It's good for them to know. Wanted to ask on the enhanced completions, getting some very good results over, and looks like over a very broad area. Does that include – obviously, it's Bakken.

Does that include the Three Forks as well, and if so does that open up any opportunities for – I know there was a lot of talk at one point about some of the other benches within the Three Forks.

Would that potentially open up some additional potential for those benches as well?.

This is Mark. Yeah, the Three Forks has been an integral part of our completion program and especially an essential part of the basin. We're doing almost an equal number of Three Forks wells to what we are Bakken wells.

As far as deeper benches of the Three Forks, they're in the very core, very central part of the basin, the deepest and hottest part of the basin. There is second bench potential. It's a relatively limited area, but we do have some of that in our Tarpon project. And so we are completing a few wells there in the second bench. But it's pretty limited.

That area extends also a little bit to the east, maybe over into the very westernmost part of the Sanish. But the first bench is fairly pervasive. And so that is, as I mentioned, an integral part of our program..

Great. Thank you..

Thank you..

Next question is from Jason Wangler with Wunderlich. Please go ahead..

Hey. Good morning..

Good morning..

Just had one quick one. I noticed, I think in the first quarter, we talked a lot about of non-operated activity, and it looked like from the release the second quarter really didn't see any.

Just curious how you're seeing that kind of flow as we've kind of seen a little bit more strength in pricing of late and if you have much expected for the rest of this year..

The short answer is not much expected for the rest of this year.

I would say that our land department here has done a stellar job of consolidating our acreage position so that we basically swap net acre for net acre with some of the operators when we have a non-operated interest, and they have a non-operated interest in a well that we want to drill where we're the operator.

So that's reduced the amount of non-operated drilling. There's also been some situations where we've had non-operated drilling proposed to us. We think it may not be in quite as good an area as what we are drilling in.

And so, in those instances, we made some deals with third parties who essentially come in, acquire a wellbore interest, our interest, and typically pay us a fee over and above the AFE cost for our non-operated working interest. And from time to time, I've noticed our land department does scrape off a little override for us as well.

So that works pretty good. And that's the other reason why our non-op drilling is down..

Great. Thanks, Jim. I'll turn it back..

Yes. Thanks..

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

Hey. Good morning, everyone. Good morning, Jim..

Morning, Jason..

So, Jim, I just had a higher-level question.

I know it's a smaller part of your asset base, but just any thoughts you have on what you're hearing regarding the Colorado ballot initiatives with the signature deadline coming up in the next few weeks?.

Well, of course we hope that the people who proposed some of the initiatives don't get the number of ballot signatures that are necessary.

The industry has done a good job, I think, of having television ads out there, especially during the dinner hour and the news hour, that explain why these would not be a very good idea for the Colorado economy or, for that matter, the environment.

And so, at this point, we're cautiously optimistic that either, A, they won't make it; or B, they'll be defeated.

And then we have our own initiative, I would say, industry does, out there, not just the oil and gas industry, but industry in general has its own ballot initiative out there, which basically requires that for there to be ballot initiatives, you have to get 2% of all the voters in every county in the state.

So that would be a higher bar to make sure that the Colorado voters are not troubled and bothered with all these ballot initiatives, which essentially are an attempt to change the constitution of the state of Colorado for things that really ought to be handled on a regulatory basis and/or through the legislature.

And so the reason that these things are coming up as ballot initiatives is that there's not the desire in the legislature for these things to be done. And so it's an end run. It's really a thwarting of the structure of both the House, the Senate, and the governor. It's a way around their wishes, really, when you think about it.

So we're cautiously optimistic that really none of that's going to happen.

And, in the meantime, I would say that if you look across the industry in Colorado, every company that I know of – and Whiting's at the forefront, I think – is doing their very best to be exceptionally clean operators, and that means everything from making sure that your lines, your tanks are all buttoned up, so you're not having emissions out of those, and that you're doing these new green completions, which we're doing out there at Redtail today, where we're basically – when we begin flowback after frac, you're flowing those into closed vessels.

And so I really think it's a very sanitary approach to producing oil and gas in the state.

I think it's something that's really good, as a matter of fact, for not only the environment but some other parts of the industry in Colorado like manufacturing, people who make tanks and other equipment, that we'll need more of as we become greener and greener. Thanks for your question..

Thanks, Jim. Just one quick follow-up just on the quarter itself. The oil realizations themselves looked like they were a little bit wider than you guys had guided to.

Was there any specific that was driving that?.

There was one item that had a little bit of dollar impact on our differential in the quarter. And that was that we made some one-time payments to royalty owners where we had to – we looked at the contracts that we had in place and recalculated them, and trued those up. So there was that one-time issue.

You can see we've guided forward to be between $8 and $9. I think we'll solidly be in that range moving forward..

Got it. Appreciate it. Thanks, guys..

Yep. All the best. Thanks..

Next question comes from Jeff Robertson with Barclays..

Hi, Jeff..

Hi, Jim. A follow-up on differentials.

Can you all just talk a little bit about what your outlook is for differentials both in the Bakken and in Redtail out into 2017?.

Well, they're really similar. We guided $8 to $9. The Bakken's a predominant part of our production, so the Bakken differential pretty much takes our differential where it's going to go company-wide. And like I just said, I think we'll be solidly inside of that range here as we move into the second half.

And as far as going into 2017, there could be improvement there. But for now, we're just going to keep it conservative and say between $8 and $9..

A question for you on the data on slide 8, the comparative well performance in the Bakken.

Is there anything you all are doing differently with your wells from a lift perspective, or I guess length of lateral versus the data you're showing for all the peers?.

No, they're pretty much 10,000-foot laterals for everybody. Really, most people are using some sort of enhanced completion design, just as we are. So I really think what you're seeing there is the quality of our acreage..

Okay. And one last question for you, Jim, or maybe Mike.

Can you all just talk about LOEs on some of these most recent enhanced completions and how they're trending versus what you might have been doing before?.

Well, as you can see, our LOE is down substantially on a dollar basis quarter over quarter. And some of that has to do with some of the staff reductions we did at the end of the first quarter. And some of that has to do with better water hauling contracts and just less water in general. As oil and gas production declines, so does your water.

So those are the primary factors..

Okay. Thank you..

You're welcome. Thank you..

Next question comes from Stephen Berman of Canaccord. Please go ahead..

Hi, Jim..

Hi, Stephen..

The oil mix at 71% was lower by historical standards. I guess some of that can be explained by the high gas capture rate.

Can you talk about what you see the mix is between oil NGLs and natural gas as we move through the second half here?.

Right. So, as you can see by our volumes, we're gathering and capturing a lot more gas than we used to. We're now at 94%, up 5% from even the first quarter. And right now some of our drilling operations are focused on parts of the basin that have a higher gas-to-oil ratio, some of the deeper parts.

So moving forward, we thought it would stay somewhat steady where it's at right now. But with the North Ward Estes sale, that is a very heavy oil production field.

And so, to give you a little guidance going forward, we'd expect it – the gas-to-oil ratio to decline or have more gas versus oil by 1% to 2% when we move into the last half of the year, but then it should be stable, perhaps improve..

Okay. Thanks for that. And then there was an earlier question about the share count. Taking that 33.2 million shares into account, what is the current share count? And what's today, July 28? Current..

Yeah. So, let's just walk through some numbers. I'll try to give you a kind of a fully diluted look. So, at the end of the quarter, we had 246 million shares outstanding. We also had about 5.4 million of unvested restricted stock out there. So if you want to add that in. We had about 520,000 shares sitting behind options that have been granted.

So, if you add those together, you get to 252 million shares. And then subsequent to quarter-end, we talked about converting the 33.2 million, so that gets you to around 285.3 million shares outstanding right now as we sit here today..

Okay. That's helpful. And one quick clarification.

Just want to make sure the $1.5 billion of liquidity at quarter-end does not include – it's not pro forma for North Ward Estes, correct?.

Well, here's a way to look at that. It is. The short answer is it is. We had a $2.75 billion borrowing base, and with the North Ward Estes sale, that was taken $150 million. So we currently have a $2.6 billion borrowing base with $2.5 billion of commitments. At quarter-end, we had $1 billion outstanding, so there's your $1.5 billion of liquidity.

So yesterday we paid down $300 million, so as we sit here today, it's $1.8 billion of liquidity..

Right. That's – okay. That's perfect. Thank you very much..

You're welcome..

Next question comes from Jeanine Wai of Citi..

Hi. Good morning, everyone..

Hi, Jeanine..

Hi. So just following up on John's earlier question on the Redtail DUCs. It looks like the year-end estimate has crept up to 117 versus 100 previously.

Just wondering whether you would ever consider maybe shopping your rigs to save on some CapEx or put some of that earmarked CapEx towards a few completions in the Redtail, or whether it's more of an efficiency call or something related to a frac crew availability?.

Well, A, we have a good frac crew out there. B, our plan is to DUC and have as many of those DUCs out there as we've currently disclosed. C, going forward into 2017, we'll see where prices are as to when we complete those DUCs.

And, Rick, do you want to add anything further in terms of maybe further discussion on the availability of other frac crews? We have a great frac crew that works for us out there right now. They're doing a great job having completed this 16-well, what we call super-pad out there. Most of the pads are eight wells, but the 16-well pad worked great.

Rick?.

Yeah. I would say that we've continue to check into that, and frac crew availability is there for us. When we choose to complete likely next year, we'll plan that, and we'll be ready to go..

Okay. Great. And then just sticking to the Redtail, just wanted to check in on kind of where we are on options for the Redtail in terms of covering any minimum volume commitments you might have and just trying to think about that in terms of the production landscape and the basin, which – it seems to be a basin a little short on barrels..

So we do have a volume commitment out there. We're not currently delivering the volumes. But we've done a very good job of going out and finding other operators with volumes to help satisfy our commitment. So it really hasn't had a large impact overall. We net those deficiency payments in the price, so it impacts our differential ultimately.

And in the second quarter, it was about $0.50 on our differential, so it's not a large effect. There's a number of things we're looking at doing to potentially mitigate the problem, potentially bring barrels down from the Bakken, to help satisfy it. Potentially move the contract out, stretch it out more years, so there's less volume now.

So we're going to continue to work on that issue..

Yeah, we're fortunate here in that recently there've been some developments that would allow us to deliver some Bakken barrels in satisfaction of that commitment. So we're optimistic that that issue will be reduced..

Okay, great. Thank you for taking my call..

All the best. Thank you..

Next question comes from Michael Glick with JPMorgan..

Morning..

Hey, Michael..

You guys have talked about a capital-efficient production profile next year.

Just, as your decline rate starts to moderate, how should we think about your sustaining – or maintenance CapEx next year?.

We haven't given any forecasts – it's Eric Hagen, Michael – for 2017. And I think the Street is somewhere between $650 million and $700 million. And we would hope to do a little bit better than that..

Okay.

And then on enhanced completions, could you maybe just give us your view in terms of where you are in the process of nailing down where the economic limit is in terms of increased sand concentrations? And then maybe as a follow-up, is there anything else you're working on that could also drive productivity higher?.

Well, this is Jim again. I'll turn it over to Mark to kind of amplify this. But, in general, breaking up the rock along the wellbore is what we're after. So there are improvements out there that we see, that we can go beyond where we are today by having more entry points and by homogeneously fracking up and down the wellbore in the near-wellbore space.

Second, with respect to the cost side of the equation, if you kind of think about all the money that got put into these sand mines, and when prices were up there in the $70s to $90s, there was a lot of sand available.

There also happens to be, frankly, a lot of ceramic available right now and – so mixing the two is another way that we can help bring down cost as well as get very efficient along the path of the wellbore in the near-wellbore area. So I'm not sure we're there yet. I used to think that there probably wasn't another 10%.

But now I do believe there is probably at least another 10% in terms of economics improvement by a combination of being more efficient and cost reduction. I would say that's where we stand right now..

Just to follow-up on the first part of your question there. Our standard sand volume now is up right around 7 million pounds, but we have tested significantly higher volumes in several of our projects. So on a standardized 10,000-foot lateral, we've tested up to about 11 million pounds.

We're still getting improved results as we add in those extra sand volumes. And we're really fortunate right now, because of market conditions we can get that extra sand at a relatively minimal cost. So it's having a positive and very beneficial effect on our acreage. The quality of the wells we're drilling, of course, has a lot to do with that, too.

So that really accounts for a lot of what you saw there on slide 8 and our improved performance. The only thing that we're doing is we're continuing to work with diverter technology.

And as Jim just mentioned, in terms of trying to distribute the frac along the wellbore, we're testing out multiple diverter runs within each of the stages that we're doing and seeing some improvement from that as well. So that's sort of the forward-looking part of this. We continue to test that and expect to get some improved performance.

But I really don't think we've hit the limit yet on what we can do productivity-wise. There's probably still a little bit of running room in terms of sand volumes..

Got it. Thank you very much..

You're welcome..

The next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead..

Hi, Michael..

Hey, good morning. Yeah. Most of mine have been answered at this point. I guess one last one I had was just on the incremental 16 DUCs that you guys are going to complete in the back half, where specifically are those in your acreage, either by county or area? I'm just curious..

Well, those are in our Razor -what we call our Razor Township, so that the northeast part of -.

Mark, I think he means the Bakken DUCs..

Oh. I'm sorry. Bakken DUCs. Pardon me. I'm sorry..

Yeah. Yeah..

This is Rick. There's four in Dunn County, four in Stark and eight in McKenzie is where they're located. We've got two of those completed. And we'll get the rest of those done by the end of October, just timing-wise..

Okay. That's all I had. Thank you. Appreciate it..

Thanks, Michael..

This concludes our question and answer session. I would like to turn the conference back over to Jim Volker for any closing remarks..

Thank you, Mia. I'd like to thank all the Whiting employees and our directors for their contributions to a solid second quarter. Lots of accomplishments in the second quarter that we're very proud of, especially bringing our CapEx down and reducing debt.

Eric?.

Jim Volker will be presenting at the EnerCom Oil & Gas Conference in Denver on Monday, August 15, at 10 a.m. Mountain Daylight Time. He will also be presenting at the Barclays CEO Energy Conference in New York on Wednesday, September 7, at 11:45 a.m. Eastern time.

And he will also be presenting at the IPAA OGIS conference in San Francisco the week of September 26..

Thanks to all of you for your interest in Whiting Petroleum, and we look forward to meeting or speaking with you soon. All the best..

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