Well, thank you very much, Zilda. Good morning and welcome to Whiting Petroleum Corporation's first quarter 2015 earnings conference call.

And on the call for Whiting this morning is the Whiting management team. During this call, we'll review our results for the first quarter of 2015 and then discuss the outlook for the remainder of the year.

This 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 two 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 the webcast slides. And please take note that our Form 10-Q for the three months ended March 31, 2015 is expected to be filed later today.

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

Good morning, everyone. We know you're anxious to get to the questions, so Mike and I will make our comments succinctly and get to that Q&A ASAP.

As you can see on slide three, we posted another quarter of record production at 167,000 BOEs a day. We continued to lead the way in new completion designs that enhance capital productivity in the Williston Basin.

We remain the number one Bakken and Three Forks producer in the Williston Basin. In the Niobrara, our Redtail production was 13,000 BOEs a day net, up 28% over the fourth quarter of 2014.

We have two rigs running at Redtail and we anticipate continued production growth at that rig count. The affirmation of our credit facility with the $4.5 billion borrowing base demonstrates at current bank pricing the confidence our banking group has in the value of our producing assets and our long-term growth prospects.

Our robust liquidity position provides us with excellent financial flexibility. In April, we sold non-core properties for $108 million.

The sale was consistent with Whiting's continuing plans for 2015 to sell mature properties that have higher LOE per BOE than our core Bakken and Niobrara assets. Our objective this year is to rig and run the company to prosper at $50 oil.

Clearly, the first quarter shows we have some of the most productive oil assets in the industry. With the reduction in well costs we're currently experiencing, by the fourth quarter, we should be able to maintain a strong production profile of approximately 160,000 BOEs to 162,000 BOEs a day on a quarterly spend of only $375 million.

For 2016, as our base decline rate flattens, we believe this translates into a strong mid-single-digit growth profile on a $1.5 billion CapEx budget. This should approximate our cash flow at current strip prices.

Focusing on slide number four which concentrates on the Bakken and the Niobrara, our total net production reached a record 167,000 BOEs a day, a 3% increase quarter-over-quarter. As you can see on slide four, 91% of our total production in the first quarter came from our Rocky Mountain region.

At 133,500 BOEs a day, the Bakken Three Forks represents 80% of our total production. We are a focused company.

On slide five, we provide an overview of our plays in the Williston Basin where we control 774,000 net acres. We have over 7,500 future gross drilling locations in the Bakken and Three Forks.

We control the sweet spots in the Central, Eastern and Southern Williston Basin where typical wells have cumulative production in the first 90 days of more than 50,000 BOEs. As recently reported in several publications, Whiting has the top two wells in the Williston Basin in terms of initial production rates.

These wells are located at our Tarpon field in McKenzie County, North Dakota. The Flatland Federal 11-4TFH well produced at an initial rate of 7,800 BOEs per day during a 24-hour test of the Three Forks formation, making this the very best well in the basin.

The Flatland Federal 11-4HR well produced at an initial rate of 7,100 BOEs per day during a 24-hour test of the Middle Bakken formation. Moving to slide six, you can see we're achieving outstanding results across our Dunn field in Dunn County, North Dakota, the Polar field in Williams County and the Koala field in McKenzie County where 12 new wells, four in each field, had average IPs of 2,800 BOEs per day and an average 30-day rate of 1,200 BOEs per day.

Moving to slide seven, you can see that in July 2014 we began to implement slickwater completion technology in the Pronghorn sand at our Pronghorn field in Stark County, North Dakota. We've completed a total of 15 slickwater wells.

On average, the slickwater wells had 90-day rates 51% greater than the 42 offsetting wells completed with crosslink fluid. Slide eight shows our Williston Basin production profile for 2015.

We have driven completed well costs down to $6.5 million from $8.5 million. Please note that at today's oil prices, we're generating IRRs in excess of 50%.

Moving to slide nine, you can see that in our Redtail Field, located in the Denver Julesburg Basin in Weld County, Colorado, Whiting has established production in four zones: the Niobrara A, B, C, and the Codell/Fort Hays formation. At year-end 2014, we had an estimated 6,700 future gross drilling locations in the Niobrara.

So combining the Bakken/Three Forks and the Niobrara, we have over 14,000 future locations. Slide number 10 depicts our Redtail Niobrara production profile.

Please note that at today's oil prices, we're generating IRRs of approximately 40%. Slide number 11 shows the infrastructure at Redtail.

We're on schedule to expand the inlet capacity at our gas processing plant from 20 million cubic feet a day to 70 million cubic feet of gas per day in the second quarter of 2015. Mike?

On slide number 12, you can see our first quarter 2015 financial results. Our discretionary cash flow in the first quarter totaled $249 million.

Our unit costs in the first quarter of 2015 have decreased significantly from the first quarter of 2014, due in large part to cost control measures and technology-driven productivity increases. Our DD&A rate per BOE has dropped 28% to $18.87.

LOE per BOE has decreased 13% to $11.07, and G&A per BOE is down 18% to $2.93. Our guidance for the second quarter and full year 2015 is detailed on slide number 14.

We continue to guide for 6% year-over-year production growth despite our recent asset sale. I'd like to provide a little more color on the CapEx and production trend.

First quarter CapEx of $835 million included $43 million of rig termination fees. Excluding these fees, CapEx was $792 million.

In terms of how we plan to hit our full year forecast, there are two points. First, we are dropping an additional two rigs but leaving our production forecast unchanged.

This means we go from 19 rigs in the first quarter to an average of 11 rigs for the rest of the year. Second, first quarter results only reflected a 10% drop in completed well costs.

Going forward, we should see an additional 20% cost reduction based on current AFEs. We completed 75 net wells in the first quarter, and we anticipate we will complete 77 net wells during the rest of the year, including 39 net wells in the second quarter, 24 net wells in the third quarter, and 24 net wells in the fourth quarter.

Thus, we expect our CapEx to be approximately $500 million in the second quarter and $375 million in the second half per quarter. In terms of the production trend, we see a moderate decline in Q3 from Q2 levels and then stabilization of volumes in Q4.

As Jim indicated, we see 2016 volumes up mid-single-digit percentage increase on a $1.5 billion budget, which should approximate our cash flow at current strip prices. On slide number 15, you can see that our capital structure is very strong with nothing drawn on our credit facility and more than $100 million of cash on hand.

Our borrowing base is $4.5 billion, of which $3.5 billion has been committed. In addition, Whiting and its lenders replaced the 4 to 1 total debt-to-EBITDAX covenant with a 2.5 to 1 senior secured debt-to-EBITDAX covenant through 2016.

We are well positioned from a liquidity and covenant perspective to deal with lower oil prices. Slide number 16 shows our outstanding bonds as of March 31, 2015.

It also shows that we are within all the covenants in our credit agreement and our bond indentures. I'd like to note a feature of the convertible bond that we recently issued that helps limit dilution.

It is our intention to cash settle the $1.25 billion face value of the bond. Slide number 17 shows our crude oil hedge positions as of April 23, 2015.

We recently layered in some additional oil hedges and are now 38% hedged for the second half of 2015 and 31% hedged in 2016. On slide number 18, you'll see our fixed differential crude oil sales contracts for our Redtail Field that are locked in at an attractive differential of only $4.75 off of NYMEX.

With that, I'll turn the call back over to Jim.

Thanks, Mike. Our capital expenditures will decline sharply in the second quarter and the last half of 2015.

Our total rig count will average 11 rigs in the second half of 2015. Nine of these rigs will operate in the Bakken and Three Forks and two will drill in the Niobrara.

Our strong liquidity position provides us with excellent financial flexibility. We are seeing lower completed well cost through service company price reductions, operational efficiencies, and new technology applications.

The Bakken/Three Forks wells are being completed for approximately $6.5 million per well, down from $8.5 million in 2014. Our completed well cost in the Niobrara is approximately $4.5 million, down from $6 million in 2014.

In summary, we have positioned the company to prosper in the current pricing environment. Zilda, please open up the conference call for questions.

Good morning, guys.

Good morning, John.

You had really strong results on those Kodiak legacy properties, and when I look at the nine Bakken rigs in the second half of the year, could you give me some color on maybe the allocation of those rigs on Kodiak legacy assets versus the Whiting?

Yeah, John. Mark Williams here.

So we have a strong focus right now to make sure that we're directing all of those rigs to the most profitable areas; that's a part of what our high-grading exercise here. And so, the areas that you'll see us focus our rig count on are – with respect to the Kodiak properties which you asked about, are going to be Polar, the southern part of what we call Cassandra now, which is really right next to Polar and sort of the same thing.

So that area in the Central Basin north of the river, you'll see roughly half of our rigs there. We'll also be – have a rig in Dunn County that we'll be operating pretty much throughout the year there.

We have two rigs in Sanish, and then we'll continue to have rigs kind of shared between the area of where Pronghorn and Hidden Bench are, so a pretty good allocation. Really, what we're trying to do is get all of our rigs to the areas where we have the most profitable opportunities on a combination of Kodiak and Whiting's legacy properties.

That's very helpful. Thanks, Mark.

And then, just my follow-up question on the gas differential guidance, that changed a fair bit. Just any color you can give on that would be helpful.

Well, there's just a lot of gas right now. Everybody's focused on their gas capture in North Dakota, and there's a lot more gas volumes there and the price has been depressed because of it.

I do think it'll come back a little bit. I'm basically guiding for it to be flat with NYMEX in Q2 and the rest of the year.

That's great, guys. I'll turn it over to somebody else.

Appreciate the answers.

Thanks, John.

Good morning, guys.

Good morning, Neal.

Say, hey, Jim, for you or Mark, just a question. I know you guys continue to do a fantastic job just on the well spacing.

I'm just wondering, I guess, more particularly on the East side there over by Sanish and Parshall, what you all are thinking about the well spacing per unit and how do you see that sort of playing out for the remainder of the year.

Sure. That's been a big area of focus for us, Neal, but the area around Sanish and Parshall and, for that matter, down into Dunn County is the highest OOIP in the basin.

So if you look at how we developed that area originally, it was on three wells per spacing unit and Middle Bakken. Most of the basin now, frankly, is being developed on more like anywhere between four and eight, and I would say an average of six in the quarter, a sweet spot to the basin.

So we're doing – we're in the middle of an infill program there. And so we have the potential to go as high as two additional infills in the spacing units we have at Sanish in the Middle Bakken.

Separately from that, we've remapped the Three Forks here lately. We're getting very good results along the southwest side of Sanish and so we have continued infill opportunities in the Three Forks there, especially along, I'd say, the western half of Sanish Field and Three Forks.

Okay. And then just one last one.

Jim, you guys are obviously making the appropriate call in letting a couple of rigs go. What's your thoughts – but you're also, as you continue to trim costs and become more efficient; Jim, what's your thoughts about sort of your IRR criteria needed to bring the rig back or step up activity a bit more the latter part of this year?

Well, I can kind of answer that perhaps in relation to oil prices. So I would say that if we were to see $70 oil, which is basically $10 above where we are today, you'd probably see us put a couple of rigs back.

Some of the rigs that we've released we can get back and sort of pick up quickly as a result of the way in which our contracts were written.

Very good. Thanks, Jim.

Thanks, Mark.

You bet.

Hey, Jason.

Hi, David.

Hi. Good morning.

Thank you, guys.

You're welcome.

Just a – Jim, could you give us thoughts on just adding hedges here? We saw you guys layer in some stuff and some three-ways, and now you have about some decent covers on a three-way collars and it looks like you're putting in some puts, sub $60.

Should we expect you guys to be adding at this level as the curve keeps moving higher here? Are you kind of clear until you see something higher than $70?

Well, if you take a look at what we're doing on the three-ways there with $55 floors, keeping in mind that that $45 number on a three-way really tells you that you have protection at $55 until you drop below $45. So that's what you've done with respect to the $55 by $45.

On the upper end, we are getting ceilings on those that are above $70. So basically, the way we look at that is that unless you're really thinking that oil is going to drop below $45 again, what you've done is basically a $55 by, say, $72 or $73 collar – cost plus collar.

That's what we've done. And we may layer in a little more; 50% would be a max that we would get to.

I'm not too sure with oil prices moving the direction that they are moving, i.e., up, that we'll go to 50%. We may end up in the 40%s.

Okay. I appreciate the color on that.

Mark, perhaps you could – we saw some successful completions on the Kodiak legacy properties in Koala, Polar, and you've seen some in Dunn. And you guys have taken the well costs down there, it sounds like to about $7.5 million or so.

Are you on all sand completion? Is Whiting still a completion on all of the Kodiak properties now with all of the rigs?

And how do you guys view – I think the criticism over time or the thought was to use ceramic in those areas to prevent crushing. How do you guys think about that and how are you seeing the results in the early stages right now?

Basically, in terms of differences in the completion design, Whiting is dominantly an all white sand style of completion. We do recognize the benefit of using ceramic in areas that have exceptionally high pressure like Hidden Bench and Pronghorn.

We still use a little bit today; we're pretty much phasing that out in – everywhere else. That's a – the only really significant difference, say between what us and Kodiak have done previously; both of us were using cemented liners and have been doing so since early 2013.

And so, we just – we've gone through a lot of trial and error with ceramic and white sand and have really concluded that other than – there are some issues with proper embedment, which is why in the high pressure areas we continue to use it. But for the most part, you're really just not getting the bang for the buck by using ceramic, so we're able to trim quite a bit of cost off by sticking with white sand.

Okay. That's helpful.

And could you just give me a sense of the range of well costs, like if you went from Sanish over to some of the deeper areas?

I'll help you with that since I'm approving every AFE that's in our system. Basically, the range is from about $7 million down to about $6.3 million; average is about $6.5 million.

Yeah. All right.

That's helpful. Thanks guys.

I'll let someone else in queue.

Thank you.

Good morning, Mike.

Hey. Good morning.

My question is on the depth of the Bakken inventory. Very encouraging to see 50% internal rates of return possible and well costs going down to $6.5 million.

Jim, if you had to look at the 7,500 future locations out there, what percentage really kind of fits that 50% IRR profile? Thanks.

Well, I'm going to let Mark help me on this, but, look, there's two things that are happening here. Well costs continue to decline.

I really think there'll be one more round of significant service company cost concessions. I think that'll happen sometime here after the middle of the year.

And I think we'll be able to get our – some of our completed well costs down there to $6 million in the Bakken. So with that as background, I'll let Mark kind of go ahead and talk to your – the rest of your point.

The slide on page five, we prepared specifically to address that question. And it shows Whiting's acreage position with the combination of Whiting and Kodiak that happened at the end of the year.

So you see where we are in the Williston, you can see the boundaries of the play there. And so what we've done is we've subdivided all of the wells in the basin based on performance.

And the ones that – the black circles in there as distinguished from the gray ones, are the one that currently have 50,000 MBOEs or greater over the first 90 days of production. That's what makes good economic sense and is approaching a number that we have been seeing here lately.

Frankly, we're a little above that right now. But with current oil prices, those are the areas that are currently economically viable and attractive to us.

So you can really see the distribution of our acreage. I will say we've moved our rigs for the time being out of Montana and westernmost North Dakota into these other areas.

But if you look at the 7,000 plus, 7,500 plus well locations that we've got across the basin, you can get a very good feel for the distribution of where those are because that's where our acreage is just by looking at that map. So we control really the central parts of the basin, the eastern side now, especially with the acreage we've picked up in Dunn County and really, the only significant player, ourselves and Fidelity, down in the southern part of the basin.

So we've got all three of those sweet spots and so I consider a very large fraction of those 7,500 to be viable under today's market prices.

Okay. I appreciate that.

And a follow-up question, on the Niobrara, the fixed crude contract at $4.50 off of WTI. That kind of surprised me a little bit.

Could you talk about the dynamics pertaining to that and is that kind of a way forward in the basin here that you could be getting?

So – yeah, thanks. Great question.

We got that by committing early to Pony Express. So that was a, I'm going to say, a discount on the discount that we got as a result of committing our crude to that Pony Express line.

Okay. So really going forward here, don't dial in – maybe on incremental volumes, $4.50; trend back toward the higher number?

Or maybe just any comments on differentials both there and in the Bakken, I think would be helpful, too. Thanks.

Yeah. That's a great follow-up question.

We actually have – the way the contract there is structured, I think all of our volumes or virtually all of our volumes, because we committed increasing volumes. So I expect that virtually all of our volumes will be sold at that lower differential.

Great. Thanks, Jim.

Great quarter, guys.

Thanks. Appreciate it.

Hi, Michael.

Hey. How are you?

Congrats on a good quarter.

Hey. Thanks.

I guess one question on my end, around kind of the efficiency improvements as you march towards the core and then the further improvements upon that as you're pushing more of the program towards the slickwater jobs. Now, how much of that has been baked in, would you say, to guidance at this point?

And how much has been risked back as you think about the outlook?

Zip. Zero.

Okay. Zip is baked in, or zip is risked?

Zip is baked in, and therefore, it didn't have to be risked.

All risk. Yeah.

Perfect. And then – that's helpful.

Thanks. And then a follow-up unrelated, but great cost improvements to date; sounds like some more are expected.

To what extent do you think these will be cyclical versus structural cost improvements for Whiting and really the industry as a whole, but in particular Whiting?

It's a great question. So, here, I would have to say that having a certain number of future drilling locations that we have, the number of rigs that we have working in the basin, our history of on-time payment, we have excellent relationships with the companies that do the frac jobs for us.

And so we were visited early on by top management. They responded quickly and decisively to our request for lower costs.

As a result, we continue to use them. We continue to keep their crews as busy as we can at this price level, concentrating, as Mark and I have commented on, in our high rate of return areas, which by the way, I really believe that through this continued focus on cost containment and reduction we have a decade's worth of drilling at these kinds of rates of return, at these kinds of prices.

So I do think it's not cyclical. I do realize that if we do see a pop-up to $80 or $90 oil again, there's going to be upward pressure.

But making my comments applicable to the current strip, I really believe these costs are here to stay and we're focusing to run in this $50 environment. If we're fortunate enough to see $70, great.

Our IRRs are going to go up and our time to payouts are going to go down.

Great; appreciate the color. Thanks.

Thanks.

Hi, Jason.

Hey, good morning, everyone. Hey, Jim.

Good morning.

So, Jim, now you have the equity and the debt deal done and you obviously sold one asset this quarter, can you just maybe give an update on the broader asset sale process? I know last quarter you said that you still expect it to be done this year.

Is that still the plan? And is there a kind of a formal process ongoing at this point?

Yes, there is. Yes, I still expect to sell $500 million to $1 billion worth of assets this year.

Speaking about that in terms of covering an outspend, I think we'll sell more than enough assets to cover the outspend and perhaps even help us a little bit with some debt retirement. So I feel great about that.

Good strong offers coming in on properties that had somewhere in the $20 to $25 per BOE, LOE per BOE and that compares. So basically we'll be shedding those assets.

And in my opinion, a year from now, you'll see even lower LOE per BOE at Whiting than we have today as a result of that. And we'll be a much more focused company, focused on the Bakken, the Three Forks and the Niobrara, and pretty much what I would call a pure play in those areas, plus any – we're still spending about a little less than 5% of our capital on some new areas that we believe would be economic at today's $50 to $60 oil price.

So you'll see a focus on the Bakken, the Three Forks, the Niobrara. And if we happen to make a discovery in one of our new areas, other areas that we think are highly economic.

Basically, what we're looking there to do is get 3:1 on our money, 1.5-year payouts, 50% or better IRRs in all the areas where we concentrate on drilling.

Got it. Thanks.

And is the midstream still part of that asset sale process at this point?

It is. It is.

Okay. And just one quick follow-up on the earlier question on the Pony Express contract.

I mean, is there a risk that you guys aren't able to meet your commitments there, given that I think the commitments see a ramp in production versus your lower rig count? And if that is the case, have you had some discussions with third parties to maybe fill the gap?

Well, first of all, I still think our production is going to increase. Second, we do have the ability to add more rigs there.

Third, we're able to – with that kind of differential, basically, there's plenty of ways to fill in for any crude that we, I'm going to say, had a shortfall on. But I don't see that happening.

I think we're going to be able to grow; the efficiency of the two rigs that we have out there is tremendous. They're improving upon the number of rigs – the number of wells they complete for us every month.

And so I'm very optimistic that we'll be able to meet exactly what we've contracted for there at Redtail.

Thanks, Jim. Appreciate it.

You're welcome.

Good morning, Jim.

Hi, Dave.

So, I'm getting back – I want to get back to that comment you made about the $1.5 billion for next year cash flow, 2016 single-digit growth, whatever language you used. So if I think about the second half of the year, if you guys have 11 rigs running at $3.75 million, annualized, that's $1.5 billion.

So are you – when you talk about that $1.5 billion, is that kind of assuming an 11-rig program for 2016 right now or how should I think about that $1.5 billion?

Yeah. The short answer is yes, Dave.

Okay. That was easy.

Second question, you haven't – or I haven't heard discussed the individual well rates at Redtail and obviously the Colorado state data is all over the board. So can you just talk about what you're seeing as far as where they're coming relative to your type curve, the variability?

Just kind of what's going on in the field?

Well, I would say that the enthusiasm of our technical team here has – it really has been making somebody like me who's essentially always wanting to look at the most updated production data to determine whether or not we are on that curve. And we are on that curve that we've put up for you here.

And essentially, it's focusing in on about 450,000 BOEs and it doesn't really matter whether we're talking about the A, the B, the C, or the areas of the Codell/Niobrara that we intend – the Codell that we intend to develop. Essentially, across our acreage position, usually at least two of those zones are good and productive from East to West and North to South.

So all I can say there is that someone who was skeptical because of our experience going all the way back into the 1970s on the variability of the Niobrara, I've been converted into a much bigger believer into our ability and essentially the homogeneity of good areas over those four zones across our acreage position. They all have some excellent areas across our acreage position.

So it's a blessing out there that we're in this area where we have these four areas and essentially where it looks to me like – and I think to our geoscience team, that at least of those zones are good at any one spot on our acreage position. And I'm especially encouraged, I might say, with what we see in the Codell from where we are sort of at the heart of Redtail, sort of the center of Redtail.

And when you look in that map and see the area that we're currently developing, all the way over to the Western edge, it basically, in my opinion, just gets better as we move to the West.

All right. Thank you.

Yeah. You're welcome.

Hey, Mike.

Hi, Jim. At slide number seven, you talked about the impact of the slickwater completions, seeing a 51% increase in the 90-day rates there.

Just wondering if you have any idea how that might translate to a potential EUR uplift at this point? And given that you started doing those about nine months ago, do you have any data beyond the 90 days?

Well, I would say that what we're doing here across the board is trying to concentrate on those areas that are 600 MBOEs to 700 MBOEs. So that's where we are.

It doesn't really matter whether you're talking about Sanish or partial or any of the areas that we've already cited. Same thing is true here at the Pronghorn.

That's where we're concentrating our drilling activity. I really believe that for the next decade, we can – even if – I'm going to say as we get out of the 600 MBOE to 700 MBOE range, maybe into the 550 MBOE to 650 MBOE range, drilling costs will continue to decline.

We're going to have – we're working on, with the service companies, even more efficient ways to complete these wells, even more efficient ways to pump them to draw down pressure, to increase the recovery factor. I really believe that as we go forward here, you're going to see us, and for that matter, the industry in general in the Bakken, pretty consistently think of EURs in that range of 600,000 BOEs to 700,000 BOEs.

And we're going to be able to do that at well costs in the $6 million to $6.5 million range.

Jim, I'll just add in there with regards with the slickwater fracs at Pronghorn, those have been a tremendous uplift and are probably leading the charge in terms of everywhere that we've tried this. You're right; we're only about 180 days into this.

But by the time you get to 90 days, you've seen a pretty good representation of what the well is going to do, and we see a very good match on that 90-day performance with the EURs that we start to feel comfortable with more towards the end of the year. So Pronghorn is then probably leading the charge in terms of the areas that we've tried this in.

We're also seeing exceptionally positive results on slickwater fracs at both Polar and Sanish. Those areas look great right now.

We haven't – we've seen, I should say, good uplift at Missouri Bricks although Missouri Bricks is a little bit below the economic bar currently at current prices. So those four areas are where we've seen the most uplift on slickwater fracs.

And then beyond that, we expect but have not yet seen results in Dunn County. It ought to look very similar to what we see at Sanish.

We haven't gotten any completed there yet. And then I will say places like Hidden Bench and probably Tarpon, those areas are doing great without slickwater fracs.

They're heavily fractured, and so we haven't seen – we saw the real uplift there more from the cemented liners, for example, at Hidden Bench. We've tried slickwater fracs but the uplift was already pretty much realized with just cemented liners.

Hey, Mike. It's Eric Hagen.

I'd just like to point out, too, you can plot that 90-day rate on our sample type curve. And you'll see it's clearly performing in line and might be better than the 700,000 BOE type curve.

And I've looked at all those wells in great detail, and they're holding up, the ones that we have 120-day rate on, they're all holding up out there as well. So those are very, very good wells meeting our new type curve.

Yeah. Great question, Mike.

Thanks for kind of pulling the data out of us.

That's helpful. I appreciate that answer.

And I guess, along the same lines, with the slickwater fracs, I guess one of the big contentions was that you're probably not getting as much extension but you're getting a more complex near wellbore fracture. And you guys, you were asked earlier about the spacing, the spacing that you've laid out previously, like particular the Polar area; I think you'd talked about 12 wells per drilling unit.

Any possibility of that changing as you transfer to more slickwater completions?

We feel pretty comfortable with the spacing that we've got now on Polar, that sort of 6-plus-6 pattern. There are going to be a few exceptions to that.

But what you mentioned first there is really what we're shooting for. We don't want to have a lot of extension on our frac wings there.

When you're drilling on that kind of density, the most important thing is that you distributed the frac evenly up and down the wellbore through a lot of entry points, and you break up all the rock in your wellbore environment. The reason for that is that the next well adjacent to that is, it's going to get the part that would otherwise be involved in the extension you referred to.

So really we're – it's really all about breaking the rock up near the wellbore.

Well it sounds like, that's already kind of have been figured into what you've laid out in terms of the spacing at this point.

That's correct.

Great. Thank you.

But what we expect to see is improvement, performance improvement, based on that spacing.

Got it. Thanks a lot.

Thanks, Mike.

Good morning and thank you for taking my questions.

Welcome, John.

I wanted to – in your prepared remarks, you talked about growth coming out of Redtail and sort of mentioned it in follow-up to Jason's questions, I was hoping to dial in there; a little more color on how we should think about that trajectory with the two-rig program. Is it low-single digits; is it high-single digits?

And I know that you are utilizing sort of pretty large pads there. How should we think about the lumpiness as we go through 2015 with volumes out of the DJ?

Well, I would think that you can think about it being in the strong middle digits, I guess, probably the best way I would think about it. And then with flexibility if oil prices come back another $5 to $10 a barrel, we could move a couple of more rigs back in there.

Okay. And any thoughts on lumpiness with regards to 2015 or just stay tuned?

Just stay tuned. We don't give quarterly guidance on – by field.

So...

That's fair. Okay.

And then I just wanted to ask, you obviously raised quite a bit of capital over the quarter. And I was hoping if you could maybe take a moment and discuss why the size of the program was selected and if oil keeps five or six handle for the next few years, do you see Whiting potentially having to come back to the market, or is the sort of mid-single-digit growth rate within cash flow really the right way, you think, to maximize share value for the shareholders in that environment?

So trying to take those in the order you asked them, no I don't see us having to go back to the market; the size was the size because there was in total, about $3 billion worth of debt that we had to take on there. Just to remind you, it was roughly $1.55 billion worth of bonds potentially coming back to us from Kodiak, and then there was about another $1.5 billion worth of bank debt there; as of year-end 2014, $900 million from them and $500 million from us.

And we did that in a manner that we thought was the least dilutive possible. We did it about a third in equity, two-thirds in debt; you look across the entire raise it was a 2% average borrowing cost across the two debt tranches.

It was just over 3%, and then as Mike has already explained, we did – we got that 1.25% interest rate on the convert. But we do have the ability to cash-settle that convert and, therefore, on the principal amount, and net share settle for only the price above the conversion price, which is $39 a share.

So I thought we were able to structure that as adroitly and adeptly as we could, given our need at the time. I think it was a reasonably good time to do it in the sense that there were lots of rumors about us out there at that time in the market, frankly.

It made it easier for us, frankly, to sell properties and get better prices when people knew that we – they basically weren't going to be able to hold us up and tough deal us. So my opinion on this last property sale, we got a heck of good price.

I think the buyers did fine, but I thought we did well.

Great.

Hope that helps you.

Oh, it was very helpful. Thank you.

Thanks for taking my questions. I'll let somebody up.

Great.

Hey, Scott.

Yeah. Hey, thanks.

Good morning. Hey, just a lot of talk on slickwater fracs in the Bakken.

Can you all discuss the Niobrara and using slickwaters there, what that could mean for returns in that play?

Mark will weigh in on that.

We've already started doing that on our completions. We've been really focused on cost reductions across the board, including the Niobrara.

But part of what we're able to do there because we have the infrastructure, and Rick can talk some more about this, too, but we've been able to start using or we're working towards being able to use our produced water there. So it becomes part of the cost containment effort.

And the results we've seen so far on the slickwater is – we're not as far into it yet as I'd like to be, but so far, the results are pretty good. You got anything to add there, Rick?

Yes. This is Rick Ross.

I agree with Mark's comments. We are doing slickwater fracs.

Numbers look very good as compared to our previous completions. And as a result, we've been able to get our costs down, both through working with vendors and with the design change down to $4.5 million as Mark mentioned.

And I think there's some additional savings that we could secure with, as Mark mentioned, recycling water and being a little bit more efficient with our infrastructure that we've put in place and are bringing online right now.

Okay. And just a little bit of a follow-up.

So am I hearing you all right that you – I mean, what percentage of wells are you completing with slickwater? And, I guess, what is limiting you from increasing that?

Is it access to water or just the relative cost of not using recycled water?

Going forward, we'll probably be predominantly slickwater jobs. I would say right now, it's a mix.

Water and infrastructure is not a limitation for us. It's just making the conversion to that new technology and making sure we're real careful and watching results and we're moving the right direction.

Okay. And you said early on, it looks pretty good.

Is it – can you give a little color on that? Is it similar to the positive trend you saw in the Bakken?

I would say at this point, we're encouraged but a little early to give hard results.

Okay. Fair enough.

And one follow-up, if I could. Acreage retention, obviously you guys are dialing down the program like a lot of others.

Can you talk about some of the outerlying acreage you may have in your two core areas, the Bakken or Niobrara, with respect to 2015? How much of that do you think may go away and I would assume to be stuff that certainly doesn't make the cut based on the return threshold you all have.

So very little. I mean we're talking here about only a few thousand net acres that we might let go.

Basically, you saw a drop from a little over 800,000 net acres to this 774,000 acres that we just talked about. So you've seen the bulk of what we intended to drop already occur.

That's great. Thanks.

Yes.

Thanks, Scott.

Good morning. Thanks for taking my call.

Welcome, Jeffrey.

I just want to make sure I understood the remark earlier in the call. Did the significantly lower Bakken and Redtail well costs cited in the press release reflect the 20% cost reductions that you mentioned earlier today?

And then if there are additional cost reductions, would that further lower those costs that are cited in the press release?

So basically, I think we're pretty – I hope we were clear. If not, I'll try again.

But our costs have come down from about $8.5 million to $6.5 million in the Bakken. And they've gone from $6 million to about $4.5 million in the Niobrara.

So as to future cost reductions, no, there's not another 20% on top of that. I was trying to focus on a number of about $6 million in the Bakken and Three Forks, especially once we get into more of a bit of a manufacturing mode on some of the new areas that have come to us as a result of the Kodiak acquisition.

So I hope that's helpful to you. I tried to focus on maybe one more cost reduction push with our suppliers.

That ought to occur, I think, right after the middle of the year here when we see the effect of the drop in rigs which then has affected the number of completion crews working. For a time there, they were suspended in animation, so to speak, and hovering at pretty much where they were in the fourth quarter of 2014.

But by the time we get to the second half of 2015, there'll be, we believe, a significant reduction in the number of completion crews that are fully employed. And so I think that'll be a time when we'll go back to the pumping service companies and try to – I really don't – I hesitate to use the word extract because with those companies, we have a great long-term relationship of working with them to try to keep their equipment working and get us lower costs.

I think they'd be the first ones to admit to you right now that they're working at very limited margins as a result of the cost reductions that they've already given us. And I think they're working to squeeze a, I'm going to say, somewhere in the range of about another 7%, 8%, 10% out of that completion cost for us and while still keeping their crews working.

So that would get us down from about $6.5 million to $6 million in some areas in the Bakken and the Three Forks. We'll see what can happen out there at Redtail.

Some of the infrastructure that we are building will be just as helpful to us there in terms of this – kind of following up on these prior questions, in terms of moving the water around and reusing our produced water for our fracs out there. So we'll be as helpful to ourselves out there, I think, in Niobrara as just going to the service companies and asking for more cost reductions.

I'm hopeful that some of that will come from us. I'm optimistic about that because we've seen it happen to some degree, to the extent we've been able to use produced water, and as we basically lay the lines out there necessary to move the water around the field.

I mean, we plan to drill up to 6,000 wells out there, so all this planning that we're doing is going to be very helpful for us as we get into more and more of a manufacturing process.

Thanks for that. That's excellent explanation; that was very explicit.

Okay. Great.

And if I could just ask a follow-up. I was just wondering, could you give a little bit of color on which of your Redtail zones you're concentrating on in 2015?

Mark will answer that.

Yeah. We're continuing on with the A and B program.

And we've got a slide in our investor presentation, I don't think it's in this one currently, but you can refer to it. It shows sort of a block diagram and what we call the wine rack of the Niobrara development program.

What you see in there, we originally, as far as the A and the B, we are in sort of an 8-plus-8 type of a development program. Right now, we're trying to make sure that we can execute on that so the – what I would say is that the A and the B program are going along just fine and we're continuing to develop there.

The C and the D or the new parts of the program. That's what we're most excited about here.

The D – what we call the D is really the – it's a combination of the Fort Hays and the Codell together and we're targeting the zone sort of right the interface between those. And so that's the part that looks like it's going to be developable across our acreage position.

Why do I say that? It's really because as you map it, number one, it lends itself to being mappable with subsurface data.

It's a little bit more of a conventional play, I would say. It's not quite as tight as the Niobrara is, and so you can rely on the resistivity logs and when we map it out, we see it being -changing character very little across our whole acreage position.

So that's where I would say, given everything that's happened in the last six months and all the turmoil and everything, this is – has been a sleeper not just for Whiting but for other people that are playing the Codell, this thing has really come on in the last six months. I mean it's a big change to how we view our inventory out here and so we're now – we have a – we've talked about the well that we've completed there.

We're right in the process of completing new – two new Codell wells; they're out sort of on a periphery of the developed area – or the developed – the area that we're developing right now. And then as we go forward this year, we've got a couple of more wells that are more step outs and so that's really how we're going to attack the Codell is we're stepping out a little bit more rapid rate than we are with the development program in the A and B zone.

So anyway, I hope that helps. But we're very excited about the – what we see is a widespread opportunity across a pretty large acreage position.

Well, if I can just follow that up real quick, I mean now that adds a lot of color to the significance of talking about those well results in the press release. But if I understand what you're just saying there, that means that going forward, there are – it looks like these locations in the C and the Codell/Fort Hays that would be economic in the kind of $50 world that you're positioning the company for.

Is that correct?

Yes. Yeah.

Both the C and the Codell/Fort Hays; we're also doing a lot of work on the C. We haven't talked very much about that.

And we don't have as much data on C as we do in Codell/Fort Hays yet. But the C is a big part of our 30F pilot, the Horsetail pilot, that we've just completed.

And we've got a couple of C wells in there. That's going to tell us a lot about the C.

And so it may – we're hoping it will be sort of the same situation with the Codell. But so far, we're not quite as far along with it.

Well, we'll stay tuned for that. Thanks for answering my questions.

Thank you.

Good morning.

Hi, Jason.

Sorry about that earlier. You guys surprised me and put me on so early.

I just wanted to stay in the Niobrara just quickly. A lot of good questions just there.

As you develop this, too, is it still a plan to kind of move southwest to northeast as you kind of extend the play? Or how should we think about the activity from a, I guess, geographical perspective this year?

Just to follow-up on the last thing there and answer your question directly, on the Niobrara, largely driven by infrastructure. We're developing the field concentrically outward.

So we're building lines into our facilities, all of that, as we move from our core outwards in the A and the B zone. The Codell, it's up to us to really try and see – test this hypothesis that it is widespread across our acreage.

So that's where we're doing a couple of additional wells that are what I call step outs beyond that to the Northwest. And so, again, we're bringing a couple of wells on this week.

We'll talk about those next quarter; and then we've got two more wells planned later in the year. But it's really infrastructure that has us drilling where we're drilling in the Niobrara.

That's helpful.

It's just more efficient to develop concentrically out away from the areas that we've already drilled and expand our facilities accordingly. It makes more sense to us, obviously, especially in a time like this of, say, $50 to $60 oil rather than hopscotching around our acreage position.

We already benefited here from having drilled on some of the extremities of our acreage, and we're satisfied with what we see there in the A, and the B, and the C; and then, as Mark has indicated, this excellent result that we're seeing in the Codell has us enthusiastic about essentially everything from the currently drilled Eastern edge all the way back to the Western edge of our acreage for the Codell. It's pretty – it's exciting for us.

It's exciting. And so, we have not only the work that we've done, but we benefit from the fact that this is an old play area for the pioneers here in the DJ Basin who drilled through the Codell/Niobrara all the way down to the D and the J sands.

And so we have all those old logs to take a look at and they give us confidence that what we're currently developing economically exists, as I've said before, in at least two good zones across our acreage position.

Thank you for that. And just a follow-up, you mentioned in your prepared remarks about the convertible.

I haven't pored through the documents, so I apologize. But in paying that off in cash, could you just give us your ability to do that, the timing on that is just how you can go about that?

It's a – it's Eric Hagen here. I'll hand it over to Mike, but so it was a five-year maturity, and Mike can get...

There's no pre-payments on; it will get paid back in cash at the end of the five-year term, March of 2020 – or 2019, sorry.

Great. Thanks.

I'll turn it back. Thanks for letting me jump back on.

You're welcome.

Thank you, Zilda. I'd like to thank all the Whiting employees and directors for their strong contributions to a very solid quarter for Whiting, and our exciting plans for the remainder of 2015 and beyond.

Eric?

Pete Hagist will participate in a panel discussion at Morgan Stanley's E&P and Oil Services Conference in Houston on Wednesday, May 13; Mark Williams will present at the UBS Energy Conference in Austin, Texas on Tuesday, May 19; Rick Ross will present at the RBC Global Energy and Power Conference in New York City on Monday, June 1; Mark Williams will be attending the JPMorgan One-on-One Forum in Boston on Thursday, June 18; and then Pete Hagist will present at the Global Hunter 100 Energy Conference in Chicago, Tuesday, June 23. And we hope to see you all at these events.

Thanks, Eric. In closing, we want to thank all of you on this call for your new or continuing interest in Whiting Petroleum, and we look forward to meeting with you soon.