Oasis Petroleum Inc
Q4 2014 Earnings Call Transcript

Published: 27 Feb 2015

[Operator:]

Good morning. My name is Sanchi. I will be your conference facilitator today. Welcome everyone to the Whiting Petroleum Corporation Fourth Quarter 2014 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. I'll now turn the call over to Eric Hagen, the company's Vice President of Investor Relations.

[Eric K. Hagen:]

Thank you, Sanchi. Good morning and welcome to Whiting Petroleum Corporation's fourth quarter 2014 earnings conference call. On the call for Whiting this morning is the Whiting management team. And during the call, we'll review our results for the fourth quarter of 2014 and then discuss the outlook for the first quarter and full-year 2015. This conference call is being recorded and will also be available at our website at www.whiting.com. To access the call and the webcast, please click on the Investor Relations box on the menu and then click on the webcast 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 our webcast slides. And please take note that our Form 10-K for the year ended December 31, 2014 is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

[James J. Volker:]

Thanks, Eric. And thanks, everyone, for joining us this morning. We know your focus will be on our plans for 2015. We do have a few highlights we want to pass on to you and then we'll get to your questions as soon as possible. I'd like to begin on slide three. Whiting is a stronger company in the wake of the Kodiak Oil & Gas acquisition and is set to prosper at current prices. We have welcomed the 145 Kodiak employees who've joined Whiting and they hit the ground running and made a seamless transition into Whiting. We recently completed our first set of wells on properties acquired from Kodiak. In the Moccasin Creek area of Dunn County, North Dakota, our first three-well pad achieved an average initial production rate of over 3,470 BOEs per day. That's a great start to the assimilation of the Kodiak acreage. We posted another record production and continue to lead the way in new completion designs in the fourth quarter. In the Niobrara, results have been strong in the Niobrara C zone and the Codell/Fort Hays formations. We believe these returns from these formations will equal our Niobrara A and B zones and complement the enhanced capital productivity we've seen in the Williston Basin. Moving to slide four, Whiting had a very strong fourth quarter and again posted record production. With a focus on the Bakken and the Niobrara, our total net production reached a record 131,260 BOEs per day, a 13% sequential increase over the third quarter of 2014 and this only included Kodiak for 24 days. In the first quarter, we will see the full impact of Kodiak, with guidance for 163,000 BOEs per day. As you can see on slide number four, 88% of our total production in the fourth quarter came from our Rocky Mountain region, primarily the Williston Basin. The Bakken/Three Forks represented 77% of our total production. On slide five, you can see the strong compound annual growth rate in reserves and production from Kodiak and Whiting combined over the past four years. Slide number six shows our 2015 capital budget. Please note that $1.8 billion of the $2 billion budget, or 90%, is going into our highest rate of return areas. We elected not to defer completions. Our goal is to continue to drive costs lower, such that 3-to-1 ROIs and just over one year payouts are possible at current oil prices. Our 2015 capital budget is approximately 50% lower than our 2014 combined budgets for both companies, yet we expect year-over-year production growth and reserve growth. We will still drill 265 wells and we're confident in their returns at current even $50 oil prices. Currently we're running 19 rigs, 16 in the Bakken and three at our Redtail play for the Niobrara. By mid-year, our total will be 13 in Bakken/Three Forks and three in the Niobrara. On slide number seven we provide an overview of our plays in the Williston Basin, where we now control 812,000 net acres and have over 7,500 future gross drilling locations in the Bakken/Three Forks. As you can see from the slide, we control the sweet spots of the Central, Eastern and Southern Williston Basin, where the wells have cumulative production in the first 90 days of more than 50,000 barrels of oil equivalent, as denoted on the slide by the larger black dots on the Whiting acreage. Whiting continues to lead the way in implementing new technologies to enhance productivity and recovery rates in the Williston Basin. We have very favorable results from slickwater fracs at our Pronghorn, Sanish and Polar project areas. With slickwater, we completed two wells at Pronghorn that averaged over 1,400 BOEs per day in the first 60 days. At our Sanish field, the Brehm 13-7H well was completed in the Middle Bakken using a slickwater frac design. Production from the well has held up, with 90-day rates averaging over 1,100 BOEs per day. Moving to slide eight, you can see our development drilling plans and what we called our wine rack for the Bakken and Three Forks across the Williston Basin. Slide number nine illustrates the improved production results we are realizing using better completion designs. In 2014, we experienced productions gains of approximately 30% over 2013 in our initial production rates, as well as our 30 day, 60 day and 90 day average rates, very important. On slide number 10, we show our Williston Basin production profile for 2015. We expect well costs to decline to under $7 million from $8.5 million. On slide 11, you can see our Redtail field in Weld County, Colorado, where production increased 18% quarter-over-quarter. Our first Niobrara C zone and our first Codell/Fort Hays formation tests continued to perform well. The Razor 25B-2551 well, completed in the Codell/Fort Hays averaged 400 BOEs per day in the first 120 days of production. The Razor 25B-2549 well, which is completed in the Niobrara C zone averaged over 380 BOEs per day in the first 120 days. Both wells were drilled on a 640-acre spacing unit and when drilled on 960s we estimate 450,000 BOEs EUR per well. We estimate a total of 6,685 future gross drilling locations in the Niobrara A, B, C and Codell/Fort Hays, approximately twice our 2014 estimate. Slide number 12 shows our Redtail Niobrara production profile. We're currently at $5 million completed well cost and are driving toward $4.5 million. Slide 13 shows the infrastructure at Redtail. We are on schedule to expand the inlet capacity at our gas processing plant at Redtail from 20 million cubic feet of gas per day to 70 million cubic feet of gas per day in the second quarter of this year. Mike Stevens will now discuss our financial results in the fourth quarter.

[Michael J. Stevens:]

On slide number 14 you can see our fourth quarter 2014 adjusted net income available to common shareholders was $58 million or $0.44 per diluted share. Our discretionary cash flow in the fourth quarter totaled $419 million. Our guidance for the first quarter and full-year 2015 is detailed on slide number 15. You will note that our LOE and DD&A per BOE were down again in the fourth quarter and are expected to continue to decrease in 2015. We anticipate DD&A of $21 per BOE in Q1 2015 down from a full year 2014 rate of $26 per BOE. In large part, this reflects the positive impact of the Kodiak transaction. Our fourth quarter G&A was elevated by transaction costs. Cash G&A costs per BOE are expected to decrease to $2.50 in 2015. Finally, please note oil differentials have been contracting and are now guiding for $8.50 to $9.50 per barrel in Q1. On slide number 16, our 2014 EBITDA margin remained strong at 69% of our blended realized price per BOE. This occurred despite lower commodity prices in the second half of 2014. EBITDA margins in 2015 are expected to remain above 62%, even with significantly lower oil prices. On slide number 17, you can see our capital structure. We have $4.5 billion of bank commitments. With $1.4 billion drawn on our credit facility, we had $3.1 billion of liquidity at the end of 2014. As we move through 2015, assuming an average $50 NYMEX oil price for the year and that 750 million of the Kodiak bondholders accept our one-on-one offer next week, we see our liquidity at 12/31/2015 at $1.35 billion. Planned asset sales of up to $1 billion would further improve that liquidity position. Slide number 18 shows our outstanding bonds as of December 31, 2014, including the three bond issues that we assume from Kodiak, our offer to purchase the three Kodiak bond series expires next Tuesday, March 3. Based on current trading levels we expect $750 million to come back in. It also shows that we are well within all the covenants in our credit agreement and our bond indentures. Slide number 19 shows our crude oil hedge positions as of February 13, 2015. On slide number 20, you'll see our fixed differential crude oil sales contracts that are locked in at an attractive differential of only $4.75 to $6 off of NYMEX. That starts in March 2015 and will have a positive impact on our company-wide crude oil differential. With that, I'll turn the call back over to Jim Volker.

[James J. Volker:]

Thanks, Mike. Despite the pull back in oil prices, ladies and gentlemen, we remain very confident in our outlook for continued growth in our production and reserves. We know that we have one of the highest rate of return acreage positions in North America. Our efficient operations and leadership in the implementation of new completion technologies enhances the capital productivity of our asset base helping to offset the impact of lower prices. We've taken prudent measures in 2015 to reduce our capital budget by 50%, while maintaining our financial flexibility. Our 2015 capital budget of $2 billion reflects a very disciplined approach to maintaining our financial strength, while preserving our long-term growth plans. In summary, over the past 12 months, we built an even strong Whiting. Our Kodiak acquisition added to the high quality of our inventory. Our asset sales lowered our operating cost structure. Our premier Williston Basin and Niobrara acreage positions deliver some of the most profitable drilling results in the industry with a combined drilling inventory that exceeds 14,000 gross locations. We look forward to implementing in the current environment. Sanchi, please open up the conference call for questions.

[Operator:]

Thank you The first question is from John Freeman of Raymond James. Please go ahead.

[John A. Freeman:]

Hi, guys.

[James J. Volker:]

Hi, John.

[John A. Freeman:]

The first question when I think about the rigs in the Bakken going to around 10 at midyear, could you give me kind of the split between the rigs that will be on the Whiting versus Kodiak legacy acreage?

[Mark R. Williams:]

John, Mark Williams here. Basically, we're taking all of those rigs and concentrating them on the best properties and those properties tend to be largely in the central part of the basin, in Sanish and we have one that's going to be going down to Pronghorn initiating a new program that we're starting down there, but most of them will be there in the central basin.

[John A. Freeman:]

Okay and then last quarter, Mark, you had mentioned when we got the first glimpse of the pretty encouraging results in the Niobrara C as well as the Fort Hays Codell. You had mentioned that you were kind of targeting like six initial test well and when after that was done you'd have a pretty good idea of kind of how of the acres was prospective, I think initially you were thinking maybe 50% of your acreage was prospective for those zones. Has that thinking changed at all?

[Mark R. Williams:]

I would if anything it's grown especially for the Codell, the way we're looking at Codell right now is a little bit differently than we look at the Niobrara, it's a little bit more of a conventional reservoir, but if you watch that play emerge across the Delaware Basin, it looks pretty widespread to us the way we map it, specifically on our acreage as we think a big portion of it is going to be prospective there, especially as we go north and west on our acreage, so we think a large chunk, I still can't say exactly how much, but that way our drilling program is designed is we have what we called ITW tests. These are initial test wells that keep it advance of our development rigs and we move concentrically out from the (18

[John A. Freeman:]

That's helpful. Thanks, guys. I'll turn it over to somebody else. See you next week.

[Mark R. Williams:]

Great. Thanks, John.

[Operator:]

Next question is from Scott Hanold of RBC Capital. Please go ahead.

[Scott Hanold:]

Thanks. Good morning, guys.

[Mark R. Williams:]

Good morning, Scott.

[Scott Hanold:]

When – you all obviously had drilled some nice wells in the acquired Kodiak acreage, can you discuss just generally what things you've been maybe doing differently than the Kodiak had been to see those results and with the well cost reductions what kind of drove that as well?

[James J. Volker:]

Well obviously you've hit on a key point. We think we're drilling them for $7 million now, a big cost savings over and above what frankly both companies were experiencing prior to the price drop in oil. And I might say I think we're well on our way toward perhaps even improving, but most of the AFEs that we're coming out with right now in the Bakken are below $7 million, $6.5 million to $6.7 million. I just frankly approved some this morning. So, we're confident in getting really across the Bakken into that 3-to-1 on your money, a little over one year payout and with oil, let's say, at $55, or even $50 depending upon where we are in basin. So, we've had to adjust and we'll continue to adjust in response to the lower oil prices. Mark Williams is sort of eager to talk to you about, what I would say is the exciting results we've seen in the Three Forks at Sanish and let's say the Three Forks on some of the – our own acreage as well as some of the acreage we acquired with Kodiak.

[Mark R. Williams:]

Sure. Just to answer your question there, we – really if you look at the way we're completing the Kodiak wells compared to the way Kodiak was doing it, there aren't a lot of big changes. They were using cemented liners; we've seen great uplift with cemented liners across our property. So, the other thing that we're doing a little bit differently there is in certain areas we're going to slickwater fracs, something that they didn't do. And I think that's across the Basin we're seeing selected areas that have responded pretty well to slickwater fracs and certainly there's a subset of their acreage that's really doing well with regard to slickwater fracs. So those would be the two biggest things. And as Jim just mentioned, we've really taken a whole new look at the Three Forks on the eastern side of the Basin, Sanish and Parshall with we've sort of fine tuned our completions to do a Three Forks-style frac rather than a Bakken frac. It's a little tighter in the Three Forks and we've remapped the Three Forks there and we're just seeing a whole new renewed interest in our acreage there in Sanish and Parshall. I think some of the other operators offsettings have seen similar things, so we're pretty excited about the Three Forks program going into the year.

[Scott Hanold:]

Okay, I appreciate that color. That's great. And one last question from me. On LOE costs, you do indicate that they're going to be dropping here going forward a little bit. What is the big reason for that? Is it just better well performance or there is something else driving that LOE improvement?

[Michael J. Stevens:]

On the LOE side, we're seeing 10% to 20% cost savings is what we're anticipating for the year. About half of our LOE is variable. I've modeled in about a 5% savings. I think it could be a little better. Rick, you can probably speak to some of the things you're seeing as far as operationally to bring it down.

[Rick A. Ross:]

Yeah, I agree with Mike. This is Rick Ross. We've been working with our vendors pretty hard, both on the capital and on the operating expense side. As you can imagine in this environment, we are seeing concessions from the vendors. And as Mike mentioned, we think we can bring our LOE down somewhere around the 10%-plus range.

[Scott Hanold:]

Okay, that's great. And I'm sorry I missed it, how much of the LOE did you say was variable?

[Michael J. Stevens:]

50%.

[Scott Hanold:]

50%. Got it. Appreciate it. Thanks, guys.

[Michael J. Stevens:]

Thanks, Scott.

[Operator:]

The next question is from Brian Corales of Howard Weil. Please go ahead.

[James J. Volker:]

Hi, Brian.

[Brian M. Corales:]

Hi, guys. The $1 billion of potential divestitures, is that all midstream?

[James J. Volker:]

No.

[Brian M. Corales:]

Okay. Can you expand on that a little bit?

[James J. Volker:]

Properties.

[Brian M. Corales:]

Fair enough.

[James J. Volker:]

Lower value properties...

[Brian M. Corales:]

Okay.

[James J. Volker:]

...that we're looking at. As you know, we're getting back the properties from First Trust that we sold. That's a couple thousand barrels a day. And we have another similar group of properties that are not key to our rapid growth plans and are not as high a rate of return obviously in terms of any future development. So, we're looking at those as well, Brian.

[Brian M. Corales:]

Okay, that's helpful. Thank you. And then if we look at the Niobrara and the Bakken at your reduced rig counts, I think it's 12 and 3 rigs. Does that keep the Bakken production flat? Or is that on a small decline and the Niobrara is still an uplift? Can you maybe talk a little bit specifically on that?

[James J. Volker:]

That keeps the Bakken fairly flat, yes, and the Niobrara is increasing a little bit. That is exactly right. And we have the other production that declines a little bit, kind of the production we're not doing any development on.

[Brian M. Corales:]

Okay.

[James J. Volker:]

It all offsets and keeps our production very flat at this budget all the way through the year.

[Brian M. Corales:]

And if we look out to 2016, I know it's really early. From where we sit today, you probably have a similar budget if we're in the same environment?

[James J. Volker:]

Well, I'm optimistic that next year due to further cost reductions, like I've just talked about, basically getting our well cost in the Bakken/Three Forks down to more like $6.5 million on average than $7 million. I'd just like to sort of remind everybody on the call when we first got in the Bakken, we were drilling them for $6.5 million. Now, we weren't fracing them as big as we are today. But we do see coming from, I would say, the aggressive and well-meaning reductions that we're seeing from our third-party service providers the ability to get down there in that same cost range again and yet realize the bump in production that we've realized as a result of the improved completion designs. So I really believe we could have a lower budget and still see some more growth. So that's our goal for 2016. Lower budget and still more growth, again, by concentrating on the highest rate of return areas that we have and continuing to drive our cost down. Again, I would emphasize for purposes of the way you think about Whiting, we're designed and continue to design into 2016 our operations to make money at current oil prices. We're not postponing completions, we're not relying on the curve to make our operations economic, by that I mean the oil price curve. We're relying on ourselves to make money in the current environment.

[Eric K. Hagen:]

Brian, if I can add just one thing. You could also expect that relative to the $2 billion budget next year, as we get into the second half of the year, the trend should be lower because there was significant carryover of higher cost wells from 2014 that were drilled then but are being completed now that don't reflect all the cost savings that Jim's talking about. So naturally you can expect a lower trend in the second half of the year and significant savings heading into 2016.

[James J. Volker:]

Thank you, Eric. That's good color.

[Eric K. Hagen:]

Thank you.

[James J. Volker:]

I know you know, Brian, that what we're talking about here is somewhat adjustable based upon oil price. Should we realize the contango that's in there, why, it's true, our budget might be $2 billion again. But should we not see that, we're hoping to have a somewhat lower budget.

[Brian M. Corales:]

Understood, thank you.

[James J. Volker:]

Thank you.

[Operator:]

The next question is from Joe Allman of JPMorgan. Please go ahead.

[Joe D. Allman:]

Thank you, operator. Hi, everybody.

[James J. Volker:]

Hi.

[Joe D. Allman:]

A question on the slickwater fracs. Is slickwater fracs the best completion method for Whiting in the Williston and at Redtail? And could you just talk about the applicability of slickwater fracs across the Williston and across the Niobrara?

[Mark R. Williams:]

Just to make a couple of geologic comments and then Rick can talk about the technique. There are certain parts of the Basin that really lend themselves to slickwater frac. So we think we've identified where largely – we're not completely through with this yet, but we think we've identified where they're going to have the most application. You can look at the results across the Basin of where people have tried them out. And the ones that are working best for us are in Pronghorn, are the Polar area, up north of the river we expect to work very well based largely on some work that was done by another company and then we're seeing good results out at Sanish as well, as is EOG over in Parshall. There are other areas that we think may respond well, but it has a lot to do with the nature of the Bakken and we're studying that pretty hard.

[Rick A. Ross:]

Yes, this is Rick Ross. I would agree with Mark. To answer your question, I don't think it's the answer across the board in the Williston Basin. For the specific areas we know we've had pretty good results and we're going to continue with that. In Redtail, the slickwater completion seems to work quite well and comparable to a gel job, so we'll be doing that also there.

[Joe D. Allman:]

Okay, that's very helpful. And then just another question on a separate topic and Eric touched on it. So, if you've got a carryover wells from 2014, does that mean that the production growth in the first half of 2014 is greater than the second half – first half of 2015 is greater than second half. So in another words, as you move from first to second to third to fourth your production growth generally is going to slow down not just because of just lower spending in 2015, but just fewer carryover wells as well?

[Eric K. Hagen:]

Just to be clear there, Joe. I meant carryover of higher cost wells that were budgeted in AFE in 2014 are being completed in 2015. It's not necessarily a big backlog.

[Joe D. Allman:]

Okay. And could you address the backlog at year end 2014?

[Eric K. Hagen:]

I think it's a pretty normal backlog. It's something exceptional for us. We probably had a little bit of backlog in Redtail, maybe 20 or 25 wells. It's a little bit higher than usual, but nothing really extreme.

[Joe D. Allman:]

Okay, very helpful. Thank you.

[James J. Volker:]

Yeah, you're welcome, Joe. We haven't – again we didn't defer anything waiting for higher prices. Basically we're going ahead and completing and bringing them on stream while driving the cost down, so that we can realize essentially the same kind of rates of return and payouts, so as close as we can get to when prices were up in the mid-$70s to low $80s. And just to try to sort of go back and address another subject here in terms of when we talk about the slickwater jobs. I think there's a total of 298, just under 300 cores that have been taken across the Williston Basin. And our geosciences team here has examined and described 234 of those. So we have here at Whiting what we think is the database necessary to customize in a bespoke manner the completions that we're doing in each one of our key project areas. I can't overemphasize that because I think that is what we can use and are using to drive down our cost, while keeping our EURs and our time to payout at the very highest end of the scale.

[Joe D. Allman:]

That's helpful, Jim. Thank you.

[James J. Volker:]

Thank you, Joe.

[Operator:]

The next question is from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

[Michael Anthony Hall:]

Thanks, good morning.

[James J. Volker:]

Good morning.

[Michael Anthony Hall:]

I guess, I just wanted to trickle back a little bit on the potential asset sales. You commented the potential was up to a $1 billion. I guess what sort of timeframe you think is reasonable for your initial sales within that?

[James J. Volker:]

I really don't want to say anything other than we'll certainly accomplish it within the year, that's for sure.

[Michael Anthony Hall:]

Okay. And you've been pretty clear in the past around the North Dakota gas plant as a – potentially in that mix. Just remind me where Redtail stands in that context, those gas plants?

[James J. Volker:]

So as you know we're in the process of ramping up Redtail from where it is at 20 million cubic feet a day to over 140 million cubic feet a day, and so it's not as well co-developed. If you want to think about it in terms of reserves, it's not as many PDP reserves behind that plant. So essentially there you're looking for partners who are willing to do two things. Number one, attribute value to the future growth for our drilling program, and then number two, people who want to participate in that and make it a core area for themselves. So I think just by sort of looking at who's the most active in the area in terms of the midstream market, you can see that there is significant competition there among those likely buyers. So we are in the fortunate position of being able to field that interest, field those indications of interest, and then I'm going to say negotiate for what I would call the best outcome for Whiting in the sense that we do have the ability to look at either a partial sale or a complete sale. So where we are as we've had strong interest and now we're determining whether we'll go with somebody who wants to be a partner or somebody who wants to own it in total.

[Michael Anthony Hall:]

That's very helpful color. Would it be fair to characterize as you guys have been looking at that market both in the Redtail context as well as North Dakota. Given the slowdown in industry activity, organic growth opportunities are probably fewer and further between for likely buyers of these types of assets and so you're getting plenty of incoming interest around these more acquisitive type growth opportunities there?

[James J. Volker:]

That's right, that's right. They have been quick to note, the areas that are having continued development and therefore continued growth at $50 oil and consequently they're concentrating their capital dollars for acquisitions and development of all those areas that make sense at $50-plus oil. And I might say some of them have already been good partners with us in other contexts, some within the same area and in some cases other areas, and so I think we have a good feel for those folks who do what they say they'll do and do it in the timely manner, and meet our needs on time, and on budget, and those are the kind of folks we like to do business with.

[Michael Anthony Hall:]

Great, that's very helpful color. And then, I guess last one from my end is what sort of inventory you have in your core, most economic areas within the Williston running at the current pace. Kind of curious how far out that goes.

[Mark R. Williams:]

I think if you take a look, first of all, at page 7 of the presentation, you can see where our acreage is and so what we consider the core is really the Central Basin, so that would be Polar, Cassandra, Tarpon, Hidden Bench, and then on the Eastern side, that's really the most prolific. They're equally as prolific, Sanish partial and Dunn County; so that's all of what we consider the core. And so if you go through there, and look at the property that we've got in there, especially if you assume sort of the current rig allocation, our inventory runs way out. We're talking out there somewhat towards ten years of drilling in the core, depending of course on exactly what the well density ends up being and so forth, but that's the way we look at it right now.

[Michael Anthony Hall:]

Great, thanks very much. Appreciate it, guys.

[James J. Volker:]

Yes, the number there would be just like we say on the slide, it's 7,500. Thank you.

[Operator:]

The next question is from Mike Kelly of Global Hunter. Please go ahead.

[James J. Volker:]

Morning, Mike.

[Michael Dugan Kelly:]

Hey, guys. Good morning. Excuse me. Slide nine really shows that 2014 was a breakout year in the Bakken in terms of improved recoveries really on a 24-hour to 90-day rate. I would imagine this was mostly driven by improvements you guys made to the completion designs this year. So I'm curious what this trend should look like as you move into 2015, as you put your rigs and your best properties really can we see what – if you want to give ballpark 90-day rates, what your expectations are for 2015's program relative to 2014? Thanks.

[Mark R. Williams:]

So if you look at it what's have been happening with completion technology, especially over the last three years, is we've really been in a period of rapid change and my belief is that as we go into the next year or two years, we're really sort of at an inflection point. We're really growing in our understanding of how to apply completion technology. What's really driving it is how we're distributing our stimulations around the wellbore, so a lot more entry points, which is accommodated by cemented liners that we've been using. Then if you add to that slickwater or hybrid fracs, which allow us to get fluids out into the formation, especially the areas of high oil saturation and that's just allowing us to reach out and touch the reservoir a whole lot better than what we were doing previously. So just getting a lot more granular and the other thing I think is important is confining the stimulation to the area around the well bore, especially if you've got a big development plan and you're planning to come in and do six plus six type of a development plan, six in the Bakken, six in the Three Forks, it's very important you breakup all the rock around the wellbore, so you're getting a benefit of all that. You don't want your fracs to go out too far and interfere with the wells that are adjacent to you, so just trying to get a lot more specific in how we're applying stimulation technology. And my belief is we're still very much on the learning curve there. We've got another two years or three years of real rapid improvements.

[Michael Dugan Kelly:]

Okay. So...

[Mark R. Williams:]

Just go ahead, go ahead. Sorry to interrupt. Go ahead.

[Michael Dugan Kelly:]

I was just going to say, combining what you're still, if you're still in the early innings, on improving the completion designs plus you're moving to your best rock, what do you think you could see if you could just maybe quantify, give ballpark rates for 2015 numbers maybe 90-day, 60-day...

[Mark R. Williams:]

I was just going to say – I was going to refer to our slide, which I mean, has it laid out. The IRR slide, the type curve slide for 700,000 BOE well is about 600 barrels per day to 650 barrels per day, BOEs per day, 90 days out. You can just look on the slide and graph it out, so we would expect something at least in that range and quite frankly if you look at the press release, our wells have been coming in above that. But that's a good baseline for you I guess to start with, Mike.

[Michael Dugan Kelly:]

Okay. Great, thanks. And then one more. Jim, I was just hoping you could maybe give a little bit more color on the potential midstream sale. And just thinking out loud of the pros and cons of going the partnership route versus an outright sale and in just really rough detail what a potential partnership structure would look like? Thanks.

[James J. Volker:]

Okay. Really what we're talking about there would apply for the most part to Redtail and not to the Belfield Plant, or for that matter the Robinson Lake Gas Plant. And to try to be helpful to you there with respect to Belfield and Robinson Lake, there is great interest in it because it has a lot of PDP reserves behind it. That gives us an opportunity to stay as operator of the plant and get commitments for capital to expand it further from people who would allow us to continue to operate through the CapEx period, basically about the next 36 months, where about in that third year from now, we'd make one more expansion. So that's helpful to us because, while we might make a sale there, an outright sale, we do have folks who have indicated willingness to allow us to continue to operate during that period of time. Second, turning our attention over to Redtail, as I mentioned, that's a plant that is on its way from 20 million cubic feet of gas a day to initially over 140 million cubic feet of gas a day. And, there, the reason that we again would want to remain in control of the operation is that we would be able to expand the plant in conjunction with our development plan so that we're not waiting on a midstream partner to do that. And so, to be clear, I'm not talking about an MLP-type of structure that we would do, but I'm talking about a joint venture with an industry partner type, 50/50 in that particular instance. I hope that's helpful.

[Michael Dugan Kelly:]

Yeah, it's great. Thanks.

[James J. Volker:]

You're welcome.

[Operator:]

The next question is from Ryan Oatman of SunTrust. Please go ahead.

[Ryan Oatman:]

Hi. Good morning.

[James J. Volker:]

Hi, Ryan.

[Ryan Oatman:]

In Redtail, I appreciate the leasehold map. And the thoughts on the Niobrara C and Codell results I thought were encouraging. Wanted to see if you guys had any plans to test the Greenhorn and any thoughts on the prospectivity of Greenhorn, Niobrara C, Codell, what have you, south of that Mineral Belt trend?

[Mark R. Williams:]

So, certainly we've been looking at the Greenhorn. Really we've got a team of guys that are working on the entire Cretaceous section in there, which includes the Greenhorn. So we have a very good understanding of it. We think that there's prospectivity right there. Frankly, we've got our hands pretty full right now with everything that's going on in Redtail, especially coming forward with the Codell/Fort Hays and C zone, which we really believe on our existing acreage position which is quite large here. As you can see, we got 185,000 gross acres to look after there. That's really, especially the current environment, where the bulk of our focus is going to be. We continue to look at other places in the Denver Basin really with respect to the Niobrara, broadly beyond the Denver Basin as well, but we've got our hands full here.

[Ryan Oatman:]

Got you. That makes sense. And then on page eight you go through the spacing assumptions for each area in the Williston Basin. Again, appreciate the color there. There are some well locations that are deferred in that wine rack view. Can you speak to what oil prices would cause you to sort of add those back into the development plan?

[Mark R. Williams:]

I'd say that what we've done is we have a strategy here. Plan for success, but drill based on current reality. It's not just the oil price. As Jim has said a couple of times here, it's about the economics of the well. And so getting the well cost down is equally important. So certainly we need to see some increase in oil prices. But as we drop our completed well cost, our profitability goes up and so we expect to be able to add those white wells back into our program at some point. Normally you'd say maybe you wouldn't do that at a higher well cost until you got up to, say, $70 or something. Hopefully we can, as we get our cost down, that number drops to something like $60 a barrel. So I think that's what we're looking at.

[James J. Volker:]

Thanks, Mark. Good job.

[Ryan Oatman:]

That's very helpful. And then just wanted to see the prior operator of Polar obviously had done a ton of down spacing work. Just wanted to see your thoughts on that down spacing and the extended tests there as well, as your own work in Sanish. Any broad trends that you can kind of speak to there?

[Mark R. Williams:]

Sure. I think the pilot you're referring to is the Polar pilot. And I will say the Kodiak guys did just a great job on that. They did something we've done in other areas, and that's intentionally on a few pads down space beyond what you actually think you could be drilling at. And so there is sort of an eight plus eight pattern and trying to test the limits, something I wish we had done at Sanish early on, frankly. But we are doing that also on our 30F pilot down in the Niobrara. So on a very selective basis, down spacing to more than what you actually think could be done. And the results of that have really helped guide what we call the wine racks diagram that show up here on page eight. And so we're not going to be doing an eight plus eight pattern, which that pilot was done on, but it gives us pretty darn good confidence that we can apply sort of a six plus six, I'm speaking very generally here, across at least the Central Basin. And that's what the basis of this wine rack really is.

[Ryan Oatman:]

Very helpful color, very helpful.

[Mark R. Williams:]

By six by six, I mean six Bakken, six Three Forks.

[James J. Volker:]

Right. And just to clarify, when we talk about what we wish we had done at Sanish, even at today's prices, we wish we would have drilled it initially on closer spacing pattern, i.e., the pattern we're following today.

[Mark R. Williams:]

Yes.

[Ryan Oatman:]

Makes sense. Thank you.

[James J. Volker:]

You're welcome.

[Operator:]

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

[Jason Smith:]

Hey. Good morning, everyone.

[James J. Volker:]

Morning, Jason.

[Jason Smith:]

Jim, I just have a few hopefully very quick questions. One is on hedges. It was good to see you guys adding some hedges in the quarter, but can you may be just talk about your strategy on hedging going forward?

[James J. Volker:]

Sure, I'll try to be direct. I would say we're leaning toward three-way collars with floors of $55 to $50 and ceilings up there in the high $60-s to $70-s and that's still available to us today. Even today with oil off a little bit today, those types of collars are still available to us today. And you'll see us adding onto the point that, through 2016, we get up to roughly 50% hedged, but we'll do it over time. So that if – who knows if there is some political event in an OPEC country that drives prices up, we'll be able to take advantage of that. We've done that from time-to-time already in our hedging strategy this year, and it's worked pretty well for us.

[Jason Smith:]

Got it. Thanks. And I guess on the slickwater wells, I think historically your costs have been a little bit higher there. So how are those trending and are you going to be able to get those in line with your $6.8 million expectations for this year.

[James J. Volker:]

That's Rick Ross' department and he's been itching to answer that one, so thanks for asking.

[Rick A. Ross:]

Yes. Concerning the slickwater fracs, right now they are probably about $300,000 incremental to a conventional job, but we're doing some interesting things in specifically Pronghorn and that is using produced water mixed with some fresh water is our frac fluid, which is going to bring our cost down. We've had pretty good luck with that so far, just tried a few, we'll continue to expand on that and again as Mark mentioned that just makes it more economic.

[Jason Smith:]

Got it. Thanks. And last one and really quick. What was your exit rate at Redtail?

[James J. Volker:]

We don't give exit rates like that typically, but...

[Jason Smith:]

Okay.

[James J. Volker:]

Yes, we just don't give them.

[Jason Smith:]

Thanks, guys.

[James J. Volker:]

Thanks.

[Operator:]

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

[David R. Tameron:]

Morning.

[James J. Volker:]

Hey, Dave.

[David R. Tameron:]

So most of the questions have been asked, but I'll just take a bigger picture. I'll pick up that slide, well a couple of things. One you talked about the well cost and it looks like you've have $6.8 million here in the curve. You're saying recent wells, recent AFEs are for $7 million, but what type of cost reductions have you seen thus far?

[James J. Volker:]

Well let's be clear. Yes, we've got a CapEx cost here of $6.8 million to be clear and then we've mentioned $7 million as kind of a average cost of that you could think about to include the highest to the lowest cost. But we're driving those costs down and I tried to make the point earlier that in terms of the more recent ones of AFEs that we're approving today for example, those are in the $6.5 million range. So I – and then I think you probably ought to want to harken back to what Eric had to say earlier about the well costs in the fourth quarter of 2014, and in the first part of 2015, January or so where we had carryover of some higher costs there. So as we go through the year, our cost will continue to come down. We're driving those down every day through things like the approach to slickwater fracs that Rick just described and we're very confident I think that we will be able to get those down consistently in the $6.5 million range and frankly that's great economics. Not to be too quick and dirty I hope, but if we're doing wells that are 700,000 BOEs and netting $30 a barrel that's $21 million. So if we can get those costs down below $7 million while we're doing better than 3-to-1 on our money and we're driving that time to payout pretty close to one year, get it down there to a year and a quarter, year and a half. At least I'll be pretty happy and I hope you will be too, Dave.

[David R. Tameron:]

Yes, 3-to-1 works. So I mean just two more questions and maybe you mentioned this and I missed it, but how much cost reduction have you build on your budget i.e. is there more downside we could see, or I guess upside in the case of lower costs that are build into the budget or downside to the absolute CapEx number?

[James J. Volker:]

They're kind of – the cost savings are kind of blended in here as we go. We're expecting somewhere in the 20% to 25% range by the time we get to the end of the year. If you average it across the year it's probably about a 15% decrease on the Bakken well and a 10% on Redtail.

[David R. Tameron:]

Okay, that's helpful. And the last question again going back to that slide 10, it looks like you have $60, $70 in here, 50% and 72% as far as IRRs. Do you have a comp for what those were at $80, $90 in the old, let's say an old regime a year ago. I'm just trying to figure out, were you getting 70% returns and with the service cost reductions that oil price needed to get, that has dropped by $15, or can you give any color around that?

[Eric K. Hagen:]

The number – this is Eric Hagen. I think the number around $80 at our old cost structure was around at 80% IRR just to put into perspective. That's the number that sticks in my mind and we can follow up after the call and track that down, so I think that's.....

[David R. Tameron:]

You said, $80 and 80%, Eric?

[Eric K. Hagen:]

$80 and 80% IRR.

[David R. Tameron:]

$80 and 80%. Okay, no, that's helpful. All right.

[Eric K. Hagen:]

It will be a little bit lower than that, but in that range.

[David R. Tameron:]

Okay, thanks.

[James J. Volker:]

Yes. And I think you've really done a good job there of bringing out the fact that as we drive our cost down, if you say $6.5 million from an $8 million well that's almost 20% savings and so yes we definitely hope to be there by the middle of the year.

[David R. Tameron:]

All right.

[James J. Volker:]

Thank you.

[David R. Tameron:]

Yes, have a good one.

[Operator:]

The next question is from Mike Scialla of Stifel. Please go ahead.

[Michael S. Scialla:]

Yes. Good morning, guys. Mark addressed this to some extent, it sounds like if I heard you right, Mark, that you consider Dunn County as part of your core acreage. Just wondering how that fits into the 2015 plan. I think if I remember correctly, Kodiak was slowed down there a little bit by some infrastructure issues on the reservation. I'm just wondering where those stand and basically how you're looking at development of Dunn County in terms of the timing?

[Mark R. Williams:]

We have one rig there working continuously in the Northern part of the acreage position. On the Southern part we just finished a five-well program, but we will have a slight hiatus on the Southern part. There is an arm of the Missouri River that divides those two areas, as we lay infrastructure in for gas takeaway, which, Rick, I think is scheduled for later, late in the summer.

[James J. Volker:]

Yes, that starts – it comes back in August that particular rig. So we have one rig sort of working in the North end continuously for the rest of the year, and then one rig that will – is there – was there in January, is there in February, and then starts up again in August.

[Michael S. Scialla:]

Okay. And then, in terms of the infrastructure, is that any impediment at all?

[Mark R. Williams:]

No, not that we can see. It seems to be going ahead smoothly. There is little additional regulatory work that we have to do in there, but there nothing seems to be holding it up.

[Michael S. Scialla:]

Okay, great. And then you had mentioned too, the 30F down spacing test on Niobrara. Just wondering timing wise, where that stands, and when you might have results you can speak to?

[Mark R. Williams:]

Sure. I've been – that thing is going really well. We're getting a lot of great data. As I think we've talked about, we're testing a 32-well density in the Niobrara on that, that's the focus, that's why we're doing the 30F pilot. So we're just about ready to wrap it up. I think we have four more completions left to do on that. So we expect and we're already getting results on that. We got quite a bit of data from it and we're continuing to get data, but we should have the whole thing wrapped up in sometime around April.

[Michael S. Scialla:]

Okay, great. Thank you.

[James J. Volker:]

You're welcome, Mike.

[Operator:]

Next question is from Pearce Hammond of Simmons & Company. Please go ahead.

[Pearce W. Hammond:]

Good morning. I hope you're surviving the snowy weather there in Denver.

[James J. Volker:]

Yes, thank you.

[Pearce W. Hammond:]

Just one quick housekeeping question from me. Based on your capital plan that you've outlined for this year and growth et cetera, do you have a debt-to-EBITDA that you think you will be at, at year end 2015 and for comparison sake, do you have like a pro forma at year end 2014 debt-to-EBITDA?

[James J. Volker:]

Debt-to-EBITDA at the end of 2014 is around 1.5-to-1. Obviously we're coming off the year with a lot of EBITDAX that we generated. When you get into 2015 if we use the strip, we do get into the upper three's, we're well aware of that and we will certainly be addressing that as we move through the year.

[Pearce W. Hammond:]

Right. Because you've got the asset divestitures et cetera?

[James J. Volker:]

We do, yes.

[Mark R. Williams:]

That's right, Pearce.

[Pearce W. Hammond:]

Okay. Well thank you and stay warm.

[Unknown Speaker:]

Thanks, Pearce.

[Operator:]

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

[James J. Volker:]

Great. Thank you very much, Sanchi. Again, we'd like to thank all of you on this call for your interest in Whiting Petroleum Corporation and all Whiting employees and directors for their contributions to a solid fourth quarter and our exciting plans for 2015. Eric?

[Eric K. Hagen:]

We'll be presenting at the Raymond James Institutional Investors Conference in Orlando, 9

[James J. Volker:]

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

[Operator:]

Conference is now concluded. Thank you for attending today's presentation. You may now disconnect.