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Executives

Nicholas J. Sutton - Chairman and Chief Executive Officer

Michael N. Stefanoudakis - Senior Vice President, General Counsel and Secretary

Jeff Roedell

Theodore Gazulis - Chief Financial Officer and Executive Vice President

Michael David Clouatre - Vice President of Reservoir Engineering

Douglas Dietrich

James M. Piccone - President and Director

William R. Alleman - Vice President of Land

Preston Evans

Analysts

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Resolute Energy Corporation (REN) Analyst Day June 19, 2013 3:00 PM ET

Nicholas J. Sutton

We might as well get started. I normally don't need a microphone, but since we're broadcasting this -- we have people on the line. In order to make sure they could hear, we are going to continue to use microphones. So, bear with us if we get too noisy. Just raise your hands and we'll dial it back. We have a couple of minutes I think before the 1:00 official start date. But, as an attempt to get going, we can waste a couple minutes. As well we should watch [indiscernible], but waste a couple minutes going over to forward-looking statement. Michael?

Michael N. Stefanoudakis

Everyone knows we will be making some forward-looking statements [indiscernible]

[Audio Gap]

Nicholas J. Sutton

We don't mean to sort of demean your intelligence. We know you all this stuff, but we have to go through this as matter of course. There's some information about the conference call that is part of this, and the replay will be available for some time. Also, the slides will be available on our website, which I think most of you know.

Let me start out by saying that I've got it easy here today. As you picked up from some of the other speakers, Ted, for example, as he went around the room. He made it clear to today is the day for all of you to meet more of our team, see the depth of the team, which include really, really good people, very experienced people. And so my job is really to be the emcee, to be the Johnny Carson, to be the bandleader, whatever we want to call it. And the real work here is going to be done by the unit managers and the tactical team. So, I'm going to give just a little bit of an overview, I think some of you have seen the slide. The base, it's fixed, our market cap. We're a small cap company, no doubt about that. But we have -- I think the key things I would look at here really involve some of the metrics on the value proposition. We have, SEC case reserves of 87 million barrels. And a takeaway from today is that, that's only the tip of the iceberg. We are familiar with the SEC rules. We all know that those rules, in many respects, as they apply to resource or unconventional plays, are in a state of flux and so we take a conservative approach to how we report our proved reserves. But, again, I think as we go through this today, you'll see that the inventory set, the opportunity set is much, much deeper than that. And not only do we have the opportunity inventory, but the economics associated with those are really very robust. So, that's the thing I would focus on, along with the fact that, as you know, we are an oil producer. You take oil and the NGLs, 11% is left for gas and so we refer to ourselves as an oil company. That's exactly what we are, and it's been about a choice since the beginning of the company when we sat around as a group of founders. Today, what is our strategy? Where are we going to do here? What are our competitive strengths? How do we see the external environment shaping up? We made the determination that were going to be an oil company. Our prior company was a natural gas company because at that time that was the place to be. We turned out to be right. In this round, being an oil company, I don't know whether we were lucky or smart. I don't much care. We turned out to be right. And so, again, from the very beginning we have been an oil company. We aren't one of natural gas companies that has been scrambling over the last, say 2 years, to transition or transform into a liquids-rich company. That's been where we have been since the very beginning.

A little bit of the history. We started in 2004. We acquired the Aneth Unit of the Aneth Field. That sometimes gets confusing because there's the Greater Aneth Field and the Aneth Unit. We acquired the Aneth Unit in 2004, right at the end of the year. And then we started working on Chevron, which was the major owner and the operator of the other 2 units in the Aneth Field, the McElmo Creek Unit and the Ratherford Unit. We were successful in acquiring those in 2006. Sometimes you may want to have some stories, we can tell you some stories about that process. It's quite interesting. But, anyway, then we went on and as we -- after those 2 transactions, we were exclusively in the Aneth Field. We decided that we needed a little bit more diversification, and so our next step was the Hilight Field in the Powder River Basin. We did that in 2008. In 2010, early in the year, we did a transaction that brought us into the Bakken. When we did our IPO in 2009, people said, well, what's next? So we think we need to have one more leg under the stool. Today, where are you go to do be? I mean, logically, if you're an oil company, you're going to look at the Bakken, you're going to look at the Permian, and there, maybe a couple other places. But the first opportunity that we felt fit us turned out to be Bakken, and so we did that in 2010. We expanded it with a farm-out from Marathon that year, and then in 2011 we saw an opportunity to really get into the Permian. As Doug Detrick [ph] mentioned earlier, he came on in 2011. We opened our office in 2012. We now have 30 employees there. That's really our focus, and now that we've got that other leg under the stool, it's time to kick one of them away. And, as all of you are aware, we're in a process that could lead to the divestiture of our Bakken assets.

So, that's kind of the history of the company, how we got to where we are. We call ourselves regionally diversified. We are -- we'll put a big question mark around the Bakken. But, again, we're in southeast Utah, we're in the Northern Rockies and we're in the Permian Basin. A little bit about the proved reserves, a year ago, 2 years ago, Aneth would have been the vast majority, including works in the other areas. But the Permian is making great inroads. We're expanding our Permian presence in a significant way, and as we move through our drilling programs and our capital programs in the Permian, I think you're going to see those ratios change significantly. And you look at the capital expenditures, obviously, the vast majority of capital go to the 2 big areas, the Aneth area and Permian.

Company overview. I mean, I can let you read it, I kind of walked through it. For those of you who are on the phone, we're on Page 6. The takeaway from Aneth -- and Jeff is going to go into a lot more detail -- is it is an incredible asset. It continues to grow in its production profile. And mostly, right now, we're focusing on expanding CO2 [indiscernible], but there are a lot of other things that we're doing there as well. So it is an asset that spins off free cash flow, stable production and we don't play the decline curve. We have an incline. Now, how many big oil fields, 1.5 billion barrels of oil in place originally, how many of those have an expanding or an increasing production profile? I would suggest not many. The Powder River Basin is area we like. It also spins off extra cash flow. And one of the things that brought us to that area, originally, was the old cliché about good things happening in good neighborhoods. Nothing good ever happens in a bad neighborhood and we were in a good neighborhood. And so, by having a presence, an operating presence, we have the ability to really examine the rocks, we have people focused on the area. And there are some great plays that emerging in the Powder River Basin, and we're targeting the Turner, the Mowry the Minnelusa.

Moving to Permian. As you know, we made some significant acquisitions at the end of this last year. We began drilling on the acquired properties early this year. We assumed operations of most of the acquired properties at the beginning of April. And we're real excited about the fact that we're going to be spudding our first horizontal well on our Permian properties, really, within the next couple of weeks. It could be this month.

We have -- we'll show a dramatic increase in production between 2012 and 2013. Now most of that is going to be the result of the acquisitions. But I the way I put is, I don't care where I get my growth from, whether it's by the drill bit or by acquiring. Some years, it's going to be more about the drill bit and some years it's going to be more by the acquisition. This year, we're going to record roughly a 50% increase in production over the last year. And that's heavily influenced by the acquisitions that we've done. We also are involved in some drilling, and we're involved in an area which is very active. And we think we're going to see not only results internally for 2013, but our activities as well as the activities of other companies in the area. I think we're going to set up some really, really exciting opportunities in 2014 and beyond.

Just a rundown of our agenda today. It's pretty straightforward. I mean, we've discussed -- started, sort of quick overview but turn it over to Jeff to do the Aneth Field. We'll do a quick break and then Doug is going to step up and walk you through what we're doing in the Permian Basin, followed by Preston in the Northern Rockies and we hope you're all able to join us for dinner and some relaxation after this.

A reminder of our guidance. And I think -- I don't want to get lost and the numbers but guidance is still there. I mean, we have an adjusted guidance that's been out for a while. We anticipate a 50% increase in production, as I just mentioned, but also we're working hard on our unit metrics. So we expect to see a decline in our LOE per BOE, a slight increase in our G&A as we staffed up to handle some of the activities that we've got on our plans. The production from those activities will eventually close that G&A metric down. But, right now, because we are staffing up in anticipation of -- as part of the early stages of some of this aggressive activity, we will see a slight degradation of G&A metric. Our tax metric is going to improve. That's partly just by the expansion of our Permian Basin production relative to the rest of the company.

With that, I'd like to turn it over to Jeff, who's going to talk about -- oh, yes. I was hoping -- something to give you. But, okay, introduction. I've covered a little bit of this. Fields like the Aneth very rare, in my opinion. We've got excellent current economics, stable production. We'll walk you through what those economics are. In large, OOIP, original oil in place, presents significant opportunity. And the way I look at it -- take a look at 1 million barrel field, and you increase your recovery efficiency by 10%, you've got 100,000 barrels. Don't get me wrong. I'd love to have a whole closetful of million-barrel fields. When compared to what you get with the 10% increase on a 1.5 billion barrel field, I mean it just -- everything gets warped. And so, with that huge OOIP, you've got significant rewards for anything you can do to the increase recovery efficiencies.

Now, you all know, we're very active in CO2 in this area, the CO2 tertiary projects. You guys know this stuff as well as anybody. CO2 projects can deliver significant incremental reserves. And, again, you measure it against 1.5 billion barrels in place, those recoveries amount to millions and millions of barrels. And this field -- another thing that makes it unique. We're 25 miles from the largest naturally occurring CO2 resource in the country. It's the McElmo Dome. We'll walk you through a little bit about our contracts with Kinder Morgan, which operates the Dome. We have a good long-term secure supply of CO2, and we own and operate the pipe that comes from the McElmo Dome to this field. Again, that's very, very unique. We can enhance production with modest capital expenditure. And if we look at our maintenance CapEx -- that's kind of a buzzword these days -- well, we can maintain this field in a flat production profile for years and years and years with very little spending. So, again, very unique.

Now, Steve Mooney [ph] stood up and introduced himself, mentioned how we had been increasing production through our Aneth Field CO2 flood [ph]. You see -- this is the field production, and in barrels per day from 2009 to where we are presently and where we think this is going to go. So, again, I challenge people to come up with examples of very large oil fields that spin up free cash flow while having an increasing production profile. Very unique, in our opinion.

And now, I'm going to turn it over to Jeff.

Jeff Roedell

So is this working?

Nicholas J. Sutton

It is.

Jeff Roedell

So, again, I'm Jeff Roedell, the Business Unit Manager for the 4 Corners area, which are in [ph] the Greater Aneth Field. And as Nick mentioned -- I mean, if you are going to design your oil company from ground zero, you'd be hard pressed to start with a better foundation than the Aneth complex. As he already mentioned, 1.5 billion barrels of oil in place, over 43,000 gross acres, I mean, it's truly a giant oil field. It's produced, right now, with about 720 -- just less than 720 wells. Most of which are produced -- slightly more than 1/2, producers. A majority of those are live wells. Although there are pretty good spattering of electric submersible pumps, and we're getting higher production levels from those wells and a few flowing wells. And then just slightly 1/2 of the wells are injectors, support the water and CO2 flux.

So we produced 430 million barrels of oil through the end of 2012. So, again, puts it in that giant perspective. And this is one of those forward-looking things is that I should stay away from. But if you look about -- even Resolute's net proved reserves of 56 million barrels, and looking forward to maybe some ultimate recoveries, it's not hard to think about -- maybe a number it has a 6 [ph] in front of it out there, ultimately. So, and things [ph] -- those are supported by current engineering or SEC rules, it's not hard to think that, ultimately, this field might get there.

Our current production through first quarter 2013 is just under 11,700 barrels a day on a gross basis, gross oil equivalent, and 6,037 barrels a day net to Resolute. And I don't remember if it was mentioned yet, but it's a 98% oil here under the Aneth asset. So, very wet and very profitable. Has ROP of about 25 years, which means a lot of things to me, and is a good solid base for a long period of time. Hopefully, there's a lot of upside potential here.

Left-hand -- talking about, before turning it over to Jason, for a minute, is this -- traditionally, the field's been operated as 3 separate units. It is developed as the Aneth Unit, McElmo Creek Unit and the Ratherford Unit. Those are divided somewhat equally across the structure itself, as Jason's going to point out. It, really, truly is one large oil field and one structure and we're moving toward operating more like that.

So, with that, I'll turn it to Jason for a second.

Unknown Executive

Again, I'm Jason. I'm a geologist for Aneth property. As Jeff mentioned, the Aneth Field is a monstrous carbonate stratigraphic trap. This map, as you see on the right-hand side, is a PhiH map summing all of the porous interval within in the Lower Ismay and the Desert Creek horizons, and these are the horizons that we produce from at Aneth. If you look at the left side here, this is a type log shown on the left track. That's a gamma ray curve so we can understand what our lithology is and how clean the rock is. On the right side here, you can see a resistivity curve, which we can use to understand fluid saturations, and somewhat, porosity. You can see the markers here that show you the different horizons that we produced from. The red horizon is the Lower Ismay, that's our shallowest horizon. And then we produce from the Desert Creek Zone I, Zone II. We set divides to Zone I and Zone II, also into the A, B C horizons. And this map here, that you see on the right, is the sum of the Lower Ismay, Zone I, Zone II and Zone III PhiH. It's a conventional oil reservoir. Porosity tends to hang out between 5% and 15%. Permeability, we see usually in the tens of millidarcies, but it can range up to 100 millidarcies commonly. And in some cases, we can even see a whole darcy of perm. And then our depths are typically ranged from 5,500 to 5,600 feet across the field.

Oh, how big is the overall column? The Lower Ismay, the total interval that you see here, this is about -- well, these marks here are 50-foot increments. So, about a 350-foot column total. So, the Lower Ismay is about 50 or 60 feet, on average, across the field. The Zone I of the Desert Creek, that's typically like 30 to 40 feet but it can get to be up to 65, 70 feet. And then the Desert Creek II, that typically hangs out around 150 feet.

Theodore Gazulis

Thank you, Jason. Moving in on the numbers, and everybody here likes to talk about dollars, so we'll start with that. If we look at 2012 actual numbers from a barrel of production, from the Aneth Field, we're actually net about 47 barrels -- $47 for every barrel in operating income, which is a great basis for the company. As we dig into that a little bit farther, you can see the majority of it here is really has made up of -- production taxes are the biggest single chunk. Not a lot we can do about taxes. But if you look at some of these other ones, work-over in particular, other parts of the LOE, you'd notice that a -- if think about those, they're really anchored more to, say, well count. So, your workovers -- again, it's more -- relate back to the number of wells that you have been working on in 1 year, not so much the oil production itself. So one of the neat things about a CO2 project is you're able to grow the production without greatly influencing the number of wells. So things, like this workover cost, it's going to stay pretty flat in overall dollars, which means that'll actually decrease on a per-barrel basis as you produce more oil with the same number of wells. That's true of some of the other things. Labor is another one that's like that. So, as we're able to grow production in the Aneth Field, another side benefit is that operating costs, on a per-barrel base -- per barrel of oil basis should reduce over time, and that'll actually improve that margin to $46, $47 a barrel.

A couple other nice things about the Aneth Field. Some places -- a few of the assets changed with the tides. We have a nice contract that's set up here, so it's very steady, not a bad offset at all. So that really helps, being predictable good basis. Another part of that foundation aspect. So I'm going to dig into that just a little bit deeper then. If you take that $47 a barrel and you multiply it out by our net production of 6,400 to 6,700 barrels a day projected for 2013, you end up with about $110 million to $115 million of total cash generation. And if you start taking away from that, the CO2 purchases, which are estimated to be $20 million to $22 million; and then from that, the other capital for development projects, drilling new wells, CO2 expansion, things like that, we're projecting that to be about $50 million to $58 million for the year. Generates free cash flow of anywhere from $35 million to $40 million. So that's a great basis for the company. It's a lot of to be invested in other places, and hope to grow the company and give everybody a good solid rate of return.

I'm going to start diving more into the technical aspects, stuff where I'm more comfortable at. So you're going to start in the -- so I'm on Slide 15, for those that are maybe online following along. We'll start with the McElmo Creek Unit. McElmo Creek Unit was one of the first or the first part of the field that was -- had CO2 expansion put into it. And they started in 1985 out there. And if you look at the production profile on the slot in the upper-left, you can see where the CO2 injections started. And then you can see how the production curve deviated from what would be the waterflood decline.

And there's a few things I'd like to point out relating to that. One is the peak out here, which turns out to be about 13 years after initiated the CO2 flood. They got a peak increase of about 30% over where they started from. So, not bad, I think that was probably a very good project for the time. But let's step back in time a little bit and think about 1985. Well, first off, this is really one of the earlier CO2 floods. So people were still learning about how to process reservoirs of CO2, how to develop those floods. I mean, SACROC, the oldest CO2 flood, has only been on for 13 years at this point in time. So people were really learning how to do this. The other thing that happened in that period of time, some of you may remember that oil prices were at single digits. So here's a company that was trying to make some large investments into a CO2 flood. They're maybe a little bit tentative about how it was all going to turn out and then they're faced with these real low commodity prices. So that certainly influenced the rate of progression out here and how they've developed this project. We're going to contrast that a little bit later with what's happening now in the Aneth Unit, where modern application of CO2 flood and the significant difference that we're seeing down there.

The other thing I can point out is you can really see it here, where Resolute took over operatorship of the McElmo Creek Unit. In about 2006, just from the -- well, production had previously gone on a natural decline of 78%, we'll say. But then it has really tapered off and has even increased a new peak in 2011. And I'm going to show you little bit later, we've got more plans continue to grow that production in McElmo Creek.

So, again, zeroing in on the Aneth Unit a bit more then, and talk more about that CO2 flood. I'm on Page 16 for those following along. Again, the Aneth Unit is about 1/3 of the overall field. It covers about 17,000 acres, has a little more than 0.5 billion barrels of original oil in place. And Texaco actually initiated a CO2 pilot there in 1998. And somewhat similar to the other story of McElmo Creek, 1998, some of you may remember, was not the best time to be making big investments in the oil field. And so I think that really stunted what Texaco was able to do with this pilot, and ultimately they didn't go any further. Resolute took over the operations in 2004, and shortly after, starting injection in 2007. They started expanding the CO2 flood across a good portion of the Aneth Unit.

In the lower-left, you can see slide with some bubbles on it. The size of those bubbles then show -- indicate the overall CO2 injection into each of these injection wells. So the larger bubble, the more CO2 has been injected in there over time; and the smaller the bubbles, the smaller amount of CO2. And that really tells us a couple things. One is that there is some variability to the rock across the field. You can see that there's some areas that there are even more prolific, they take more CO2. Probably offset after higher production levels in others. So these smaller bubbles, in that sense, might be opportunities for us to improve the processing rate. The other thing you can see from that is just the overall progression of the CO2 project. And so this area down here, where we have the real small bubble, those are just due to time. This is the Phase 4 area as we call it. So we've really just started an injection in there. So it's a very small CO2 has been injected in that part of the field so far. So we really aren't even starting to see the CO2 response there yet, just initial indications of CO2 response. So, a lot of growth just coming from the CO2 injection that's already been started in that part of the field. Ultimately, we expect to get about 40% of the original oil in place, through the combination of primary, waterflood and then the CO2 flood in the Aneth Field.

So we'll talk a little bit more about the barrels here. Steve kind of alluded to this early on. In the upper-left, on Slide 17, is a production plot. I'll start by looking at -- you see our first injection in this part of the project was in July of 2007. From that point, up to the peak, is actually an increase of 123%. So this is just looking of the project area, not the full Aneth Field or even the full Aneth Unit, but just the project area where we've put CO2 on the ground. We've actually more than doubled the production out of that area, with the CO2 projects, so great response.

And then the other way to look at that is by looking at this dashed line. The dashed line indicates what would probably have happened under the waterflood if we haven't gone out and done the CO2 flood. So we probably would have progressed along this line, ended up about here. And the difference between where we're at now and that line is about 2,100 barrels of oil a day. So 2,100 barrels of oil a day difference just associated with the CO2 projects. So, very prolific project. If we look at the SEC parameters then, we're expecting, on a gross basis, to recover about 45 million barrels with this project.

On the bottom is a table that kind of breaks out the various phases. We've combined the first 3 phases of the expansion because they're done relatively same time frame and then separated out Phase 4, which was the earlier expansion necessary that I highlighted earlier, very immature, really just getting started. There's a number of statistics I'm not going to spend much time going over. I would like to point out one thing, though, and that's fairly consistent between the 2 projects at the time between first CO2 injection and first response, see, it's roughly about a year. So there's good side and bad side to that. So maybe from an economist standpoint, you'd like to see your return really, really fast. Put CO2 -- spend that money, put CO2 on the ground, we'd like to see production tomorrow. Well, typically, these CO2 projects just aren't like that. There is a time delay between when you put all the CO2 on the ground and when you see the production.

The good side of that is it typically indicates that your process is pretty uniformly out to the reservoir. So in a CO2 flood, if you put CO2 into an injector and a couple of days or a couple of weeks later, you're showing up with CO2 in an offset producer, typically not a good thing because it means that CO2 is channeling through the rock directly from that injection to that producer. And you're not contacting a lot of the reservoir with that CO2. Ultimately, that would lead to lower recovery factor. So the fact that these projects are on the order of a year is actually a good thing. It tells me, from an engineering perspective, that we're probably flooding fairly uniformly out to the rock, recovering a lot more in the reservoir, and we're getting to improve the overall recovery in time that way.

Nicholas J. Sutton

I think the other thing, I'm not sure if [indiscernible]. I think an important point here is the first part of our project is -- or most of that 2,100 barrels a day increase can be a Phase 1, 2 or 3.

Jeff Roedell

That's right.

Theodore Gazulis

I mean, [indiscernible] 1, 2 and 3 of 198 is not standard today for us. We got a lot of opportunities remaining as well.

Jeff Roedell

Yes. So that's really a good point. To repeat what Ted has said is that most of the production we're seeing right now is really from the first 3 Phases, Phase 1, 2 and 3 of the CO2 expansion. And if you look it on an original-oil-in-place basis, it's roughly half of the total area, a little more than half of the total area that we have under CO2 flood now. So there's still a lot more production to come from this Phase 2. So thank you, Ted.

So Slide 18 then is a couple of tables, the top table just explaining the expenditures to date for both CO2 and the facilities. And then looking forward, on a discounted basis for the CO2, future facilities to get a total out here, we take that total of roughly $619 million provided by that 45 million barrels that I indicated earlier. And you get a finding cost, discounted finding cost of under $14 a barrel, which I think could be hard for us to argue as a great finding cost. I mean, we'd like to reduce that in a lot of places.

Good thing to point out, though, is that when we acquired the Aneth Unit, probably without much argument, you can say that it wasn't in the best state of repair. I think that some of the larger oil companies kind of turned their focus from assets like the Aneth Field, and there was a lot of work to be done. So mixed in with some of these facilities number, in particular, was a lot of work to get even the waterflood parts back up to speed, a lot of line replacements, some facilities works, stuff like that. So a lot of infrastructure cost in that $224 million. But if you're able to really segregate those out, and they're all done as part of the same projects when we're doing that CO2 flood, it's hard to separate those assets, if you're able to separate those out, you'll probably find an even lower finding cost for that, so great return on that project.

And then turning on to the McElmo Creek Unit, and if you think back to the initial map, kind of a horseshoe shape to the 3 fields which is out on the zone in McElmo Creek Unit. And I did mention that that has been under CO2 flood since 1985. And so you might think, well, there's not a lot of potential there. It's already been CO2-flooded. Well, kind of an interesting thing happened there when Jason was talking about the various formations in stratigraphic column. We talked a little bit about this DC IIC. The DC IIC is a very prolific part of the reservoir. When you put fluids in there, they move through pretty fast. And the result of that is during the waterflood days, they put a lot of water into that DC IIC, they produce a lot of waterflood back. And again, we look back in time, in 1960s, 1970s, the tolerance for water was quite a bit different than it is now. Oil prices were a lot lower. I think on a relative basis, it cost more to handle that water than it does now. So just for economic reasons, through the 1970s, they're sort of plugging back a lot of these wells to eliminate production from an injection into the DC IIC, what we now call the DC IIC. So really, there's a few spots around the edge that were left open, but for the most part, that part of the reservoir was plugged off and isolated during the years of the CO2 flood. So it's almost like having a whole another field or at least a whole another portion of the reservoir that hasn't been contacted with CO2.

One thing we were finding, too, as we go back into that, and we started in 2010, drilling, back down to either deepen some newer wells or re-completing some of the older ones into that formation, one thing that we're finding is that there are actually a lot of waterflood reserves left behind as well. So we're approaching this as a kind of a 2-phase project, first by kind of finishing or completing the waterflood and then following that with the CO2 flood. And there's a couple of advantages to that.

So moving on to Slide 20, just looking at the waterflood aspect, you can see in the upper left a production chart. So the black line here indicates the production from kind of the upper parts of those wells. So it's everything above the DC IIC and the McElmo Creek Unit. And you can see that they were roughly along a pretty steady decline, maybe just slightly above 500 barrels a day in this part of the field. And then you can see when we started these re-completions, just for waterflood, just really isn't CO2 response, and you see that the actual production is up approaching 1,800 barrels a day from the combined production from that project. And that's actually ahead of our projections, which is indicated by the dashed line. So this has been a very prolific project to date, and we're really just getting started. We've identified 70 well pairs in this area. We've done 25 of those to date. We're working our way through 10 of them through this year. And they have an average of anywhere from 0 to 460 barrels a day, but we'll point out that 0 one was way on the edge. So that's where the DC IIC is really kind of pinched out by the oil and water contacts, so not a lot of reservoir there. But interestingly enough, it may have some good CO2 potential in the future.

So if we look at this thing as a well-pair basis, so 1 injector, 1 producer splitting the DC IIC, it costs us about $1.8 million per well pair. Average production from that well pair is about 110 barrels per day, the initial incremental production. We're estimating about 60 million barrels of -- or 60,000 barrels of reserve for each of those well pairs, and a finding and development cost of about $30 per barrel. So you kind of multiply that out, and you can see what the opportunity really is down here. So it's a great opportunity.

A couple other things I'd like to point out on that. Maybe that finding and development cost is a little bit higher than what we saw earlier in the Aneth Unit, but the one difference here is that you're getting your production upfront. So maybe you spend a little bit more on a per-dollar basis, but you're getting up production early, which really helps out with the economics.

The other thing is that -- I don't know how much everybody knows about CO2, but maybe you've heard from other forums or whatever that CO2 processing really operates the best if you're above what's called the minimum miscibility pressure. So how the CO2 interacts with the oil in the reservoir significantly changes when you're above that minimum miscibility pressure versus being below it. And being above that sets you up for a lot higher recovery ultimately from the CO2 project. So we're also taking advantage of this time during this waterflood to re-pressure that zone, the DC IIC zone, with water and prepare it for future CO2 injection.

Nicholas J. Sutton

[indiscernible]

[Audio Gap]

Jeff Roedell

Good point. So for those who couldn't hear, Nick pointed out that the work that we're doing on these wells that represent about this $1.8 million per well pair is also preparing those wells for future CO2 injections. So while we're spending money upfront, we're avoiding costs in the future when it comes [indiscernible] to do the C02 flood. So thank you.

So Slide 21 then on the left is kind of a map of these opportunities. You can see the darker spot, the darker circles are the wells that have been completed to date. The red are the remaining opportunities. And this is just kind of the center of this opportunity, where we think the best DC IIC opportunity is. One thing I didn't point out previously is when we've done these 25 to date, we actually picked 2 of those to do us kind of a little pilot for CO2 injection into the DC IIC. It's not quite optimum conditions. We're not above the minimum miscibility pressure, but we wanted to get out there and kind of test just to see what it was doing. Now it's really early because we just started that injection in 2012, so we don't have any real production report with that. Like most facilities, there's no bad news. The zone takes CO2 well. We didn't have any of those immediate breakthrough problems that would cause you concern. You can put injection in here one day, and it shows up over here the next. So from that perspective, everything's looking really good going forward with CO2.

We continue to progress this through the waterflood expansion and then on into the CO2 flood. We expect to grow production about 29% per year in 2014 to 2019, after which we should go on a pretty consistent, about 8% decline afterwards, as you saw with the previous CO2 flood in McElmo Creek. There's about 84 million barrels original oil in place associated with this project area. And so when you combine the 2 ultimate recoveries that we expect between the remaining waterflood reserves and then what we can get with CO2, we're looking at somewhere around 17% or about 14.6 million barrels for this project.

Now looking at it the same way we did with the Aneth CO2 flood, you can look at the facilities that have been spent to date, so that's mainly well cost, as I think mentioned before, working these wells to prepare them for CO2. And you get those waterflood response now. We're looking to get in the same method, kind of discounting the future CO2 stock, facility stock. Now we do have higher future costs there because we'll have to install some infrastructure to handle that additional CO2. There'll be a similar -- excuse me, more well work and facilities work to do. That brings you to a total of about $222 million all in, again, for that 14.6 million barrels of expected ultimate recovery. Now it brings you just over $15 per barrel of oil equivalent for finding and development cost, which, again, is very competitive.

So again, move then from -- around to the third field. In a lot of respects, this really has been the third field. And I hate to admit it, but I think historically speaking, Ratherford Field just hasn't gotten the attention of the other 2. It's roughly the same and in terms of original oil in place, about 1/3 or 400 million barrels of original oil in place. But if you look at the expected ultimate recovery right now just based on what we're seeing now, we've got a lot of work, we're talking about 26% ultimate recovery, so significantly below that 40% that we are looking for in the Aneth Field. There's a lot of work that we think we can do. I mean, I think the story here for Ratherford is really a lot of upside potential.

So we're looking -- we're working right now on optimizing the existing waterflood, so by improving the sweet and the processing rates to the existing waterflood. So we'll do that. There's some redrills, some infill laterals, injector producer sidetracks. And then ultimately, we'd like to introduce a CO2 flood in the Ratherford Unit as well, and I'll talk about that a little bit more. So I'm on Slide 24 now. And on the left is an area map of the Ratherford Unit. And you can see outlined in red is the potential in a DC IIC. So this is a deeper zone that Jason talked about earlier. And then there's also some potential for CO2 flooding in the upper zone, the DC I. And there's somewhat overlap, and in some ways, they're a little bit different. I'm sorry, I got these 2 confused. DC IIC in the blue, in the upper right; DC I in the red, up in the lower left. But ultimately, between those 2 projects, we're looking at somewhere between 15 and 21 million barrels of ultimate gross production, incremental production from those 2 CO2 projects, so great upside potential in that. Resolute's share of that would be about 11 million barrels. So we're working towards ultimately initiating that flood. Of course, there's a natural progression of how we're going to move these floods across the Aneth and McElmo and ultimately, to Ratherford. But as Bob mentioned earlier, there's a lot of things to consider when you think about how you time all these projects and what yields the best result, so a lot of work to do in that area.

Again, moving now back up to the whole field perspective, the whole greater Aneth. And what we have here are kind of 3 opportunities. These are all well-related opportunities that exist across all 3 units. And we've outlined the infill laterals, new drills and what we're calling short lateral pairs. And again, 3 different opportunities. The top 2 kind of address the same thing. So here, you're looking at it from an aerial perspective. You've got a portion of the reservoir that you're just not contacting, you're not getting production from. So you either need to put a well there or somehow contact the reservoir in that area. And there's 2 way to go after that. You can do it from a lateral, potentially from an existing well. So you go out, and you go somewhat at a high angle or even horizontal to target an area that doesn't have a well now. Or you can go out and stand in the middle of that and drill a vertical well. There's advantages and disadvantages to both. If you haven't had a tin play, maybe it's an area that there is no DC IIC, there's only DC I in this area, you've just got one zone that you're targeting, then a lateral might be a great way to get that because you can do it for lower cost, you can contact a lot of reservoir, but you're not getting a lot of vertical coverage. So it works well in that single-zone situation. Now if you're in an area that you've got a lot of DC I and DC II, if you want to cover that whole 350 feet, you're best doing that through a vertical wellbore. So that's what's identified here.

The short lateral pairs are really addressing another opportunity, and Steve has done a lot of work mainly in the Aneth Unit, where we've got some wells that, just compared with their surrounding wells, just don't produce as much and don't inject as much. Something's wrong with this well pair, and a lot of them go back to when they were initially drilled and completed. And so it could be that there's some localized geologic problems here. It could be that they were damaged in the initial drilling and completion process. So we're actually trying a few right now. What we're doing is kind of what we call a short lateral pair, where we just exit the existing wellbore and we just try to get a little bit away from the -- in the original wellbore and do a modern completion on that. And hopefully, we can get around whatever type of damage is there, whether it was induced during the drilling completion process or if it was occurring from a small geologic feature or whatever.

So there's a number of locations outlined here, 9 to 15 on these infill laterals, new drills of 15 to 30, 25 to maybe as high as 55, and this is just in the Aneth Unit, on the short lateral pairs. The other thing I want to point out about this is -- well, first off is a huge amount of opportunity there, just looking at this completely aside from the CO2 and waterflood assets, great opportunities here. The deal of point is that this isn't even an exhaustive list. I mean, when we go out and try some of these, at least taking short lateral pairs, for example, in the Aneth Field, we find out that we come up with a great way to implement these and we can find the application across the other 2 units and expand that opportunity. So there's a lot of upside potential with all of these.

Another thing I want to point is this is not exhaustive and that there's other opportunities to enhance the flood in all 3 of these fields. So that might be through trying to improve sweet by realignments or other techniques. I mean, there's people doing things [indiscernible], stuff like that. There's always ways that you can improve recovery through improving sweet or maybe edge possibilities moving closer to the boundaries of the units with production and injection. There may be opportunities for a residual oil zone processing the CO2. There's a whole suite of opportunities there to identify in either the current waterflood, CO2 flood opportunities and these well-related projects. So again, some success with some of these will really determine how far we can apply and to what extent.

So an example of that is up in the Aneth Unit. So we're cleared out in the far west corner of the Aneth Unit. To those following along, I'm on Slide 26 now and looking at the map on the upper left. You can see the red star was an open 40-acre location, and in 2012, we drilled that open location. And for being so close to the edge, I think a lot of people are probably amazed at the results that we saw. And so it came on with a peak production rate of about 832 barrels per day. So for one day, it produces 832 barrels. Now averaged out over the whole month of a peak production, it came in at about 550 barrels a day for that month. Still a well I'd like to have in my personal portfolio and instill great results out there and put it on the edge. And it did drop off some, but it's still maintaining above 200 barrels a day, having one kind of odd test back in February that we haven't quite got our hands around. But it looks like it's going to sustain that over-200-barrel-a-day rate for quite some time. So just an awesome well.

We have some traditional wells in that area that we've permitted and are occurring, hopefully, in January 2013 drill schedule. And that's 1 producer and 2 offsetting injectors. So initial inclination might be to just go out there and drill a bunch of producers, but that really sub-optimizes the CO2 flood and ultimately could reduce the recovery from the surrounding wells. So we need to get some injection out in that area to support that the B-414 and the C-123 producers that we're going to drill. So ultimate recoveries from those wells are estimated to be about 250,000 to 300,000 barrels per well. So a great project there, and hopefully, we can reproduce that B-414 or even come close.

Another inherent thing with the CO2 flood is that if you inject a CO2 and then switch through the reservoir what comes out with your production on the other side, that CO2 contacts that oil, and a certain amount of the oil products, or the hydrocarbons, get mixed in with that CO2 and aren't really separated out easily. So they're entrained in that CO2. So a lot of the fields have gone through the process of looking at different ways to extract those other hydrocarbons and gain value from them. We're looking at a potential membrane plant. So a membrane plant is just one of those techniques that you can use to extract those hydrocarbons from the CO2 stream. It's simply -- as I concluded, it's almost like some giant filters that kind of filter out the -- actually, that kind of filter out the CO2 from the hydrocarbons, but they leave you sellable hydrocarbons when it's all said and done. Now if we're able to put this in and based on a peak throughput of about 100 million cubic feet a day, you can achieve as much as 8 million cubic feet of methane per day and 1,500 barrels a day of NGL. And again, this will be a pretty capital-intensive project. It's highly dependent on NGL and methane cost. So right now, we're still reviewing

[Audio Gap]

the project design itself and the economics. We want to make sure that we -- if we make an investment like this, it's a good investment and has a good rate of return for all our investors. So that's currently under review right now.

Theodore Gazulis

[indiscernible] everything that we do is -- every project we look at [indiscernible]. And this project is a great project as we look at it, but realistically, we may [indiscernible]. This is a theme that really sort of ripple throughout everything [indiscernible].

Jeff Roedell

And so to summarize that for those online who couldn't hear Ted, his comment was that all of these projects, membrane plant included, have to compete from the same product capital with all the other projects throughout Resolute's business. And for the membrane, we put up against those other projects and we'll invest our money where it makes the most sense. I hope paraphrased you.

Theodore Gazulis

Perfect.

Jeff Roedell

Okay, thank you. And so I'm going to finish up my portion by talking about the CO2 supplies. So one of the other things you may or may not know about CO2 flood is that CO2 supply can be a challenge. And if you think about where most of them are in the Permian Basin, I'm sure many of you have heard stories about the challenges to get consistency if you supply to those projects. We are -- again, if you could handpick an asset for a company like Resolute to be its foundation, you can imagine putting a 1.5 billion barrel oil field just 28 miles from one of the world's largest natural sources of CO2 and having a dedicated pipeline between that field and ours. So I mean, it's just amazing to have those things lined up like that. So we're really, really fortunate from that aspect to be so close and if you upstream from a lot of the problems that you're having with the deliveries into the Permian Basin. We do have a long-term contract with Kinder-Morgan for that CO2 supply. Right now, they're contracting to supply up to 72 million cubic feet a day for 2013. That increases in 2014 and '15 to 100 million cubic feet a day. Our current capacity [indiscernible] we have a pump at the McElmo Unit, McElmo Creek Unit into the pipeline, and it can supply about 68 million cubic feet a day right now. And we're in the process of installing a second pump. And so when the need arises, we should be able to move up to 100 million cubic feet a day through that pipeline with that installation. I believe that is the last line. I think this one is for Nick, right?

Nicholas J. Sutton

[indiscernible]

Jeff Roedell

So thank you all for your time, and I look forward to talking with you more.

Nicholas J. Sutton

And what we've done on this slide is summarize the various areas that we've just gone through and try to quantify for you with one spot just what we currently have on our books in terms of reserves and what's out there unbooked. And I think the takeaway from this is that if you look the bottom right, you total it all up, 10 million to 16 million, 17 million barrels. That's net to Resolute. That's not a gross number. Now you can see it is made up of a lot of different line items, and each one of those line items, as Jeff pointed out, has the possibility, if not the likelihood, of expanding with time. As we go through these, we learn more and more. We did that in B-414. I think the results were -- we asked our engineers and said they were shocking. Again, it gets back to the fact that we have a 350-foot section, 1.5 billion barrels in place, and so we produce a little over 400 million barrels a day. There is a lot of hydrocarbons left in the system. So right now, we've identified 10 million to 17 million barrels net to the company that are not on our books. And I think we're going to see that number go up. I don't think we get any credit for that, but we are working diligently to bring those from one column into another column.

I'd also just point out in passing that we showed a production growth curve. That was strictly oil. You saw that earlier. If we added for example the NGLs from a membrane plant, another 1,500 barrels a day plus 8 million cubic feet of gas, on a BOE basis, that curve would go up rather significantly. And the reason I point that out is some graphs that you've seen in the past have been on BOE rather than BBLs. The curve you saw earlier was strictly oil.

So before we go on to the Permian Basin, I'd give something -- we'll do a Q&A. That's always good news. I was going to say before we go on to the Permian Basin, let's wrap up with a Q&A on Aneth, especially while Jeff is still -- got a mic handy and can jump in. So are there any questions? Yes?

Question-and-Answer Session

Unknown Analyst

Going back to Slide 10, where you have peak production for Aneth around 2016, 2017, do you have any of the resource potential in that slide captured in that number, where it starts to decline after that and then ...

Jeff Roedell

Well, Aneth -- I think as Nick said, what you see on the slide is simply proved oil out of our reservoir. So that doesn't have things like Ratherford CO2 on it. It doesn't have any of those other resource projects.

[Audio Gap]

Nicholas J. Sutton

We are recycling, maybe, 25 million to 30 million cubic feet a day. We continue to expand available compression and, right now, we're recycling about 55 million cubic feet a day. There's -- I think our peak was 58 million on 1 day when everything was proceeding smoothly and perfectly. But consistently, about 55 million cubic feet a day of recycle.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

[indiscernible] With the Aneth 414 B was such a good well, I understand why you down in injection [indiscernible] then we have rating issues that's not there before...

Nicholas J. Sutton

Are you talking to the financial guy or the engineer?

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

[indiscernible]

Nicholas J. Sutton

So what I will tell you what I told you off-line and then we'll see if anybody wants to add to that. So I think pretty close to immediately after seeing those results, they started permitting 3 other wells. And the permitting has taken a, while. With even -- with the several different agencies to get the permits for those wells. We're -- I think that more and more of those are in hand now and the rest are pending shortly, if you have a drilling rig in the field. So our intentions are to drill those just as soon as we have all the pieces in hand which would definitely be before the end of the year, barring any unforeseen circumstances. Now I did allude that there were 2 injectors planned and one producer. I think part of Noel's question was, why aren't they all producers? And my answer originally was that, for the long-term recovery -- to recover the most oil out of that area, we really need that injection support to enhance both the waterflood and the CO2 flood operability and, ultimately, the final recovery and reserves. That's not to say that we might test those injectors for a short period of time, we wouldn't want to draw the reservoir pressure down too much in that area. Like I said it, ultimately, it can reduce to what you get in the long run. So the plan is to have one more producer, 2 injectors. And I think what you'll see is, will more than make up for -- in the long run, you're going to make more barrels of oil through having an additional producer in those 2 injectors than you would, if all 3 were producers.

Theodore Gazulis

So now that you've heard from the engineer, probably, the financial side, of course, we don't know -- we would love to see all that stuff, all of this work be done strictly on the producer bay. But again, the philosophy that we've taken here and, essentially, everywhere within Resolute is short-term decision making, it just -- it doesn't really work for us. What we want to see is, how do you maximize recoveries over the long term. And by drawing down pressures, at the edge of the reservoir, you're deferring the ability that injects CO2 there, in an effective way and that doesn't work well.

Unknown Executive

I'd also point out, with respect to timing, that our permits are largely dependent on the federal government and some agency offices work well, and we can apply for permits in one office and get the permits turned around very quickly. In this particular region, it's not uncommon for your permits to sit for months and months, going on years. It's a bit up in the -- the well is, if you run into the same thing, where it could take a year to clear a permit, so I've had an enlightened -- that team is working diligently to get out ahead of permitting, but it is largely outside of our control. The other thing I would point out going back to Jeff and Ted just talked about is that this is -- this field is giant analog system and everything connected together in same thing where it could take a year to clear your permits. And if you take too much out of one place, you're going to be drawing down pressure, everything is in constant balance and so, Steve does a lot of work along with the field guys to monitor, where is the injection going? And what is the surrounding production coming from, what does it look like? Are we over injecting a particular area or are we under-injecting in a particular area? Now the fact is, that strong production in an area can cause one to say "Well, we're under injecting. But you balance all that and it's a team effort between of reservoir engineering and operations engineering, that it's something we do on a pattern-by-pattern basis to try to isolate areas that we should be adjusting the relative injection percentages, or ratios. So again, very, very complicated, as Jeff pointed out early on, we've got -- we have over 700 wells down here. We also have 700 wells, our 700 injection points or take points. All of them have to be in balance and it all has to go through an infrastructure system that has to be imbalanced, but you're not not banking up to bin balance but you are backing up pressures in any particular part of the field. Again, huge effort and a lot of good people spend a lot of time doing, -- looking at those and, working with those, to make sure we do stay in balance and maximize production. John?

John Freeman - Raymond James & Associates, Inc., Research Division

We heard what we [indiscernible]

Unknown Executive

The latest numbers I saw were roughly 20 million net to our Resolute share, roughly 40 million on 100 gross basis. Ron?

Unknown Analyst

[indiscernible] ended so [indiscernible]

Unknown Executive

Yes. That the -- my recollection is, and I don't have the pages right in front of me, but if you look at Aneth and McElmo, if we produced everything that's on our books, it would take us to roughly 36%, 37% ultimate recovery in that area and depending on which price that you use, you could get that up to 40%. That is not targeting 40%, working backward, but it is filled up of how these 2 units are engineered. Interestingly, we think, and we can't point to necessarily anything in particular, other than other CO2 flood fields, that, that 40% could go significantly higher. Historically, our engineering groups, they work with something called dimensionless curve. And its your hydrocarbon core volume versus your ultimate recovery and it goes up, and then it just bends over. They take a horizontal, in other words, they assume when you get to roughly 12% incremental recovery for the CO2, everything stops.

That is somewhat artificial and it's just the way the field has been engineered, thus far, and there's an ongoing dialogue about that. So simply changing one's approach to that metric could raise it to a higher number than 40%. And I think some of the Permian producers are clocking 50% or even more. And so that is all within the realm of possibility they will have to engineers out of 26% because of really 2 things in my opinion. One is, as Jeff said, that is really the third field. I mean, it wound up when we acquired it, it was being operated by Exxon Mobil and Exxon Mobil was also operating McElmo Creek. But the 2 fields came to Exxon Mobil, up through different channels of acquisitions, and historically, they were operated by different companies. And I think that we first-- our first entry in the field was with the Aneth Field that we acquired from Chevron. So that's were we put all of our focus. And that's where we did the basic and tackling, and Answer to the field with the Aneth Field that we acquired from Chevron, so that's where we put all of our focus and that's where we did all the basic blocking and tackling and all of that fundamental field worked to the well. And then the demo is the 2 things, so that's the next area that we focus on, partly that's where the CO2 pipe comes into the field, that's where the infrastructure is built out, so it was logical to kind of work in that way. As a result, Ratherford has always been out there and there's this field and it hasn't gotten nearly its attention in its history from any of the major operators and frankly, it's third on our list of priorities, as we go through there. Can we take that 26% up to 40%? I don't think there's any reason that we could take -- we can't. A lot will depend on, once we get in there and look at the results. But that's a 14% increase in recovery against that 40 -- 430 or whatever it is, million barrels, ultimate recovery, but's original oil in place as to that unit. I'd do some back of the envelope and I'd say, take that 400 up by approximately 14% [ph]net it down for a call of 15% [ph] royalty, net it down to our interest and it is a lot of barrels. And it's never been booked by us and, at some point, it will.

Unknown Analyst

Now before you leave [indiscernible]

Unknown Executive

In that particular slide, the question is, is that factored in to the slide that we kind of, as a wrap up slide or some of these various projects? And yes, there is a line item for the DC IIC and a line item for the DC 1A and I think that encompasses the, some CO2 has, by no means, a complete CO2 roll out across that unit, that is one of those, the -- that's the original slide where we showed you the sort of area encircled with red and area encircled with blue, that's our current focus point on the studying of this field but this does not, by no means, represents all that the red unit could deliver to us. The numbers on the slide that have the circles on them, those are gross numbers, this slide is net numbers. So to sum it up, Ratherford is partially -- Ratherford CO2 is partially in this slide that you see on Slide 29.

Unknown Analyst

[indiscernible]

Unknown Executive

I think that we should be able to roll it out across the field to get the 12% incremental you're referring to. And add that 12% we'll be on a gross basis, then we have to net back our ownership share. Yes?

Unknown Analyst

[indiscernible] Operating

Michael David Clouatre

I think that the -- when you start, when you say, operationally, let's talk about -- I'm going to turn it over to the operations guy.

Unknown Executive

Hey, Mike, I think there's some work to do there first. I mean, the numbers show that, really, the water flood itself hasn't been optimized yet, so I think it will be premature to jump out there and start with the CO2 flood without first going in and trying to optimize water flood and make sure that we're effectively flooding the reservoir and also getting our minimum visibility pressure. Then in the process of doing that or, in conjunction with, there probably would be a lot of a -- a fair amount of facilities work. Lines that would have to be installed for both injection and production, some separation facilities and then the biggest piece, ultimately, is going to be the recycle capacity and that's where some future decisions need to be. Are we going to pipe that gas to one of the other fields in the Aneth Unit gas plant or what do we end up doing at McElmo plant or do you build a separate plant in Ratherford. So it's a lot of questions yet to be answered before some internal questions that need to be answered before we can really directly answer the end of unit gas plant, or what we end up doing with the plant or the separate plant in the Ratherford, so there's a lot of questions yet to be answered before, a lot of internal questions that need to be answered before we can really directly answer your question. And as to the part about whether you're at the DC 1 or the DC 2, I think that also remains to be seen. I mean, ultimately, you'll probably look for a way that you could take the advantage of both maybe in that area where they overlap, there might be an ideal spot to start and try to get from both there and then spread out in both directions depending on how your facilities go within the other resources that Nick alluded to earlier, available CO2, recent capacity and some power. So that's not quite a direct answer but there's also a lot of things that need to be done before you know exactly how you'd implement that plan.

Unknown Analyst

[indiscernible]

Nicholas J. Sutton

And so the question was, looking more at the DC IIC area and then the current well density and a mix of vertical to horizontals that, the question is, is that area developed? How you would you want it for the CO2 flood now or isn't there work to be down. And then I don't know a direct answer to that, because I haven't personally studied the Ratherford unit, as much as others have, I just -- I can't go on back to the fact that the waterflood probably hasn't performed to the highest extent. I think there's work that needs to be done there and I can't tell your right now if it's through additional wells or through repair of existing wells, but there certainly has to be some work done.

Unknown Executive

[indiscernible]

Unknown Executive

Yes, Craig's here, Craig Phillips is our engineering manager, he could probably speak to that.

Nicholas J. Sutton

Yes, that particular part of the field is very unique. It's -- you can't really say that any of the rock out here is homogeneous, but that DC II area did waterflood relatively well, even on an 80-acre spacing, with vertical wells. And so it's not clear that we would need to use horizontal wells in that area in order to get the speed of response that we'd be looking at. It's certainly an option that we'd consider as we'd be down spacing to 40-acre vertical wells. But that's an area that I'm personally very optimistic about, in terms of our ability to efficiently CO2 flood that. Does that answer your question?

Unknown Analyst

[indiscernible]

Nicholas J. Sutton

I don't know if -- was there a question that? One thing I was going to say is that, Jeff mentioned that, kind of said well, if we pipe fluids from one area to another and the fact that where's your gas can come from or where you're going to take it to, as well as water, where's the water, where's the water going to get injected, all of that, that raises one point, that it's like I've mentioned, it is. We are on a process of trying to put Humpty Dumpty back together again. This field was originally divided into the operating units back in the '60s and it was discovered 1956 and did not take long for a lot of players to be in there drilling and, I mean, it was just a -- production went up to 100,000 barrels a day and it was clear, in the early '60s, that reservoir pressure was being drawn down and they would have to do some sort of pressure maintenance and that meant waterflood, where you can't do an effective waterflood, when you've got Epson or at that point, the standard of New Jersey drilling, right next to Phillips, right next to Superior, and there's no effective way, so that's why the federal units were formed. It was to bring some rationality and capability into doing effective waterfloods. And you notice that those 3 units all have roughly comparable original oil in place. And so they add to that, it appears be how those units were divided up, how the assets were divided up and then, they divided up operatorship with each unit being operated by a different company. Well that works reasonably well but if you look at the development of the field and why did McElmo get CO2 and no place else did? With and get CO2 in no place else, well they were operated by different companies, different priorities. Now that we've got one company that operates the entire field, it's more efficient for us to try to, as they say, put Humpty Dumpty back together again, but take and reunitize from 3 different units into one unit. So we don't run into who owns the gas that's being recycled, off Havana, when it could be brought over to Ratherford and reinjected there, and water coming out of Ratherford could be put into the water injection well, that's in the Aneth unit and all that now. All that can be done with contracts and then you're monitoring exactly how much water you're shipping or how much CO2 you're shipping. All of that creates a level of accounting headaches, engineering headaches, it lessens flexibility to a degree. And so we, as they say are in the process of trying to put the entire field back together as one field. It should be relatively straightforward. But life doesn't always work that way. We're the largest working intra zoner and the other very large working intra zoner is Navajo Nation Oil and Gas. Between the 2 of us, we've got essentially 100%. Not exactly, but essentially, 100%. So we're in a process of trying to work with Navajo Nation Oil and Gas and the Navajo Nation for them to see the benefit nomination for them to see the benefits and understand really what it means. And that's just a process and we have no idea how long that process will take. But I think that, overall, it will benefit us, it will Vale Nation Oil and Gas benefit the validation of oil and gas and the rest of the nation itself, so it's something that we would push forward with all sensitivities there. Any other questions?

Unknown Analyst

The $20 million [indiscernible]

Unknown Executive

We would certainly perhaps to incur LOE on an ongoing basis. And some of that would include evolve working over wells and whatnot. But the CapEx we're talking about essentially is CO2.

Unknown Analyst

[indiscernible]

Nicholas J. Sutton

Well, you saw that out of the field, right, if we look at 2012, we cash flow $47 a barrel for the field operating cash flow standpoint. And so we have time for a serious reduction in oil prices and still have positive cash flow, especially when you consider that the largest component of LOE is taxes. And the taxes will go down as oil prices go down, and so you get to get some ripple-effect like that has to you take them into consideration. So we could operate the field and keep everything going and be cash flow positive at a substantially reduced oil price, even if can do math. A different number would be, when do you start reevaluating your capitol plans now would be we had to do that. A different number would be, when do you start reevaluating your capital plans? And clearly, it would not be X minus $47, would be a higher number but you saw the rates of return on these projects and the good thing about the field that I'll keep emphasizing is we don't have to spend a lot of money on the whole production plan. It's not as if we're on a hyperbolic decline curve and if we stopped doing something, we're going to be quickly be going from 100 a day to 10 a day, let's take a look at the maintenance CapEx, it's nominal. And so, at probably $60 of value, you start to reassess some of your capital plans. But the other thing I'd point out is, when Jeff went through his, he to get free cash flow of about $30 million or $40 million or something like that. He also took out $50 million to $58 million of CapEx. Now all of that CapEx, or virtually all of it, is discretionary. So if you really want to look at free cash flow, it's a substantially higher number than the bottom line that Jeff pointed out. What he wanted to be sure to include is that you take some of that cash and recycle and get back to the field to grow the production. But in a reduced product price environment, we can put your scale at capital to that and that field will continue throughout a lot of cash flow. Other questions? Okay. We already had a break. So why don't we just move on into the Permian, we'll be a little bit ahead of schedule instead of being a little behind schedule. Doug, are you ready?

Douglas Dietrich

Yes, sir.

Nicholas J. Sutton

Okay, where is the little slide -- here we go. Need to steady. I think we've done talking about some of this, as I do a little bit of the introduction. As we moved into the Permian in 2011, when we acquired acreage in Reeves County, the Delaware Basin, as you know, to the Western part. We subsequently acquired a small producing asset in the Midland Basin. I mean, we like both of those basins. The Midland Basin is, certainly, as you all know well, has more activity than the Delaware Basin. But as you'll see, the Delaware Basin has activity that is incredibly intriguing and, I think, suggests really strong potential for our acreage. We mentioned that, that Doug joined us in November of 2011. And we really go about trying to build a good solid operating and technical staff, scientific staff in our Midland office and, currently, we're at 30 employees and we are fighting the ongoing Midland battle of where do we put people? And I think we're ready to move forward on some new office space, that should take care of that for, at least, the near-term. Then we talk to you all over time but how we wanted to take those initial positions and expand on because we do like the Permian, for the obvious reasons. I mean, here I'm preaching the choir in most respects. And so, at the end of 2012, we did 2 acquisitions. One that involves Midland Basin, assets a dead plus, bit acquire in most respects. And so at the end of 2012, we did 2 acquisitions, 1 that's been involved, Midland Basin assets plus field coverage, field out of the Northwest shelf in New Mexico. And then we acquired about 32% of the assets of a company package that we called the 5 RSP assets because RSP was the company that we acquired it from. But part of that deal was we had an option to acquire the remaining portion in the first quarter of 2013 and that's what we did. So we think we have a really strong position, we're continuing to lease, we're continuing to look at opportunities to expand our position there, but in the meantime, there's just a lot happening really on a grassroots basis and I'll turn it over to Doug.

Douglas Dietrich

Can everybody hear me all right? Okay. all right. Thank you, Nick. For those of you who are -- didn't get a chance to listen to the introduction online, my name is Doug Dietrich, I'm the business unit manager for Resolute in the Permian Basin. As Nick pointed out, I came on board in November of 2011, and I wanted to spend the next hour, 1 hour and 15 minutes, talking about the Permian with you guys. It's one of my favorite subjects, having been in Midland for the last 23 years and having spent my entire career in the business in Midland. I see it as a very exciting place right now, one of which Resolute is very well-positioned to take advantage of a lot of the opportunities that are coming around within the Midland, the Permian Basin and so on and so forth.

And so you'll see that, as we kind of go through the presentation here. But the Permian, as far as Resolute is concerned, is really a transformational asset base. Not only to the company, but I see the Permian as well, kind of transforming a little bit from verticals to horizontals, we'll get in to a lot of that, as we go through. But we've got roughly 40,000 acres, spanned over 3 really different geologic basins. We talked about the Midland Basin, the Delaware Basin and then the Northwest Shelf. 20,000 of those acres or net, 67% of it, is held by production and 90% of it is operated. So we can control most of what we do out there.

One of the reasons I believe that Resolute focused on the Permian back in 2010, 2011, when they were trying to add stools was the function of looking for something that was pretty oily and you can see right here, 70% of all our production, based on Q1, was oil production. So another interesting topic on the Permian, not only oil, but it's also very operator friendly, which allows us to move very quickly. We can get drilling permits within 2 to 3 weeks. So in that aspect, it's very nice to be able to operate in the Permian, and you got a significant infrastructure of service companies, manufacturing, places that are shipping all over the world. So it's all right there in the Permian, as I'm sure you guys know. So it's an exciting place to be right now, not only for me and the Midland team, but for Resolute as well.

Looking out on a pro forma basis. In Q1, we were just over 5,000 BOE per day. We've got approximately 400 vertical drilling locations within the Permian and it also provides -- our positions right now provide exposure to about 70 horizontal locations and we believe in each one of those locations. We have between 2 and 5 potential horizons per location. And it's a fact that the Permian just keeps giving back, multistage, multi-state, we're finding things in it everyday.

So let's kind of dive into it, a little bit deeper in the particular areas. We'll go to our Gardendale area first, which is in the Midland Basin. We've got 4,600 growth in net acres, we own it 100%. For those of you who've ever flown into Midland, we're nearly located just on the outside of Midland, north of the airport, you'll fly right over it. We've got about 3,100 barrels of oil a day coming out of it in Q1 and our plan for 2013, includes 3 horizontal wells and 20 vertical wells. We'll get into those a little bit later. We're halfway through the vertical wells program now and, as Nick mentioned, we are set to spud our first horizontal in about 2 weeks.

Primarily, we're collecting microseismic data over the vertical wells and the horizontal. We actually will be frac-ing 2 wells this week, vertical wells, that will include some microseismic work to it, so we'll get that in-house as soon as we can and then on the horizontal, we also plan to do some microseismic on it. All that information will allow us to further develop and define what our development strategy looks like going forward. We also had some petrophysical model and data we've licensed from seismic data and have that and are reviewing that currently now.

This was the acquisition that we did, we acquired 32% of it at the and of 2012, we acquired the remaining 68% in March of 2013 and assumed operations in April. So we've had it for 2 months, 2.5 months and continuing to find opportunities through the property.

Let's kind of talk about the stratigraphic column. Michael Rumin [ph is in the back, he's our geologist, kind of looking at this project so if you got any questions, you may turn it over to Michael. But we then talked about, our capital program includes 3 Wolfcamp horizontal wells, it's going to be targeting this Wolfcamp B section right through here. Why the Wolfcamp B? Because we're seeing some positive offset results from offset companies. We're also seeing very good characteristics on the logs that indicates that this is a primary target for us at this point in time. We also do see secondary targets, which includes the basal Spraberry, the Wolfcamp A and maybe a client, things like that. So again, 2 to 5 horizontal segments through this property. We also are developing it, in combination with the horizontals, we have a vertical well program going on. It is frac potential. Each 1 of those vertical wells are usually frac-ed between 7 to 10 stages and we're targeting right now of up to the Spraberry. But as you can see, it's just a wealth of reservoir right here. We talked about the horizontal activity that's offsetting what our position and here is the slide that kind of represents that, I'm on Slide 35 right now. So we've highlighted our Resolute horizontal locations. The first one that we will drill is this 1818H, which is right here, the mid-cap 1818H. Again, it is a Wolfcamp B target. We've got some really significant results from a couple of offset wells that were drilled by Diamondback and RSP, all in the Wolfcamp B, so this, obviously, gets us excited. The logs through the sections gets us excited, they've got the team in place now to capitalize on these opportunities. We've got a drilling group, we've got a completions group, so we are geared up and ready to go and we'll be moving to this Wolfcamp B mid cap shift 1818H. Yes sir?

Unknown Analyst

[indiscernible]

Douglas Dietrich

The question was, will those horizontal wells be replacement for verticals in the Wolfcamp B? And I think really the answer is, it's going to be a combination. We do, obviously, like the horizontals for a lot of reasons. Wolfcamp B zone is a primary target right now, but in order to capture some of that other reservoir rock within the other portions of the Wolfcamp, the Cline, the strong, we're all going to need to continue to do some vertical work. So let's go to Slide 36. This is kind of the outline in the well design for our horizontal. Again, we anticipate spudding in about 2 weeks. Drilling will target the Wolfcamp B in 9,800 feet TBD. We'll go out approximately 4,300 feet of the cased and cemented, and the drill cost to get us to that point is estimated to be $3.1 million. Upon the completion, after we get it drilled, the completion will include a plug and perf design with a total completion cost of about $4.2 million, that includes microseismic of about $200,000 for this first well. Again, that will allow us to really enhance our development strategy, moving forward, with the horizontals, with the verticals and how we jointly develop this property.

So let's kind of talk about some of the economics behind our horizontal wells. We're estimating about $7.1 million in capital, to drill, complete and equip these things. The first one includes some microseismic data so that costs us a little bit higher, but moving forward, we anticipate about a $7 million well with 30-day IP numbers between 400 and 1,000 BOE a day, with ultimate recoveries in the 300,000 to 600,000 barrels of BOE range. It's good gas, it's 1,300 BTU per MCF, liquids rich, economics generated 25% to 45% rate of return. And if we put it on paper, right now, we've identified 22 locations horizontally and, if you had up 2 to 5 horizontal targets for each location, you get to some pretty impressive resource potential numbers through there.

So moving to Slide 38, kind of ties in a little bit more, in depth, on the vertical program. Right now, as I mentioned, our plan for 2013, includes 20 vertical wells, 10 of those have already been spudded or drilled; so pretty impressive that we could stake up the property, start operating April 1, start executing on our capital program and already be halfway through our vertical well in 2, 2.5 months. So it speaks volumes to how we're able to react and move. Yes, sir?

Unknown Analyst

[indiscernible]

Douglas Dietrich

We would like to look at longer laterals. [indiscernible] Right now, we're focused on sections, and sections, mile by mile, 50 to 80, I think, across one way or the other, most of these things we anticipate drilling in kind of a northwest -- I mean, a north-south orientation. So a lot of times, we're going to be limited to what we can do by our leases. There is a few locations like right here where we could get into some longer laterals. Yes, sir?

Unknown Analyst

[indiscernible]

Douglas Dietrich

I'm flexible, either way. I mean, if you guys have a question you need answered, I'd be happy to answer it at the time. I have Michael back there telling me we need to hurry up a little bit so... Oh, okay. I got you. All right. So we're on slide 38, talking about our vertical program. Again, 20 wells, 10 of which have been drilled and spud. We have a completion program in place to complete 3 to 4 wells per month, 3 of which have already been completed and are flowing back. We've got early indications that they are in line with our expectations, both from a capital standpoint and from a reservoir component standpoint.

So we go over into the economics of the vertical program, $2.1 million capital per drill, complete and equip. 60 to 200 BOE at 30-day IPs, generating about 125,000 barrels over the life of the well. Again, some nice gas production associated with it, with factors of 1.3 rates of return, pretty attractive. You got 40 locations out there that we've identified, geo-vertically and resource generating about 5 million barrels. Yes, sir?

Unknown Analyst

[indiscernible]

Douglas Dietrich

The question was, how are we getting to these location camps? And when we talk about our verticals, we're talking really about 40-acre locations on the Midland Basin side and on 80-acre locations on the Delaware Basin side.

Unknown Analyst

[indiscernible]

Douglas Dietrich

We may be able to downstate. Maybe in the Q&A, we can get Michael to kind of talk a little bit more about that question for you. All right. That is Gardendale. It's our newest property. It's our focus right now. It's got all the capital, or most of the capital associated with the Permian budget focused on it. And we, like I said, we've got a horizontal planned, we've got verticals planned, we're after it, we're busy, it's exciting time. Let's go over to the Delaware Basin, now where we acquired acreage in 2011. And Jim, I'm sorry, I'm probably right in your way.

James M. Piccone

Yes. So let's say -- I did mention we acquired acreage in the Delaware Basin, Grace County in 2011. We started really putting out a full-court press on the development of that acreage in 2012 where we drilled several vertical wells. So it's a -- when we finished up 2012, we now have 21 gross wells out there, a little over 10 net. We've got 2 primary project areas in Reeves County, the first one being Mustang, we call it Mustang, which is this acreage block here, operated at 51%. And then we talked about Appaloosa, our Appaloosa acreage, which is right here in the circle, and we have that 100%.

I'm talking off of Slide 40 right now. Our Q1 net production was about 250 BOE a day, 59% of that was oil. And we are transforming or transitioning from a vertical play to a horizontal play in the Wolfcamp, that we'll begin talking about. Here's is a strati column for the horizontal and vertical opportunities that exist out in Delaware Basin, Slide 41. We've got about 1,250 feet of stacked Wolfcamp A. We focused on the Wolfcamp in 2012 with several stage completions designed vertically. It's -- our current vertical wells have completed all the way through the Wolfcamp D up into the third Bone Spring. And we've got some offset operators out there that are targeting Wolfcamp A, C and D from a horizontal standpoint. And we are currently monitoring all that activity right now to help us, as we proceed with the transition. So here is a map of the Delaware Basin and then our acreage in Reeves County on Slide 42.

This acreage block right here is our Mustang. I want to point out a couple of things on this slide. We spent the effort and attention to putting in an infrastructure in this area in 2012, which includes a gas gathering system that takes produced gas out of the field, ties into the Southern Union's gas line up here. We also have an SWD well, which is this blue spot and so all our produced water volumes run basically through the same network and tie into the SWD. So we are well-positioned right here from an infrastructure standpoint to not only reduce the LOE charges with disposal of water, but also to immediately start selling gas as it is produced.

You can see, and as you probably know, if you follow the business, as you guys do, this is getting some interesting press coming out of it, this particular area with the horizontal wells. We've got a couple of EOG wells to the south of us, we got some Cimarex wells over there in our Appaloosa acreage here that's pretty interesting. Again, we're following it really closely. And when they talk about projects, setting ourselves up for a really attractive drilling program in 2014, this really comes to mind right away.

So I can probably flip back and forth between these slides if it helps, but on this slide, we've got a numbered -- the different horizontals, numbers 1 through 5, actually 1 through 6. And here, kind of break those out. So as you can see, really some pretty significant results coming out of this area. Lateral lengths in the 4,000 to 4,500 foot range that sets us up. Our laterals would be just every bit as long, get some really good oil and liquids coming out of this system. And again, with our current infrastructure, we're well set-up to handle this.

When we get into the -- looking at the economics on our Delaware horizontal well, we're looking at about $7 million to $8 million capital expenditure, a little bit more than Gardendale, just a little deeper over here other Delaware basin side. 250 to 700 BOE a day on a 30-day IP, generating 500 to 1 million barrels out of the single well. So our rate of return, pretty attractive, and we believe we've got 50 locations out here with multiple targets. And as a result, it could generate between 50 million and 250 million barrels of oil. When we roll all this up at the end, and I'll turn it over to Nick to talk about the toys and the toy chest. These are nice toys.

Now let's talk about OTB. OTB is -- stands for over the border or on the border. It's our property right here that sits right on the Martin-Howard County line. We are back now into the Midland Basin side. These are Wolfberry-type projects that we're looking at. Part of the acquisition that we did at the end of the 2012 with Siluro [ph] . We did pick up this non-operated piece that we call Big Spring. So we've got about 4,400 gross, 2,200 net acres out here, more than 90% of it is held by production right now and what we're doing in 2012, it was a vertical Wolfberry asset for us. Both areas get us to about the 42 gross wells or 25 net producing wells. We were looking at about 800 BOE a day net coming out of this area in the first quarter on a pro forma basis. We also believe that this also has some horizontal potential as well. And you can see, actually, some activities are starting to develop in this area, in Howard County, on a horizontal basis. You've got element well up to the north and a little bit east of this that is drilled, and I think they're completing a Wolfcamp horizontal.

So again, another exciting opportunity as not only Resolute is taking advantage of these positions, but the Permian as well with the new technology that's coming through, and people are really considering horizontals, looking at the horizontal.

The stratigraphic column for a Wolfcamp or Wolfberry well, we were targeting the Mississippian from 10,500 through the Wolfcamp at 8,500 on our vertical completion. Again, they were about a 7-stage completion. We were leaving the Spraberry behind and we'll come back to it for some recompletion opportunities. The drilling and complete cost were approximately $2.3 million. And I mentioned before the Spraberry does offer some recompletion opportunities behind pipe that are very attractive.

Kind of share with you the economics on a OTB/Big Spring vertical well, $2.3 million, generating 150-plus thousand BOE over the course of the well. We've got 64 locations based on 40 acres of vertical wells and generating a resource potential of about 10 million barrels of oil.

Now moving to Slide 47. We talked a little bit about the recompletes that we have. As I said, we are leaving the Spraberry, currently, right now behind pipe at 7,000 to 8,000 feet. A couple of reasons for this is in the main one, it looks to be -- the Spraberry looks to be a little bit under pressure as compared to the Wolfcamp and Strawn Canyon zones. So it makes sense for us to originally complete the lower zones, leave the Spraberry behind, as those lower zones de-pressure then we can go in, complete or recomplete the Spraberry, bring all of that back together, where the pressure we've seen are pretty similar and we don't see a whole lot of cross flow and things like that. So pretty robust economics. We can do one of these for about $600,000. You've got 81 BOE 30 day IPs. Rates of return can get up to the 50% range. If you look at it across-the-board, we believe we've got 60 to 70 locations or opportunities generating about 4 million barrels.

Then I wanted to spent a little bit of time talking about our Denton field. Denton was an asset that we picked up at the end of 2012. We're now in New Mexico, in Lea County in New Mexico. It is a Silurian, Devonian carbonate. It's really a legacy field. I mean it goes back to 1949. Highly fractured and faulted. We've got cumulative production through December '12 of roughly 110 million barrels and about 100 Bcf worth of gas. So large OOIP numbers, very interesting reservoir and you can see some wells have produced more than 2 million barrels. These are either deep wells, about 12,000 feet, 12,500 Silurian Devonian production. The production profile is very flat on these things. And first quarter, we were generating about 800 BOE a day or 88% oil.

We've got a team of technical people, very talented people that are studying this field as we speak, and they have been charged with defining the opportunities in 2014. Again, that's another thing that we're positioned very well for in going into 2014. We can improve the field economics by lowering operating cost, pretty high-cost-operated area. We can leverage our abilities and our experiences through Aneth in our corporate operations group and all our people that are experienced in the operations of high cost areas, bring those guys in, lower these operating costs. We can also enhance the field through infill drilling. I've seen some preliminary work. It looks really good on going down to do some 20-acre spacing. We also believe we have deepening opportunities that are available to us throughout this section. Well optimization work and we've got seismic available to us, too. So the take away from Denton right now is that we've got people studying it. We had some really interesting ideas when we captured it and did the acquisition, and now we're just kind of fulfilling that, looking at it and we'll be ready to go in 2014.

I think that kind of breaks it down between the 4 different areas that we kind of have focused on in the Permian. This slide kind of rolls it all up. Again I heard Nick talk about the toys and the toy chest and these are some really exceptional toys that we can play with. So, I do know, Nick, if you want to kind of speak to the roll up and this slide.

Nicholas J. Sutton

This is some of the formats which you say with respect to Aneth. And the real point is down on the lower right hand, you see that we have identified resource potential of 45 million to 2 -- over 200 million barrels and that, against our existing reserve base, is significant. And the key thing is that as you think back over the areas that Doug walked you through and talked about, these are not stretches by any means. I mean, we don't have anywhere on our books, the Delaware Basin horizontal well despite the fact that EOG has drilled some very stout wells, right off of our acreage. Similarly, in the year, we don't have any horizontal in OTB and Big Spring, and yet the work is -- the horizontal activity is coming our way. So we haven't reached out and make things up. These are very thoughtfully presented, thoughtfully build-out, Denton has no additional potential listed in yet. We believe that there's a lot there in terms of end zone, in terms of deepening.

So across the board, there's further potential for this. If we just look at those things that are sort of within our fence, within our boundary, that's very carefully thought out from the scientific standpoint and operation standpoint, it's 45.5 to over 200 million barrels, and that's on top of our existing reserve base. You see it's a self multiplier. We think it could go higher than that as the industry continues to learn and get better in some of these resource plays. I think the only reason they're not on our books is if you have traditional reservoirs, if EOG drilled right next to our lease line, we can go ahead and be able to flip that, but these resource plays now are subject to a whole different set of rules and regulations as you know so well. And so until we get a broader statistical sampling, where we can draw the curves and make the analog-type argument, there out there is resource potential, but they're very, very real. I think that's about it. Do you want to click on to the next slide?

Unknown Attendee

Yes, sir.

Nicholas J. Sutton

Let's do a Q&A on the Permian, and Doug mentioned a couple of times that Michael is in the back and ready to step in with it is -- was investigated and you see, he's kind of grinning [indiscernible] but, yes, let's take some Q&A.

Nicholas J. Sutton

Yes.

Unknown Attendee

[indiscernible]

Nicholas J. Sutton

Bill, would you address that?

William R. Alleman

On that end, [indiscernible]

Nicholas J. Sutton

Okay as to the particular slide, some of the tracks we don't see red horizontal locations. We have a very, very small interest. It did stretch throughout that section. So when we depict our lease acreage position, we show what we have in that section, in fact, we do have everything in that section. So really what -- we've narrowed those 50 locations down to where we have usually 100% or 50% with a partner, okay. So that's kind of the distinction there. And I'll just add one note to numbers Nick was just talking about, we're in the middle of a current leasing program and we're successful in billing [indiscernible] out here. So we plan on growing this and the grow rate as well. So again, those numbers could be added, too.

Nicholas J. Sutton

Thank you, Michael. Do you have anything to add to that?

Michael David Clouatre

When we put this map together what we're trying to do is put locations on lease holds that we felt we could drill at this time, so the higher working interest section. From a geologic standpoint, we've got well control. You can go all the way from the west side up into over our Appaloosa block to the East. From looking at that Wolfcamp section, it's a very similar section across the highest [ph] stretch. So from a geologic standpoint, it's the consistent section that we think has potential across the old acreage. It's more a function of the working interest we have in employment basically.

Unknown Attendee

[indiscernible]

Michael David Clouatre

Yes. We have a relatively low working interest, there's also [indiscernible] in there. And I believe Apache has somewhat of a lowered interest in there as well. And so we pick that up, I believe in 2011, kind of mid-2011. There hasn't been that much activity, but it's also one of the things where people are going out here and drilling on acreage that they hold the majority interest in. And so what I believe on how these things is going to fall is you're going to end up with partnerships or [indiscernible] agreement. And so what those type of positions do press out here is they close out too much big a spread, even if it is at kind lower working interest, so you can correct the -- you can get in the opportunities without burdening all that cost on yourself.

Unknown Attendee

[indiscernible]

Michael David Clouatre

Correct, yes. Part of it is, one, leasing, and there's also consolidating the area you could block but geo [ph] benefit into other operators' benefit to [indiscernible] .

Unknown Attendee

[indiscernible]

Michael David Clouatre

Sure, yes. Rick was talking about that central, that drilling hole there, and part of that is when we got out here, we realized that part of this is you're going to have to dispose the water and you're going to have to deal with gas. The road commission won't let you produce more than 90 days on a drilling permit. And so that led us into zoning that. We've got a gas infrastructure now, an electrical infrastructure and a disposal infrastructure. And so when you look at this map, we're the only group out here that has that in this area. So it gives us a lot of advantage, especially in that doughnut hole, where you have other operators, they're not going to want to replicate that infrastructure. And so it gives you a value standpoint, an advantage there to work together with other operators to drill horizontal wells.

Unknown Attendee

Just a quick follow, I think with Reeves County. How does the acreage break up between Mustang and Appaloosa in terms of acreage?

Unknown Executive

[indiscernible] probably right now, it's about 2/3...

Nicholas J. Sutton

Talk into the microphone, so people on the webcast can hear.

Unknown Executive

Currently what we have is 2/3 in Mustang and about 1/3 in the Appaloosa.

Unknown Attendee

Just a follow-up on that answer because I'm not sure my math is adding up. But you got 8,200 net acres, your total position in Reeves County is relatively low, 34% working interest, and then at Mustang, it's 51%, Appaloosa, 100%. So, I guess, I was trying to get the exact acreage numbers in just Mustang and Appaloosa. Relative to the rest of the acreage, it's is obviously pretty below working interest in all the other areas.

Unknown Executive

I don't have the exact numbers, I didn't bring those with me today. But in Mustang, and I hate to hip shoot well, but I think we're, on a net basis, around 4,000 acres, give or take. And then in Appaloosa, we're close to about 2,500. We have some other areas, the [indiscernible] area, which is a little satellite area where we drilled 4 wells, the open wells. We got the [indiscernible] area and [indiscernible] acreage to the North. Close that in, but we've been talking about and pressing upon, these are the core areas that we're also additionally having growth, additional leases, too. Yes?

Unknown Attendee

A couple of things. You talked about the operating cost through Denton. So I was just curious what sort of numbers we are actually talking about there? And then the second thing was, in the slightly risk for resource potentials, there's a big swing for the Delaware Basin horizontals. I just want to know sort of what causes the upper or lower limit do you see?

Unknown Executive

I can talk a little bit -- I think, I can talk to the Denton property and our operating cost asset. If you look at our plans, it is about a 27 barrel per BOE operating cost, with the entire Permian rolled out at about 13. And then you have a second part to that or you had...

Unknown Attendee

Potential number for the total Permian. The biggest swing I think is -- it's kind of on this slide.

Unknown Executive

Yes, right here?

Unknown Attendee

Yes, 23 to -- no, it's like 50?

Unknown Executive

50?

Unknown Attendee

Yes. So the horizontals in the Delaware Basin between 23 and 117 just wondering about what causes the lower and upper limit.

Unknown Executive

Those basically calculate back to the higher end of the EUR versus the lower end of the EUR. And it also ties in to how many laterals you think you get at the spacing. I think we went 2 to 5. So fewer laterals and lower EURs gets you the lower number. More laterals, better EURs gets you the higher number. We're aiming for more laterals and higher EURs.

Unknown Attendee

On all the return slides, you gave your returns. What's the commodity price assumption on the range that give on all of them?

Unknown Executive

90 and 325, I believe.

Unknown Attendee

[indiscernible]

Unknown Executive

The returns are more based on the EURs, the deliveries. And the product prices were held fixed, not like REF [ph].

Unknown Attendee

For the EUR numbers on the slides, are those on a 2-stream basis or a 3-stream basis?

Unknown Executive

Mike?

Michael David Clouatre

Hold on, I'm answering to the please. Bookings have been on 3 stream. I think with the exception of, maybe, OTB. And Craig do you want to weigh in on that? The question is on your EUR slides here, was it based on 2-stream or 3-stream?

Unknown Executive

Those were 2 stream.

Unknown Attendee

[indiscernible]

Nicholas J. Sutton

Mike said 3 stream with the exception of OTB for the actual bookings.

Unknown Executive

Yes, Timothy?

Unknown Attendee

[indiscernible]

Nicholas J. Sutton

He was talking about SEC, what our SEC filings. Yes?

Unknown Attendee

Regarding the Gardendale vertical well, what formations, this opportunity you've been drilling in? How deep are you drilling to?

Unknown Executive

We've been going to be Atoka, testing the Atoka on up through the Wolfcamp.

Unknown Attendee

[indiscernible]

Unknown Executive

Yes.

Unknown Attendee

Nick, obviously, there's a lot of exciting activity going around, Gardendale and also the Mustang area from a horizontal basis. What do you guys need to see to be able to commit significant capital from a horizontal perspective over the next, call it, 12 to 18 months. So basically you want to rate full-time in both those areas?

Nicholas J. Sutton

We're starting out with Gardendale. We're going to drill 3 horizontal wells between now and the end of the year. And then as we set up the program for 2014, I think we're just going to continue right along with the combination of horizontals and verticals. And that's at the Gardendale area. Now at the Reeves County, we've been holding back. We had an active vertical program there, and a lot of that was intended to hold acreage. And right now, we are working with a working interest owner to determine the optimal way to go forward. So we're holding back on Reeves until we get things worked out with the joint working interest owner. I would expect to see get resolved before next year, and I would see that -- I would expect that we will be actively drilling horizontally in Reeves County at some point in 2014. Ron?

Unknown Attendee

In Reeves County, in lateral lengths of average, plus or minus 4,000 feet, is there something from a unit size standpoint that's limiting the laterals? Or is it people trying the HBP acreage? Or is it -- is that something that we can start to see those laterals get further?

Nicholas J. Sutton

I really can't comment on other operators. If history is a guide, you look at how did the other different plays were. You start out with the lower lateral, shorter lateral and as the operator get more confident in their ability to stay in zone and just by the economic, we start to reach out further. But certainly, that's going to be done with consideration given to the acreage positions. And I think that in our case, we're starting out, as pointed out in Gardendale, with the section laterals. So you're talking 4,000, 5,000 feet. And if and when we think it's appropriate, there are some areas, some locations, where we could probably put a longer lateral. In Reeves County right now, the ones that we have penciled in are more on the shorter side. And could they go longer? I think, in Reeves, we've got some acreage limitations that would keep us on the shorter side as long as we want to stick to the preferred azimuth of the wells. If you want to go East-West, which I think experience shows as not optimal, and we could probably go longer, but that would be a stretch for us, that is a viable option at this point.

Unknown Attendee

And then shifting to Gardendale, a lot of recent results from Diamondback and even RSP. My understanding, you don't have any interest in the existing RSP or the horizontals that have come out. What's your relationship with RSP in terms of knowledge gathering from the drilling of those wells leading into drilling your Gardendale wells. And the reason I'm asking is you've been able to gather information from the EOG wells, I think, relative to them using your system, but the relationship with RSP and where does their -- where do you start, what did you buy and what did they keep in that Gardendale area?

Unknown Executive

As you remember, back towards the end of the year, RSP had 3 different geographic blocks for lack of a better term, but they were considering divesting, and we really focus on the Gardendale area and only the Gardendale area because we felt that for our purposes it was the most attractive. RSP continues to own the acreage in those 2 other sort of areas of focus for them, and part of that is what your seeing drilled here, and then there was something, I think it was to the Northeast of Gardendale. So RSP is still active, and from a 30,000-foot view, I can say we've got a good relationship with them, but I would turn it over to Doug, because he's right on the ground with them on a regular basis.

Unknown Executive

I think that is a very fair assessment. You know those guys personally. They have been willing and forthcoming with some information. If you remember, at the end of 2012, we picked up a nonoperated position in RSP, just this Gardendale piece. And so from basically January 1 through April 1, the whole first quarter, we were meeting with them regularly on a weekly basis about the assets that we had the interest in, but also they were very forthcoming in some other information on some of their other properties that they had. And so that's -- we continue that relationship. They -- that's where we get some of that information. But this is all -- what you see here has all been publicly disclosed.

Unknown Executive

Yes?

Unknown Attendee

I'm just wondering about the appetite for acquisitions. How big do you see this position in a couple of years Permian in total, or where do you want to get to?

Nicholas J. Sutton

I would approach it this way. And that is we think the Permian is a really good place to be. I go back to the days of the Wattenberg, when we put the Wattenberg together, and I believe I coined the term that is now in common usage that the Wattenberg is the gift that keeps on giving. We see many of the same characteristics of the Permian. You got that large geologic section charged with hydrocarbons. It's got some challenges associated with some of the formations that are not blocking. You get a lot of lenticular stringers of potential hydrocarbons in there. But overall, over that 3,000, 3,500-foot section, there is a lot of hydrocarbon, a lot of opportunity. So we are in the process of building positions there, and our Midland staff and Doug are a key part of that. I think that the technical team and the operating team that we have in place are very skilled, very qualified, very experienced. So I think we've got the various pieces in place that will help us to build in the future. A lot depends on what happens to product prices, a lot depends on what happens to competitor activity, a lot of it depends on how big our checkbook is that particular time. But right now, our intention is to continue to try to go to Permian, and whether that's like that or like that, it just remains to be seen based on a lot of variables. It is an area of focus, and you asked about where we we'll be in 4, 5 years, like I'd be very surprised if we haven't substantially expanded our presence in the Permian Basin. Okay, Bill has got one more.

Unknown Attendee

[indiscernible] What's the lease situation in Reeves County now at this point?

Nicholas J. Sutton

The lease situation declaration with respect to what?

Unknown Attendee

Explorations and how much HBP are you at this point?

Nicholas J. Sutton

Where's Bill? Here you are.

William R. Alleman

Sure. Right now, we have 8,200 net acres. I would say about 2,000 of that is HBP from our 21 vertical well program. We're in an active effort to extend that and actually been very successful on some of the acreage. A lot of the leases have what's called a Pugh Clause. You can only hold with -- where the well is located. In the center of continuous drilling program, we've actively gone out there. In addition to our new leasing, we've extended some additional leases. So I think we're going to be really set for exploration not occurring until 2015, probably 2 to 3 years from now on average. Okay?

Nicholas J. Sutton

okay, it looks like that pretty much wraps up the questions as to the Permian. Ted, how are we going for time? Do you want to just take a short break?

Theodore Gazulis

So we'll take a...

Nicholas J. Sutton

Take a short break?

Theodore Gazulis

Yes.

Nicholas J. Sutton

Quick bio break, and then we'll get started at about 10 minutes, and it'll be Preston's turn to talk about the Northern Rockies.

[Break]

Nicholas J. Sutton

Okay. I think we're ready to get started again, so I'd appreciate it if you take your seats. Okay. Get us to the right spot here. Okay, just a brief introduction to Wyoming, and I'm going to turn it over to Preston Evans, who's our Northern Rockies Area Manager. As I mentioned earlier, we established our operations in this area in 2008 with the acquisition of Hilight Field in the Powder River Basin. This asset continues to deliver good free cash flow, and the Hilight team, I think, has done a remarkable job of reducing cost there and in shallowing the decline curve. Every week when we review the numbers, I'm pleasantly surprised that the Hilight Field and the Hilight team is delivering results above budget above plan, and they do it week-after-week, month-after-month. Our acreage position is well situated. As I told you before, it's in a good neighborhood. And the whole Powder River Basin is just seeing a remarkable resurgence as modern technology is brought to bear on some formations of [indiscernible] known to be hydrocarbon bearing. But generally they -- in order to be productive in the former world, there had to be more conventional reservoirs. We had to find pockets of real strong porosity and permeability. And now with modern technology, we're finding that these particular plays have much larger area like stent.[ph]These include Parkman, the Sussex, Shannon, Niobrara, the Turner and the Mowry. And Preston's going to talk with you in more detail about a couple of those in particular. So I turn it over to Preston.

Preston Evans

Well, I'll do a mic check. It sounds like it's working. As Nick said my name is Preston Evans, and I'm the Business Unit Manager for Northern Rockies. My background is primarily production and well operations. I'm supported with Mike White in the back on Reservoir Engineering and then to Bret Siepman, who stepped out for a second, on our Geology side. I'll spend a little bit of time talking about our base asset there in the Hilight Field, and then spend most of the time talking about our exploration activities in 2013 and where we look to go beyond that.

The Hilight Field, as we said, we picked it up in 2008. It's currently doing about 1,530 barrels equivalent a day, 15% of that is oil. This is an old legacy oil field developed in 1970. It's now currently in the blowdown phase. It went through a water flood between 1975 and 1996. And after the water flood, operators turned it down to blowdown and had a few additional opportunities that we continue to pursue. It is 100% operated and 100% HBP. So what that allows us to do on the exploration side is as the tighter oil plays in the Powder has come to fruition, we've been able to watch various operators experiment around us for our field and not have any lease expirations to worry about.

There's a few assets there in terms of what the Muddy was and what it is. It's a substantial oilfield, 345 in BOE -- MMB'09 in place originally of that, and 68 million barrels of oil sands produced and 162 Bcf of gas.

Let's switch gears to exploration. Our primary focus for 2013 is on the Mowry and the Turner. Offsetting us or around 2008, EOG started experimenting in the Turner about 25 miles south of us in the Crossbow field, [ph] and since then has marched up with the development by Yates, PetroHunt and now Devon. But our quick strategy column there is the legacy production in the Muddy is now based on the column that we show. There are more hydrocarbon intervals in the Powder, obviously, even if you go deeper than the Muddy all the way down to the Minnelusa on our property and shallower above the Niobrara, you get Shannon, Sussex, Parkman, Teapot [ph] in various areas.

Again our current focus is on the Turner where we have about a 20-foot type sandstone. When I say type, it's in the microdarcy range. And then in the Mowry, which is a black shale, it's a source for the Muddy. We're also looking at a deeper Minnelusa prospect. We did, in the exploration height, we had -- we took part of a 3D seismic survey that was shot on our acreage along with PetroHunt, and we're able to identify some Minnelusa pieces on there, as a bonus to exploring more into the characteristics of the Mowry, Turner and Niobrara.

It's a quick overview or a view of where we see the Turner being perspective. And a couple of slides, I'll get to a PhiH map and kind of show you where we see the brighter spot if will and the thicker pieces of each. Down to the Southwest of us, the most -- closest operator has been PetroHunt, and they're directly adjacent to us right here, and then down to the southwest. We believe we had about 12,000 gross acres perspective for the Turner from what we know now, and we plan to explore not with one well this year and currently permitting 8 locations to explore further next year and beyond. And pending the initial success, our result and plan would be 1 well this year, 3 to 5 wells next year, and then in 2015, looking at a continual development program. And if you have questions, chime in as we go along. I can answer this production operations piece. It's got the reservoir side. Let's hold to the end in terms of micromanagement.

We got here is we're showing some key offset wells that we think are indicative of what we should see on the bulk of our acreage or on the bulk of our prospective acreage. Our prospects are supported by the 3D seismic, as well as our well control in the Hilight Field. The Hilight was developed primarily on 1 60s. There are some 80s in there. We dug well every half mile with fairly good logs. And that's a lot of -- developed a fairly model of what we think the Turner looks like on the southern end of our acreage.

To date, there's 46 horizontal Turner wells that have been drilled within 25 miles of Hilight, that includes EOG's crossbow[ph] prospect, a fairly big Yates development then PetroHunt and Devon amongst the major. There's also Ballard and a few other smaller ones. The Turner wells are going down a fairly big piece of the Hilight production. These wells should be 70% oil -- oil well offsetting us rather than the existing base and the Hilight is predominantly gas or wet gas. These is our PhiH map, and the combination of this slide and the previous ones are a case for what we see as perspective here. Where we have seen good offset results, we have seen thicker, which is indicated by the red PhiH. We've got a great -- PetroHunt's probably the best well, just offsetting us by 0.75 of a mile right here in the [indiscernible], and that sets the bar for what we think can get on our acreage. There's also been some fairly good wells here, which are listed in the previous slide. Now the -- we also have going on is Devon out here and what we thinner area, but so far, the initial results are fairly good. They've had some press releases that have come out last month or 2 that may seek to or may expand our view of what's prospected in our own acreage. And as those results -- as we get more time with those rather than just the 30 or the 24 hour IP, when we get our 30, 60, 90-day production results, we're taking a hard look at what they've done and where they've done it and see whether that applies to us.

One of the earlier questions in Texas is, what about the lateral links here? Right now, most of the activity has been on 640 or 1 mile laterals, either straight north or south or taking advantage of predominant -- the national horizontal stress direction. We are starting to see 10,000-foot laterals permitted and drilled in our new area. Across the Powder, you have several operators really getting after the 1280s, Hilight being one of them. Petron is permitted 2 1280s just to the south of us, but more data is starting to come out of EOG with full 1280s with 3 or 4 months in production. I think we have 1 well that's public. [indiscernible] key numbers [indiscernible] to see what the cost benefit is to 1280 versus 640 in the Turner.

Through that tight curve and what we think these wells will look like for us. We see a gross capital cost between $5.8 million and $7.3 million, 30-day IP between 320 and 650 BOEs a day with a gross ultimate recovery of 230 to 350 MBoe, and the rates of return are calculated just as we did in Texas. We take the low end of the -- or the high end of the capital, the low end of the IP, the low end of the EOR and some other rate of returns and vice versa on the high end. Right now -- or with what we know now in terms of ability to down space, we're currently looking at about a 40-well development program in the Hilight, pending the success of the first round of appraisal well. But that works out to be the reserve potential and resource potential of 9 million to 14 million barrels gross. Laid out over what the Hilight currently is at 3.5 million, we're talking about substantial change to the field. Here's a quick view of what that 40 wells spacing looks like. If you get down and you count all the number of wells I plotted up there, you won't count 40. This is really just an indicative plot of what the spacing would like across our acreage. Again on 320s, that's about it there.

The second thing we're really looking at -- go ahead? Go for it. Well, if we could get the mic or...

Unknown Attendee

On Slide 57, is your acreage marked in red, or what's there -- or is that a 3D issue or is the blue the 3D outline? What's your acreage? I'm trying to get a sense of -- it looks like you have, in terms of the relative hotspot in terms of porosity?

Preston Evans

Quality is right. We don't have a scale on there. The red is our acreage. The lower bit is the Central Hilight unit; the upper 2 bit, you can see this getting cut off with the grayed adjacent units, so it comprises the greater Hilight Field. The blue, the light blue is the outline of the 3 seismic tubes.

Unknown Attendee

And so I would assume where you have the higher porosity shots, that's where you're coming up with your plus or minus 12, so almost a quarter of your acreage is 12,000 acres perspective for this horizontal Turner?

Preston Evans

Yes. Exact 12 is defined by this line right here, put down there, and then the rest of it.

Unknown Attendee

And from a more regional standpoint, have you all been able to do some mapping compare at this type -- your type of porosity maps versus PetroHunt and EOG and Yates and others given the fact that, that activity spans a 25-mile area? Or was it just a 0.75 miles step out for PetroHunt?

Preston Evans

Yes. The number of wells that PetroHunt has within our current hotspot area today are limited. So we have done on maps both the EOG area and the Yates area, and what we think we see is some porosity pinch-outs that separate Yates from EOG and again from us. So this area is just the analogue, the exact analogue for us. Yates and EOG or in 2 different tanks.

Unknown Attendee

And when do you think you'll start drilling the horizontal well? You have one plan this year?

Preston Evans

We have one plan this year, anticipate a spud in the third quarter. The permitting in Wyoming isn't as great as in Texas. They are slammed with all kinds of activity, and we're looking at a 60 to 90-day permitting window for a state lease for our state [indiscernible]. Much longer if we're in the Federal.

Unknown Attendee

[indiscernible]

Preston Evans

It's not -- if you took a hold of the Central Hilight average, we do have a 98.5 working interest in that, where, I didn't give you a net, is where we get into pushing to our only 50-50 in a well or where we were a quarter in a spacing unit, those variations in there. But it will be very close. It would be high working interest.

Unknown Attendee

[indiscernible]

Preston Evans

Your question was -- is what is our approximate net? We don't have a number for you right now. It is high.

Unknown Executive

What I would estimate is 90-plus percent out of that 12,000.

Unknown Executive

Okay. I'll shift over to the Mowry. The Mowry is a really interesting prospect to me. It's a black shale toy [ph] struck from the Muddy. So different from the Turner, which is a tight sandstone. It is the source for the oil and gas that came into the field. Few offsets drilled to date, there's been few offsets if you just look of the entire Wyoming in terms of horizontals. A bit of vertical development around the basin. It was a haul-back zone or an additional zone that people would perforate frac parallels to the Muddy. One of the things that we're attracted to in the Mowry is that, with the advances in what we're doing with Horse Shale [ph], Barnett, Marcellus, possesses [ph] the resource potential, fits in the shale as much as it has been expelled into the Muddy below it. It's matter of figuring out how to tap it. We've been testing vertical re-fracs, 2010, 2011 area. We've done 9. We came over that and shot 3D over it to match where we had good success and where we didn't have success in those vertical re-completes. And so what we're looking to do in 2013 is test up some of the theories that we've gotten out of that 3D seismic. And really is that where you have fractures formed, we think we have a lot of potential in the Mowry.

So the next map we have is where we think we have fracture swarms. So success in the Mowry is a little further off. It can lead to an expanded horizontal program in and of itself. So this map is fairly busy. It does have a better set scale than my previous map [indiscernible]. We've got the Hilight units mapped out in red, the 3D in light blue. And then we have low EUR bubbles for the Mowry re-completes we've done, and they are to scale. So up in the north side in the Grady, we didn't have much success. And we found that we weren't near as many fracture swarms, say, we did in the, call it, southwestern bit of the Hilight, where overlays a juncture of 2 fracture -- 2 aqua [ph] fractures. Within the fracture swarms we've highlighted here in kind of a light red, we think we have 9,600 gross acres. The net would be in a similar line, 90-plus percent. Depends if you get out of the -- unitize leasing your backup to the original leasing blocks.

So pending success of the 3 re-completes we do this year, and they're not interdependent. One doesn't -- if you have one loss, it doesn't necessarily impact the other 2. If you're out here on the East Side, and this one doesn't work, it doesn't say as much about this other one. This other one can link up with our existing successes, and same with this northern one. So each one really tries to address a different part of the Hilight complex. And pending success of this year's program, we could look for horizontal exploration well in 2014 with then appraisals following on after that.

Quickly touching upon the Big Horn basin, shifting out of the Powder, we have 74,000 net acres of exploration leasehold out there. And we're actively digging into the various plays with our chief geologist. Most of these are federal leases with 10-year term, and we have about 3 years remaining. So we do have to get after it. There's been a lot of -- or some decent activity with other operators such as Plains, Cirque, Barrett, Koch, just to name a few. And the perspective formation's similar to Powder. You have a lot of stacked hydrocarbons and a lot of old legacy production, Frontier, Phosporia, Mowry, Muddy, Dakota, Ten Sleep [ph]. It's another stacked play basin that has a lot of production attributed to it.

And that's it for the Powder. I probably should hand over to Nick to talk about Bakken real quick.

Nicholas J. Sutton

Okay. The Bakken, not much to say there. I mean, you all are we're the fact that we've initiated a divestiture process. It is moving along. We are working with several parties at stage of refining PSAs [ph] and due diligence and the usual steps that have to be taken, and we anticipate mid-summer closings. So not a lot more to say there.

Here's what I would like to really focus on, and that is so we take that sort of the toys in the toy box components and roll them all up into a single slide. You can see that we've got 87 million barrels of currently proved reserves. We just walk you through resource potential, if you can go from 64 to 33 million. I'm once again going to emphasize that that's only part of the picture. For example, I don't know in the 7 to 12 million whether that includes Mowry. I don't believe it does. It also does not relate for sure -- it doesn't include for sure the Minnelusa.

Unknown Executive

That's just Turner.

Nicholas J. Sutton

That's just Turner. And so we have a very active deeper Minnelusa prospect that's been defined by 3D seismic. And I think you may be aware of the fact that Minnelusa is a conventional reservoir and when you find it, it can be very, very prolific. I have to say that these days, I would be really happy to drill a conventional reservoir, so that you, for $1.5 million, $2 million, you drill it, you test it. And if you got a good well, you go ahead and complete it. If you don't have a good well, you go ahead and kick [indiscernible]. It's not like you have to spend $7 million for horizontal, put a big frac on and then wait to see what you've got. So I'm kind of excited about the Minnelusa prospect.

And throughout all of these areas, I mean we haven't included anything at the Big Horn, and we haven't in the Permian or in Aneth scratched at all. Try to just give you an impression or a picture of what we believe we've got right in front of us. So it's a great, great opportunity. I don't think most of you have really focused on this. I mean, frankly, we haven't until today really been all that forthcoming about some of the resource that we see, mainly because we always are cautious that we don't overpromise and under-deliver. And here, we're trying to at least give you a picture of some really, really stout upside in the various activities that we are doing.

So with that, I think I'd just like to summarize what we think are key investment highlights. So I think we're really well-positioned to move forward a strong plan. I think we've got a good history of being able to execute. We got a high-quality asset base of long-lived, oil-producing properties. I'd like to emphasize long-lived. I like to emphasize oil again. We've walked you through a portfolio of significant organic development opportunities. And these are things that could be infill. It could be in Aneth, the short laterals. It could be any number of things. But on top of all those, we've got some really exciting exploration projects that are poised to provide some real positive results. And I don't know what you want to call the [indiscernible]. When you get the PetroHunt wells, it is immediately offsetting our acreage, being the strongest Turner well in the vicinity. Is our well a development well as an exploratory well? I don't know. All I know is I think it's got great potential and I'm looking forward to getting after it.

I think that we've halfway demonstrated to you our project rates of return. I think we've been conservative on how we have approached these and we try to give you ranges and you can -- you guys are all really smart. You know the industry and you know how to calculate numbers. So you can put all those together and draw your own conclusions. And then I'd say 1 last time that we are very experienced. If you can get a sense today of some more of that depth in our team, the experience in our team, how many people have been at this for 20 years, 30 years, how many people have worked all over the world, that worked conventional and unconventional, have done a lot. And I think that these people are all highly focused, highly motivated and I think they're delivering excellent results.

We also -- our team has done this before. We built a company from basically scratch and sold it for great returns to our shareholders. And I think we're not new to this game at all.

So with that, I'd like to wrap it up and just open the floor for Q&A. And we've taken a few along the way, but I suspect there are few more.

Unknown Analyst

Can you give us a sense how we should we think about '14 as far as -- I know you guys have targeted double-digit oil growth. Can you just -- it seems like [indiscernible] make it there, so I'm just...

Nicholas J. Sutton

The thing about targeting 2014, I don't focus on much at this stage on the production growth. We certainly have calculated what we think our production growth could be in 2014 and we have not announced anything in that regard. And so I want to be very careful. I'm focused on 2013 but I will tell you that I personally am very, very excited about 2014 because many of our activities here in 2013 are really set up to deliver stout growth in 2014. For 2013, we achieved 50% growth through our acquisitions. And so we've looked at our capital program for this year as being one that sets up 2014. And I think it sets up really, really well. We will share more of that with you of course as we refine our budget, or capital, our financial and operating plan. The real challenge that we have is almost one of abundance of virtues or opportunities and that is all of these opportunities, as has been pointed out by Ted and others, compete for capital and we will be going through our linear programming solutions and other tools and techniques to try to outline those projects which will deliver the strongest return to our shareholders per dollar deployed. So it's not a very specific answer. I'll just leave it at that, that we think 2014 is stacking up to be a really good year. Okay. No, could you wait a second? I appreciate you bearing with us on the microphone. You all are very familiar with [indiscernible] and we've got people on the phone, and if they can't hear...

Unknown Analyst

If I remember right, with PetroHunt, wasn't there a well about a year ago that you guys were partnered in. And I don't remember ever hearing what the result of that one was.

Nicholas J. Sutton

Okay.

Unknown Analyst

I turned off my mice. We did trade into the PetroHunt well and they elected not to drill it. So we don't have those results. We were able to do some data sharing on oil sampling and gas sampling, but that has been the extent of it.

Nicholas J. Sutton

I don't see any other question, so I think that wraps it up for the day. And of course, we're looking forward to as many of you joining us this evening for just some relaxation as you can. But we also really recognize that people have planes to catch and things to do. But if you are free and can join us, we'd love to have you with us. And for all the people on the webcast and on the conference call, we appreciate your participating in this. And once again, were always available for questions. Thank you very much.

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