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Comstock Resources Inc. (NYSE:CRK)

Acquisition Announcement /Update Call

December 06, 2011 10:30 am ET

Executives

Roland O. Burns - Chief Financial Officer, Principal Accounting Officer, Senior Vice President, Secretary, Treasurer and Director

Miles Jay Allison - Chairman, Chief Executive Officer and President

Mark A. Williams - Vice President of Operations

Analysts

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

John M. Selser - Iberia Capital Partners, LLC

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Comstock Resources call to discuss the acquisition of the Delaware Basin. My name is Lacey, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Jay Allison, President and CEO. Please proceed.

Miles Jay Allison

Lacey, thank you, and thank you to everyone that's listening in for short notice and, again, we woke up this morning, there's snow on the roof. We're in Dallas, Texas. Not -- to say today couldn't have arrived any quicker. I was ready to get this announcement out to the public.

In the last 4 business days, we canceled presentations at 2 conferences and numerous one-one-one appointments, including probably 7 or 8 today that we canceled on. We apologize for the cancellations, but now you know why we canceled that.

Late yesterday afternoon, we're pleased to announce the Delaware Basin acquisition of Eagle Oil & Gas Co. and partners for this $332.7 million with an effective date of November 1, 2011, and an estimated closing date at the end of this month, December 30, 2011. But prior to the announcement yesterday, we had spent the majority of this year focusing on the Permian Basin as a new oil basin for Comstock, and in fact, you'll see in the press release we had leased about 12,000 net exploratory acres in the Permian region so far this year in 2011, with acreage cost on that 12,000 acres of anywhere from $400 to $500 per acre. And although our producing and finding cost were among the lowest of any E&P company in the industry, at Comstock, we knew we needed to add an oil liquids component to our asset base to complement the 130,000 net acres in the Haynesville and Bossier shale play that we control in Louisiana and Texas, which as, is you know, about 6.5 Tcfe of dry gas upside. So in 2010, we started leasing acreage in the South Texas area, which is this Eagle Ford region. And this year, as you all know, we added another 10,000 net acreage to our Eagle Ford lease inventory to give us the 28,000 net acreage that we currently own, which is yielding excellent results, as Mark Williams, who's here with me today, will go over to you -- with you. And you'll see our press release with the results of our most recent 5 Hill wells in McMullen County, are paying from 801 to 1,120 barrels of oil equivalent per day on a 16/64 inch choke, which it states in our press release. But Comstock still needed to add a major acreage position in a premier oil basin, really that was accessible to us, that was environmentally friendly, that was a proven basin and in one in which our G&G team had experience in. So our focus turned over a year ago toward the Permian for the results that you see today.

Today, you see Comstock materially reducing our gas rig count from a high of 7 in 2010 to 1 rig by the early 2012. We're increasing our oil and liquids rig count to 3 in the Eagle Ford and adding the Permian as a new core area that will materially change Comstock, making us a much more balanced E&P company with a material oil story to tell in a major oil basin, the Permian Basin. And our goal in adding a new region was, one, we needed to operate; two, it hadn't had -- it had to have enough size for years and years and years of drilling; three, it had to be an oil basin; four, it had to have infrastructure in place for the producing properties; and five, really, it had to be materially de-risked by recent drilling activities if we were to use our bank credit line to purchase the properties. This acquisition satisfied all of those goals and more.

If you're following us on the slides, of course, Slide 2 is the risk statement. Everybody has seen that a gazillion times. If you look on Slide 3 and you look at the properties, the purchase says 68,000 gross acres, or about 44,000 net acres, so about a 75% NRI; about a 65% working interest. It's all in Reeves County, Texas. It's in the Delaware Basin. It's perspective for the Bone Spring-Wolfcamp development, and it is 86% operated. If you look at the reserves that we're buying, it's about 23 million barrels of oil equivalent. The resource potential we think it has about 178 million or 180 million barrels of upside. It's about 900-plus net vertical wells that we will drill. The additional upside we think is material, and Mark Williams will go over that in a moment, but it's horizontal development either in the Avalon, the Bone Springs or the Wolfcamp shales.

You can see the well count. The well count, in our opinion, de-risked the 44,000 net acres that we'll be closing out on the 10th of this month. There's 29 producing wells and there's 5 wells that are waiting to be completed. And then the current production, as you all know, is 1,400 barrels of oil equivalent.

On Page 4, we'll just show you our major properties, and we've added the West Texas region on the top left-hand side. Estimated proved reserves, you see this 139 Bcfe and 34 wells, and that complements our existing reserve basins, which is in East Texas, North Louisiana, South Texas. And then the other region, which is the bottom right-hand side, of course that -- that's probably a divestiture region sometime in the future. Company overview, the pro forma, you'll note that we're about 294 million a day equivalent of production. We're 91% operated, 88% natural gas.

With that, I want to turn it over to Mark Williams. He will go through Slides 5 through 12. Roland Burns, who is here, go through Slides 13 to 16. Turn it back over to Mark for a couple of slides, and we'll close it out with a summary then open it up for questions. Mark?

Mark A. Williams

Thank you, Jay. Slide 5 shows the Permian Basin activity, and this shows permits for 2011 only. Green are the vertical permits. Red are the horizontal permits. And in yellow, on the west, southwest side in the Delaware Basin, is the Eagle acreage that we are acquiring.

This is the most active basin in the country. You can see how active it is, there's almost 10,000 permits here with over 1,000 of them being horizontal permits. There are almost 500 rigs running in the Permian Basin, and over 100 of them are horizontal rigs. And you can see on the western side of the Delaware Basin, that the majority of the activity to the north of our acreage has been horizontal, while the activity to the south of it and on the acreage itself has been vertical. And so we're targeting this as a vertical play, but there's a lot of horizontal activity, which has worked the direction of this acreage, which we feel like has -- gives us a lot of upside potential.

Slide 6 is a subsurface topographic map that shows the Permian Basin. And you can see on the east side is the Midland Basin. On the Westside, where our acreage lies, is the Delaware Basin. What's important about this map is that what we're targeting is basin-centered hydrocarbon source rock, mainly the Bone Spring and Wolfcamp shales. And you want to be in the bottom of the basin for these source rocks. And you can see the Eagle acreage is right in the bottom of the Delaware Basin, which we feel is the best place to find the best source rocks to target. The depths of the Wolfbone, the Wolfcamp and the Bone Spring shales run from 10,000 to 11,500 feet.

Slide 7 is a cross-section from the Midland Basin on the right across to the Delaware Basin on the left. We are targeting the -- what's everybody is calling the Wolfbone section, which is the Bone Spring and the Wolfcamp shales. You can see that on the left side. And as you come across to the east side in the Midland Basin, it's very similar relative to the Wolfberry play, which is very active over on the east side. It's an emerging resource play in the Delaware Basin. Like I said, it's equivalent to the Wolfberry, except that it's deeper. It has higher pressure, which gives us more reservoir energy to push oil out of these very tight source rocks.

Slide 8 just shows the location of the Eagle acreage in blue. You can see it's in Reeves County. There's 68,000 gross acres, as Jay said. There's about 44,000 net acres in the acquisition. There are over -- based on 40-acre spacing in the Wolfbone, there over 900 vertical locations. Total resource potential based on our tight curve is about 178,000 MBOE or 178 million barrels equivalent. And in addition to that, that's strictly the vertical potential that we've determined where there's also horizontal potential in multiple objectives.

Slide 9 shows the Reeves County drilling activity on and around our acreage. And as Jay said, we feel this acreage has been very much de-risked. You can see the drilling activity has covered almost all of the acreage. The colors depict the different ultimate recoveries that we have calculated on these wells, and they range -- green is 150,000 to 200,000 barrels equivalent, yellow is 200,000 to 250,000, and red is over 250,000 barrels equivalent. So you can see that this acreage has been very much de-risked by drilling, so we look at this as totally as a resource play.

Slide 10 shows our 2012 drilling plans. In yellow, you'll see the current existing wells that are either producing or in the process of being completed. In red are 46 gross and 40.2 net wells that we have scheduled and planned to drill in 2012, and you can see that we are continuing to de-risk this acreage. And drilling is defined by de-risking and also by maintaining the lease situation that we have out here. Our cost on these wells will range between $4 million and $4.5 million per well. We expect the EURs to be between 180,000 and 250,000 barrels equivalent. 30 day IPs on these wells run between 150 and 300 barrels per day. And the depth, again, for the Wolfbone section is 10,000 to 11,500 feet. These are completed with multistage frac-ing, and much like our Cotton Valley program in East Texas, we have a lot of experience in that. And normally, 8 to 12 frac stages is what we will target for these wells.

Slide 11 shows the formations that are productive in the Delaware Basin. We're really excited about this acquisition because it's in a proven basin that has hydrocarbons you can see from 5,000 feet all the way down to 20,000 feet. So it's a very prolific basin, a lot of source rock in this basin. Our primary target is in the red box, and it's the Wolfbone, which goes from the third Bone Spring down through the Wolfcamp shales at a depth between 10,000 and about 11,500 feet. It's a vertical target primarily. But in addition to that, you can see we've highlighted 4 additional intervals that we think have horizontal potential, including the Avalon Shale, which is very active to the north. It hasn't been tested on our acreage, but it looks similar to the activity to the north. Third Bone Spring, which is also active to the north and northeast of us. And then 2 -- at least 2 intervals in -- within the Wolfcamp shale that we feel are prospective for horizontal development based on analogs in the Midland Basin or activity to the north of us or our experience in the other shale plays.

Finally for me, on Slide 12, kind of shows the players in the horizontal play of the Delaware Basin. You can see you have Cimarex, Oxy, Linn, Anadarko to the north. They're targeting mainly Avalon shale. And close to our entire acreage, you've got Energen, Cimarex, Devon, which are targeting either Avalon and/or Bone Spring. And then to the south of us is Concho and Exxon, which are targeting shales within the Wolfcamp section. BHP, which announced the acquisition of Petrohawk recently, has noted that they're very excited about the potential of the Wolfcamp Bone Springs in this area, and they have a large acreage position just to the west of us. So a lot of companies, a lot of very active companies are excited about this play just as we are. I'll turn this over to Roland for the -- for Slide 13.

Roland O. Burns

Thanks, Mark. On Slide 13, we present our revised 2012 drilling budget that incorporates this acquisition, which we plan to complete right at the end of the year about December 30. And you can see that we are now budgeting to spend $170 million in the Delaware Basin on the new properties to drill 46 gross wells about just over 40 net wells. And then if you incorporate that in with our previously announced budget, our budget for the Eagle Ford still is the same as we announced earlier. We'll spend $222 million to drill the 32 wells in our Eagle Ford shale program. And then we have trimmed a little bit off of our gas program in the Haynesville, primarily as we've been able to -- a little bit of projects out, so we revised that budget to about $153 million to drill 32 wells, but only 11.3 net wells because we still budgeted -- we still think that we could have a fair amount of non-operated proposals, so we budgeted for those to the extent that we know that would be fine too. But overall, that sums to total drilling budget for 2012 of $545 million, and it will drill 110 wells, or 80 net wells to Comstock.

On Slide 14, we kind of get some high-level summary of what this acquisition -- what type of impact this acquisition has for Comstock. And we've kind of compared it to our original 2012 program, which was kind of focused primarily on the Eagle Ford. And under that program, as we announced earlier, we expected our production to increase by 8% to 12%. The composition of our oil averaging for all of next year of 2012 was going to be 10% to 12%. But oil as a percentage of our revenue as kind of based on the current market prices was a bit -- was going to be about 30% to 34% in 2012. This is all based on our original drilling program, which was focused in on the Eagle Ford. The total cost of that original program was $381 million, and about 60% of that budget was for oil-related projects. So now if you go to our revised program, which would incorporate the Eagle acquisition into it, we now expect to see higher production growth of 13% to 17% with acquired properties and the drilling program on the acquired properties. Oil as a percentage of our total production increases to 14% to 16%. And that oil as a percentage of our total revenues is 39% to 43%. And then our total drilling budget, as we have showed you in the slide before, is $545 million, and 72% of our budget would be going toward oil projects.

On Slide 15, we will be financing this acquisition with borrowings under our bank credit facility, which will be increased to $700 million at the close of the acquisition. So as we look at overall of our total financial profile, we do plan to supplement the cash flow that we expect in 2012 with proceeds from some planned divestitures. We've identified certain, what we call wet properties, oil and kind of wet gas properties that are conventional properties that we don't have any future plans to develop and that don't really have potential for unconventional development. So we've identified a group of properties that we plan to sell and start marketing in early January, which we think would generate proceeds to the company of $100 million to $130 million. We also will continue to monetize our investment in Stone Energy, which should generate proceeds of anywhere from $50 million to $60 million. So these are some additional sources of cash flow that will supplement our operating cash flow in 2012.

In order to reduce our exposure to the volatility of commodity prices, which is something that we have to live with in this industry, we are putting in a hedging strategy in place for 2012, which is really designed to protect us for what we're drilling, which is, as you saw, focused on oil. So we do plan to hedge approximately 50% of our oil production, which is mainly relating to this acquisition and relating drilling we're doing on this acquisition and in our Eagle Ford shale program. And then we're going to -- we'll continue to maintain a lot of flexibility in our drilling program itself so we can adjust the drilling program. Even though we've targeted $545 million to the extent that there's a lot different commodity price outlook next year, we could upsize or downsize that drilling program as we think it makes sense.

On Slide 16, we haven't got in to put some of those oil positions in place. So as of yesterday and probably still as of today, we do have about 2,000 barrels a day of oil production hedged at a NYMEX price of $99. This is just a straightforward swap, and basically, the index price for these oil contracts is based on the NYMEX WTI monthly average future price. So right now, we have tied this hedge really to our Eagle Ford production, and we continue -- we will build on our hedge position so we can meet our targets of our hedging program for 2012 and then also look ahead to 2013.

With that, I wanted to turn it back over to Mark for a few minutes to kind of go over some recent results that we've had in our Eagle Ford program.

Mark A. Williams

Thank you, Roland. On Slide 17, we show our current Eagle Ford acreage position. And we have previously announced that we've added to that position from 2010, where we had about 18,000 net acres, we've added about 10,000 net acres in 2011. That acreage is showing in yellow. So that brings our total to 32,000 gross and 28,000 net acres. And then again, based on well spacing of 100 acres and our average per-well reserve value that we're using of 400,000 BOE per well, we now have a resource potential in the Eagle Ford of about 83 million BOE.

Slide 18 shows the initial potentials on all of the wells so far. And in addition to the ones we've previously reported, we now have 5 new wells that we've included in this current press release just to update everyone on where we stand. We had expected to report these in the third quarter. But just the timing of the frac-ing and flowback of everything on the wells, we didn't have them ready to report at the time, so we thought we'd add that to this, get everybody caught up on where we are on the Eagle Ford.

As you can see across the bottom, we've added 5 new Hill wells. So we have developed our Hill lease on these 5 wells, average depth on them runs from between 11,000 and 11,200 TBD. And their lateral lengths range from 5,000 to 7,500 feet. And you can see on the Hill #2, we had an initial potential of 801 BOE per day; on the Hill 3, 985 BOE per day; Hill 4, 890. The Hill A1 was the best of the group at 1,120 BOE per day. And in the Hill A #2 is also very well at 1,048 BOE per day. We have very consistent results here. These match very well with the Hill #1, which we have previously announced at 1,095 BOE per day, so we're excited about the results. We're very pleased with these results. They match what we had expected and hoped to get. All of these results are based on our restricted rate program, which we previously talked about where we restricted the wells to a constant choke, normally a 16/64 choke, so we can maintain our reservoir pressure, pull the wells down slowly. We feel we get higher EURs. And also in the Eagle Ford, one other result of that is we've really deferred the need to install artificial lift on our wells. We only have artificial lift on one well, which we talked about before, which is the Jupe #1. And you can see up to the north, we had initially reported an IP of 218 BOE per day on it flowing naturally. Since we put it on pump, it's increased to 293 barrels equivalent per day. So it's doing much better. It's producing at a fairly low decline rate, so we're going to monitor that result and see how it turns out. But that's the only well we have on artificial lift at this time. So the restricted rate program has had that benefit as well.

So that's it for the update on the Eagle Ford shale wells. I'll now turn this over to Jay for Slide 19.

Miles Jay Allison

Okay. And now going back to Slide 18, we told you at the third quarter conference call that we kind of gave you our B-team results on the Eagle Ford. And if you look on Page 18, I mean, the 5 gold bars at the bottom, I mean that's a pretty good entrance into Slide 19, and we gave you your -- our A team. And again, I would applaud Mark for taking risk but not being reckless on the production in the Eagle Ford. And we do have a "choke back" program, and it does work, and you can see the results at the bottom of Slide 18.

There kind of is a conclusion before we open it up for Q&A, which we'll only open that up for our analysts. But if you go back and recap, again, we -- we're now developing in, what I think a sensible way, our Eagle Ford shale program. I think we -- although we had become a very low-cost producer, we were a dry gas company. We didn't really have any catalyst. Yes, we had added the Eagle Ford. And, yes, it was working. And, yes, you can see the 5 wells at our most recent wells in Eagle Ford, but we were still lacking a catalyst, which is an oil component that was real that we could get aggressive toward developing. I think if you look at the -- our dry gas component to Haynesville and look at the Bossier, we positioned that now where if we keep anywhere from 1/2 rig to 1 rig busy in that region with this 130,000 net acres, we can hold all that acreage. So we're very comfortable with inventory in that 6 to 7 Tcfe reserves. So now what we've done today, when we've kind of turned the corner, we've turned a new page. We have now disclosed to you that our new basin is the Permian. We've disclosed to you that we have 12,000 net exploratory acres that we had already been adding prior to the announcement of this acquisition. Told you the cost was anywhere from $400 to $500 an acre. And then if you flip over to Page 19, the summary, so you look at the first 2 or 3 bullet points, I mean, we have had predictable strong reserve growth at low cost. We've had a very low cost structure. We've had very strong production growth even in 2012. We're saying it could be 15-plus percent. But our component of oil is going to increase materially. Then you really get to kind of the guts of this telephone call. Our Eagle acquisition establishes a new core area which is focused on I would say de-risked oil. It adds low-risk vertical oil as far as the drilling program. Like Mark said, it's over 900 vertical locations, and that's on 40 acres. Maybe at some point in time, you can go to 20-acre spacing. But we plan to drill 46 wells in this Delaware Basin in 2012. The upside in the future horizontal development, Mark went over that, we think it's phenomenal. It is a oil/liquids growth formula. We're going to go from 2% of oil production of which is where we started in 2011, and we should exit 2012 with 20% or more of our production being oil/liquids production. So that's the right direction. At the same time, we've inventoried our dry gas, and, as Roland said, we've kept our balance sheet reasonably strong. We will reduce our leverage in 2012 with some assets that we need to sell, they're non-core assets. I think they're valuable assets but not to us. They are to other parties, and that's anywhere from $110 million to $130 million. And we still own probably $50 million to $60 million of Stone stock that we'll be selling in the future. So with that, Lacey, I'd like to have you open it up for questions either me, or Mark or Roland.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question will come from the line of John Selser with Iberia Capital Market.

John M. Selser - Iberia Capital Partners, LLC

Your comments actually lead me to this -- I guess, to my question, but it's in regards to the horizontal potential. There's so many potential horizons, producing horizons there. Which zone would you target first? What would be the cost to that well and expected reserves? And when might we look for something to happen along those lines?

Mark A. Williams

John, this is Mark. Our primary target right now would be one of the Wolfcamp shales within that overall Wolfcamp section. And that is what we look at currently as the most appealing target of the group. Now that may change over the next 3 or 4 months as we continue to analyze this and get some additional data from outside parties who -- when there is activity going on almost in every direction from us right now. So that's our target right now. Depth-wise, it's about 10,500 feet. And so it's going to be a very similar well construction to our Eagle Ford well construction. Depth, pressure, more or less the same casing program, very similar frac program. So we expect our cost to be similar. So around -- between $8 million and $8.5 million is kind of what our target is on the Eagle Ford. So that's also what we expect it to be here. EUR is where -- if use some of the industry multiples, you can get to a pretty high number on EUR in the vertical to horizontal multiples. But here, the vertical wells produce from multiple horizons, so it's a little bit difficult to apply that. But we look at the rock quality and we believe it's better than we what we've seen in the Midland Basin. And so you can look at some of results over there. And we really think it should be similar or better even maybe than the Eagle Ford results that we're getting, which are 400,000 BOE. So that's kind of our target. It's early and we've got to do some more science and get it well-tested. But that's kind of what we expect is at least 400,000 barrels.

John M. Selser - Iberia Capital Partners, LLC

And do you think you might do this in the second half of 2012?

Mark A. Williams

That's probably what we're expecting right now. Third quarter is kind of where we penciled in. And we've got to look at our -- what rigs we have, all of our lease commitments and such to fit it in. But that's kind of what we expect.

Operator

And our next question will come from the line of Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you all talk about where the asset sales are, what area or is it kind of scattered?

Roland O. Burns

Brian, this is Roland. Yes, we don't want to specifically identify the properties because we want to be able to market those. But it's kind of scattered. It's not a -- it's conventional assets, so it's not any of our properties that would have any potential for shale development.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. Are you all including that in the guidance as of now?

Roland O. Burns

We are. We have, because we do really expected that done. We are -- we have included that in the guidance. And that's -- the properties that we've targeted that met the numbers that we put out, it's about 10 million a day of production, 7.5 of that is gas-related and the balance is oil. They're kind of -- It's kind of weather properties. Even the gas has some liquid, so that's going to -- we think be very -- give us a good price in this market. And a little under 50 Bcfe in reserves. So...

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then switching to the acquisition, on the vertical Wolfbone well, how much of the -- I think you're running $4 million to $4.5 million, how much of that is drilling, and how much of that is completion?

Mark A. Williams

I believe the cost of rig release is between $2 million and $2.5 million. So you're looking about 50-50 on the drilling and completion side.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, okay. And then one final one on the Eagle Ford. Outside of kind of restricting the chokes, have you all done anything on the completion differently in some of the prior wells? But you had such a nice increase and the wells look pretty strong. I just want to see if there was something you all did to change it or is this kind of you all figuring it out a little better?

Mark A. Williams

I think we're figuring out a little bit better. It's incremental. We're still experimenting with frac design, so each well has a little bit different cluster spacing or frac design per stage. And then we've linked in our average lateral link somewhat since the beginning. We were probably in the 4,000-foot range, and now we're upwards between 5,000 to 6,000 foot on average. So that's helped us in addition to the changes in the completion design. So we're experimenting and we're monitoring other companies who are also experimenting.

Operator

And our next question will come from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

As it relates to the acquisition, the -- can you give us a sense in terms of what the lease expiry looks like on the acreage you acquired here? And it sounds like you have a couple of rigs or Eagle had a couple of rigs running on it, what your plans are with that rig count?

Miles Jay Allison

Yes, the goal is we have 2 rigs in place right now. One is well-to-well, and we plan on keeping that rig. And the second one is a 2-year commitment, and we're on the second year of that commitment. We plan on keeping that rig also. And between now and, say, third quarter of 2012, we will probably have a 5-rig program in the Permian Basin. So we'll go from 2 rigs to 5 rigs sometime between now, and we'll add them every couple of months or so between now and the third quarter. And as far as holding acreage, if we keep a 2-rig program going and pay a little lease extension dollars, we can hold all the acreage through the end of -- or through the middle of 2013. Basically for every vertical well, you have to drill, I think, 160 acres per well is what the acreage holds. For every well you drill holds 160 acres, but you've got the perpetual drilling clauses and stuff. If we have a 5-rig program active in 2012, we shouldn't have any issues about holding acres.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And from a spacing standpoint, you've highlighted the initial expectations to some 40 acres. Are people starting to downspace at this point beyond -- down below that in the Wolfbone, or people really still -- is an industry you're still really focused on the 40 acres at this point?

Mark A. Williams

I think the industry is focused right now on 40. But really, it's early in the Wolfbone, and nobody's drilling on a development pattern yet that I'm aware of. It's really still holding acreage and testing acreage. So nobody's tested -- significantly tested even the 40-acre spacing. That's just kind of that primary oilfield assumption of the -- back to the old days of a standard oil well holds 40 acres. So we look at this as the rock is shale, it's nano-darcy rock. It's not going to drain far at all from the hydraulic fracture. So once we determine better the direction of the hydraulic fracture, I believe we'll be able to downspace from that.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And Roland, I don't want to leave you out. A couples questions for you. When you look at your model, how do you expect the addition of the Permian production to impact your oil and gas price differentials? And also, as you look at LOE, I assume that the addition of the Permian on a unit base will start to increase that LOE, which is more than offset by the revenue side. But how should we look it from those -- modeling those costs? And also on the G&A, is there going to be anything that you have to add from a G&A standpoint to operate these properties?

Roland O. Burns

Sure, Ron, I'm looking at the forecast. As far as price realizations, the new -- the oil from the acquisition is mainly going to -- definitely be tied to WTI. And I think we've seen the WTI, less $1 or $2 as far as realizations at the wellhead, where the Eagle Ford was starting to -- is a premium to WTI, typically $5 to $6 over WTI right now. So as the Louisiana light price and WTI become more into balance, it may not have much of an effect. Right now, it would -- if we would have a little lower -- it would lower our differential a little bit than what we went ahead with just Eagle Ford because it's higher priced oil there. On the cost side, again, we're in the early stages of this property and it's not a real high cost property lifting cost. I think it's going to have very nominal effect on our total lifting cost. Numbers, as realized, less than -- maybe it's $0.02 or $0.03 higher average rate at the most. So I think it's a very small impact now. As we shift more and more to oil and over time, especially if the oil -- if any of the oil projects going artificial lift, which so far, we haven't -- we only have one, you'll tend to have slightly higher operating cost. Yes, on G&A, we've added -- we've assumed maybe a total of $0.5 million of additional G&A that we would just forecast over time because we will want to add some technical, some -- we want to add some technical people to really focus of the Permian. We do have -- that's something that will happen right away, but that's something we'll add as those people become available to us. And we've done a little bit of that already on the geologic side and starting to build a team that's focused on the Permian.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then one last one, just from a funding standpoint. Obviously, you had drained in your 2012 CapEx quite a bit. This moves it back up. When we look at your expected cash flows with this transaction and then the expected asset sales and Stone Energy shares and the increased borrowing base, when you look at your funding, I assume the expectation is to remain fully funded here on your revolver potentially look to term some of it out over the course of the next 12 to 24 months and just fund it via debt and cash flow/divestitures, is that the right way to look at it?

Roland O. Burns

Well, we'll initially fund the acquisition with the revolver, and it's going to be increased -- borrowing base availability increases with the closing of the acquisition to $700 million. And then as we go into 2012, we see -- I agree that without higher prices that cash flow and the new operating -- the new drilling budget will be not in alignment like they were before. It's probably to the tune of less than $100 million, so it's probably anywhere from $70 million to $90 million that would be that shortfall. We would see funding that through the asset divestitures, which will be great, and we would also see potentially using the credit facility a little bit. We do expect the borrowing base to grow over the next 2 redeterminations just because of the large amount of drilling that we're doing in the production and reserves that we're putting into producing proved developed producing. So we'll continue to maintain good liquidity. In the long run, it's something we'd look at as to term out some of the short-term bank debt or the -- with some longer-term debt, but probably not to a very large extent. Our goal would be to work the debt level down. As -- and in our 2013, we would see very much being in balance on our budget and hopefully delevering some then.

Operator

And our next question will come from the line of Jack Aydin with KeyBanc Capital Markets.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

I know most of my question are answered, but I got 2 ones. What made you think -- how did you arrive at the decision of 40 acre spacing, while some of the other are using much higher spacing in the area?

Mark A. Williams

Jack, this is Mark. Well, we -- I think the higher spacing is just because they have a lot of acreage and they haven't drilled many wells yet. It's a new, pretty much an emergent play the way it's being done. And I know that Eagle tested a 40 -- one 40-acre spacing well and did saw no interference. So that gave us some confidence. But we look at the type of rock that we're dealing with here. This is a very tight rock. It's all, like I said, it's nano-darcy shale is what we're targeting. And so if a -- the way we calculate and determine is that you can only drain maybe 150 to 100 feet on either side of your hydraulic fracture, so you can't drain much rock at all. And if we can drain 80 to 100 acres with a horizontal well in a 5,000-foot lateral, then we'll probably going to be at well less than 40 acres for a vertical well.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Second question, Roland, did you run a model on -- I'm sure you did, 2013? If you're looking at the production growth this year the way you announced, what kind of oil leverage you're looking at for 2013? If you're exiting like 20% in 2012, what should we assume going forward in 2013?

Roland O. Burns

Well, we wouldn't assume anything yet, I mean, because it's really going to be based on what is our investment going to be in our gas program and if gas prices are stronger in 2013. If we continue on a path of underinvesting in gas and overinvesting in oil, similar program to 2012, we think we can raise that percentage of oil another 10 percentage points to 30%. So we can get oily. With the inventory of projects we have now in the Eagle Ford and in the Permian, Delaware Basin area, we can -- the company can get to a very good balance of oil and gas production on a production basis. But we have a great asset base in the Haynesville and to the extent that we could start growing that again, it's very prolific. So if we start growing the Haynesville again, it will -- the percentages may be different.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Okay. Jay, in terms of leverage -- balance sheet leverage, I know you are uncomfortable with debt. What -- ideally, what kind of leverage you'll be happy with? I know with this deal, it's a little bit -- will go up. But what kind of leverage you'll be happy with?

Miles Jay Allison

Our debt-to-cap typically is in the mid-30s, and that's -- it's in the low-50s. But I'd like to see it somewhere in the 40s, that would be great. But Jack, it takes a while to get there. You have to get there through equity, and we don't plan on issuing any equities, you know that. And profits, we should be very profitable in 2012. But it's a little harder road. I think what we really look at is, really the flexibility that we have. We've created such a strong bank credit line that we haven't used that when an opportunity comes along like this where we really can add a material oil component, and kind of as Roland was alluding to, and you're asking the question is what percent of our production will be oil in, maybe, in 2013? And the real answer to that is we have total flexibility that if we want to spend more money on our gas basin, we can. But Jack, if we don't want to and we only want to keep a rig or half a rig busy in 2013 in the Haynesville/Bossier, then we have the luxury to do that without losing any of that acreage. So that's the real flexibility that we provide, and I think the stock will perform better. I think we'll delever ourselves through the divestitures of some non-core properties that we need to sell now that we've upgraded ourselves in really 3 core areas, 2 of which are oil/liquids. So I'm not uncomfortable with the debt we have today. I mean, we're going to have a lot of liquidity, I think, after the borrowing base is redetermined because of the past performance that we've had in the last quarter of this year plus this acquisition. And I think, again, we've mentioned this, we -- historically, if we buy something, we will hedge. And what we've done now is we've put some swaps in place and we can protect ourselves from some of the volatility of oil because you don't know if it's going to keep going up or go down. But as Roland said, if you look at half of our oil, wherever that might be in Eagle Ford and in the Permian, and we plan on putting a swap-in or hedging that. So I'm not covered. I think if we were to lever up any more, I think that would be a bad thing. I do think that we put in 2012 part of our budget is to develop and see what kind of value we have, Jack, on this 12,000 net acres that's elsewhere in the Permian. No one has talked about that. It's exploratory, but it's an investment that we've made. Again, it's maybe $5 million. And maybe it's got a lot of sizzle and upside or we wouldn't have been acquiring that acreage over the last year. So there's a lot of things that we can do to delever if we want to. And it would be nice to have less leverage, but I'm not concerned about that versus where we are with the flexibility and the quality of assets that we have.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Roland, going back to Ron Mills' question on LOE, if you were switching from gas, which is low LOE, to oil, I have to assume your LOE, current Bcfe will be more than 2 -- can you give us a little bit more indication what you're looking at on a -- potentially?

Roland O. Burns

As far -- and I think it's also a different answer like where you are in the stage of the life of both wells, because we're in the early stage where you don't have artificial lifts, so that helps. And over time, as you put in more artificial lifts, you'll have higher lifting cost. But overall, because -- I would say that the biggest element that we're adding is production taxes because they're going to be higher on oil, and we had a lot of -- we had exemptions in other areas on the gas. But I think when you combine this program with the Eagle Ford program, we see our lifting cost probably get a little bit over $1 per Mcfe basis where we had them down to as low as $0.80, I guess, in the third quarter. So I think that's the combined impact of both of those, and mainly that's the production taxes driving that up.

Operator

And our next question will come from the line of Michael Bodino with Global Hunter.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

This is actually Dan Morrison, with a couple of quick questions. Michael's out. Most have been answered but the -- I wonder if you're thinking about the ramp in activity on the new Delaware Basin stuff as the rig count builds, what sort of cycle time do you see in the drilling out there just kind of a spud-to-sales number?

Mark A. Williams

Dan, we're modeling spud-to-sales about 60 days.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

60 days?

Mark A. Williams

Yes.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

And a couple more nits out there, gathering system access, is there CapEx built-in for that or is -- does Eagle already had a lot of that...

Mark A. Williams

The gathering system was set up as a separate entity. The gas gathering system and the salt water disposal gathering system were set up us 2 other entities and were marketed separate from this package, simultaneous for this package but separate. So they will be sold to a downstream-, midstream-type company, and we'll deal with them. But the basic structure has already been established. The contracts are in place, and most of the major lines are already on the ground. So it's really just tying in the well as we go from here forward.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Great. And as to the other acreage, Jay mentioned that it's not necessarily in this area. Can you describe it generally as to what other parts of the basin it's in?

Mark A. Williams

I'd rather not go into more detail other than this. In the Permian Basin, and we're focused on a -- as an unconventional shale player.

Miles Jay Allison

There's a major operator in that area, and we still need to visit with them about what their direction is as far as developing their part of that region. So I think this is probably a first quarter or year -- this is probably a year-end, a February-type event and we'll talk about it.

Operator

And our next question will come from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Kind of make up, you guys talking about being 75% oil. I'm assuming that the gas is pretty liquids-rich, can you give us a sense of what the NGL content in there is? And talk about the Eagle gathering system, I imagine is also some process systems to deal with the NGLs. Can you kind of talk about that and give us any sense of what type of transportation or processing cost might be involved here?

Mark A. Williams

I don't have the transportation cost front of me, Leo. This is Mark. But the gas is transported via this midstream entity that Eagle had set up, and then it's purchased and processed most of it by Regency, and there is a processing agreement in place

[Audio Gap]

Some of it based on the processing statement that the gas, including NGLs is worth about double what NYMEX is and so about half the value of the gas is in NGLs and about half of it is in the residue is the way to look at there.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. So I guess you talk about value there being worth double just the gas stream when you factor in NGLs. Is that net of cost you might have to pay to the processers here? Or is that kind of prior to that?

Mark A. Williams

That was net of costs. That was the net back from them.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. Just in terms of your acreage there in the Delaware, it looks like you got like around 65% working interest. Just wanted to get a sense of who your partners are there?

Mark A. Williams

They are various partners. Atlantic is an operator adjacent to us and they have some shared acreage. J. Cleo Thompson is a partner, and they have some shared acreage. And then some of it is just made to be available or leased to other parties that hadn't been drilled on yet so we don't -- we're not sure who the partners are. On top of that, at about 85% of this acreage, we will own at least 50% working interest in it. And so we will operate about 85% of it, which we really like. We like to operate what we buy, so that was a big thing for us.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. In terms of the economics you guys put out there saying $4 million to $4.5 million well cost, 180,000 to 250,000 BOEs per well URS, are those numbers strictly based on your -- the 29 gross wells that have been drilled in and around your property? Are those kind of just more based on actual results, or is there any kind of projection involved there from you guys?

Mark A. Williams

Well, you have to project all the wells that are currently producing. So, yes, I guess, it's a combination. But it's based on the 29 producing wells, plus there were a good number of wells drilled and producing by other operators adjacent to our acreage and in the vicinity that we use as our analysis. So we had a good basket of wells to do our projection from and feel comfortable with those averages.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. So I guess maybe put it in a slightly different way, were the well costs thus far $4 million to $4.5 million?

Mark A. Williams

Yes. Those are based on actual cost and then looking at that and how we would do it versus what they were doing and make some small adjustments. But pretty much, that's about what they're running from there.

Miles Jay Allison

Yes, and that includes the 5 that are either being connected to sales or the one that just TD or the 2 that they're completing also, that's where we're getting our numbers.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess last question, you guys talked about the 12,000 acres. Are you still adding to that position?

Miles Jay Allison

We've added probably all the acres in what we call an A region. We do have a B and a C region. Because we started out in the A and we still have some acreage in the B, C, and then we'll talk to an operator that kind of has some contiguous leases and see if we can come up with agreement to develop that. It is an exploration play, though. So...

Roland O. Burns

So it's a ground-floor leasing, going door-to-door. We've got other -- we have more in process, so we'll definitely grow.

Miles Jay Allison

Again, that's probably a February-type of announcement, just where it is and what we're doing. We're going to spend a few dollars in 2012 to drill the well on that acreage, and then depending upon the success or failure, then we may add to that.

Operator

And our next question will come from the line of Kim Pacanovsky with MLV and Company.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

I have a question about your Slide 5, where you show the horizontal and vertical drilling in both the Delaware and the Midland basin. And you did note in your comments that there is a pretty -- I mean, there's a clear demarcation in the Delaware Basin between the region that is being drilled, or permitted, horizontally versus vertically. And I'm wondering if there's something geologically that has controlled how does this is being developed, or is it just how the play has pretty much moved south? It's quite different from how the Midland basin was developed vertically and has moved to a horizontal play.

Mark A. Williams

Yes, Kim, this is Mark. We don't see a real -- a geologic region for that demarcation. That's one of the things we really like about this deal is I think a lot of it has to do with which operators are aware. You've got the Avalon, which is really hot in New Mexico and has worked south with the horizontal operators. And then the way Eagle developed this, as just a vertical play to start with, they'd looked at the horizontal, they just hadn't executed -- really executed it yet. And then the other players just to the south are more traditional vertical players. So I think they just hadn't made the next step yet. So we don't see a reason data-wise why that demarcation is there.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay, well that's good news. And can you give us an idea of what the -- you've announced the IP rates on the 29 wells and neighboring wells. What are the 90-day rates look like?

Roland O. Burns

Those were EURs that we've...

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

No, didn't you -- you had some IP rates on the -- on your 29 well. I thought you did.

Roland O. Burns

No. You got me there. I think all we have...

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Yes, 30-day IPs, 150 to 300 BOE a day.

Roland O. Burns

Yes, 30-day IP, they run between 150 and 300 barrels a day.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. What about 90-day rates?

Roland O. Burns

I have not looked at the 90-day rates, Kim.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. Wondering if you would put a curve out on your slide deck showing the decline curve and the IRRs, that would be interesting. And just a question for Roland, just confirming right now, you were at $500 million line with $350 million available, is that correct?

Roland O. Burns

Yes. The borrowing base before the acquisition is $550 million.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

$550 million, okay.

Roland O. Burns

And it goes to $700 million at close.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And then when's the next redetermination after that?

Roland O. Burns

The next redetermination is -- the spring line when it usually wraps up in April. It's a March-, April-type timeframe.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And again, what was the date that you'd anticipate to have the property sold? Is that, is this -- do you have any bids on the properties yet? Is this already ongoing?

Roland O. Burns

No, it's not going to go onto the market until January. We're assuming that we would own those properties in the first quarter, but probably, the second quarter, we had hoped to be out to close on those divestitures.

Operator

And our next question will come from the line of John Freeman with Raymond James.

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

What was the PUD percentage on the 23 million barrels of reserves you picked up?

Roland O. Burns

It's -- John, this is Roland. Basically, the reserves are 10% developed and -- so it's 90% undeveloped, the 90%.

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

Okay. And then, the other question I had, in terms of just other ways to think about possibly reducing the leverage further, I guess to sort of use your words, Jay, would you all consider or entertain the idea of maybe selling the B team sort of acreage in the Eagle Ford in that, especially that, that southwestern out-of-scale don't have any plans to drill in 2012?

Miles Jay Allison

We gave you some B team numbers, I don't know we had B team wells, and we have better A team. I think we have 1,000 acres near the GP well, which you described as the 5,000 acres being bad, which I disagree with. I think we have 1,000 acres to the north of that GP well is probably not good. But I think the acreage to the south of that is getting better and better and better. Like Mark said, we're not using any new type of frac techniques. We're just learning a little bit better on how to frac these wells. So, no, I don't think we'd be interested in selling our oil/liquid properties like the Eagle Ford to sell those and then buy in the Permian. I mean, the reason we own the Eagle Ford is we want to add the Eagle Ford to the Permian to have a greater percent of oil. We're not interested in royalty trust. We're not interested in perpetual preferred shares. We're not interested in environmental production payments or those things right now. We'll delever by some asset sales, but I think we would sell the properties that were not nearly as oily/liquidy outside the Eagle Ford versus selling the Eagle Ford right now.

Mark A. Williams

Yes, I think, John, over the longer term, we have other conventional properties, especially in some regions that we don't have a big focus in, that we would like to divest of. But they're not as -- they're very much dry gas, and we fear we would not get the kind of price we want for those at this time so we've identified the properties in that same category that were wetter, so that's what's going to go on the market. But then as the long term gas prices show some strength, we would -- there's quite a bit of unconventional properties that we would sell that wouldn't tie into the future of developing unconventional shale. So that's definitely on the horizon, but it's not our immediate business plan because we don't feel like the gas price is high enough to get that done.

Operator

And our next question will come from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

So does this acquisition say as much about East Texas gas as it does West Texas oil, meaning is the message here that the domestic gas market is not about to tighten anytime soon, and that maybe the move to further diversify is critical to building sustainable growth? I guess, that's the long way of me asking you about your outlook on natural gas.

Miles Jay Allison

Well, I think right now, we never thought we'd have a 343 50 gas, and we do have right that now. And I think the size company that we are, we needed to have more balance. I think we're very fortunate, Dan, to have the Haynesville/Bossier and to be one of the very first ones to enter it back in 1995 when we bought Sonat out of their assets, which happened to be in the Logansport area. And we're fortunate not to sell that for 16 years. And the very first well that we deepened to "find a shale play," which was in Logansport, and so the Parish happened to be the Tier 1 at the Haynesville. So we kept that. We developed it. And we got to the point where even though we became one of the top low-cost producers, I mean, we still had to fight the commodity price. And we had traditionally hedged if we bought something, but we didn't hedge a drilling program, we just quit drilling wells. And we got to the point where we said, "We got a really good dry gas play." We wanted to inventory it. We don't want to sell -- we don't want to sell a core asset to buy "another core asset that's a little oilier." What we like to do is we like to preserve the one we have then we'd like to add kind of an oil region. As you remember in '08, we divested ourselves of our -- of Bois d'Arc into Stone, and then when we did that we eliminated a core area, which is the shallow waters of the Gulf of Mexico. So we kind of like we needed to add another core region. It goes back to my opening statement, we've been looking, and the very first thing we did is we said, "Well, South Texas is already a core area, let's just expand it to the Eagle Ford. We're already in the Vicksburg, Wilcox. But that's not a shale play, let's go to the Eagle Ford." We started adding then 2010. We looked at the strength of our G&G group, our reservoir engineering group and operations groups, and we said, "Well, where's another really good basin?" And it's the Permian. And we advertised for probably a year, even with you, Dan, that we'd like to add another oil basin that's proven, that's mature. So we start adding acreage in the Permian, which is at 12,000 acres, because we had to have a balanced E&P company. We were so gas-oriented that even though we put 3, 4, 5 rigs in the Eagle Ford, it wouldn't make a big difference over a 12-month time period. And besides that, I always say we don't want to be reckless. And I think you can put too many rigs in a new basin, which the Eagle Ford is a new basin, as it is a couple of years ago. You can have some strained results, kind of like John from Raymond James said, "Well, some of your wells are better than others." That's right, because it takes a while to figure out how to do that. Well, we've added now a basin that's been there 60, 70 years, which is the Permian. We needed it, and we can adjust this -- if for the very first time in our corporate history, even though we've got a little leverage here, we got 50%, 52% debt-to-cap, which is still -- it's not preferred shares that we've issued or royalty trust or volumetric production payments or joint -- JV partner. This is our bank line, that even though we levered up little bit on our bank line, what we're able to do now is we can reduce the CapEx dollars that we could put in to Haynesville/Bossier, at the same time, we can now increase it on oil and make a difference. I mean, anytime you could go from 2011 to 2012 and all of a sudden in 2012, 72% of your budget is for oil projects, and a lot of those are vertical, which are probably little safer than horizontal in a very mature area, which is the Permian. I think we've added a huge chapter to this company. I think the issue you should have is whether they have too much leverage in a risky basin, and I'd tell you it's -- in our opinion it's been de-risked. That's why we use our credit line to buy it, and now we can turn these knobs. I mean, we don't have to sell our core area to add the Permian. So I think it's a great thing. I know some of the comments we're -- we want to give you -- we don't want to change any value until you drill a couple more wells out there. I think you're going to see with the 34 wells that been drilled and 29 completed and connected to sales, that's what you're going to see in the future except you may see a little better wells. I mean, the company that bought this and how they were financed, their business plan was take the leases, de-risk it, sell it. And we're very, very, very fortunate to buy this from really a knowledgeable, experienced seller. And they achieved their goal and we've achieved our goal. And we needed to turn this corner sooner or later. It's a long way to answer your question.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And just a follow-up question, you've got a lot of neighbors in West Texas, as you illustrate on Slide 12 in your presentation. How much bigger can you get in that part of the Permian Basin? And where else would you venture to increase your exposure to West Texas oil?

Miles Jay Allison

Sure, I think that's a really great question, that's something we leave out. Once you're in a basin like that in a material way, which we -- we didn't want to "nickel and dime ourself into a new basin." If we're going to get in a new basin, we wanted to get into it in a big way. That's why we never came out during 2011 and said, "Well, we've picked up 2,000 acres in the Permian. We'll pick up another 3,000." Well, guess what, we have 12,000 net acres now that are exploratory. We didn't -- we thought that would just trick your ears, and we didn't talk about it. We said we're -- we have started adding acreage in the new basin, and we wouldn't have talked about the 12,000 net acres in the Permian even today had we not added this "marquee asset." So now that we've added this, I think then you can add to that. One of our directors has lived in Midland his whole life. I mean, I was there for 5 or 6 years in the oil and gas business as a practicing attorney. I mean, we've got a lot of relationships in the Midland area. They're great people. It's a great basin. So I think we'll grow that basin, I think we'll grow it materially. But we'll do it cautiously and not recklessly, because at the end of the day, you have to have a profit.

Operator

Ladies and gentlemen, this concludes the Q&A portion of our call. I would now like to turn it over to your President and CEO, Jay Allison, for closing remarks.

Miles Jay Allison

Again, we gave everybody short notice for a great cause. We did cancel out on some conferences. We're sorry for that. I hope everyone is as pleased with the transaction as we are. It was unanimous at Comstock, from the Board all the way to the management, that this is an acquisition we should go forward on. We thought it's a safe acquisition. I rely upon Roland as far as leverage, and I rely upon Mark and the group as far as the quality of reserves and the risks that we might be taking. Subsurface, I'm pleased with the outcome. I think we've turned a corner, and as much oil as we want to add in the next several years, we'll be able to do that. We're always thankful for the following and the support, and we'll continue to work hard for you. Thank you.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day, everyone.

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Source: Comstock Resources' CEO Discusses Acquisition in the Delaware Basin and Provides Update on Eagle Ford Shale Drilling Program - Conference Call Transcript
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