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EXCO Resources Inc.

Q2 2010 Earnings Conference Call

August 4, 2010 09:00 ET

Executives

Douglas Miller – Chairman and Chief Executive Officer

Harold Hickey - Vice President and Chief Operating Officer

Steve Smith - President and Chief Financial Officer

Paul Rudnicki - Vice President of Financial Planning and Analysis

Analysts

Neal Dingmann - Wunderlich Securities

Brian Singer - Goldman Sachs

Gil Yang - Bank of America Merrill Lynch

Jeff Robertson - Barclays Capital

Nicholas Pope - Dahlman Rose & Co.

Irene Haas - Canaccord Genuity

Daniel Morrison - Global Hunter Securities

Ronnie Aisman - JPMorgan

Ray Deacon - Pritchard Capital

Chris Pikul - Morgan Keegan & Co.

Nathan Weiss - Unit Economics

Operator

Good morning, my name is Maria and I will be your conference operator today. At this time, I would like to welcome everyone to the Exco’s Second Quarter 2010 Earnings Release Conference Call. All lines have been placed on mute to prevent any background noise.

After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you, Mr. Doug Miller you may now begin.

Douglas H. Miller

Thank you. This is Doug Miller, Chairman and I will lead off the meeting but before we get started first of all I have eleven guys in here today with me so…I have Steve Smith, Harold Hickey, our COO, Steve’s our President, Vince Cebula, one of our board members is with us today; we are going into board meetings right after this. John Jacobi, Paul Rudnicki,, Chambers and Jameson are here to run all the Haynesville area. I have 2 lawyers to keep me -- say explaining Boeing and Justin Clark Ramsey is here and Mark Wilson so we are going to stick with you as long as we need to.

From a question-and-answer, I think things are cleaning up pretty good around here so before we get started Doug, would you read our disclaimer.

Doug Ramsey

Sure, thanks Doug. I would like to remind everyone that you can go to www.excoresources.com and click on the Investor Relations tab on the left hand side of our home page to access today’s presentation slides.

The statements that may be made on this conference call regarding our future financial operating performance, structure and results, business strategies, market prices and future commodity price risk management activities, plans and forecasts and other statements that are not historical facts are forward-looking looking statements as defined in section 27-A of the Securities Act of 1933 and section 21-E of the Securities Exchange Act of 1934. Please refer to pages 28 and 29 of the slide presentation for the complete text regarding our forward-looking statements.

In addition please refer to our website for the earnings release which contains additional information regarding our forward-looking statements and the preparation of our financial disclosures including reconciliations and other statements regarding non-GAAP financial numbers which will be discussed on today’s call; Doug?

Douglas H. Miller

Thank you, I’m just going to make a brief statement and then we’ll come back…we’re going to go through this in detail with everybody. I just want to say that it's been a long, hard year and a half. Many of you who’ve been long time shareholders, we’ve told you what we were planning on doing which is emphasize our shale plays, try to figure out if we can get joint ventures done and most importantly, reduce debt.

We just recently done a road show and shown everybody mission accomplished. We have gone from $400 million a day to pro-forma about $200 million a day while reducing debt from $3 billion down to about $600 million. And at the same time we have closed two joint ventures with a spectacular partner who is really bringing something to the table. And we are matching forward on an aggressive development plan in Haynesville Bossier which we’ll get into in a minute. And by the way, I think we’ve told everybody down there that we now have identified the Haynesville play as a 600,000 acre play in our mind as something that has economics at current gas prices. We have a slide in here in a minute that will talk about that.

We are beginning our planning stages for the Marcellus, we do have a rig up there running, we are going to three rigs. We are going to start drilling there, we’re going to have a busy August, September as far as frac jobs but we do have a plan but we’re in meetings with our team and BG’s team trying to get a three-year plan put together, which, I might add, includes a lot of pipeline work; Hal will get into that in a minute but it's something that’s going to be a slower ramp up than the Haynesville was but I think it's going to be very exciting cause we have seen some interesting results in our neighborhood and we continue to look for acquisitions up there.

We just recently closed two acquisitions down in the Shelby Trough; we continue to look for additional down there. We do have up three rigs or four rigs running down there.

Unidentified Company Speaker

Three.

Douglas H. Miller

Three rigs running down there, I know one of them is being prepped as with today and we have two or three more lined up. August is going to be a very, very busy month for us as far as fracs go, I know that we have about ten of them coming on so everybody is running around.

I want everybody to understand that we are not looking for oil; we are not looking for additional plays. These two plays are going to keep us active for the next ten years. We continue to do tack-ons in those areas. And I also want everybody to understand that if gas prices go down from here, we do have a plan and we will shut rigs down. We’re doing this for economics; I want everybody to underline that we’re doing all these over the next three to five years inside our cash flow. Having a great partner like BG allows us to that; the two carriers that we have are allowing us to stay inside the cash flow.

We’re going to continue to be like that and if gas goes down we will shut down rigs; we have shut rigs down in four areas already as gas came down below $5 and they will continue to be shut down.

And we also believe that -- I believe, I don’t know about we, that probably 80% of the gas drilling that’s going on right now has a low rate of return. So this -- there’s a lot of guys drilling for other than pure economics right now, whether it's conventional or parts of the shales; we’re not going to do that.

With that I’m going to turn it over to Steve, are you next up?

Steve Smith

I’m next up. Let’s turn to slide 5 in the slide presentation and we’ll just do this. I’ll just reiterate a couple of things that Doug said. One is that we are up to 23 of 73 operating wells in the Haynesville now that the IPs are over 20 million a day meaning most of them are over -- average about 23 million a day.

The Shelby acreage that we bought included 23,809 acres to Exco 47,600 to the joint venture. It's going to be a tremendous focus area for us, we’re going to be ramping up very rapidly and Hal will get into that. We spent about $400 million on that acreage and we think that it's going to be a really, really strong area.

The Appalachian joint venture was a $985 million transaction of which 835 million was cash and 150 million carry, which the carry work with BG in effect pays seven eighths for a half and we’re paying 8 for a half until 150 million is spent. And we did recognize the gain in our financial statements on that of 575 million. There was a little bit of a cash tax leakage like $9 million or something which was alternative minimum tax but outside of that we had it covered with bases and our wells etcetera.

Our organic growth going forward is going to be extremely strong, of course team is going to be real strong because of the low level at which we got our act of the sales our production was but we’re expecting a 30+% growth over the next five years so we’re pretty excited about where we are.

On page six, I’ve been struggling to try to give you something that is comparable and the best I can do is we compared our Q2 ‘10 to our guidance that we came up with earlier in the year. And really we pretty much are right on, revenues, hedges; the whole -- every metric is pretty much right on. Obviously the sales complicate comparisons to prior year numbers but from our production standpoint -- I’ll show you a slide in a second that will kind of put that in perspective.

Revenues were more than our guidance because volumes were high and we had stronger differentials particularly in the little Permian asset we have and also in East Texas, North Louisiana. Our production growth compared to the second quarter of 09 on a pro forma basis was at 33% and our direct operating costs we’re pleased with where we are on that; they were down 20% year-over-year.

Quarter-over-quarter there was a slight increase in lease operating expense but that should reverse itself pretty quickly, we think, as we get our water disposal systems up and running and get our water usage tap lines built. So that’s going to be -- I think that will be something that will be going down.

Our Haynesville production is about 44% of our total production in the second quarter and as many of you have seen, we’re ramping that up very rapidly so we will go over there as we go through this.

Slide seven shows our production growth between the -- we’re really think what we’re going to be doing is adding about 50 million a day over the next few quarters where so far our active rate is 41% compared to the end of 09. We’re growing it 33% quarter-over-quarter and 14% Q1 versus Q2 of ’10, so all of that is right on what we’ve projecting that we would do and it's working smoothly.

The next slide number eight is the net cash operating margin; we took a little hickie in this particular area this quarter primarily almost exclusively because of the price. The average price was $1, and a nickel less between the first and second quarter and then as I said we had a little bit of an increase in overall costs of about $0.04 which -- that plus some cash sale -- we had more cash sale actually in the second quarter than we did in the first so that’s what happened in that area. But still, it's a strong operating margin…

Doug Miller

We had more in the first quarter than we had in the second, isn’t that right?

Stephen F. Smith

No, actually.

Doug Miller

Okay, I’m sorry.

Stephen F. Smith

So anyway, that’s kind of where we are on the margin slide and obviously a little more price will help a lot.

I’m going to turn this over to Paul and let him roll on through this and he’ll discuss a lot in more details.

Paul Rudnicki

Thanks Steve, I’ll pick up on slide ten. Looking at our liquidity and financial position at the end of the quarter, we ended the quarter with $173 million of cash of which 75 million was restricted cash where we put on deposit for some of our activity in the joint ventures.

Our bank debt into the quarter at $477.5 million even though it's continue to be outstanding at $444 million total debt, 922 million net of the cash were at 750 million roughly of net debt at the end of the quarter.

Our borrowing base just to remind everybody as we close the Appalachia joint venture in the second quarter, we reduced our borrowing base for 100 million so now our borrowing base is1.2. With the outstandings on the cash on hand we’re at nearly 900 million of liquidity. All of our transactions have closed, the major acquisitions and obviously the joint venture sale.

Shown down to slide 11 highlighting where we are in terms of our hedges for the rest of our hedge book, we continue to be pretty well hedged for 2010. We have added some hedges in 11 and 12 and we’ll continue to do so as we see opportunities in the market.

We’re targeting getting the 2011 hedges up to 50% of our expected production and ’12 up to 25% of our production. And that’s going to be our new target for rolling our hedges in this environment with the capital structure that we currently have.

Slide 12, looking at our guidance in a little more detail versus where we came in, Steve mentioned, our production came in right on the high end of our guidance at 292 million a day. Our differentials continue to be strong; oil came in a little bit better, nearly $1 better and the gas differentials as Steve mentioned were affected by the strong BTU that we have in the Permian as well as our marketing groups’ efforts in East Texas, North Louisiana.

Lease operating expenses tended toward the higher end of our range. Those were mainly as a result of chemical and treating costs that we had both at the Vernon fields and in the Haynesville. In the Vernon field we’ve been working to arrest the decline there and the guys have done a good job and been successful in it. We did have some higher treating costs as we went in and worked over some wells.

In the Haynesville we experienced some higher levels of H2S and going forward our midstream subsidiary is going to take up the treating of that so it will be covered by the charges that we pay to them. And as Steve mentioned we’re finalizing all of our water distribution and disposal systems in East Texas, North Louisiana and we’ll expect to see our trucking of water going down significantly.

Going down the line, gathering expenses came in below guidance mainly as a result of the higher volumes we were able to utilize more of our firm transportation that we have and we’ll be fully utilizing that here in the third and fourth quarters.

Production taxes came in a little higher than guidance as the prices came down. The bulk of our production today is obviously coming from Louisiana where their severance taxes are fixed per MCF, so as prices come down, you’re percent of price for taxes goes up. Starting July 1, for the next year, the state has reduced its production tax by [50%] so we’ll see that going down.

Everything else was pretty much well in line down to our cash G&A. Again we tended toward the higher end on guidance as we made some final office and personnel moves for all the sales and the joint ventures as well as some higher legal costs related to all the transactions we’ve been involved in in the quarter.

Interest expense came in a little bit lower on a cash basis as a result of the joint venture. We were able to get that thing closed a little sooner than anticipated. And then the non-cash interest was lower as we finalized our new credit facility we were able to defer expensing some of the old financing costs. And I want to point out again the TGGT Holding that we show as an equity method gain came in right in the middle of our guidance and it was well over where we were in the first quarter and as we’ll show you in the guidance going forward, we’ll expect to see that growing significantly.

One other thing to point out as Steve mentioned on the deferred taxes as a result of the sale of the joint venture in the second quarter, the company became an AMT tax payer for the year. We recognized kind of a catch up entry for half year, roughly $4.5 million of cash taxes. We will expect to have the same number for the second half, so about $2.2 million a quarter for the next half year. 2011 we expect to be back into 100% deferred position.

So just to highlight, our EBITDA came in at $99 million for the quarter which again excludes the $6.6 million net of EBITDA to Exco from the TGGT entity.

Going on to slide 13 just looking at our guidance for the rest of this year, there was some discussion about what caused our production guidance to move around and as we’ll talk about it, Hal will get into a little more detail. We had a successful test in the second quarter of a multi well pad in the Haynesville, actually two successful tests, and as a result we are shifting the bulk of our drilling in the core to DeSoto position to pad development. As a result we’ll have ten rigs currently that have gone from single well drills to multi well pads and what that drilling is causing some of the completions to be deferred into the fourth quarter. So our guidance is down a little bit for Q3 and up a little bit for Q4 to represent that. We are not currently experiencing any delays because of the ability to get frac leads, we’ve got what we need and again Hal will get into that.

That’s really the bulk of the change in our guidance, it was just shifting the production and again highlighting that we will be a slight cash tax payer for the rest of this year for the AMT issue that I just discussed. And the highlights we are expecting for the full year are EBITDA to come in at around $519 million.

Going on to slide 14 looking at our capital for the year, relative to that $519 million of EBITDA, we expect our capital to be $472 million. We spent $135 million in the quarter, $90 million in the first quarter and when you look at the first half of 2010, we had $248 million of EBITDA and $225 million of capital expenditures, again living within our cash.

On top of the capital for the year we’ve also closed $454 million of acquisitions, plan to contribute up to $75 million to our TGGT subsidiary during the year and we also expect to receive an additional $130 million from BG Group for certain acquisitions we have made that they’ll be reimbursing us for.

And as Hal will get into, we’re focused on costs…we’re focused on operating costs as well as development costs and we’ve got some initiatives in place that we think will be able to start reducing some of those.

With that I’ll turn it over to Hal for the operations section.

Harold Hickey

Thanks Paul. I’ll start on slide sixteen. It’s a great picture of what this company has done and where we are going. Our teams are doing a great job working together and we are positioned for growth. It’s going to happen, like Paul said, within our EBITDA and we’re going meet our economic hurdles as we drill and our economic hurdles is that we -- our basic one is that we are going to exceed 20% before tax rate of return on our drilling. The portfolio is very focused, Haynesville Bossier and Marcellus shales, and this year we’ll deliver, like Steve said, organic production growth of 50%, 60% or even more.

Slide seventeen gives you some detail on what we are doing with our well cost. Back in the second half of 09, we averaged slightly above $10 million, came down in the first quarter and it’s crept back up to about 9.9 or so for our Q2 average. We have a target going forward for the year that we are going to try and push that back down to the $9.5 million range. And what you can see with some of the detail on this slide is that our OCTG oil country tubular goods or casing cost have actually come down a bit. Our rig costs have come down a bit over the first -- since the second half of 09 over the first six months of the year. And we are actually averaging just slightly over $20,000 a day now for our daily drilling rig rates.

Drilling special services, and this includes our mud, our drill pipe rentals, location preparations search has come down a bit. But where it’s gone up is actually on our fracture stimulation services. And we are working with our service providers, we are getting long term commitments, like Paul said there are no delays at all. We have all the services we need, we are actually going to grow that fleet. But right now the costs have crept up and it’s something we are working to manage and working with the service providers.

Slide eighteen shows that in our Hali DeSoto and Shelby asset locations where we are exceeding $20 million a day and in our $10 million well cost you need $4.00 to $4.25 gas price to achieve our rates of return. We are very well positioned for that. But overall, we think that there are some areas of the Haynesville where it’s a tough ticket.

Average, including our averages that are exceeding the 23 million are about 13 million a day and that’s probably gotten better over the last a couple of hundred wells. But that said, there are parts of the Haynesville where it’s pretty tough to meet these 20% hurdle rates that we use as a minimum criteria.

In turn we’ve deferred drilling, like Doug said, in parts of the Haynesville play and across our portfolios so we are only drilling where we can achieve the appropriate rates of the return hurdles that we are that we target.

Doug Miller

I think an interesting number that we got, I don’t know when this was as but there have been 868 Haynesville completions in the entire Haynesville area with an average IP rate of 13.4 million a day, that included ours. If we took ours out, it would be roughly 800 million with an average IP rate of 12, 6. And as you can see, we will not drill those wells. So the industry, you know we had higher prices for a while and a lot of guys are learning but there is a lot of areas there that there is uneconomic drilling going on which is why we exited, okay?

Harold L. Hickey

Okay slide nineteen, I’ll spend a little time on this slide. There is a lot of detail here I want to get into. Our current rig count, we got eighteen rigs drilling in the Haynesville Bossier. We’ve got one drilling in the Marcellus and we’ve got two drilling in the Permian moving about our all year play.

At year end, we’ll probably be at twenty two in the Haynesville Bossier, three in the Marcellus, we’ll hold Permian flat. So we’ll go from probably twenty one operated up to about twenty six or twenty seven operated. And we currently have 73 operated Haynesville horizon wells that we’ve drilled and that are going to sale.

There is probably another ten more as a result of the acquisitions that we’ve done in the first and second quarter. We are participating in about 57 none operated Haynesville wells. And we plan to complete probably nearly 60 operated Haynesville wells during the second half of ‘10 and then we’ll also participate in another 15 plus of outside operated wells.

Today, we have three Haynesville wells that are being fracced. We have thirteen that are TD’d and awaiting completion. And our average between rig release and turn to sales is running from three weeks to eight weeks depending on whether the wells are on a single pad, a single well or whether we are on pad drilling. So that’s impacting us a little bit. That reflects the numbers that Paul was talking about; how we are deferring a few of the completions we had originally scheduled for Q3 and the Q4.

We’ve completed our first two Bossier wells in DeSoto Parish IP’s of 11 and 13. We will not be drilling additional Bossier wells there this year. We don’t like the returns at this point. We think it will be worked out over time. We will drill a couple of additional Bossier tests down in the Shelby area in 2010.

We recently had our Marcellus completion that had IP of four million a day. I’ll talk about that in a minute when I get to our Appalachia division. And we are on track to spread some 260 total wells this year, about 210 ours operated. And things are going swimmingly. We are doing a good job. We’ve got about 15 of our rigs are in DeSoto, nine of them are on pads now we’ve got three rigs in Shelby. And we’ll be adding rigs in Shelby that I’ll talk about in just a moment.

Slide twenty, we got about 80,000 net Haynesville acres. You could see we’ve got two focused areas. One Northern DeSoto Parish and a little bit of Southern Caddo, and two over in the Shelby area particularly in North West and Augustine County where our drilling activity is today. We’ll continue to optimize our drilling and completion methods.

You heard me talk about how we are targeting bringing our cost down to about 9.5 million from just below ten. We are trying a different proper mix. We are trying varying our volumes of stimulation. We’re optimizing our bins bits. We are looking our submit programs. So all across the drilling and completion effort we are looking at how we can improve our efficiencies and improve our cost.

Our average IPs remain outstanding and of course our development is going to focus on those key areas where we can get 20 million a day. This map besides you showing the two focused areas I will remind you Doug showed our EXCO BG JV area. That’s outlined in dark and then all the tan is where we think we’ve got Haynesville Bossier shale. The green is our EXCO lease position.

Slide twenty one, I talked earlier how we had the 73 operated Haynesville horizon wells going to sale that we’ve drilled. We’ve about got ten more that we have acquired through acquisition. We’re ramping up dramatically.

I do want to take just a moment here and say that when you go out and look in the public databases whether it’s from industry or from maybe even some of the state information, it shows us as having significantly less number of completions than we’ve actually done. We think that these databases are six or seven months behind. I think one of the databases I looked at said that we had about 29 completions. We had 29 completions in January so take some caution if you will when you’re looking at those databases.

We’ve initiated our pad drilling that’s going to be a big advantage for us. We think it’s going to bring down some of our location costs. We think it’s going to add some efficiencies and at the same time it’s going to help us manage our completions and looks going on sub surface. We’re monitoring and controlling the pressure drill down on every well. You might recall earlier in these types of calls we talked about how we matched our chokes up to 26 to 28 64s then matched them down.

And typically we’ve held them at 20 64s so we are actually going to go below that then we’ll hold some at 18 or 16. We’ll continue to monitor that program and see what’s most effective both for the initial production to get the water off and over the long term to maximize or optimize our estimated ultimate recoveries.

Slide twenty two is a great picture. It shows our leap pad in our Holly DeSoto area. Back in April or May -- late April early May, we completed our first four well 80 acre spacing test. It’s worked out great. We had an IP rate from those four wells of 92 million a day. They were drilled to laterals of 4,400 to 4,600 feet. 12 to 14 frac stages. Overall we did 53 frac stages on this pad that you are looking at here. You can see the locations of our well heads.

We had over 100,000 horse power on location, probably a hundred people. This was a big logistical effort. It was done safely, it was done efficiently. I’m very proud of the way our teams worked to make this thing happen. So we drilled four wells with two rigs simultaneous drilling from this pad. It was a nine acre pad. We completed with two frac fleets. Used 20 million pounds of propane, 23 million gallons of water that we got from surface sources. Now we are in the midst of finalizing our water source project to access water from a nearby industrial plant which will alleviate some of the truck traffic and alleviate some of the use of source water. But what else we are doing is we are monitoring this performance. We built a monitor well here so that not only did we look at the fracture stimulation as it occurred but we’ve transitioned that monitor well through a monitoring bottom hold pressure at the reservoir here. We’ve got two monitor wells in play here.

Slide twenty three is our new Shelby area. We’ve got nine operated horizontal shell wells falling to sales. One of those we completed. We completed twenty two million a day. I’ll say that for the last three that were completed prior to our acquisition were also in excess of twenty million a day. So we are very happy with these preliminary results. You can see on the map some of our competitors have had results their IP’s are actually in excess of 30 million a day. We’ve got three rigs operating here. We’ll add a fourth in the middle of August, we’ll add a fifth in September, we’ll add a sixth in November so we’ll end the year with six rigs operating in this area.

We now have a dedicated frac fleet down here. It’s going to be moving to twenty four hour operation. They’ll definitely be able to keep up with our drilling up into the fourth quarter. We’ll probably add a second frac fleet down here later in the fourth quarter. And today we have like I said one completed, we’ve got one being completed, we’ve got three drillings and we’ve got four that are awaiting completion. So this is going to be an exciting area for us. We are still looking for opportunities to build onto our acreage. And it’s -- we are confident that this is going to be an outstanding opportunity for us. Now the other thing I’ll say and I’ll get to it in a minute when I get into our mid stream slide. But we are working very closely with TGGT. We’re going to build out a similar mid stream business here as we have in Holly area with headers and flow lines start wells.

So we’ll continue to have prompt hook up and in effect we’ll be testing the sales when we bring our wells on.

Twenty four is our growth plan for the next couple of years. On this slide, it shows that we have about 500 million a day of gross production. Actually over the second and third of this month we were averaging over 540 million a day of gross production. We plan to end the year between 900 million and a billion a day of gross operated production and you can see by the end of 12 we plan to be in the 1.7 to 2 BCF a day ranks. This is going to be some phenomenal growth.

Of course we are working with take away capacity both through our mid stream equity company and with third parties we’ve secured a significant amount of firm transportation. We continue to work with the parties and ensure that we have some non-firm or secondary transportation as well.

So we are in good shape here for this growth pattern and this is what’s going to be done within cash flow and the speed is going to be done while meeting our economic hurdle rates.

Steve’s already talked about the Marcellus JV. I’ve got a few highlights on slide twenty five of that. We closed the JV on June 1. What this thing is going to do is really allow us to accelerate development of our existing acreage and it’s going to capture operating efficiency center. And we are in the midst of a development planned teams effort where since June 1 they’ve got 100 days to come back to us and tell both parent companies BG and EXCO what the proposed development plan is going to be here now.

We are not slowing down. We are continuing to drill with our one rig. We are adding a second rig in August and a third rig is coming in November. But we’ll plan through this joint team on how we’re going to move forward with the number of rigs, how it’s going to be organized, how it’s going to be staffed. So it’s an exciting time for us in planning ahead for what’s going on in the Marcellus.

Now current activities depicted on slide twenty six, we have a drilling program underway. I talked about the delivery of the rigs. These are all brand new fit for purpose rigs, really good day rates, on average below $20,000 a day. The map here is depicting our Leakey, West Leakey area right on the center Clearfield County line. This is where a lot of our activities or the bulk of our activity is going to be undertaken in 2010 for a couple of reasons.

One we’ve arched our contagious acreage position allows us to drill from our pad. We’ve had some pretty good preliminary results, we like to rock here and there is take away capacity as well. So you’ll see here we are on the map about in the middle, we show we have three planned Q3 completions. It’s off of the single pad. We drill these wells and they are all in excess of 5000 foot laterals. And the longest, I think, is about 5800 feet. So late August, early September we’ll be completing those wells and moving them to sales.

Now we recently had in IP in excess of 4 million today just to the west of this map. We are excited about those results and we are going to continue to solidify our land position here. Now on this map, this is probably 40,000 acres or so in these leaky areas, it’s about 20,000 net to Exco. You can see some of the activity there and most of our activity like I said will be here. There will be some other appraisal type drilling that’s going across our acreage across this wide play.

Slide 27 which is the last slide I will talk about again I will talk about our 50% equity interest company TGGT. Throughput has been up around 1.1 billion a day, it’s continuing to grow both in actual throughput and in capacity. We’ve got about 1 billion cubic feet a day of treating capacity here with the inner connects in Holly.

On the left side of this slide you can see our broader map of TGGT and it does not depict what we are going to do in Shelby. And the slide down here in the bottom left of the slide just shows a blow out of our TGGT Holly system. We are building midstream infrastructure like I said in Shelby Country. It’s going to be similar to our Holly system. We’ve got multiple inner connects available we are not going into Ted County but there are several other parties in the area too that have good take away capacity including Tenaska, ETC, NGPL and Ambridge.

So with that I will turn the floor back over to Mr. Miller.

Douglas Miller

Before we wrap up, does swimmingly mean good?

Harold L. Hickey

Good

Douglas Miller

Okay I just to make sure, I wasn’t sure. That’s the first time I have ever heard you use that, is that a North Louisiana term?

Harold L. Hickey

Yeah I learned that up North of Louisiana.

Douglas Miller

As everybody can see we are busy. We’ve had a very successful year and half, with a lot of effort to get where we are. And we are marching and I’d say this time next year, our budget kind of calls for us to be in that 500 million a day. That’s subject to gas prices not falling below $4. If gas prices go below $4 we are going to shut rigs down. But at 4.50, 5, 5.50 these guys that got some heat on them, they are sitting here. Mike can you make that?

Mike Chambers

Sure.

Douglas Miller

Okay. With that, I am going to open it up for questions because I think this is getting pretty simple for us. All we have to do is execute that’s with a capital E and I think we do have some questions so Mariah if you would open it up for questions right now we’d appreciate it.

Question-and-Answer session

Operator

Certainly. (Operator instructions). Your first question comes from the line of Neal Dingmann from Wunderlich Securities, your line is open.

Neal Dingmann - Wunderlich Securities

Great quarter guys. To say Doug’s first question on the pad drilling just wondering as you go forward, what are you all or maybe for Paul, I wonder what you’re sort of estimating kind of cost savings as you go forward and connect that from the four to five to six wells, what are you thinking?

Douglas Miller

I think right now I am going to pitch one out and then you guys are going to all answer. Our forecast going forward is no cost savings. We expect and we are going to try to do some but we’ve used $10 million flat for all our costs and our modeling. So we kind of expect -- Mike, can you handle that?

Mike Chambers

Surface cost savings obviously we’ve been able to use the same path but there are some directional costs that we have to incur to come off of that so by the end of the day it’s about a wash.

Douglas Miller

I mean we are working on it and that just come up and Steve and I keep pushing them but the thing about it is, that pad you saw in the picture there was a 9 acre pad and we drilled some monitor wells and everything else. So we did not save money and that was not the intent, we think we are going to get more production more efficiently. And surely we are going to figure out if there is cost savings.

Neal Dingmann - Wunderlich Securities

Okay then on acquisitions; obviously you mentioned a lot of -- maybe people drilling on some so not economical areas. Are you getting approached more often are you becoming busier looking at things and how aggressive you want to add acreage I guess say the next 6, 12, 18 months?

Douglas Miller

Well we are seeing probably five deals a day. Four of them are in different plays so that’s easy, we are turning them down. One of our problems with our stock that we’ve heard while we are on the road is Doug Miller is a serial acquirer and can’t turn anything down. So we are turning down about four a day.

I would say in the core areas John, I’d say we probably looking at ten deals ranging from 200 acres to 2,000 acres. In the Shelby area and the Holly are we’ll be a very aggressive buyer. Again, nothing big is coming up and I’d say up in the Marcellus I mean it’s unbelievable how much is for sale up there. But I’d say in our focus area maybe 50-60,000 acres that we are working on and no assurances.

We are going to be very disciplined, we want to add if we can add it right but as we add, we have to able to drill it. I mean we do take acreage cost into consideration in our rate of return and that Shelby is a true test. The reason we have six rigs running over there is we pay the price that calls for six rigs running by the end of the year.

Neal Dingmann - Wunderlich Securities

Got it

Harold Hickey

Keep in mind Neal as we add leases and as we are making any new acquisition BG will be buying out. So we are looking at 50,000 acres that’s 25 Net to Exco. Yeah.

Neal Dingmann - Wunderlich Securities

Got it okay and then just in some of your DeSoto and Caddo areas as far as fracs completions, fluids are you still looking at different types or you are pretty much convinced you have what is working the best right now.

Steve Smith

We are really pleased with the selection we’ve made up to this point. Our well performance is -- our wells are performing very well. We are doing some tests we are continuing to look for alternative options and additional options more cost effective. We probably got a half a dozen -- at least a half dozen completion types that are in the ground where we use an alternate type profit. Hal mentioned the cluster spacing, the distance between our perforation clusters, we are really a lot of focus on that just to see if there is waste, enhance our completions but we are trying a few different tests right now.

Neal Dingmann -Wunderlich Securities

Okay and then the last question if I could, just on in similar sort of the same core areas in the DeSoto and Caddo, in Harrison, are you seeing different as far as now the activities wells as you mentioned the numerous wells now you have had on line now for a few months, are depletion rates varying on sort of a well by well or are they all sort of behaving sort of inline?

Harold Hickey

There is always some variations even between the individual sections in the core Holly area but if you step back and you look at it from a bigger picture there is a very -- you can see from the high pitch chart we looked at just a minute ago. The IP’s are very consistent. There are some variations but in overall well performance, I would say in large is very consistent across our acreage.

Neal Dingmann - Wunderlich Securities

Thank you all.

Douglas Miller

We don’t consider Harrison part of the core.

Harold Hickey

Yeah right.

Douglas Miller

Yeah, we said we have acreage in Harrison we are not drilling over there, underline NOT.

Neal Dingmann - Wunderlich Securities

Okay.

Operator

The next question comes from the line of Brian Singer from Goldman Sachs; your line is now open.

Brian Singer- Goldman Sachs

Good morning.

Douglas Miller

Hey Brian?

Brian Singer - Goldman Sachs

On the Marcellus, can you put into context the IP -- the 4 million IP relative to the longer lateral line versus the earlier couple of wells that you drilled that had lower IPs and lower lateral lines.

Douglas Miller

The IP that we got of 4 Billion a day was from a lateral that was about 4700- 4800 feet long. The others were significantly short of laterals as you can see from the slides I think in the 2300 and 2500 foot range

Brian Singer - Goldman Sachs

I guess should one think about that as proportional, whereas a longer lateral line should produce the higher rate, and if so, it didn't necessarily look all that different, correct me if I'm wrong, this well versus the prior two, if we look at it on a per foot of lateral line basis?

Steve Smith

Exactly

Doug Miller

That’s right.

Brian Singer- Goldman Sachs

So I guess as you go forward then, do you think that this is a reasonable Marcellus well, or what do you think will drive improvement on a pre-unit of lateral length basis?

Steve Smith

We’ll continue to refine our completion procedures. We are still early in this play relative to a lot of our competitors frankly and we are very early in this play relative to our Haynesville unquestionably. So yeah we are going to refine it, we do think that there is a definite relationship between the lateral length and IP and ultimate productivity, so yeah we are going to be working on that but it’s something that we’ll continue to refine.

Douglas Miller

Hey Brian, Steve and I like rules of thumb and we’ve been using like a million a day for a thousand of feet as a rule of thumb. And it kind of looks like it’s worked on those first three wells. But up to our north and east we have heard and I think it’s out there that Anadarko has got two IPs probably with less than 5,000 ft laterals at around 7 million a day. So where we are right now using a million a day per a 1000ft. and that north piece is offsetting the acreage we showed you on that map, yeah.

Brian Singer- Goldman Sachs

Great, thanks.

Douglas Miller

Okay I am talking about the Center County.

Brian Singer- Goldman Sachs

Great, thanks. And shifting to the balance sheet with now greater flexibility post the JV. How are you thinking about and what's going to -- what are the key drivers you're looking for to make a call on how aggressive you want to buy back stock versus do acquisitions versus keep debt prices low, and if we look ahead 12 months from now, should we expect that you'll have the full share of purchase that you're approved to do?

Douglas Miller

Well we are not just buying stock to buy stock. I think when we look at deals, we have a comparison. As long as I and our board think our stock is trading at half of what we can liquidate it at, is something we have to take into consideration when we are looking at doing the deal.

Some of this acreage if it’s in a section where we are already operating it, it’s always going to better to do that than buy stock. Having liquidity right now is very critical because if gas prices stay and they have in the past go lower and stay longer than we think, we want to be here when there is a problem. So we want to have liquidity, we plan on keeping liquidity and if opportunity comes, we are going to buy stock. If we can buy it at half of what we think it’s worth and we are getting ready to go into board meetings starting this afternoon and we are going to determine just how aggressive we are going to be at that meeting.

Brian Singer - Goldman Sachs

Great, thank you.

Operator

Okay, your next question comes from the line of Gil Yang of Bank of America Merrill Lynch; your line is open.

Gil Yang - Bank of America Merrill Lynch

Hi. Good morning. On slide 21 of your presentation you have a nice historical illustration of how the well, the IP rates have evolved over time or maybe in some instances not evolved over time. But if I look at the line, it does seem to me that the more recent completions are trailing off just a bit. You have one out of every five wells ticking above the average. Whereas before, every other well was above average. Can you comment on any trends you see there?

Douglas Miller

I think we ought to get a pay cut for some of these guys who are on these wells. Mike, Harold can you talk to that?

Harold Hickey

You know I think there is a little bit of difference you can see at the overall average you see how it compares to 23ft a day. We’ve got in terms of the rate I don’t know is that we are more conservative but everybody has talked about pressure draw down and shift management.

We have elected on a couple of wells if on the trading side when we were bringing the wells up. If we have trading limitations such will limit the rate at that particular point in time. So there are probably a couple of these, there‘s probably more; two or three of these that are on the chart that may have an upward limitation due to pipeline reasons. We are really shifting our focus form IP, I mean IP is a good indicator but it’s not the indicator.

We are really more interested in the first 60-90 day numbers. We are starting to shift towards that and I think in the future you will see us talk about that more than we do currently. But that’s really the key now is really looking at the more long term performance over time

Gil Yang - Bank of America Merrill Lynch

Okay

Mike Chambers

If you’d looked at a lot of these or probably more on the 26 that we IP’d them on and we’re probably more like a 24 or a 22 now. So I would think given a higher pressure of a smaller choke size…

Douglas Miller

Next quarter we do compare an IP of 30 day and a 90 day rates of surveys is at. We’ll do that next quarter.

Steve Smith

Having said all that, the last well we put on production last week was updated 26…

Douglas Miller

Twenty sixth, on the twenty sixth six fifty.

Steve Smith

But not depressed.

Gil Yang - Bank of America Merrill Lynch

Okay. Well, they're still good wells. So, I'm not really complaining, I was just seeing if there are any trends there. In a different subject, the four wells that you put online in the pad, they averaged 23 million a day for the four of them, but beyond that, are there any synergies that you see getting or -- other than the cost side, or do you think the well performance is showing any synergies, or is there anything to speak of there?

Paul Rudnicki

I think we believe that we are putting more energy in the ground and a focused area and we are going to get better production returns and we are seeing that from these. That their performing is good or better than their offsets in that area; so I think we can get by ultimately. We are targeting to be able to pump less fluid and achieve the same results in an area because we have less leak off an we are able to control it more in that area. so yes, we are already seeing benefits from all of our wells of what we have done, separate products and more of these kind of operations.

Steve Smith

And one built on that that I’ll add is we had probably 5 or 6 wells that we saw some interference on from fraccing operations to stimulations operations. When you do it this way, you are minimizing any interference at all, you’re maximizing energy that goes in the ground. So it has positive benefits all the way around.

Gil Yang - Bank of America Merrill Lynch

Okay, and last question. I apologize if you said this, I got on just a bit late and I think I caught the tail end of your discussion. But could you address the issue of -- your recounts ramping up, your costs have gone up for the well, yet you brought down your CapEx guidance for the year. How do I start to think about those different trends because they seems to be conflicting?

Paul Rudnicki

Well first of all Gil, this is Paul. We from the beginning of the year have been assuming well costs at these levels. We saw this early on that these frac costs were coming back. This is not a shock to us and we’ve had that modeled in.

Gil Yang- Bank of America Merrill Lynch

Okay.

Paul Rudnicki

And in terms of the rig counts going up this has been part of our plan from the beginning. I mean I think there really is no change.

Doug Miller

We got some conventional in there at the beginning. We cut all that out.

Paul Rudnicki

We cut some of the conventional back, we have to a small degree offset that, we’ve added a rig in the Permian as we are focusing. We’ve got to get returns on the oil that we are drilling. But it’s really just moving dollars around in the program and I failed to mentioned that we went through guidance, that’s one of the reasons you are not seeing our CapEx go up as we were basically planning on $10 million wells all year.

Gil Yang - Bank of America Merrill Lynch

Okay and I think you’d also been planning going to 22 rigs next year anyway, right?

Paul Rudnicki

That’s right. Part of the Shelby acreage that we bought, this is just, some of this is going to be a rig move from other areas. So we are moving dollars around in our capital program.

Steve Smith

Going into the year, like we said, we had plans to drill in Harrison, we pulled back, it’s not where we are going.

Doug Miller

And those Harrison rigs are moving to Shelby.

Gil Yang - Bank of America Merrill Lynch

Okay, I heard along those lines you said in your presentation that you may slow down activity. You know have you given any…can you elaborate on that. It doesn’t sound like in summer you’d want to slow down but are the current plans you know if we were to see current commodity prices and the current inflation and if you could not get that well cost to 9.5 would you actually slow down on your completions going forward?

Doug Miller

I mean right now if you give us 450, what slide is it?

Paul Rudnicki

Slide18.

Doug Miller

If you look at slide 18, with a $10 million well, if we can continue to make 20 million a day type wells in terms IPs, we see returns at below where we are in terms of commodity prices.

Steve Smith

I think if gas were to go to 3.50 and below we would all sit around with BG and we would… and they will think the same way we do, will price slow down. I mean we are not in this…we’re all shareholders and when we get 30%, 40% rate of return which these guys are getting at 4.75, $5 gas, we are going to continue to drill and continue to look for more opportunities in the same area.

Doug Miller

And I’ll add that we can slow down when you look at the rigs, we’ve got about half of them on long term contract, half of our rigs drilling just well to well.

I mean we are not afraid of shutting down. And we will do it. And BG totally agrees, they are doing this, this is a math problem. And the critical part of the math problem is the gas price.

Gil Yang - Bank of America Merrill Lynch

Okay, Alright. Thank you.

Operator

Your next question comes from the line of Jeff Robertson from Barclays Capital. The line is open.

Jeffrey Robertson – Barclays Capital

Thanks, Doug in the Haynesville you all talked about 3 to 8 weeks I believe spud to sales on your well, is that just your operated wells? And can you talk about how long it’s taken on your non operated wells.

Doug Miller

Talk to him about the difference Paul or

Harold Hickey

Three weeks is our single wells, eight weeks is more of an average on our pad drilling.

Jeffrey Robertson – Barclays Capital

Right.

Harold Hickey

And that is for our operated well. On some of our non operated wells, we have literally seen months, where some of our competitors have had taken extreme amount of time to…

Doug Miller

[Inaudible] to the advantage we have in that pipeline system. Our guys are in every meeting, they have 57 projects they are working on today, or last Monday, hopefully they got one of them done. But it’s such an advantage they are in the meetings, the pressure is on them and if there is going to be a delay because of a permit or something, our operating guys know it. Now we have had some delays, we are getting production shut in that we didn’t think about a year ago, either from offset fracs or tubing and I’d say what are we using in our models, about 8%?

Paul Rudnicki

Yeah, we are 7.5% or so as we call our ”field down time” which as Harold mentioned too, we haven’t changed it in our forecast. But with the pad drilling, we are expecting that to go down significantly.

Jeffrey Robertson – Barclays Capital

How long in Shelby County do you think it will take to start putting pipe in the ground or in your new acreage?

Steve Smith

We are putting pipe in the ground today. We are literally putting pipe in the ground today, we think by year end, we’ll have a pretty good system in place, it’s going to be in our core area where most of our drilling activity.

Doug Miller

They are working their rumps off out there because it is critical to having those rigs running and they know it. So we are putting high pressure pipe in and we are working on inter connects as we speak.

Harold Hickey

When we bought that asset it came with two 8 inch lines already.

Doug Miller

Yeah, it had a good starter kit.

Harold Hickey

Yeah, we haven’t maxed out their existing capacity yet and we are in the process of looping that with a 16inch line right now. So we have capacity in Shelby, it’s not a big concern.

Jeffrey Robertson – Barclays Capital

Is your business there designed just for equity gas or will you also look to add 3rd party gas if it’s available?

Doug Miller

I’d say right now, we are going to focus on equity gas and depending on how and when they get that system done, we will look -- I mean we are already being approached by 3rd parties. I mean right now if we start making these 20 and 25 million a day wells, we are going to need all the capacity we have.

Harold Hickey

We do currently take South Westerns and some of other people’s gas down there.

Doug Miller

Yes. But there is some other actions going on down there Exxon, XTO is drilling I think Cabot has some stuff. We are being approached and there are going to be some needs for pipelines from 3rd parties.

Jeffrey Robertson – Barclays Capital

Okay, thank you.

Operator

Your next question comes from a line of Nicholas Pope from Dahlman Rose, your line is open.

Nicholas Pope – Dahlman Rose & Co.

Morning guys

Doug Miller

Morning.

Nicholas Pope – Dahlman Rose & Co.

I think all my questions have actually been answered. I'll just say good morning and sign off.

Doug Miller

See you Nick.

Operator

And your next question comes from Irene Haas from Canaccord Adams, your line is open.

Irene Haas – Canaccord Genuity

Thank you. Two questions. Firstly, this is really for Paul. I just want to know, is there any adjustment to your first quarter CapEx? Right now, in your most current slide, on slide 13 it's roughly about $90 million. But if I look to your July's presentation, about $130 million. And so really, what I'm trying to get is apples to apples, are you cranking down your CapEx a little bit? So that's question number one. Question number two has to do with the Haynesville timeclock and the Shelby trough area, understanding that most of the other stuff is held by production. So, I just want to get a feel for whether you are under any time pressure to be drilling the Shelby acreage?

Paul Rudnicki

Sure, I’ll handle the capital one and let Hal handle the other one. One of the things that we have done in terms of changing the way we talk about our capital is when we look at our lease dollars, we are looking at leasing that of reimbursements from BG.

As we budget $100 million of leasing for a year of 62 that we’ve got for this year and we go out. That’s budgeted to our net so we think it’s more representative to show what our true net is even though on the cash flow statement we have to show the gross purchase and then the sale later as a disposition for discussions on capital versus what we expected to spend, it’s more appropriate to net those two. So that’s just a presentation that we change.

Harold Hickey

Okay, that’s a good question Irene on the HBP down in the Shelby area. What we have identified is the focus area, we have a plan by the end of next year we will have HBP’d or held by production all of the acreage in that area that’s what we call our [Inaudible] area and our Highland area. [Inaudible] which is an area to the North East we’ve got a term that expires in 2013 on the bulk of that acreage. So we are making plans now but yeah, there is some need to HBP the acreage, we’ve got a solid plan in place and it’s not something that could be of concern to us.

Irene Haas – Canaccord Genuity

How many wells do you have to drill to pin that down?

Harold Hickey

I don’t know, Mike.

Mike Chambers

Between 4 to 6 wells.

Harold Hickey

Down there but I think we only think about 3 to actually HBP everything by that time frame.

So how fast the HBP is is. We are going a little bit faster.

Doug Miller

So we need three and we will be running 6. So we are in good shape. And I think everybody that I have talked to around here thinks that we’ll be our key acreage a 100% HBP by the end of 11. And it doesn’t expire, and 11 expires in 12 and 13.

Irene Haas – Canaccord Genuity

Okay, one more question. Any H2S? Because that's a pretty deep area as well.

Harold Hickey

No

Paul Rudnicki

Haven’t seen any at this point, no. There’s no difference or probably even on the low end of what we have seen compared to Holly.

Irene Haas – Canaccord Genuity

Got you. What controls the H2S? Is there anything with the methodology that would make one area more prone to H2S or no?

Mike Chambers

I don’t know

Doug Miller

I can’t answer that.

Irene Haas – Canaccord Genuity

Okay

Mike Chambers

In Holly, even it’s a little bit of a shotgun, you know we’ll see [Indiscernible] over in one side and 5 on another and the well right next to it will be 5.

Harold Hickey

CO2 definitely [multiple speakers] you get higher CO2 but we don’t see that kind of relationship on the H2S.

Operator

Okay your next question comes from a line of Daniel Morrison from Global Hunter. Your line is open.

Daniel Morrison - Global Hunter Securities

You covered most everything. But one quick one. Have you given any thought to vertically integrating and getting your own frac equipment, given the fact that's such a cost driver on the well side?

Doug Miller

Absolutely not. If you ever catch me getting the service cut slide I’ve given you permission over the last 20 years to shoot me.

Daniel Morrison - Global Hunter Securities

Can I have the stick?

Doug Miller

Yeah you can have the stick. We have had discussions on participating -- we do not want to operate any service companies; if somebody needs some support, we would entertain that. But we are not interested in getting into that business.

Daniel Morrison - Global Hunter Securities

Okay great, thanks.

Operator

(Operator Instructions) Your next question comes from Ronnie Aisman from JP Morgan. Your line is open.

Ronnie Aisman – JP Morgan

Morning guys.

Doug Miller

Hey Ronnie?

Ronnie Aisman – JP Morgan

With the high grading of your drilling in the Haynesville away from Harrison County, does this have an impact on your forecast for 2011 and 2012 production growth?

Steve Smith

No, we -- that shift in capital really started first quarter, late first, early 2nd. We’ve incorporated that in our plans for some time.

Ronnie Aisman – JP Morgan

Okay great. Thank you guys.

Operator

Your next question comes from the line of Ray Deacon from Pritchard Capital. Your line is open.

Ray Deacon – Pritchard Capital Partners, LLC

Yeah, hey Doug, I was just wondering, with your Marcellus acreage, how much capital do you see yourself needing to spend to kind of block up the acreage and make it an efficient development project?

Doug Miller

I mean [inaudible] you saw that one, there is 40,000 acres there we have ten guys up in the field today and John is working. We are looking at deals everyday but I mean it’s down to 200 acres and 500 acres at a time and we are seeing stuff anywhere from 1000 an acre to 6000 an acre in that little core. So it’s detailed now and if we were to buy 50,000 acres in the next 12 months, we would be very happy and 50, 000 acres times 3,000 is 150 and we would only have half of it. So if we spent 75 Million, it would be a lot.

Ray Deacon – Pritchard Capital Partners, LLC

Great, thanks very much.

Operator

Okay your next question comes from the line of Chris Pikul from Morgan Keegan. Your line is open.

Chris Pikul - Morgan Keegan

Hey, thank you. Paul, can you remind us what kind of EUR you're assuming there with that 20 million a day IP rate that gives you that 20% RLR at $4?.

Paul Rudnicki

Sure. At this point, we are -- high curve points to a 6.5 to 6.7 BCF EUR.

Chris Pikul - Morgan Keegan

Okay, and then, I guess, as a follow-up, based on drilling results this year or any choke management or conservatism last year, are there any other performance uplifts you may expect to see this year in the Haynesville from a reserve booking perspective, or incrementally, do you think some of the higher costs you're seeing could be detrimental to the engineering expectations?

Paul Rudnicki

Again, we’ve been assuming these kinds of costs so the cost side isn’t really changing much of what we’ve looked at.

Doug Miller

80 acre space

Mike Chambers

We’re looking at 80 acres. That just goes on the cost side. The 80 acres is the wild card is whether or not we go to 80 acres basing on our reserve reporting this year or next year.

Paul Rudnicki

We have been on 160.

Chris Pikul - Morgan Keegan

Okay. Thanks. And then, Doug, out of curiosity, you mentioned you weren't really interested in moving into a new area from the deal flow you're seeing. Is that because you don't believe you can achieve economic rates of return given acreage costs, or is that just because you don't feel EXCO brings any operational expertise into a new area?

Doug Miller

No, we can do it. We are so busy right now, you need to come in here. Mike and Herald were working on bring people in for 2012 right now. Ramping this up with 80% first year decline rates and with the rig activity we have, we are very busy., I just don’t want to dilute what they are doing. I don’t want to go to the Barnett or the Bakken or whatever. I mean we see -- those deals are floating around and we literally have 10 years of hard work in front of us in these two plays.

Chris Pikul - Morgan Keegan

So you see this as a personnel limitation at this point?

Doug Miller

Well not really -- yeah that’s part of it. But I think we have to dedicate the capital -- you know you can see our budget for the next 3 years is within cash flow. We are at a size if it weren’t for the carry we would really be challenged to ramp up two shales. We don’t need to get in a third one.

And the reality of it is if we can spend that same money instead of entering a new area adding to our current existing position, that’s the best position to use capital for us because we’ve already got the infrastructure, we got the program running -- to start up in a whole new area is just a whole different.

Paul Rudnicki

I can’t tell you how advantaged guys are in East Texas North Louisiana because of our infrastructure. I mean there is no way that we can duplicate that within the next 5 or 10 years in any single play.

Chris Pikul - Morgan Keegan

Great that’s good cover. Thank you guys.

Operator

Okay your final question today comes from the line of Nathan Weiss from Unit Economics. Your line is open.

Nathan Weiss - Unit Economics

Hey guys, how are you?

Doug Miller

Good, how are you?

Nathan Weiss - Unit Economics

Very good, Just a quick question around the hedging. Running through some of the numbers, it looks like you did your incremental 2011 hedges around the 560 area. You stated you're going to 50% coverage for 2011. Are you required to do that in kind of a round--?

Doug Miller

No, we are not required; that is just me and Steve getting old and like and -- 53% rate of return at $5 gas.

Nathan Weiss - Unit Economics

Okay. So there is nothing in your debt covenants that stipulates certain coverage.

Steve Smith

Hey, Nathan?

Nathan Weiss - Unit Economics

Yes.

Steve Smith

Have you raised your target price to above a dollar yet?

Nathan Weiss - Unit Economics

We are 8 bucks. We have been there for a while and now we are still at 8 bucks.

Steve Smith

Bye, thank you -- good talking to you.

Nathan Weiss - Unit Economics

Yeah, you to.

Operator

And there are no final -- further questions at this time. I’ll turn the call back over to you.

Doug Miller

All right thanks. We appreciate everybody tuning in for our conference call and I hope we answered everybody’s questions and stay tuned. I think everybody is executing and everybody is planning on doing it. Any other questions you have give me or Steve a call. Thanks everybody

Operator

This concludes today conference call, you may now disconnect.

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Source: EXCO Resources, Inc. Q2 2010 Earnings Conference Call Transcript
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