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Executives

Douglas H. Miller - Chairman of the Board, Chief Executive Officer, Chairman of EXCO Holdings, Chief Executive Officer of EXCO Holdings

J. Douglas Ramsey - Treasurer and Vice President of Finance

Stephen F. Smith - Vice Chairman, President, Chief Financial Officer and Director

Paul B. Rudnicki - Vice President of Financial Planning & Analysis

Harold L. Hickey - Chief Operating Officer and Vice President

Harold Jameson - Vice President and General Manager of East Texas/North Louisiana Joint Venture area

Analysts

William B. D. Butler - Stephens Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Anne Cameron - BNP Paribas, Research Division

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

K. Adam Leight

Howard Henick

Unknown Analyst

Carl F. Giesler - Harbinger Group Inc.

Alex Heidbreder

EXCO Resources (XCO) Q1 2012 Earnings Call May 2, 2012 11:00 AM ET

Operator

Good morning. My name is Steve, and I will be your conference operator today. At this time, I would like to welcome everyone to EXCO Resources, Inc. First Quarter Earnings Release Conference Call. [Operator Instructions] Thank you. I'll now turn the call over to Doug Miller, Chairman. Please go ahead.

Douglas H. Miller

Thank you. Before we get started, I'm going to have Doug Ramsey, read our -- whatever you call it. What do you call that thing?

J. Douglas Ramsey

Disclaimer.

Douglas H. Miller

Disclaimer. So, go ahead, Doug.

J. Douglas Ramsey

All right, thanks, Doug. I'd like to remind everyone that you can go to www.excoresources.com and click on the presentations link in the Investor Relations section at the bottom of our homepage to access today's presentation slides.

The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategy, market prices and derivative activities or other plans, forecasts and statements that are not historical facts are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on a variety of assumptions that may change depending on future events which are difficult to predict. Actual results may differ materially from those forward-looking statements. We caution you not to place undue, if any, reliance on such statements. Please refer to Pages 24 and 25 of the slide presentation for the complete text regarding our forward-looking statements, as well as the cautionary information set forth in our most recent Form 10-K, Form 10-Q, and other SEC filings, which are available on our website at www.excoresources.com.

In addition, the slide presentation contains information, including reconciliations regarding certain non-GAAP financial numbers, which will be discussed on today's call.

Doug?

Douglas H. Miller

Okay. Welcome, everybody, to our call. We have a slide show that is on our website, that we'll be going over today. With me today, I have 10 people, lawyers, all our financial guys and our operating guys. And we're going to be going over, in some detail, our quarter and we'll be sticking with you through -- as long as you want, as far as Q&A goes.

Just to get started. We have been -- with gas prices going down -- I could sometimes feel like we were driving across Kansas going 90 miles an hour, a year ago, with gas prices high and working as hard as we can. And here about, beginning of the year, we ran into a school zone. And so, I think we've had to figure out how to go slower and we're doing it and I think we still have guys in our industry speeding. So some of them are starting to get tickets. With that -- what we've been doing is we have been ramping down and cutting our capital budget. We do believe that you run a company, an oil and gas company inside your cash flow. We've been doing that. We've cut our capital expenditures 3 times since our November capital meeting. We'll continue to do so as gas prices stay cheap.

But with that, we report 533 million a day of production. In most times, that would be good. But it's mostly gas, so that was bad. We did have a spacing test in Shelby that was very successful. Hal will go over that a little later. Our TGGT, our treating has resumed. We did have a borrowing base redetermination, it did go down as we had forecast. It's $1.4 billion versus $1.6 billion. It was voted on and signed, I think, last Friday. Is that right?

We started adding some hedges for '13 through '15. But a little bit -- I think a lot of people have criticized us for not moving fast enough into the oil side. This has been a gas company. It was set up to be a gas company. We're still looking at gas transactions, but we do have a small oil property that has been successful. We've been running 1 rig over there and we are, now, in evaluation on how to get into it on both the Wolfcamp and the Cline. There has been some recent results in our neighborhood over there. We are drilling a vertical test, doing some coring as we speak. With the idea that if we can get it figured out, we would bring another rig in there later on this year.

And on top of that, we have quite a bit of -- across the Cotton Valley and even in West Texas. We do have some NGLs. We're going to start reporting them separately but we have 2 deals we're working on, in the Cotton Valley, that'll separate the NGLs. I did note -- however, I do note that we have a couple of thousand barrels a day of oil and maybe 1,300 barrels of NGLs out in West Texas. But we're going to start separating that in the Cotton Valley and expect to see that -- start reporting next quarter.

What's going on in the industry -- we've got too much gas. We've got too many independents that have been outspending their capital for the last 5 years. And the equity markets and the capital markets have allowed them to do it. So it is coming back to haunt all of us right now. We do have an abundance of gas, but I think what you're going to see -- and I've recently seen a couple of really good reports coming out, I think Joe Allman [ph] did one of them and somebody else talking about how fast the decline is occurring. I believe that you're going to see, at least in the Haynesville, maybe a 2 Bcf year-over-year decline with what's going on out there. Rigs got up to -- what, what is called? 186 down to around 50. And you can really see the declines. A lot of people have just quit over there. We're slowing down and we're willing to quit, but we're taking it at a proper pace. And if we have to quit, we will. But right now, I think we have 7 rigs, 8 rigs running. 7 as of this morning, and we're prepared to go to 4 if gas prices stay where they are. But I think you're going to see supply coming down faster than anybody expected. And I think -- the other side of that is I think you're going to see demand going up a little faster than anybody expected. We're seeing a lots of power getting turned on gas. I think we've had a lot of power companies in here looking for long-term supply. We have not made a deal and will not at these prices, of course. But I think you're starting to see some of the results coming out of the EIA and others, January, February, maybe 5 to 7 Bcf a day for power. But I think that's going to expand. I think you'll start seeing it in the second half of the year. There's just a lot of activity going on but I think, as people quit drilling dry gas, it's going to come down a lot faster.

And finally, up in the Marcellus, I saw where Anadarko's cutting a lot of rigs, Talisman's leaving. So that has been a boon for the industry. People are going a little bit too fast up there. Including us. But we're down to 3 rigs out there. We have 850,000 acres in the Appalachia, a couple of hundred thousand in the Marcellus. And we're at 3 rigs and prepared to go to fewer. We have had some interesting results here recently, on an area that I think everybody gave us 0 credit, including us. And Hal will talk about that a little later.

But again, where supply and demand -- you're starting to see 15, 16 -- you're starting to see some potential export. And I think everybody thinks that gas is not going to go up until then. I'm not in that camp, I think you're going to start seeing some direction, maybe, as soon as the second half of this year. I'm hoping it stays days down because we are actively seeking some acquisitions in the gas market.

We have been approached by a lot of potential partners to participate with us. There are a lot of deals in the market today. We are reviewing them. We would not drill for the gas if we bought it. The 3 deals that we bid on this year were all oily. We missed all 3 of them. One of them we got real close on, again they were joint ventures with third parties. But Jacobi's been here and he's busier today than he's ever been. We think there's probably $40 billion or $50 billion worth of assets on the market today, both oil and gas. And there is plenty of money and we've been approached, domestic partners, and more recently, some foreign partners that are interested in buying dry gas in the U.S. because they expect to be exporting to their own country.

Monetization, I think we've got criticized on the TGGT a little. It's an asset that is pretty much fully developed with our drilling program right now. So we did sign a 45-day exclusive with an infrastructure fund. We did get an offer for 1/3 of it from them but during that process we received a lot of indications from strategics. We have reviewed that and we are entertaining and discussing with 3 today and we have 2 more coming in. The possibility of selling 100% of it. BG is on board and so we continue that process but I think, right now, we're leaning towards selling 100% of that instead of just selling 1/3.

We continue in negotiations on our conventional joint venture that we've discussed. As recently as yesterday, we have shared some information with a partner. I expect something on that. We'll either happen with them or backup that we have 2 or 3 other people that have shown an interest. I expect something to happen there within the next 30 days.

With that, I'm going to turn it over to Steve and I'll get back to you later.

Stephen F. Smith

All right, I'm going be -- my remarks will be starting on Slide 5. We'll talk about kind of the highlights of the quarter, and particularly, I want to spend a little more time on cost and then Hal will also spend some time there. Obviously, I mean, we -- the production level that we're at right now is pretty much right on our guidance. It's what we expected, and of course, it's a big increase over last year. And it's flat, pretty much flat with the fourth quarter. The average realized price, obviously, at $2.78 versus $4.40 is a problem. Gas only is $2.45. So that, of course, makes things difficult. But our hedges have been working and our revenues, including the cash settlements, are flat between years and so that's been a plus for us from a cash standpoint. Direct operating cost, G&A, all of the cost and we will talk about them in more detail in just a minute. But they are trending downward, both in absolute dollars on a Q1 to Q4 basis. They're down by -- operating cost are down like 5% between quarters and all those costs are trending down and which we're very pleased with and which is -- it has to happen in this kind of environment.

Our adjusted EBITDA, our cash flow from operations also are pretty much in line, given the fact that the gas price is lousy and we're pretty much in line with what we had thought -- of where we thought we would be.

In our adjusted net income line, there are 2 things that are not included in adjusted net income. One is the saving cash write-down of $276 million on an a pretax noncash write-down. We used the 12-month average at the beginning of the month. So March 1 of '11 -- I mean, '12, back through the April period. And that was $3.73 on gas, $98.15 on oil. So that's why we had the write-down. We would expect that if the gas doesn't strengthen, we'll have additional write-downs. It's just the way the math works on the full cost pool.

In addition to the write-off on the full cost pool, we also have an impairment of our -- of some assets at TGGT and it affected our equity net income in that entity. It doesn't have any impact on our EBITDA, et cetera, because they're not included in EBITDA. But the write-down -- we have some temporary -- we've started out with temporary units to restore the production in the plant that -- where there was an explosion back in -- about a year ago. And we ramped that temporary unit construction up pretty heavily. But this quarter, we decided that the permanent facilities out there were not damaged, one of them was not damaged very much at all, and so we're going to put that unit online probably in the next few months, 6 months or so. And as a result, we didn't really need all of the temporary treating capacity that we have. And the treating capacity that we got online, right now, we're not going to need for very long. So we went ahead and took a write-off in the first quarter, in the equity income line.

All right, let's look at Page 6 and let's talk a little bit about the rig count and Doug has covered it pretty well. We've got a couple of more rigs that are just coming off contract by their own terms here pretty soon and those will -- if prices don’t firm, we're going to let -- we'll let those go. We might even let an additional rig go. We're expecting to be in the 5 -- 4 to 5 in the Haynesville at the end of the year, and 8 or 9 overall. We could cut back in Marcellus if we need to, from a cost standpoint.

Douglas H. Miller

But it could go up in the Permian, yes.

Stephen F. Smith

That's right, exactly. As far as the drilling costs are concerned, we have had good news in that area in the Haynesville. We were quite around $9.5 million at the -- during the fourth quarter. We're down to about $8.5 million now and we feel like, about the end of the year, we'll be down to $8 million. We've had a lot of cooperation from the supplier of our drilling services, of our frac services, et cetera, and I'll get into a little bit more detail on that on the next slide also. But we're very pleased with where we're headed. We need to get lower, obviously, with this kind of prices but at least we're on the right track.

As far as expenses are concerned, you'll see down at the bottom, I'm just comparing the Q1 of '12 with Q4 of '11, good progress in all areas there and on a -- both an absolute dollar basis, which is what's in this table. But also, on a per Mcf basis, good progress. So we're pleased with where we're headed on cost.

Over on Slide 7. I'll talk a little bit more about the drilling completion reductions. We've been able to obtain a great improvement in our frac cost from $220,000 a stage down to $165,000 and that's about $600,000 per well, which is a real jump start to getting those costs down. We've also changed our tubing design and how we run tubing and that saved us -- will save us at least $200,000 per well. We've gone from chrome to steel tubing. We've also had good reaction from the service suppliers of wire line, car [ph] tubing and a lot of the other pumping services that we use. In our operating cost, we've reduced our headcount, obviously, when we reduced the rigs like we have. We've also renegotiated our saltwater disposal cost in our principal area in DeSoto Parish. And we've removed a lot of wellhead compressors that we didn't really need over there. So we've had -- and Hal will get into some more details but those are just some of the highlights. G&A, we're down of strong percentage between quarters. And we're headed on down on that and it's primarily a headcount situation in the G&A.

The last Slide on 8, for me, is just our production and debt profile. I'd like to share this each quarter. As you know, we have redetermined our borrowing base, and Paul will get into a little more detail there, but this slide just shows where we're from a debt standpoint at the end of the quarter. Where we expect to be without any potential monetizations of assets and then, obviously, with a little bit of success on monetizations, we're going to be able to drive that down pretty quickly.

So at this point, I'll now turn it over to Paul and let him pick up with our guidance, liquidity, et cetera.

Paul B. Rudnicki

Thanks, Steve. I'll pick up on Slide 10. Looking at our liquidity and derivative position at the end of quarter. We ended the quarter with $194.6 million of cash. We had a $177 million -- sorry $1.1 billion drawn on the credit facility and we can see we had $750 million of notes outstanding for a total net debt of $1.7 billion at quarter end. Looking at where we are at the end of April, we paid down little bit on the debt. We're down to -- still holding at the $1.1 billion level, paid down about $30 million in the month. As we talked about in the press release, our borrowing base was redetermined, as we expected, from the $1.6 billion level, down to $1.4 billion. And we also amended the debt-to-EBITDA covenant up to 4.5:1 from the current 4:1 that it was at. With the cash on hand of $183 million at the end of April, left us with $427 million of liquidity.

Looking at our derivative position, our 2012 hedges remain as they were. We have 60 Bcf hedged for the rest of this year, at $5.27, 412,000 barrels of oil at $98 for a total equivalent, $229 million per day or right at 50%.

We did add some hedges here in April, as we lay out in our Q, it'll be filed shortly. What we did is we went out and swapped 2013 through 2015 for 35 million a day of natural gas, 35 million Mcf a day, and at a price of $4.18. We also sold 35 million a day of calls at $4.18. So effectively, we have 35 million a day swapped at $4.18 and a ceiling of 35 million a day at $4.18. And we're going to continue to look at additional structures, as well as just straight hedges

Moving on to Slide 11, as we compare our results for the quarter versus our guidance. As you can see, our oil production came in above the high end of guidance. Gas production came in right at the midpoint of the guidance and our overall was right at the midpoint, slightly a little bit above. The one thing to point out on our differentials, we have seen a widening of our Permian oil differentials, as reflected in the first quarter. And we'll talk about that in the guidance going forward.

Our gas differentials came in at the low end of guidance. And our lease operating expenses also came in at the low end of the guidance as we've been successful in getting those operating cost down. Gathering expenses right at the midpoint. Production taxes, a little bit higher than expected, partly as a result of the new Pennsylvania impact fee. In this number that we're reporting, this is just the ongoing current position. We also recognize the $2 million retroactive impact fee for everything before 2012. We've excluded that from our earnings as an out-of-period nonrecurring number. That will be paid out in September of this year.

Looking at our DD&A rate, it came in at $1.84 versus the guidance of $2.10 to $2.20, and that's a reduction of the ceiling test write-off that we took at year end. Cash G&A, as we've discussed, we've had good success in bringing those costs down and we came in substantially below guidance on that number.

Interest expense was right in line with guidance, as well as our equity income from TGGT and our other investments, excluding the items that Steven mentioned already.

Our capital budget, capital spending for the quarter was $162 million versus the guidance of $180 million to $200 million. A part of that is the result of the timing of certain capital projects that we expect to flow into the second quarter. And also just a regular reduction in the activity level that we're seeing.

All that said, our adjusted EBITDA which, again, does not include any impact of our equity investments, including TGGT, this is basically just the upstream EBITDA, it was $110.5 million versus our guidance of $110.6 million. And the TGGT EBITDA, net to our interest which, again, is not included in our corporate EBITDA, was near the high end of the guidance and came in at $17.4 million.

Slide 12, looking at the guidance for the rest of this year. We're keeping our production guidance flat to where we had guided previously. The one thing we are doing, as Doug mentioned, is we are going to breakout our NGLs. Currently, we forecasted the effect of the NGL production we have in the Permian basin. As Doug discussed, we are looking at some additional processing upgrades in our East Texas position, which is not reflected in this guidance as well.

Hal will get into the some of the Permian upside that we're working on. But I will note that none of the upsides for many potential horizontal drilling or the water flood project that we're working on are in this guidance. This is just our normal Canyon Sand development drilling.

Look at our differentials. As we show here, we're showing the expanded oil differential out to $6 to $7, under NYMEX for the rest of this year. And we started, again, showing our NGLs separately. We're expecting 45% to 55% of NYMEX oil for those differentials. I will highlight that the Permian NGLs that we have are relatively low in ethane. There are only about 1/3 ethane. The other 2/3 are the heavier components. That kind of compares to our liquids production, and expect the liquids production coming out of the East Texas, which is closer to 60% ethane. So we're able to get some -- still get some pretty good prices on our overall NGL mix on the Permian due to the component balance out there. On our gas differentials, we're showing a wider differential than we have in our prior guidance. The main effect there is for stripping out the liquid revenue that was included in our prior gas differential.

For all of the other items, we're essentially keeping them flat at this point. We brought G&A down a little bit to coincide with where we are at the end of the quarter. I do want to point out, on our capital, we have shifted some of the capital dollars out and we are still guiding towards $450 million to $488 million of total capital for the year, with roughly a $470 million midpoint. We do expect that number to be lower. We want to get another quarter under our belt and see exactly where we end up with the rig count this quarter. But at this point, we're just going to hold guidance equal at that level.

And with that, I'll turn it over to Hal to get in to some more details on the operations.

Harold L. Hickey

Thanks, Paul. First, I'd like to say that in this tough environment, our teams' have responded very, very well and I'm really proud of the way the teams has reacted during this low natural gas price environment challenge that we face. And we've had some really good operational results and we foresee good operational results going forward because of their activities.

On Slide 14, you can see the map we always show of our operations. I'll emphasize that we have 8 Tcf of reserves and resources across our portfolio based on March 30, NYMEX strip price. At 8 Tcf, we have 1.7 Tcf of proved reserves and of that 1.7 Tcf, we have -- 60% of that is PDP, and overall, 70% or so is proved/developed. We continue to see the bulk of our production from East Texas, North Louisiana and in the Permian, holding steady with our production rates but there's a big push toward liquids and I'm going to emphasize, in a few minutes, the opportunities are presenting themselves.

In Appalachia, we're down to 3 rigs now. The teams are very focused on operations and production in Northeast Pennsylvania, particularly in Lycoming County. But we've had some really good results in the central area, like Doug said, nobody was giving us credit for. I'm going to talk about that in a minute. But I will say that, also in Pennsylvania, West Virginia and the whole Appalachian area, our teams, both here and in Warrendale, where our office is, just outside Pittsburgh, are evaluating liquids opportunities there as well, in the Appalachian region.

We achieved our operational targets for the year. In the Haynesville/Bossier, our big focus is now going to be on drilling in Holly area, primarily in DeSoto Parish, where we have 7 rigs operating today. We're implementing a very, very successful, at this point, restricted choke flowback program. What we do is we set our limit on the high end of the choke at 18/64ths. We manage to a 25 psi drawdown on our surface pressures, and what we're seeing is some enhancement in our overall type curve, leading to an overall EUR improvements. Down in Shelby, we completed the delineation effort. We drilled 8 wells on 880-foot or about 130-acre spacing. A partner of ours drilled, on an adjacent unit, 6 wells on 1,200-foot or 160-acre spacing. We flow that back, we got about 215 million a day IP. This was in late March. We put a restricted choke on that program as well, the chokes range from 18 to 22/64ths. And what we're seeing down in the Shelby Area, that's very, very encouraging to us, is with this restricted choke program, we're seeing our cumes [cumulative volumes] actually crossover. So, before, we were opening chokes up higher, 26/64ths to 30/64ths and we're having a big bump of the initial production. Now we've restricted that initial production but the cumulative rate coming out of these wells with restricted production are actually equaling, on a couple of our most recent wells, the higher flow rate wells at 100 days. So we're really excited about that. We've only seen 2,000 psi drawdown and after that 100-day, 200-day period and so we think that this is going to leave us some positive, positive results down there. Now, as we evaluate the spacing, as gas prices are lower, noting that our costs are higher in Shelby, because of the deeper, higher pressure, higher temperature, we have deferred drilling there, and at least for 2012, we're not going to drill anymore. Talking about some of the activities up in the Marcellus. I've noted that the focus is in Northeast Pennsylvania, particularly in Lycoming County. We're making about 116 million a day gross production out of the Marcellus now. We're continuing to build out our water infrastructure, and of significant amount of that is in place, we're actually building more. But look at water infrastructure does for us is -- obviously, it takes trucks off the road but it's saving is $300,000 to $500,000 per well about being able to pipe as opposed to truck.

Permian area, of course, we're continuing our Sugg Ranch Canyon Sand development where we're seeing 50%-plus rates of returns and really strong cash margins. We are testing Wolfcamp and Cline shales in our acreage, we've got a vertical well that we're working right now. We're coring that well. I'll give you some details on that in just a moment. And we're pursuing opportunities to increase acreage. I'm going to give you some more information on that shortly.

Flipping over to 15 is our capital budget. The $470 million budget is actually 54% less than what we spent in 2011, and as Paul said, we're likely to drop this even more as we manage our programs going forward. We do have the 1-rig forecast for Permian, and I will say, if some opportunities materialize out there, that we're hoping for, we could increase that rig count. The 3 rigs in Appalachia, we have 2 rigs in Northeast PA now, shortly we'll have 3 rigs operating there. And with the 7 rigs in the Haynesville, we have 11 operated rigs in the portfolio as we previously noted.

Look at our capital budget of $470 million which is, again, likely to go down. I'll note that we still have $30 million of BG carry [ph] remaining as of end of Q1 for our Appalachia drilling and completion operations. A big focus of our spending will remain in the Haynesville/Bossier area, which represents about -- just on the drilling side, 57% of our total budget. And of just looking at the whole drilling and completion budget right now, about 75% of our drilling completion dollars will be spent in the Haynesville/Bossier region.

I will say that, as we've released rigs, the cost to do that is actually been less than we had forecast in our budget. We forecast about $15 million and I think we'll end up spending somewhere $8 million or $9 million per rig termination cost. So that's a positive that's occurred.

On Slide 16, you will note that we were at a peak operated rig rate of 28 back in 2011. We got a big focus on cost and Steve's already talked about how the costs have come down in our Haynesville operations. I will note that in the Northeast area of the Marcellus, we're targeting, right now, about a $6.3 million, $6.4 million well cost. We've got a plan to get down to $5.8 million or so by the start of 2013. I talked about how the water infrastructure will help us in that regard. I will say that we're working very diligently on drilling and completion efficiencies as well. I'll talk a little bit about of those more so in a minute. And I better note that the well cost we're talking about is for an average lateral of about 4,200 feet.

On the OpEx side, we have shut in some of our less profitable wells. We've shut in about 655 Cotton Valley wells at this point, that make a lot of water. It's only resulted in a production decrease of about 1.2 million a day, net our interest. The gross cost associated with the shut-ins is about $5 million of cost that we've taken out of our system, that's about $2 million or so of net cost to us. We are targeting the significant reduction of our work-over program. We're still doing the things that are important and that payout very quickly. We have 6 work-over rigs, at one point, working in our Shelby area. We're down to 2 or 3 now. We've got several other initiatives underway to reduce our operating expenses. We've cut company vehicles, we've cut about 10% of our company vehicles out. We're carpooling. We're finding other means for our people to get around. Wellhead compression, we have continued to cut down. I know Steve noted that there was about $1.1 million in annual savings that we're realizing from wellhead compression, and with the plans that we actually have in place now, we may double that impact on our annual savings up to as much as $2 million.

Labor cost, we've cut out a lot of our field contract labor, as Steve noted. What I do want to say is we're not cutting back on maintenance when we do that. Our people, our EXCO employees have actually stepped up. They're doing some routine maintenance now and filling the work that was vacated by Lou [ph], letting go some of the field contract labor with some of their time and their efforts. So we're in good shape there.

Other reductions we're looking at. Chemicals, we've cut about $600,000 a year out of our chemicals in our Cotton Valley area, in our Haynesville area. Also on the Haynesville, with this restricted choke program, we've actually cut back some of our water production, and in turn, we aren't having to have as many coolers on our wellhead. So we've cut those back significantly and that's actually going to save a couple of million dollars of years as well. So really some good efforts that are ongoing in managing our cost.

Slide 17, getting into some of the details on East Texas and North Louisiana. First, I'll say that the 264,000 gross acres is actually for our -- all of our North Louisiana, East Texas holdings. We have 132,000 net acres there and our net acreage in the Haynesville/Bossier shale is about 64,500 to our interest. The majority of this shale acreage is HBP, in Holly, virtually everything's held. In Shelby, we've got 85%-plus held and we have plans of going forward working with our partners. While we may not be drilling there, others are and we've negotiated some deals that we'll able to hold our acreage through some of the partners drilling, as well as just if we choose to do some lease extensions.

Average gross shale production, 1.2 Bcf in the first quarter. That includes an OBO, we averaged about 390 million a day, we're up from that now. Actually, saw a number of well over 400. Yesterday, we got 324 operated horizontal shale wells flowing to sales as of the end of March. Big point, average in the first quarter was about 72 million a day of curtailment, and that was from off-set operations and well work and the treating facility. I need to make sure that everyone knows that. Now, that number is down to less than 30. So where we were at -- hell, I don't know, lot of times last quarter I was seeing 15% to 20% net shut-ins a day. We're down to about 6% or 7% net shut-ins a day. So really good movement and a lot of that has to do with the startup of the treating facility that Holly takes over and right over Parish. We've seen continuous improvement on our drilling days and optimization of our frac designs, our drilling days. Talked about this before, but our spud to rig release is now 37 days, that's down about 40% over the last couple of years. On our frac designs, we continue to manage our profit mix, we're using less chemicals, and in addition to the discussions and bidding and working with our frac stimulation service, obviously, our frac costs are coming down.

One thing we're targeting, like Steve said, all of our services procedures -- one thing that I will note is our drill costs, there is some threat there because of the availability of the cross, that's actually grown, that's used in production of gel. I think they call it guar. And we'll see how that works out but that is one little threat that could drive, raise cost a little bit across the whole industry.

Slide 18. Talking about Appalachia, we've got nearly 800,000 gross acres there, as Doug said. About 140,000 net acres, net to EXCO, have Marcellus shale potential. About 2/3 of our acreage there is HBP and we have plans, of course, in place on how we'll hold that acreage through a combination of drilling and lease extensions renewals. So we're in good shape there on our HBP. We're -- actually entered this year with a plan to have as many as 7 rigs operating there with the gas price. We've dropped that down to 3. We actually had 4 on contract and we released 1. So we're at the 3-rig level I talked about. Some major ongoing evaluations could add some substantial production later in this year and some of our activity will also add substantial production later in this year.

We've had some good results with seasoning. We'll actually bring on the well, flow it back for a week or 2 and then shut it in for 3 or 4 weeks and allow the pressures to build. And couple of examples, we've actually seen 2 million a day wells jump up to 5 or 6 million a day rates following the seasoning period. We're looking at completion methods and how we can optimize our completions. We're looking at our volumes of sand, we're looking at cluster spacing and our numbers of stages. We're, obviously, looking at how we manage, during simultaneous operations, where there's doing fracs or some of our hookups. We're going to plan to put our facilities in before we complete and that'll give us some online time quicker. Present delineation of some of our acreage is going well. I said earlier we've got the focus in Lycoming County. We have had a really, really strong result with the well over in Armstrong County. We brought it on, this is -- before we tubed it up, before we seasoned it, it was flowing 6.2 million a day, 1,500 psi flow-in pressure. We've now shut that well in to tube it up. I'll attribute it to a combination of good rock, good choke management, good completion method and so we're excited about how -- what opportunities that could present.

If you look the table on the right-hand bottom side of Slide 18, you can see how our turn to sales activity is really going to ramp up in Q3 and Q4 this year. We plan to spud 49 wells through the year and we'll complete 51 but you can see 42 wells will actually turn to sales in Q3 or Q4. So that's when you'll see most of our ramp-up in production occurring.

While we did see, recently, that one of the river basin commissions put a stop to some water takes from about 10 or so points of water sources. That has no impact on us, we have multiple water sources. So the water moratorium, from a certain amount of the take points, is not going to have an impact on us at all.

Going over to Slide 19 and looking at our non-shale asset. We have over 1 Tcf of reserves and resources potential and 65% of that is proved. Good production from East Texas, North Louisiana, Cotton Valley, Vernon. Appalachia, about 16 million a day. Shelby and Permian, you can see we're starting to report that on a Boe per day basis. Some 1,700, 1,800 barrels of oil, some 1,300 to 1,400 barrels of NGLs and about 6 million a day of natural gas make up the 4,000 BOE.

Like I said, drilling in the Permian with 1 rig, but we could add to that if some of our opportunities materialize. Cotton Valley is very focused on cost management. We've got some really good re-completions lately, in the Cape field, in our Vernon area. We've got a good footprint in our shale development area and I'm excited about the footprint that the Permian provides for some of future opportunities we may realize out in that area.

We're negotiating a potential joint venture, that Doug's noted, in certain of our shallow and conventional assets. I will note that, in that, we'll continue to operate. Other opportunities, we talked about some processing deals with third parties. We'll be extracting NGLs from some of our higher BTU Cotton Valley gas. And another thing we're doing in our immediate area is looking at some of our offset operators, drilling of Cotton Valley horizontal well. And I think what they're doing is pursuing high-BTU content opportunities in the Cotton Valley that could lead to some ideas for us and obviously some processing opportunities as well.

So going now to the Permian on Slide 20. You can see nearly 27,000 net acres in the Permian that's dominated by our Sugg Ranch position in Irion County. We've got a good operating cost, it's about $1.20 per Mcf, and you realize really good cash margin out there of about 9.47. We're evaluating Cline and Wolfcamp. In addition to other opportunities with Cline and Wolfcamp, we're looking at some shale opportunities. The water flood that Paul referenced earlier has forecast EUR of nearly 900,000 BOE. At 1 injector and 2 producers that we're going to use out there, we actually started injecting water in February. To this point, the pressures have risen just as forecast, and we anticipate that we'll start realizing production from this water flood come summer -- summertime.

Another thing that we've done out there is, with some of our 3-D activity, we've actually identified some carbonate mounds. We've drilled 6 of them, 5 of them had been very successful, 2 recent ones. IP-ed at 200 barrels of oil a day, each one was cumed 100,000 plus barrels and is still making 60 barrels of oil and I think we have another 10 or 12 with some of those identified that we'll evaluate their prospectivity and make decisions on whether we drill more of those.

21 shows Cline Shale and horizontal Wolfcamp activity and potential. Let me point out on this map. It's kind of deceiving the way it's depicted, but the blue, which is where a whole lot of our acreage is and some of the opportunities that we're looking at are, frankly, contains both Wolfberry and Cline potential. So that's where we are. We're looking at both Wolfberry and Cline potential. Our acreage is, of course, depicted in yellow. If you look at the green, that's really where you're forecasting of Cline only. So we think we're in a good position there, and like I said, this footprint really gives us a good, good opportunity to expand our operations out there. There's significant industry activity around us. We're seeing some IPs in the 800 to 900-plus range of oil. We're drilling a vertical test now in on our acreage. We've already taken about 290 feet of core in the Wolfcamp. We're drilling down to the Cline. We'll take roughly 360 feet of Cline core or 90-foot cores and we're optimistic. And if this thing plays out as we anticipate, we'll start drilling our first horizontal test later this year, based on what we learned after we get the data and evaluate the opportunity.

Last slide I'll talk about is on 22. TGGT, of course, is our 50-50 equity investment with BG, a midstream company. Average 1.5 Bcf a day in the first quarter. Throughput has been up around 1.6 Bcf a day now. It's very, very important to note that we have no current volume curtailments because of treating capacity. Treating facilities in Red River Parish are operating very well since we started them up in March. I'll note that, over in the Shelby Area, we've started up a 250 million a day treating facility there as well. It's now treating 160 to 180 million a day. It's just recently started up. And with those, and with some pipes we've put in, our major infrastructure and treating facilities work is really behind us. We've spent about $300 million in TGGT between us. Well TGGT, spent about $300 million of capital last year. We'll spend about $130 million of capital this year, $100 million of that has effectively been spent or will be spent by the first of the year. And marching forward, we'll look at, probably, $30 million for the rest of the year after we reach 1st of July and about $30 million to $50 million for the next several years as the major work's been done there.

We've increased our credit facility at TGGT as well, as we did at EXCO, at TGGT. And we increased to $600 million. We've got about $495 million outstanding as of the end of March. We are doing a little work, we're looking at third-party volumes. And as Doug noted, we are evaluating the monetization of either part or all of our interest in TGGT and working with BG on that.

With that, I'll turn the discussion back over to Mr. Miller for Q&A -- in time for Q&A.

Douglas H. Miller

Right now, why don't we turn it over -- I see there's some guys who want to ask some questions. So Steve, why don't you open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

Can you guys prioritize for us the various strategic options you all talked about at this point?

Douglas H. Miller

Boy, that's good. This group in here would really like to know that. Prioritize. Let me tell you what -- I mean, we have several plans, but we are working -- the pipeline does not need to be sold. However, it's something that I think if we got the right price, it would benefit all of us. It would give us the liquidity to make some of the acquisitions we're looking at. But I would say, we're -- from a priority standpoint, the 2 things that we're working on the hardest are the pipeline sale and the joint venture on the conventional because part of that joint venture is to put a group together to buy additional conventional assets and drop into there. So that's an exciting project which would kick off. Now I'd say people have done a spectacular job around here when we put the brakes on. So everybody's looking for cost cutting. That's probably the top priority. Everybody's doing a good job on that. But we're looking at the 2 asset sales to give us quite a bit of liquidity, and we're looking at acquisitions and some sizable ones because we have partners lined up that want to do those. I'd say priority 1 is cutting cost, speed limits. We're slowing down, but with that we have the people in place to look at every $0.01 and look under every rock, and they're doing a great job at it. So I mean, we're -- priority, cut costs. But I think that the west Texas group thinks their priority is go find some oil, and they're doing it. So we have 10 priorities around here, sorry. And I think that's probably what everybody in the room thinks. They'd like to know what our priority is, too.

William B. D. Butler - Stephens Inc., Research Division

Right. In terms of the cost reductions in the Haynesville, could we see an impact -- sort of a detrimental impact to well performance, either on new or existing production from, I guess, on existing -- releasing the compressors you're talking about? And then could there be any potential impact on the tubing design and the procedures you all are talking about?

Harold L. Hickey

Well, the compressors we relayed for the Cotton Valley, we don’t even have compression on the Haynesville yet. Those wells have performed outstanding. They're still over pipeline pressures, so that's a future consideration. As far as the tubing, no. With our chemical program and the design and the analysis, then evaluation that our guys have gone through, we're very confident the changing of our tubing is going to have a minimal impact, no impact on our production.

Douglas H. Miller

William, I think what you're going to see is we're not going to have the large IPs that we've had in the past because of our restricted choke. But I think 200 days of production you're going to see it's going to increase.

Harold L. Hickey

And one other point I'll make is that our base Haynesville production is actually performing better in the Holly area than we had anticipated. I think that's a combination of just well performance and less downtime. So we're in pretty good shape there. We feel pretty confident.

Stephen F. Smith

And all of the cost saving techniques in drilling and completion have been field tested on other wells. We haven't just jumped in and we do the well and time see what happens and then it's to get a program overall. So that's been a big push for a number of months around here.

William B. D. Butler - Stephens Inc., Research Division

Okay. One last question then I'll hop off. Do you all have any commentary on Permian differentials? Looks like your guidance is a little wider, certainly been a topic of discussion of late.

Douglas H. Miller

Yes, we've taken a lot of pipe out of the Permian over the last number of years. And there's projects coming online to take the bottlenecks out. But we're seeing it expand a little bit wider. I think we're comfortable from where we see it for the rest of the year. But there's a lot of oil showing up and not a lot of places to take it.

Operator

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

With the discussion on the CapEx trending down, I guess for the full year. It seems like the inverse of that is production is actually performing better. Do you guys have any thoughts on expected Q4 production, whether the bias is up or down from current guidance?

Paul B. Rudnicki

Yes. Paul. I'll take that. Kind of it's going along with what Hal's comment was on base production in the Haynesville. We are seeing -- we put our guidance together at the end of the year. We really did not have a lot of history on these restricted chokes. We had a lot of noise in our numbers again from the treating facilities being down, and as we're going through this year, we're seeing our base gas performance produce better. So I think give us another quarter and let's make sure that this is a good trend. And I have a feeling that we'll probably be looking at the fourth quarter exit rate pretty higher this year. I think it will be biased towards the upside.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

The capital efficiency is definitely heading in the right direction for you guys, I'm guessing.

Paul B. Rudnicki

That's right. The other thing -- just to kind of comment on the production again, as we look at capital -- as capital comes down, when you look at what we're doing in the Haynesville and what we're doing in the Marcellus, we're pretty much well locked in to our completion schedule. So whether we go to 4 rigs or stay at 7 rigs in the Haynesville, our production will not move in the Haynesville. Same thing in the Marcellus. Those are wells predominantly that have been drilled that are completing or waiting on completion. So keep that in mind as you think about the variability in our capital program going forward. It's really looking at inventory that would be produced in 2013 more than anything that would affect us this year.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Got it. On the liquidity side, could you guys provide a little color on just some stress tests? If you look at current strip prices through 2013, given your spending plans and cash flow expectations, do you expect to stay below the 4.5 debt-to-EBITDA covenant?

Paul B. Rudnicki

Yes, I think we're comfortable with the 4.5 through 2013. We set out this year looking at 2 to 2.50 gas for this year and 3 to 3.50 gas for next year, and we're still very comfortable with that.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's great. And then on the TGGT sell impact to liquidity, is there any impact of that sell potential to liquidity?

Douglas H. Miller

Yes. If we sold our half interest for $500 million to $700 million, it just goes straight to pay down debt. I would say that's an impact.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

But there's no impact to the current borrowing base for the E&P business?

Douglas H. Miller

No. Well, I canceled that. Part of our borrowing base, we agreed to reduce the revolver by $200 million minimum. So if we sold it for $500 million to $700 million, the first $200 million would go -- that would go -- again, our borrowing base would be reduced. Then, the rest of it would just reduce the outstandings. But it could give us a lot of liquidity.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, I understand. And then the last question for me is on the Permian, I was a little bit confused. On the water flood, what zone are you flooding? And then how many wells right now are producers that will make up that flood?

Douglas H. Miller

We're flooding the Wolfcamp, and we have 1 injector and 2 producers.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, so you -- I didn't know if you meant that the pattern is 1 to 2, but you mean literally, you just have...

Douglas H. Miller

Literally, it's -- what is it?

Harold L. Hickey

[indiscernible]

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Is it a 30-acre deal? Something like that?

Douglas H. Miller

Yes, 30 to 40-acre. It's Wolfcamp sand.

Harold L. Hickey

Actually, that's carbonate.

Douglas H. Miller

Carbonate, sorry, but it's not a shale. And we had some producing wells in there, and our 3D picked it up as potential. And our guys have been working on it for years. And we started it middle of last year, and it started to respond. We know there's oil there because we've produced out of the initial wells. Now the question is can we get this up. But it looks good early.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And is that for sweep? Or is that to also repressurize the zone?

Douglas H. Miller

That would be both.

Operator

Your next question comes from the line of Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just a question about TGGT. Your throughput is now I think 1.6, and in February, it was 1.5 Bcf a day. How much of that increase was third-party volumes and how much of it were volumes that were offline?

Douglas H. Miller

That's a good question because a little of it is coming from third parties. We made a deal with Encana and El Paso to hook up a couple of their sections. Some of that is on there, and then the stuff that was offline is half, 50-50-ish.

Anne Cameron - BNP Paribas, Research Division

Okay. And how much can you grow that third-party business because I think you said at the beginning of the call you think the Haynesville is going to be in decline?

Douglas H. Miller

Yes, I think when we set these, we have a 36-inch header system in there. We thought our capacity was 2.5 to 3 Bcf a day with all our interconnects. And we've kind of stayed away from third parties because if gas were at 5 or 6, we'd be using it all ourself. But now that we've slowed down, anybody in the neighborhood that would like to hook up and have 10 to 12 outlets to interstates, we're in discussions on. So we think we have 1 Bcf a day. Wait a minute.

Harold L. Hickey

And one other thing I'll add to that, Ann, is the Cotton Valley horizontal drilling, there's -- in particular, up in one of our areas in northeast Texas, there's a party that's drilling 10 to 20 horizontals. And we think that could present us over the next year or 2, 100 million a day upside. So there's some real upside there, not to the Haynesville but Cotton Valley.

Douglas H. Miller

I think a lot of folks is coming back to our legacy system over in east Texas. Hal was pointing out there's a lot of activity ongoing after some liquids-rich gas, and I'd say that's really essentially a liquid stream that was -- I mean, liquid system that was built 20 years ago, stuff that we're managing. I think there's a lot of upside to third parties there.

Anne Cameron - BNP Paribas, Research Division

Okay, do you expect overall TGGT volumes to grow or roughly stay flat from here on?

Douglas H. Miller

I think ours are going to go down, and I think third parties could go up. And so we haven't forecast up a bunch, but we're sure in discussions with some guys that are talking about doing some horizontal Cotton Valley. And we're trying to make deals with them.

Anne Cameron - BNP Paribas, Research Division

Okay. It's just that $500 million to $700 million range for your 50% stake seems pretty aggressive. If you're on track for $130 million of EBITDA this year, something like 13x of that...

Douglas H. Miller

So what if that EBITDA was 150?

Anne Cameron - BNP Paribas, Research Division

I would say that, that's still 11x for that asset. Is that...

Douglas H. Miller

And they're trading at 13x?

Anne Cameron - BNP Paribas, Research Division

Okay, okay. You're the boss.

Douglas H. Miller

Not that I ever look at it, but we've had 6 investment bankers in here telling us where they trade.

Anne Cameron - BNP Paribas, Research Division

Okay. All right. Just another question on your plans for either JV for conventional gas or a leasehold acquisition. I think you said on the fourth quarter that you didn't have any plans to issue equity. Is that still the case?

Douglas H. Miller

That is still the case.

Operator

Your next question comes from the line of Leo Mariani from RBC.

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

Just, Doug, you have mentioned doing some JV potentially to buy conventional gas. I wasn't sure if you guys had any specific opportunities to identify that this is more of a concept that still come in together. Can you provide some more color on that?

Douglas H. Miller

We have some specific ideas identified. We have offers out, and we're in discussions.

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

Okay. And obviously, you mentioned a number of other initiatives as well. I think liquids opportunities in Appalachia came up. Could you give us some more color on what you might be targeting out there?

Douglas H. Miller

Well, we're looking at several deals in the Utica right now. And I would say that would be the majority of them. John's group, we've signed CAs on 3 to 4 not huge deals, but if they fall on the liquids window, it's something we're going to be aggressively pursuing.

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

Okay, and how about in the Permian? You mentioned trying to add acreage. It seems like a hot area. Is there stuff that's available around you guys? Have you seen a lot of deals there?

Douglas H. Miller

We have seen a lot of deals in west Texas. As you probably remember, we used to have a lot of people out in Midland, our previous company, Coda, and so we know a lot of people. But we're in discussions with some significant pieces of land in our neighborhood. And probably, if I'm right on the $40 billion, I would say at least 1/4 of the assets that are for sale are out in west Texas, and we're looking at them very aggressively.

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

Okay, and I guess [indiscernible] liquids opportunities in the Cotton Valley that most of the operators have had success with. Can you update us sort of where you are in that process in terms of your own evaluation?

Douglas H. Miller

Yes, we're actually doing some recompletions of hole in both the east Texas and north Louisiana. We have found some liquids-rich gas. We've actually recompleted an oil zone over in east Texas that looks good early. We're not ready to start jumping up and down yet because there may be some leasing opportunities in the neighborhood. But it's something we have 2 teams working on, and they've had good success early. It's definitely an opportunity, and we're not the only one looking.

Operator

Your next question comes from the line of Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Doug, could you just describe a little bit more about the conventional JV you're talking about. Is your priority to -- for that JV to help the liquidity situation? And then a little medium to the longer term,

[indiscernible] the asset base and more conventional assets and are you talking about conventional oil, conventional gas? And which assets in particular are you talking about dropping in there?

Douglas H. Miller

Yes, I'd say it wasn't initially thought of as something that would create liquidity, but it does. It's kind of a private MLP. We've been approached by a couple of private equity guys that are significant in oil and gas, have done deals before, looking for conventional gas. So the idea when we started it was we would roll our conventional gas into it. We would operate it, but they would put up the bulk of the money. And we would put money in it also, and it would have a distribution. And we would just attack conventional gas areas where we operate, and we would focus on the Cotton Valley and maybe the west Texas gas out there, so where we already operate. We're still seeing a lot of opportunities in the Cotton Valley, and sometimes we see an opportunity where there's Cotton Valley and Haynesville, so we've separate the Cotton Valley and put it in. It really was a conventional gas play. We've been approached by more than one person to put it together. It was not initially thought of as a liquidity but it, for sure, is. And it would help us.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So you're talking about maybe dropping 100% of your conventional assets in there, getting cash for, say, 50%. You maintain a 50% interest, and then on a go -- you operate on a go-forward basis, and then as time goes on, you potentially together buy some more. Is that how it works?

Douglas H. Miller

Yes. That's kind of how it works. You've got the concept. That isn't exactly the right numbers but I'm not -- yes.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, I understand. And then -- okay, that's helpful. And then in terms of the Cotton Valley shut-ins you talked about, did you shut those in for economic reasons? In other words, are you losing money for every Mcf you produce there or could you just describe that?

Douglas H. Miller

Yes, I think what we have done, we started several months ago to look at how many wells do we operate out of 13,000 or however many wells we operate are losing money at these gas prices, just gross revenue versus operating cost. And we found out that we had quite a few in the Cotton Valley, and that's a product of low productivity, but more importantly water hauling costs and so -- and some compression. So what we did -- we're saving $5 million or $6 million in costs by just shutting those wells in. It's only $1.2 million a day. And I think every operator ought to be doing it because there's a lot of gas being produced at a loss. Our partners are not amused when we send them a check for a $1,000 and we send them a bill at $1,500.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. That's very helpful. And then, Doug, could you just give us a timetable on these -- I think you said with the JV, we should expect to hear something within the next 30 days. What about the TGGT deal? When...

Douglas H. Miller

We have a couple of offers. We have a couple more people coming in to look. We're scheduling them right now. I'd love to say 30 days, but give me 30 to 60.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. Any other transactions we can look forward to?

Douglas H. Miller

You never know.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, got it. And then lastly, what's the minimum that you need to spend to meet any leasehold or pipeline or any other commitments you have?

Douglas H. Miller

It's getting really low. Haynesville, what do we have if we try out to run a rig? Ish? Not even. No, no. Let's say 0 capital in the Haynesville. Marcellus, we could do it with 2 rigs.

Harold L. Hickey

We're looking at that right now. It's a combination of rigs and then some extension on some leases, but I don't have the dollar amount yet. Two is probably I guess...

Douglas H. Miller

Two -- use 2 rigs out there, none in the Haynesville. Obviously, none out in west Texas. And then in TGGT, it's a separate event, but it's very minimal. I mean, we can cut this down to the bare bone. Now that means that we have 875 people playing golf every day. No, we're not going to do that. This is the time when you we make hay. This kind of reminds me of the '80s. Now drilling wells in the gas fields are stupid, but buying gas production at the current price is smart. And so I would love to do some of that, and if we can find the right deals out in an oil area where you can make 50% to 100%, we're looking at that. Acquisitions are going to be a significant part of the consolidation of this industry over the next 12 to 24 months.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And for you, is your focus -- even though you may be seeing some very attractive gas opportunities, is it a focus for EXCO to balance the portfolio and bring in some more oil and liquids-rich?

Douglas H. Miller

Yes. Obviously, if we could have the magic wand, we'd be 50% oil and 50% gas. Right now, we're 90% to 95% gas. Our team has done a spectacular job over the last 5 years figuring out 2 areas which, I think, are going to be the most prolific gas areas in the country over the next 10 to 20 years. The Haynesville, we're going to continue to look at opportunities. The Marcellus, we're going to continue to look at opportunities. And those teams are in place and looking. But I think from a shareholder standpoint, I think the shareholders would like us to see more balance, and if we're going to drill wells, drill something that has a reasonable rate of return, which is on the oil side. So we're looking at those all at the same time. We would love to be 50-50, but there's a lot of things I love.

Operator

Your next question comes from the line of Subash Chandra from Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

Just to clarify some things. So on the TGGT sale, the $500 million to $700 million, that would be the net cash after debt paydown at TGGT?

Douglas H. Miller

That's what I pitched out there.

Subash Chandra - Jefferies & Company, Inc., Research Division

Got you, okay. And any tax leakage...

Douglas H. Miller

I should have never pitched that number out. I hope it doesn't come back to haunt me, but that's kind of a neighborhood number for our half of the equity.

Subash Chandra - Jefferies & Company, Inc., Research Division

Right, right. $500 million to $700 million after the gross debt, and that's your half. When -- how does that compare to, I guess, the private offer you had?

Douglas H. Miller

Right in line.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And any tax leakage of any magnitude?

Douglas H. Miller

No. Actually we have a lower basis there, but one of the things that EXCO has that is an asset that you guys forget about all the time is we have a $1.8 billion live NOL, and so we would have no tax leakage.

Subash Chandra - Jefferies & Company, Inc., Research Division

Got it, okay. And I think Joe might have been -- might have asked this question definitely. So in the JV -- again just to clarify, you expect cash up front in the conventional JV?

Douglas H. Miller

Yes. Why would we do it?

Subash Chandra - Jefferies & Company, Inc., Research Division

And I think you'd previously had said how in your view dry gas PUDs are worthless. And so is this someone else's view then that you're -- exploiting is a bad word, but more or less?

Douglas H. Miller

No, no, no. When I say -- it's only worth an option value. But our Cotton Valley, if you look at our Cotton Valley wells across our portfolio, we have several hundred of them that are producing. And the value of that asset PV-10 are PDP. All of the offset locations, which are 700 or 800 are worth 0 because you wouldn't drill them. Those would go in -- the locations would go in, and if we're buying somebody else out, we're not going to give a lot of value for Cotton Valley locations today. They're just option value. If gas goes to 5 or 6, you would drill them. If it doesn't, you wouldn't.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. So in the JV, you would get the PDP value -- some component of PDP? Or it will all be PDP value in effect?

Douglas H. Miller

Right, right, pretty much.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. So I guess I'm trying to get my head around if you then -- does production come out -- I mean, do we take your production numbers down?

Douglas H. Miller

Sure. The joint venture depending on our ownership, the Cotton Valley production, Vernon and our interest in the Cotton Valley and potentially up in the shallow Appalachia, that production would be in a joint venture with monetization. Hal, can help you with that next week.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, yes. So I mean, I shouldn't look at it differently than the sale?

Douglas H. Miller

No, it is a sale, but we will have an interest in it, and a promoted interest. We'll still operate it, and we will aggressively seek additional acquisitions.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. Can you remind me again how the restricted cash component works and sort of what direction it takes from here?

Douglas H. Miller

That would be Paul.

Paul B. Rudnicki

The restricted cash, again, is 1 quarter's worth of capital and operating expenditures related to our Haynesville joint venture. So as those activities come down, that cash is essentially released. We'll be putting less in than we're taking out. We fund that thing every month. So we expect that to be down to the $50 million level by year-end. When you look at our cash spending, it will be funded with $100 million of cash.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, got it. And...

Douglas H. Miller

That was a deal that we did with BG on the front end. BG has the same restricted cash account as we do.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And just a couple of more, if you can bear with me. One is so on the Haynesville wells, I think you commented previously that there's absolutely – there's no operational effect from these efficiencies really across the board that you're working hard on and experiencing. Just a couple of things on the stages for these Haynesville wells, are those dramatically different or any different than what you've done typically? And second is, I guess, the chrome was put in for high temperature environment, possible H2S and sort of what are going to steel there, what that does.

Harold L. Hickey

Our number of stages have remained the same. We average about 11 stages or so in our Holly area on our 4,200, 4,400-foot laterals. As far as the change out on the tubing, like I said earlier, that wasn't done just casually. That was done after a lot of evaluation and ensuring that we have the right chemical program and looking at the components of our gas to make sure that it's an appropriate thing to do. So we're very comfortable with going to LAV [ph] instead of chrome.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, and one final one so maybe with Steve, who mentioned this on the call, and it was how when you're comparing this year versus last and last year, gas prices were so good. And I guess, in the rear view, it doesn't look a lot better but it was 4. And so if I was to read forward, is that the price where you would go back to normal operations?

Douglas H. Miller

No, no, no. We have a part of our portfolio that has a 20% rate of return at 3.50 or 4, but I wouldn't say we wouldn't go back to normal operations. Cotton Valley price takes 6. Marcellus -- parts of the Marcellus works at 3.50 or 4. But I think we'll be very slow in coming back and I think the industry, as a whole. If we start finding stuff out in west Texas and we move 2 or 3 of those rigs in the Haynesville out there and oil stays above 80, we won't move them back if gas goes to 6. The rates of return are totally different. It will be slow.

Operator

Your next question comes from the line of Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Just a couple of quick ones for me. I guess first, just question on my end around TGGT. Is the private offer still outstanding, i.e. is that still a good offer?

Douglas H. Miller

No, it's expired. I have a feeling I could resurrect it by noon. There is a -- let me put it this way, the reason we did it, we did a total review of selling 100%, doing an MLP or talking to infrastructure funds. The infrastructure funds that we've had discussions with have a lot of cash and are looking for assets like this. It would not be hard at all to do a partial sale to them. But we think, in the best interest of our shareholders and putting our capital where it really should be, if we can monetize 100% of it with a strategic operator, that doesn't need all the G&A. They can pay us more, and that's what we're looking for and think we found.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. Look forward to hearing more. On the JV then, sorry if I just missed this, but how much production do you actually have in your mind that could potentially be contributed to that? Are we like 5,000 per day [ph] kind of number? What's your ballpark thinking around that?

Harold Jameson

Well, in our slides on 19, we lay out our conventional assets. So we got a little bit over 4,000 BOEs in the Permian, and we've got about 100 million a day of gas across the portfolio. I would say...

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

That's really about 100 million a day then?

Paul B. Rudnicki

Yes. Well, potentially.

Douglas H. Miller

That's to 100%. Now all of it may or may not go in. But I would say you'd kind of like me using the rules of thumb. With this long life, these assets, probably Cotton Valley, if you use the forward strip we're probably worth in the 7,000 to 8,000 and flowing. The spend, like it used to be, in that 5 like a short life asset is, kind of middle of that.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

That's helpful. Appreciate it. And then, I guess, the only one for me is the Haynesville. You provided a nice little turn to sale schedule in the Marcellus. Do you have similar schedule for the next 3 quarters in Haynesville, how many wells will be turned to sales?

Douglas H. Miller

What was on there?

Harold L. Hickey

For the whole year, it's 83.

Douglas H. Miller

We are actually -- let's see. We have already -- we've got a turn to sell sales for the full year in the Haynesville of 81. We've actually turned 37 or so to sale now, so we've got a balance of 45, 44 for the rest of the year.

Paul B. Rudnicki

It's going to be about 14 to 15 a quarter. We're essentially going to be turning on 2 sections a quarter going forward.

Operator

Your next question comes from the line of Adam Leight from RBC Capital Markets.

K. Adam Leight

Most of my stuff has been exhausted here, but a couple of follow-ups. Just can you clarify on the sale of midstream TGGT, is there a timing issue in borrowing days reduction if you sold conventional assets first?

Douglas H. Miller

No.

K. Adam Leight

Okay, so it's 200 associated with?

Douglas H. Miller

Either one of them and if and when we sell them and no time. For us, there's a time. But I mean, but as far as the bank is concerned, there's no time.

K. Adam Leight

No, I just meant in terms of if you sold something else first, it doesn't...

Douglas H. Miller

Right, okay. Either one.

K. Adam Leight

And the calculation of the leverage test and the credit agreements, are there any significant adjustments perhaps in the reporting?

Paul B. Rudnicki

Yes, it's filed as an amendment out -- as a document out there. But it's -- we -- in our EBITDA we add back [indiscernible] and some other nonrecurring items. That's kind of the biggest one and then essentially it's a net debt calculation.

K. Adam Leight

Appreciate that. And then another sort of odd accounting question but working capital source of funds in the quarter, does that reverse itself? What was that attributable to?

Paul B. Rudnicki

The working capital changes predominantly. As we're slowing down, we're collecting our partner's funding of activity. So we'll have a flush of working capital. And then probably for a quarter, we might have a little bit of a use, and then it's going to flatten itself back out to normal. So initially, you're collecting your -- because we have about 1/3 or 40% working interest everywhere, we've got a lot of partners so we're collecting receivables from them on the capital side. And then, we'll have a deferred flip on collecting lower priced revenues.

K. Adam Leight

Okay. And then lastly, just to clarify on northeastern Pennsylvania. With the prices that you're looking at and the obligations you have, is there a breakeven on fulfilling your FT obligations? And what would you be looking at for production expectations at that kind of rig rate?

Douglas H. Miller

We don't have any FT up there, so that's not a problem. And what was the second part of the question?

K. Adam Leight

Production outlook, if prices are where you think they'll be.

Douglas H. Miller

Well, what do you think they'll be, and I'll give you the answer because what I think and what you think may be 2 different things. I mean, if they're $2, we're going to be slowing down, and if they're $4 up there, we'll maintain or slightly pickup. And in the middle, we have a lot of board discussions and decisions to make.

Paul B. Rudnicki

It's really, again, it's going to be a question for '13. I mean, '12 is locked in, but we could go essentially to no more wells drilled for us this year, and we're essentially locked in to our completions because we've dropped the rigs fast -- we dropped the completion rigs faster than we've dropped the rigs. And if you are looking at Appalachia, we've got 40-some-odd wells in inventory right now, and that's basically our completions for the full year.

K. Adam Leight

Got that. I was looking and trying to get it out into '13, but I hear you.

Douglas H. Miller

Yes.

Operator

Your next question comes from the line of Howard Henick from Scurlydog Capital.

Howard Henick

We talked a lot about the TGGT sell, et cetera. Assuming your rate is $500 million to $700 million, which I hope you do obviously, will all of that cash be used to pay down the debt? And to the extent you don't use all of it, it will it just go into working capital? Or is that your war chest for the joint -- JVs that you're planning?

Douglas H. Miller

Well, we'll just pay down the revolver with it because that's all accessible again if we need it. That would be part of the war chest but we'll just pay down -- we don't need to, say, put it in the mattress.

Howard Henick

Right, okay. Fair enough. My other question, you guys talked about that you've done some hedges into 2013 through '15. I'm just curious what percentage of your production or your expected production, I know that can change, is currently hedged for a 2012 and '13 and '14. And I understand that what your reduction will be at '13 and '14 are sort of a guess versus what your current planning is or at current prices where you see hedges on?

Douglas H. Miller

Yes. It will be in the 15%, 20% range right now.

Howard Henick

15%, 20% range for '13, '14, '15?

Douglas H. Miller

Yes.

Howard Henick

What about '12?

Douglas H. Miller

'12, we're 50% hedged for the rest of this year.

Operator

Your next question comes from the line of Raymond Brillo [ph] from Pendulum Capital Markets.

Unknown Analyst

Is there anything precluding Wilbur Ross from adding to his equity stake besides his normal course of being on the board?

Douglas H. Miller

No. I think he is now on the board, and he has to deal with the board restrictions as all board members do. But there's no poison pill that was all gone. So he can -- he theoretically could go over 20% if he so desired. But he's still subject to all board restrictions.

Unknown Analyst

Yes, of course. And also, for 2013 you just -- on the last question there, what do you guys have modeled for the price of nat gas for 2013?

Douglas H. Miller

Which model?

Paul B. Rudnicki

3 to 3.50. We're looking at a range of 3 to 3.50 price gas for next year.

Operator

Your next question comes from the line of Carl Giesler from Harbinger.

Carl F. Giesler - Harbinger Group Inc.

Quick question. You talked a lot about the midstream JV and the conventional, would that preclude or complement some potential larger transactions that you just talked about on the last call?

Douglas H. Miller

Well, actually, one of the big deals that we're working on is subject to those 2 transactions happening. A couple of the deals we're working on, they have nothing to do with it. That's why we're marching ahead because it would sure give us liquidity to do some significant deals. I mean, it's mixed. We're working on 3 or 4 deals -- let me -- we're working on 3 or 4 deals where the financings are in place. We don't need to sell it. We're working on one significant deal where that would be the equity towards the deal.

Operator

Your next question comes from the line of Alex Heidbreder from Millennium.

Alex Heidbreder

Actually 2 questions. First, can you -- you might have raised this a little bit earlier, I apologize if I missed it. But can we get some more color on that Shelby Area test. What was the spacing? What was your working interest? And the 215 growth, you brought all 14 wells online at the same time, is that...

Douglas H. Miller

Yes, but they were highly restricted. Let Hal do that.

Harold L. Hickey

Our working interest is 25% in both of those units. One of them we operated, one of them we did -- we do not. We brought all of those wells on simultaneously. We frac-ed them together, and then we flow them back together. We managed each of the wells, as you would expect, individually as far as it goes. We brought on both Haynesville and Bossier. So in the wells -- the units that we operated, we actually drilled 4 Haynesville and 4 Bossiers. And the unit that the other operator drilled and completed, there were 3 Haynesville and 3 Bossiers, a total of 6 wells. And again, there was, on our side, roughly 130-acre spacing. And on the other operator's side, roughly 160-acre spacing between like Bossier to Bossier or Haynesville to Haynesville.

Alex Heidbreder

Okay. And the -- I guess what are you -- how was it different than what you've previously done there? And I guess, what are the takeaways you guys are trying to get to?

Harold L. Hickey

The proper spacing as we make decisions going forward on how we develop the field, you'll note that in the Haynesville, Holly area where we developed a 80-acre spacing, this one, obviously, has got a bigger, broader spacing so we're trying to determine that. We're trying to determine the impact between the Haynesville and the Bossier and how that plays out. We're very encouraged by those results at this point, and again, we're using a restricted choke program that's a little more restricted than what we had used previously. So there's a lot of data to be analyzed. There's a lot of information to be gained. But at this point, we're very encouraged about the results, and we're excited about the opportunity to drill in there again when the prices recover in a year or 2.

Alex Heidbreder

Okay, great. And then my other question is actually on the Holly spacing. How many -- and I guess core Holly, how many locations do you guys think you have left, either gross or net?

Douglas H. Miller

A lot.

Harold L. Hickey

It changes every day. I mean, we're adding...

Douglas H. Miller

I'll let Harold Jameson on that. Harold is actually a frac guy.

Harold Jameson

Let me speak to the unit count in the Holly area, really DeSoto Parish. As of current -- currently, we have 27 units that are fully developed in the Haynesville. 27 units that we operate there are fully developed. And if you look at the total number of units in the DeSoto Parish area, we're in the 67 range. So if you look at where we are currently, we're about 40% of the current -- of the units in the DeSoto area that are fully developed on 80-acre spacing in the Haynesville.

Douglas H. Miller

The point is we have several years drilling that.

Harold Jameson

There's Bossier, and we have -- we've only drilled 2 Bossier wells in the entire Parish. And that's a debate that goes on around here, and we're actually looking at some more units to buy. That's a place where we would buy more units.

Alex Heidbreder

So it's 27 gross units are fully developed out 67 gross units?

Douglas H. Miller

Right.

Alex Heidbreder

And your average -- just the DeSoto Parish and you're working interest there is from 30% to 40%?

Douglas H. Miller

That's right.

Operator

I'm showing there are no further questions at this time. I'll turn it back for any closing comments.

Douglas H. Miller

All right, thanks, Steve. Obviously, we appreciate everybody getting on. It's been a tough go, but I think everybody's got their heads up and working hard. You can see that we have a lot of priorities around here, whether its liquids drilling in west Texas, whether it's acquisitions in west Texas, joint ventures. We're interviewing a lot. We've had a lot of contact from foreign investors wanting to buy dry gas in the U.S. because in anticipation of them needing it for LNG. So a lot of activity probably as much as we've ever seen. And we're not going to hide under a rock, we're going to be out amongst them.

From a capital standpoint, we have enough liquidity to maintain. If gas prices go lower, we will further cut our budget. We will leave within our cash flows. And I think having 8 to 10 Tcf of gas equivalents is a spectacular portfolio. One of the assets that we have that nobody does, and I think it's really tough to evaluate, is the $1.8 billion live NOL so any transactions we do have 0 tax consequences.

We believe that we're seeing supply going down faster than most. We believe that we're starting to see some demand coming back faster than most, and we hope these cheap gas lasts long enough for us to double our size. But I think we're going to see -- by the second half of this year, you're going to start -- people are going to start realizing supply is going down.

With that, we're going to keep running as fast as we can. And anybody that needs to talk to us, give us a call. Thanks again.

Operator

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.

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