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EXCO Resources (NYSE:XCO)

Q4 2011 Earnings Call

February 24, 2012 10:00 am ET

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

Unknown Executive -

Analysts

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

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Unknown Analyst

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

Mark Ferris

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

Howard Flinker - Flinker & Company

David Neuhauser

Alex Heidbreder

Geoffrey Hulme - Porter Orlin, LLC

Operator

Good morning. My name is Tracy, and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Earnings Release Conference Call. [Operator Instructions] Thank you, and I will now introduce and turn the call over to Mr. Doug Miller, Chairman and Chief Executive Officer. You may go ahead, sir.

Douglas H. Miller

Thank you. Welcome, everybody, to our fourth quarter and year end conference call. Before I get started, well, with me today I've got 1, 2, 3, 4, 5, 6, 7, 8, 9 people and we'll be here as late as you need us to answer any and all questions. But before we get started, Ramsey will be reading our disclosure statement.

J. Douglas Ramsey

Thanks, Doug. I would like to remind everyone that you can go to www.excoresources.com, click on the Presentations link in the Investor Relations section at the bottom of our homepage to access today's presentation slides. Statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and derivative activities or other plans, forecasts, 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 23 and 24 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

Is that longer than normal? It seems like it. Okay, we'll get started. With me here, Steve Smith, Paul Rudnicki, Ramsey, of course, Hal Hickey, Marcia Simpson, Mike Chambers, Mark Wilson and our 2 lawyers to keep me quiet, Lanny Boeing and Justin Clarke. So with that, we'll get kicked off. It has been a wild year, to say the least. A year ago at this time, we were going private, and here we are public, with $2.02 gas or whatever it's trading at. So it's been a challenging year, even though we had quite a few accomplishments. Our operating guys set all kinds of records. They hit their targets. We averaged 552 million a day in the fourth quarter with quite a bit shut in because of the plants still not being on, averaged over 500 million for the year, which is up significantly over the year before. They've -- we have kind of unpicked the lock on the manufacturing in DeSoto Parish, so we have continued to upgrade and change and we'll get into that as we go. We delineated Shelby but what -- because gas fell below $4, we have ceased drilling down there. It takes $4 to make our 20% rate of return down there. And so all rigs have been released from there. Hal will get into that. We do have 14 to 16 wells coming on here over the next month or so.

Marcellus, the guys are doing a good job up there, especially in the Northeast. We'll get into some of the results there. We're over 100 million a day of production up there. And it looks like -- we were thinking at year end, because we worked our first budget back in the fall, it looks like we could get a 20% rate of return down to $3. But since it's gone under $3, we're going to slow that drilling down also.

I'd say that part of the reason for going private last year, we wanted, we had a group that wanted to be a buyer and consolidator of gas. We didn't think it was appropriate to be a public company at the time, so we were going to take the fair and full price. We -- I thought gas would be a $3 to $4 commodity for a couple of years, until e-vehicles or power started using it. I think what's happened is gas has gone down a lot farther than we thought. Clearly, if we had gone private, we'd be down 25% right now. But with gas going down farther, I think what it's done is accelerated what I expected to be some demand increase, the power which we expected to really be a gas user by the end of '12 and really getting into '13, you're starting to see it already. There's a lot of people that are really benefiting from low natural gas price, chemical companies, fertilizer companies and I kind of expect those guys to start beginning hedging at these prices right here, because many operators are shutting in. Hal will get into that. We're not going to be shutting in our Haynesville gas, but we are looking at the rest of our portfolio and we do have uneconomic conventional gas wells and Hal, we are going to be shutting those in. And I think, across the industry, if everybody'll look at their portfolio on conventional gas, especially the ones that make water, I'll bet we have 10% to 15% of the production that's out there that should be shut in just because they're losing money at these prices.

The other thing that we've done since the beginning of the year is it's all hands on deck on looking at costs across every venue, especially on the operating side and we're starting to find some. Well, I expect during '12, we'll have some fairly significant cost cutting going on. We're already seeing that. For this year, we're working on our balance sheet. As we explained, we have an unrestricted subsidiary, TGGT pipeline a joint venture with BG. We have signed an exclusive agreement to sell 1/3 of that. We're marching on that and that is an unrestricted subsidiary, cash that comes in here. We will just go to reduce debt and again, what I'm trying to do is get as much cash available as we can because there's a lot of opportunities out there. I mentioned to the banks a week ago that I thought there was at least $20 billion of deals in the marketplace today. I think that's expanded by about $10 billion since I made that statement. So there's a lot of deals in both oil and gas. We have been approached by a couple of large institutions to do joint ventures in acquiring conventional gas. We're working on that as we speak. We think there are some opportunities out there to buy conventional gas and obviously, all you would be doing is buying it. You wouldn't be drilling any of it. We've also been approached recently to do a joint venture on buying shale gas with somebody that will be putting up some drilling dollars. We're evaluating that. So we have a lot of things cooking that we'll be getting done. Four or 5 oil deals are on the market. We've had people in the field this week, reviewing those. I expect we'll be making bids on that in the next, not-too-distant future. Again, we're going to be focusing on liquidity and we're going to be focusing on some M&A that was out there. With that, I'm going to turn it over to Steve.

Stephen F. Smith

All right, let's go to Page 7 in the slide book and talk a little bit just about the year of '11 and the fourth quarter. As Doug has already mentioned, we had a good, an excellent year, really, in terms of production. We averaged 501 million a day. That was a huge increase over last year, 63%. We also increased revenues. We increased EBITDA. So it -- year-over-year, was a very good performance and our operating people have done an outstanding job. Our operating costs are really down between years like 39% and we expect that trend to, not that kind of decrease, but we expect to maintain those operating costs at a very low level. Our operating costs in the Haynesville right now are about $0.08. And so that tells you that -- why we have no interest in shutting in that production. And the Marcellus operating costs are also low. So we're looking forward to continuing that trend.

The quarter of '11 versus '10 is also about that, those same kind of growth numbers in terms of revenues and all the rest of it. As far as Q4 versus Q3, there was a tremendous decrease in gas price by 17% between Q3 of '11 and Q4 of '11. So obviously, the fourth quarter wasn't exactly what we anticipated it would be, but on the other hand, it was still a good quarter. We made $0.64 of cash flow from operations, which was strong and so in spite of, as Doug mentioned already, the curtailments that we have at the TGGT facility, we should be back online by the end of March. Cash G&A costs are down a lot, 36%. And so all in all, it was a pretty good year and a pretty good quarter.

Over on Slide 8 is a slide that I like to put in here just to show what we're doing from a standpoint of a per Mcfe costs and revenues. You'll see that in spite of the very -- the low gas prices in Q4, we still had a $2.40 cash operating margin and a $3.40, when you take into -- the cash settlements into consideration. Obviously, a big part of our success in operations has been in reducing costs at all levels and we'll continue to focus on that thing. Now in '12, obviously the gas price, just we're, and Paul will get into it, but we're looking at an overall average for '12 of $3.21, counting the oil that we have out in the Permian. So we've got a good hedge book going into '12. So '12 should be in pretty good shape. So we're moving ahead on a lot of our capital reductions that we'll be discussing. We're cutting capital substantially and should be flat on our capital expenditures with our EBITDA.

Page 9 is the chart showing where our debt was back in '09, what it's done at this point. As you can see from this chart, the production levels obviously are going to drop some during 2012 because we are cutting back our drilling rigs dramatically from 22 rigs to 9 on average. So obviously, production is going to tail off some. But Paul will get into a little more on that when he talks about our guidance going forward. Debt is at $1.7 billion right now, net of cash. And if we get a deal done on TGGT, that would be $1.5 billion. We're well within all of our covenants on our revolver and don't anticipate any problem with that during this year.

On 10, as a summary of our cash and debt, the bank revolver is the same as it was at the end of the year, $1.147 billion and our bonds of course are the same. The net debt is $1.747 billion. Our bond base is $1.6 billion. Because of the decline in pricing we're expecting that to be in the $1.4 billion neighborhood, something like that. So should be ample, we're not anticipating any debt increases in the bank debt this year in terms of operations. So we're moving in the right direction there. The hedging, we've got about 45% of our production hedged. The gas at $5.27, the oil at $97.84. Very little hedging in '13 but we're looking to add to those hedges as we go through the year here. So all in all, obviously '12 is going to be somewhat challenging, but I think we've got the plan in place and the one thing that we still have and will continue to have, are world-class assets in the 2 best shale areas in the country. So Paul, with that, I'll turn it over to you.

Paul B. Rudnicki

Thanks, Steve. I'm going to pick up on Slide 12 and go through a little detail on our fourth quarter numbers compared to our guidance. As you can see from the slide, our actual production of 552 million came in below the low end of our guidance by 3 million a day. A couple of things were going on there. We continued to have the curtailments from the treating facility, which obviously took us to the low end of guidance. With the curtailments that we were seeing in the field, in some ways we took advantage of that and we curtailed wells that -- and accelerated some work on them. One of those things is accelerating a tubing program as we tube up the wells after completion. We also deferred some completions in the quarter. As you know, we announced that we ended the year with 18 rigs. We were able to start dropping rigs during the quarter. We also slowed down the pace of completion in the quarter and that affected us by nearly 5 million a day of volumes there, just on the completion deferral.

We also instituted a more restricted choke program, especially down in our deeper Shelby assets, which Hal will get into later. And that was instituted in the fourth quarter. We're expecting to see a much flatter decline. But on the front end, it will take some of the initial volume out and that affected us in the quarter as well.

On the differentials, the gas differential, obviously came in on a percentage basis, much lower than we had forecasted. On a dollar basis, the gas differential was in line with our expectations. As some of you are aware, most of your differential has a fixed and a variable component in it and as you get to lower and lower commodity prices, the fixed component is a larger contributor to the differential than a percentage component. So when commodity prices came down in applying a percentage differential, it implied a stronger differential than we actually realized.

Lease operating expenses, as noted in the slide, were a little bit above the high end of guidance. Again, as we were curtailed in the field, the operating guys looked at wells that we could increase the maintenance on. So if we're going to have some wells shut in, go ahead and shut in wells that you can accelerate some maintenance on, that affected us on the operating expense. Gathering expenses came in towards the high end of guidance. The main contributor there was our last leg of firm transportation came on during the quarter with our Enterprise Acadian, firm transportation contracts, as well as the impact of lower volumes on a per unit basis would raise your per-unit gathering charge. There was no change to any of our TGGT gathering rates as those are fixed market-based rates.

DD&A came in higher than expected as a result of the year end gas prices used to calculate our year-end reserves and the removal of the conventional PUDs. It resulted in a lower base to deplete from. So it increased your DD&A rate and effectively was also a true up for the year to get us to that annual rate.

The capital side of the equation came in well below guidance, 2 things going on there. Again, the reduction in activity led to a good chunk of the difference in terms of, again, we were letting rigs go and deferring completions faster than we initially anticipated, as well as just coming in below our run rate that we had used as a component of coming up with the guidance. We expect that to continue to come down, obviously as the capital spending program comes down.

Going on to Slide 13, looking at our guidance on a quarterly basis for 2012. As Steve has pointed out, based on the plan we laid out, we anticipate having relatively flat volumes in the first half of the year and a little bit of a decrease towards the second half of the year. One of the things we are [indiscernible] is although we are going to run an average of 9 rigs in the Haynesville, we're going to manage our completions. So to flatten out the production profile, as we pointed out in the press release, if you look at what our plans are for the end of the year, for 2012 compared to what we ended 2011 with, we had about 52 wells that were either waiting on completion, drilling or in the completion phase at the end of 2011, using the 22 to 18 rig count for the fourth quarter. By the -- with the reduction in the rig count by the end of the year, we still anticipate pushing out about 41 completions into next year. And again, that's a reflection of reducing the completion activity faster than we will reduce the drilling activity.

Differentials, you can see that we are forecasting our differentials to get a little bit better during the year and that's mainly a result of some increase in price, but also just a different mix in the volumes as the Haynesville comes down a little bit as a percentage of the volumes. Lease operating expenses, you can see in the back half of the year we're forecasting some pretty good decreases. We are anticipating that those will come in sooner in the year but at this point, we're going to keep the guidance to reflect the back half as where they would start showing up. DD&A rate is raised to the kind of current level that we're seeing and everything else is pretty much in line with our fourth quarter results. Would like to point out on the capital expense, again you can see the reduction in our capital. We're expecting Q1 to average between $180 million to $200 million. Again, a reflection of the activity we're carrying in from 2011. But as you look into Q4, our capital expenditures should be in the $60 million to $70 million range. So for a full year, based on the Nymex prices noted below, $2.80 for Q1, $3 for Q2 and Q3 and $3.50 for Q4, $100 oil flat, we're anticipating EBITDA at the midpoint of around $465 million, with our $470 million of capital expenditures.

One other thing to note that as you all may remember, we carry a restricted cash balance as part of our joint venture agreements. It's there to prefund a quarter's worth of activity in our Haynesville. And as our activity levels are coming down in the Haynesville, our restricted cash balance will come down as well. So with a flat to EBITDA spend and a reduction in our cash balance, our debt balance will be flat to down by the end of the year.

The other thing to highlight is while we're forecasting to end Q4 between 445 million to 465 million a day, depending on a lot of things that happened this year, especially commodity prices and what our plans will be into 2013, we expect to maintain, to grow those volumes and -- going into 2013 and start growing again from there. Bottom line, what's going on in the year is the production profile is going to adjust to the capital spending and we expect that to happen by year end and we'll be growing from a revised decline base and capital program going forward. With that, I will hand it over to Hal to kind of go over some of the detailed operations.

Harold L. Hickey

Okay, let's look at Slide 15. Here's a map of our portfolio and of course, we remain focused in the 3 basins: East Texas/North Louisiana, where we have about 88% of our production; Appalachia, where we still have tremendous upside from our Marcellus shale; and the Permian area, where we have our most liquid production. In fact, in the Permian area, we're making more than 1,700 barrels of oil a day and some 1,300 barrels per day of NGLs, that previously we've always reported in our gas numbers. So we do have a significant NGL component in the Permian that we manage.

Across our whole portfolio, more than 8,400 wells. We operate 94% of them so we can control our spending patterns. I want to talk about reserves for a minute. You might recall, in 2010, we reported a 576% reserve production replacement. This year, we're reporting 110% production replacement. And if you step back for a minute and think about what's more meaningful when you're booking reserves the way the industry is now and the development, the way we're doing our development now, it makes more sense to look at these things on a 3-year basis. So overall, 3 years reserve replacement of 319%. Step back again and think about a year ago, we were able to book virtually all of our core Holly, DeSoto Parish area into proved and we think that we'll have enough wells drilled in a contiguous or nearly contiguous area up in the Marcellus in Lycoming County during 2012, that we'll be able to do some similar booking there and book across that whole area and book in the PUDs. So it's meaningful to look at this thing over a period of time because you're going to have some ups and downs as you get critical mass drilled. Three-year all in F&D, $1.99 when you adjust for the benefit of the carry from BG Group. Proved developed reserves in 2011 grew 22% from 2010. PD represents 74% of our total proved reserves and we had a 221 per Mcfe F&D in our PD category. Now, if you look at the FEC strip pricing, we had 1.3 Tcf of reserves. Of course, that's what we'll report. If you look at it on management strip pricing, we have 1.5 Tcf of proved reserves.

Moving onto Slide 16, I know Paul started to give you some color on our capital budget plan, you might recall that our budget in 2011 was some $976 million. We came out in November when prices were still relatively high compared to today and we had reduced that budget to $710 million. We planned on a 13-rig program in East Texas/North Louisiana. We're going to further reduce the budget as Paul said, down to $470 million. We'll still spend some 80% on shales. 61% will go into the Haynesville/Bossier area. Of course, that will be dominated by drilling. In Haynesville/Bossier, East Texas/North Louisiana, we have 13 rigs operating today for us. We plan to drop that to some 8 rigs or so during the second quarter. And by the fourth quarter, we plan to end the year with a number between 4 and 6 rigs, likely to go to 4 but depending on what prices do, we have some flexibility with our program and our service providers that we could end at 6. We will enter next year 2013 at 4 to 6 and if prices follow the strip, we may ramp up during 2013 and by '14, hopefully we'll be back at the 13 rig count in our Haynesville Shale play.

The Haynesville program in both DeSoto and Shelby, like was mentioned earlier, is being operated today with a more restricted rate flowback program than we've had before. We've always been on a restricted choke program, but you'll recall early within our development, we were reporting high IPs. Now, we've come to a point where we're testing a restricted choke so we're not maxing out at about 13 million a day IP in our DeSoto Parish area, about 16 million a day IP in our Shelby Area and what that's doing is keeping a higher pressure over time. So we believe that though in Shelby, within the first year, you have what I'd call a crossover of volumes and you meet what you would have been before in Holly. Gosh, it's happening as quick as in the first couple of months. So initial results, early results, are that we think this is the right thing to do. In the Marcellus program, we had planned at one point to go as high as 7 rigs and in November, we cut that back to 5, and that would have entailed some appraisal drilling. At this point, it looks like it's going to go down to 3 rigs here very shortly, we are at 4 today. We're going to drill some 49 wells or spud some 49 wells there, only 2 of which will be appraisal wells. We're very focused on moving quickly into development in Lycoming County, where we can get very good returns at $3.50 gas.

Other spending, we're cutting way back in our other areas. Permian, we will maintain at least a 1-rig program. There's a possibility we could increase that. We do like the returns out there, obviously with our liquid content. And the last thing I'll note on this page about our budget is we do have, as of 1/1/12, some $55 million of BG Carry remaining for our use. We hoped that -- we are likely to use that up this year.

Cost reduction initiatives are very important to us. We're talking about that on Slide 17. Obviously, we're reducing the rig count, as I've mentioned, focus on well development cost. And Holly, Haynesville, we ended '11 at approximately $9.5 million drilling complete. We've had some recent frac service bidding and we're confident, and in fact, just a fact, we're going to go down some $600,000 because of some reductions in the service cost on the fracture stimulation side. So our current, most current AFEs that we signed are around $8.9 million. Of course, the team's very dedicated to meeting that target and then reducing it further. In fact, we would aspire to be at $8.5 million per well later this year and perhaps as low as $8 million in 2013.

It's not just the frac service contractors that are providing us some cost relief. We're getting reductions across the service lines in our drilling program. In the Northeast, in the Marcellus area, we've been spending about $6.5 million per well. We're going to target $6.3 million and ultimately hope to get that down, of course, below $6 million. A lot of that reduction is going to come as we continue to get experience there. But a huge amount will come from building up water infrastructure and having the ability to move water more easily through the basin into our development areas.

Operating expense is a very big focus, naturally. We reviewed some uneconomic conventional wells. And in fact, we've shut in about 163 Cotton Valley wells at this point. It's about 14% of our Cotton Valley portfolio. It reduces our production by about 1.5 million a day net but it saves us more than $5 million of net expenses in a year. So it's the right thing to do. We're going to encourage others to look at that same thing and do what we do about gas demand and supply. We're targeting some workover reduction. And overall, we hope to reduce our operating expense somewhere around 20%, we're reducing -- we're releasing compressors, we're managing our chemical programs, we're looking at our saltwater disposal, there's just no stones being left unturned.

East Texas/North Louisiana is detailed a little bit more on Slide 18. Our operated shale production remains at around 1.2 billion a day gross, dramatic growth from nothing in late 2008 to this level of production. We have some 278 wells flowing to shale, now about 50 or 55 of those are in the Shelby Area. About 223, 225 are in DeSoto Parish. Our guys are focused on not just cost from service providers but what can we do in our drilling operations and managing our drilling days, and I've talked about what our targets are. I'll reiterate what Paul said, we will drill about 70 wells in the Haynesville this year. That's down dramatically from some 160 or 170 in 2011. We're carrying in between, as of 1/1/12, we had 18 or 20 wells being drilled. We had several wells in the completion phase and then we had several quite a few wells, 25-ish, waiting on completion activity. So we carried in 52. Our overall completion total in 2012 is forecast to be around 81 in this play. And so we'll likely carry out some 41 wells for completion in 2013 that actually are initiated in 2012.

Appalachia, we're very happy with the success we're seeing in the Lycoming County area. We've averaged between 5 million and 6 million a day from 3,600-foot laterals. We've got 3 rigs operating there now. We'll ramp that up. That activity's going to be steady, I mean. We're producing about 110 million a day gross. We expect that to be ever 200 million a day very shortly over the next 3 or 4 months. We have a huge HBP position of our 56 operated wells and 10 OBO horizontal wells. The big focus is going to grow in the Northeast. We plan, like I said, to drill 49 wells. I talked about that a moment ago.

Flip over to Slide 20. The conventional assets remain a significant portion of our portfolio and about 70% or so of that comes from East Texas/North Louisiana. The Vernon Field actually is the most prolific field in our Cotton Valley or conventional asset portfolio. Permian, about 21 million a day. I talked about how much oil and how much NGL that entails. Appalachia, we've got about 16 million a day. Across our whole conventional assets, we're only going to drill for the full year with one rig out in the Permian. Actually, today we have 2 going. We've got sort of a one-off farm out opportunity that we're testing. We're very encouraged by some of the shells as we've drilled that well. We'll have some results for you on that next quarter.

But overall, in this portfolio, our focus is on cost management and making sure that, that rig provides cash flow to the corporation. There's a significant inventory of drilling locations that would light up at that $6 gas. I'm waiting for that. But some 7,500 producing wells, a lot of undrilled locations and then very importantly, this might be an opportunity for some sort of a transaction because there's definitely some interest from private investors in joint venturing in this type of a portfolio. And seeing what you can do to manage it and grow it while gas prices are depressed.

Slide 21 shows the Permian basin. The big focus there remains Sugg Ranch, 26,000 or so net acres. It's a multiple sands but we really target the Canyon for starters. Really, really strong cash margin of $10 per Mcfe, thanks to the oil. And you can see the split on our production down in the right-hand corner of the page. This asset's out in Irion County, Texas.

Finally, I'll note TGGT continues to operate very well at about 1.5 BCF a day of current production and the 3 facilities, as Steve noted earlier, are scheduled to start up in March. I was down talking to them this morning. That seems like a very doable schedule at this point. We're also completing a treating facility down in our Shelby Area. And what that's, what's important about what's going to happen in Shelby, not just from a TGGT perspective, but we're actually, as Doug noted in his opening comments, drilling and have drilled and are now completing across 2 sections, 14 new drilled wells that will supplement the 2 initial unit wells. It's testing from 110 to 88 for spacing, and testing both Bossier and Haynesville, and we're going to flow that back likely in mid-to-late March, if not sooner. And we're going to -- there's going to be a huge effort in assessing the performance of that program. It will bring home roughly 200 million a day or so of gas that will flow into TGGT. So it's a significant task for us. It's a significant opportunity for TGGT to flow more volumes.

We are, as you noted in our earlier press release, working on a potential sale of 1/3 of TGGT's equity interest to a third party. Both BG and EXCO are aligned as the partners in the TGGT venture and going forward with that transaction. We're in a diligent space now. We've reduced our capital budget in TGGT. It will be in the $70 million to $80 million range. We've got a big focus as opposed to years past when we were really focused on equity, equity, equity and flowing equity volumes for EXCO BG. Now, we're looking at the opportunity to flow additional third party. And there is some out there, despite the reduction in rig count. And the last thing I'll note is that TGGT was successful in increasing its credit facilities, $600 million in January of '12. And so TGGT, between its cash flow and the facility, will be self-funding. Don't anticipate cash calls on EXCO from TGGT. All right, with that, Mr. Miller?

Douglas H. Miller

I think bottom line is with cheap gas prices, we've got everybody looking at everything. We have a lot of partners that would like to do joint ventures, and I think if you really look at the map, you buy gas today and you can drill for oil, even out on our Sugg Ranch, at $100 oil, we're getting 70%, 80% range of return. But I think there's going to be some opportunities to buy. We are in discussions on that again. This portfolio, we've got 8, 9 Tcf gas between proved, probable, possible, at different prices. We have thousands of potential locations and it just doesn't make sense to drill them today. But the gas isn't going anywhere. I mean we've got it, we own it, it's held by production and as the gas market firms up, if it ever does, we have plenty of assets around here to grow the company when it needs to grow. With that, I told everybody, I said, we do have plans and backup plans and backup plans to the backup plans, that we're all working on together. And I think it will, from a shareholder's standpoint, I think it will bear fruit during the year for '13, '14 and years to come. With that, I'm going to turn it over for questions.

Question-and-Answer Session

Operator

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

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

On acquisitions, how big of a deal are you all willing and able to do based on what you're seeing out there?

Douglas H. Miller

Well, I hate to say it, we're willing -- we believe we're willing and able to do a large one. We just got turned down on a $3.5 billion deal and we had all the money raised with 2 joint ventures. I think most of the deals that we're looking at right now will be smaller than that, but there are 2 or 3 oil deals out there that are probably of $1 billion in size. But I'd say, the deals are all over the spot. I'd say, we're not looking for acreage. Let's start with that. We are looking for something that has production with it, especially if it's oil, where we could put in a 5-year hedge and manage that. We do have guys that have got a lot of experience in the Permian, so and we have a lot of contacts out there. So we're working on some potential drill to earns and things like that. So I'd say we're not afraid of anything. And anything over about $100 million, we're going to have to do it in a joint venture.

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

Okay. And so, I guess, that was my next question, sort of thinking about say $100 million up to that $1 billion level, sources of liquidity for that?

Douglas H. Miller

Yes, we have…

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

Is BG kind of on board for all these or?

Douglas H. Miller

No, no, no. It wouldn't be BG. I'm not saying they wouldn't. I'm just saying we have other third parties, significant private equity guys, including some of our shareholders, have indicated interest in teaming up with us. We're having those discussions right now. I'm not going to disclose any names, but we have been approached by several of them. And we're working on that as we speak.

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

And you guys, it sounds like are looking more on the private market side as opposed to corporate M&A?

Douglas H. Miller

Yes. I can't think of one public deal we're working on. Everything we are looking at today is private. Some are individuals and quite a few of them are owned by a private equity.

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

Okay. And then on speaking about the Permian, can you all talk to the potential for the Cline Shale under your Sugg Ranch at this point? It's right in your range, which was talking about yesterday?

Douglas H. Miller

No, no. I get it. I can't talk about it right now.

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

Okay. And then one question on the guidance for '12. Does the LOE guidance, it looks like roughly sort of $0.45 to $0.50 per Mcfe. I know that changes through the year, but does that contemplate these cost reduction initiatives you all are talking about already? Or could we see some more upside or foresee those costs come down once you implement that?

Paul B. Rudnicki

Sure, William, it's a combination of both. It does contemplate some of them. Doesn't contemplate all of them, and we've tried to kind of be cautious about when they do start showing up. I think there's a good chance that our LOE comes in lower, faster and to a higher degree.

Douglas H. Miller

And with, the other thing that if we do a joint venture in the conventional and we put it over in what I call a parking lot, the conventional, we end up with the bulk of our production with LOEs under $0.20. Keep in mind, in conventional, you're looking at $1.50, $2 an Mcf in cost because of the water. I mean, if we could shake that, we'll have a hard time bringing that $0.08 a thousand operating costs.

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

Right. And on the JVs you're contemplating, so you're thinking about sort of typical half, 58% interest, or is it…

Douglas H. Miller

Well, yes. We're looking at all -- I mean we've got one where they want to buy it, the whole thing, and have us operate it with a promote. I mean, we're kind of interested in a 50:50 deal, but all -- everything's on the table.

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

Okay. And just one final question, as we're sort of around borrowing base redetermination season. Is that something you've all have done yet or is that coming up in the…

Douglas H. Miller

Yes, we haven't done it, but we're sure prepared for it. We have spent a lot of time with JPMorgan and all their engineers. We have an annual bank meeting that we just had. I think depending on gas, we polled our top 9 banks and what we're trying to do is figure out what their price decks are. And they, seriously, they range from $2.50 for this year up to $3.50 for this year. We think if it comes in at $2.75, $3, like Steve said, we think it'll end up around 1.4. And I think that will be easy to do and we've had that indication. But we have been in discussions since November. Our meeting, I think is set for April, is that right? Yes. Our meeting's set for April. Any banks, they have our reserves already and we're working our way through it and anybody that wants to come in and I'd go over it in detail, the door is open.

Operator

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

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

Curious, Doug. At what gas price does activity resume?

Douglas H. Miller

Our activity or the industry activity?

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

Your activity.

Douglas H. Miller

Well, I think $4. We have -- we're one of the few people that has spots where $4 really lights up a lot of our locations. I think we have -- it depends on cost. Like Hal said, if we get our cost down to $8 million in Holly or below, they start talking to us at $3, but I'm not sure we're going to do it. I think the M&A will drive where we'd go with our rigs. But I think up in Lycoming, $3 to $4, again depending on cost. That's what we're working on right now. Drilling costs, frac costs, location costs, everything we're working on it. And we're -- and they're being cooperative. Those guys don't want to move out of the areas. So between $3 and $4. I don't know that we will go crazy even if gas went to $5. I think our old history, going back to Dakota and EXCO is your capital budget should be about 50% of your EBITDA, and we're just at, we're at 100%. So we still have room to slow that down even if gas prices go up.

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

That's something that BG's on board with, has to be on board with or it doesn't matter if they're on board there?

Douglas H. Miller

No, no, no. It matters, for sure. And the reason we were so late in coming out with our second capital budget was we just met with BG this week and we're all totally on board. And I think as prices go up, they would love to see acceleration. But I think right now, anything under $6, they're very content with slow -- keeping it slow. They know how much reserves we've got here.

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

Yes, so I guess reconciling that, Doug, if they're thinking $6, you're thinking $3 or $4, How do you think that works itself out in, with drillbit activity?

Douglas H. Miller

You didn't tell me when we -- you told me when we could.

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

Yes.

Douglas H. Miller

Yes, I got it. We can, and so can BG at $3 to $4, but we probably won't, until we all agree, whether it's $5 or $6 or whatever. I mean we don't have to drill. This is all HBP. I think BG believes, like we do, that gas is going to be very cheap for the next couple of years. So we're going to be working on M&A opportunities because these reserves aren't going anywhere.

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

So when you talk about -- when you think about 2013 and I think you'd refer to growth in 2013, fairly confident you'll deliver it. That is more premised on the M&A you're shooting for this year?

Douglas H. Miller

Well, it depends on gas price, but I'd say yes. I'd say right now, the way we have the rigs forecast with them coming down and then starting back up in 2013, we should have growth organically, whether it's 5% or 10%. But I think we're going to have a lot of opportunities on the M&A side to add to that.

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

And these JVs, I guess that's the structure of how you're going to -- assuming [ph] more than your weight is to -- via pro mode [ph] and all the operating expertise you have at EXCO, which is what I presume your PE partners want. But what is a -- what do the PE partners get? I mean, are they trying to do, I guess buying gas cheap? Or do they want big businesses where you guys operate? It would seem to me they were fairly happy with having a liquid interest in EXCO. So it goes from liquid to illiquid. So any commentary on that and sort of what their angle is?

Douglas H. Miller

I think you're seeing private equity guys with a lot of money that are really playing the gas market. You just recently saw Samson done, led by KKR. There's rumors going around that Apollo's getting ready to buy El Paso, again mostly gas. We have been approached by several of those type guys that want to buy, specifically, conventional gas because of the low margin. If we can get it bought and stack it, a very slight movement in gas creates a huge rate of return. So I think it's mostly a gas play. But there are guys out there that are doing both. We have been approached by guys that if we could find the right oil play, would love to play. But I would say, by and large, there's a lot of money being raised, there's a lot of them willing to invest in gas plays, just because people think we have 6 months to 2 years of cheap gas because of demand and you're starting to see some supply go down. You're starting to see demand come back. At least, the power is probably a little sooner than I had expected, but if we get a lot of gas power coming, your gas prices could go up sooner than we hope. I want to make some deals. If, we've got guys frothing at the bit to team up with us and I'd sure like to make a few deals.

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

And the -- how do banks, in the redetermination process, how relevant is that PV-10 metric? $1.7 billion is about the depth that you have now on a $4 plus price tag and you're 96% proved. Does that -- do they have a different metric they use and -- or are they looking for also non-proven stuff that you might have that, those that show up and?

Douglas H. Miller

Yes, let's start with the banks, mostly land on PDP. We're one of the few companies that can say we have 74% of our proven reserves that are in proved developed. That's the first thing they look at. They use a forward curve, not a flat curve. They will give a minimal amount of credit for PUDs. They use a slightly different discounting and a slightly different risking profile. And, but we look at them all the time. But I mean, they probably use a 9% discount and get on anywhere from 60% to 65% of that number will be the borrowing base.

Harold Jameson

And the hedges we have over...

Douglas H. Miller

Oh, yes, the hedges count. Hedges do count.

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

Okay. So the hedges are not in the PV-10, right?

Douglas H. Miller

No.

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

Yes, okay. And a final one for me, can you just maybe explain it in more detail, my expectation always is that as volumes come down, some of the fix lifting cost, the per unit numbers go up because there's element of lifting costs that are fixed. Yet, you're targeting very aggressive reductions in overall lifting cost. So maybe some more detail on how that's being achieved?

Paul B. Rudnicki

I'll start and Hal can jump in here when he wants. If we did nothing and didn't operate the business right, then that would probably happen. But there's a lot of levers that you go out in the field and look at, look at all your wellhead compressors and see if everyone of them need to be on, look at all your activity around there. So we're -- the volumes that are coming down are not the conventional volumes. So the conventional per Mcfe isn't going to be moving around, but that's exactly what you have to look at. You have to look at the fixed costs and that's where we're going to be seeing a lot of the cost reductions.

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

Okay, so compressors, okay. Any other sort of examples of that?

Harold L. Hickey

The typical programs, compressors, saltwater disposals...

Douglas H. Miller

Saltwater disposal, that's huge.

Harold L. Hickey

That's a huge component of what we're doing. We're working with one of our service providers to get some more reliability in the particular saltwater disposal line that will bring down some of our trucking costs. And we're also releasing coolers, wellhead compression, like you mentioned, the gas jack type compression. I think we've released about 100 of those. And so a lot of that is just those are kind of fixed costs.

Douglas H. Miller

That was fixed costs, though.

Harold L. Hickey

Right.

Douglas H. Miller

We're looking at every fixed cost there is and I think you're exactly right. Over the past 20 years, every component of LOE is partially fixed, partially variable and we're looking at both.

Operator

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

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

Question here on your completion schedule in the Haynesville. You talked about going from 13 rigs to 8 to 4 to 6, and then deferring some completions. Obviously, your production is peaking. It kind of, it looks like here in the second quarter and then rolling over. Are we going to see many completions in the second half of '12, or are most of those just being pushed to '13? Any color you have on that would be great.

Paul B. Rudnicki

Well, the plan is obviously we're well down the path in the first quarter and a lot of our completion activity is tied up in our spacing test down in Shelby. But we're going to drop down to a pretty -- well, we're going to drop down to potentially one frac fleet equivalent for 2 to 3 quarters here. So it's starting now. And but yes, you are seeing some increased volumes from 20 to 30 completions a quarter going down to 15. But it's going to be at...

Douglas H. Miller

Right, we can't. We're not -- all we're doing is going down to one frac fleet we're just going to stage -- we're not delaying them to delay them. They're going to -- if they stack up a little, we'll get to them when we get to them.

Paul B. Rudnicki

It's not like we're going to stop completing at some point. We're just going to we're going to lower the completion activity relatively early in the year, irrespective of the rig count.

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

Okay. In terms of your TGGT facility, why did you guys decide to just kind of try to sell 1/3? Why not sell the whole thing?

Douglas H. Miller

That's a good question. We were approached -- we looked at doing an MLP. We talked to several of the infrastructure funds. They would all like to buy somewhere between 1/4 and 1/3, and the guy that we have signed up with was talking about 1/3. And so we're under an exclusive deal to talk to him right now. I'm not saying we wouldn't sell 100%, but I think right now this particular partner could be a great partner. And it's something that could be thrown. And then if the gas prices got better and drilling activity picked up, we would probably do an MLP.

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

Okay. And in terms of your Marcellus activity, you guys talked about moving to 3 rigs. Are you guys planning on deferring any completions there in the Marcellus or should that be, kind of, relatively steady completion throughout the year?

Stephen F. Smith

Well, we drill mostly on pads up there, as you know. And so it will be cycling depending on when the pads are completely drilled because we do frac stimulator complete all those wells at one time. So there'll be a little bit of a cyclical nature to it, but overall it'll average out to be pretty steady.

Douglas H. Miller

It's bumpy out there because we drill 2 to 5 wells, and then we complete them all at once. So we might go 2 months before a pad gets completed. But the schedules are done, and they're working on it.

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

Okay. But are you going to defer any completions like you are in the Haynesville?

Douglas H. Miller

No. No deferrals.

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

Okay. And in terms of your Permian activity, what formations are you targeting with your drilling program this year?

Douglas H. Miller

Wolfcamp.

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

Okay. And is that going to be any horizontal activity or mostly vertical?

Douglas H. Miller

Canyon Sand is where we're drilling, too, but we're seeing some pretty interesting results in the Wolfcamp. And so that's what we're looking at right now.

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

Is that horizontal, vertical or both?

Harold L. Hickey

Vertical this time.

Douglas H. Miller

So far, it's vertical, but I wouldn't -- it wouldn't surprise me if we didn't have a couple of our geologists, engineers who want to do a horizontal well.

Harold Jameson

The shale would be in the latter half of the year.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Hal, when you speak to your Holly Haynesville costs falling to $8.9 million and potentially going down from here, how much of this is secular via efficiency gains? And then how much is just cyclical because of low gas prices? And I guess in other words, if we do get gas prices back to $4 or higher, should we expect that once the contract you're signing here roll off, the cost would just go back up?

Douglas H. Miller

I think what is going on right now, a lot of frac crews are around, and the first 600 is pure frac job, coming from a major hand. Now does that go back up? Maybe it does, maybe it doesn't. It doesn't look like it does because they're all continuing to build more frac fleets. I think additional down from $8.9 million could be a little more secular. But we're looking at down to building pads. We're spending $500,000 on a pad that we need to have as big as the unit. Do we need that big of a pad? So everything is being looked at but I -- Hal, give me your opinion?

Harold L. Hickey

One thing we haven't been -- built-in here at all is our rig contracts are rolling off. Some of those are relatively high from when we were chasing rigs, when there was a huge demand for them. We may have some opportunity for day rates to come down if we were to contract new rigs in a different cross [ph] environment in the future. I think that there is definitely some overall reduction in costs that will be maintained simply because the number of service providers have gone up. The fleets have gone up. There's a lot of coal tubing units out there. They're built in response to the high demand. The service contractors seem to respond at the peak and start building things, and in turn, you end up a little bit oversupplied. So I think some of this cost reduction will be sustainable.

Harold Jameson

We're also having some drilling efficiencies continuing to improve. We continue to improve our days versus depth, so we're seeing a lot of that.

Douglas H. Miller

And I will throw in another thing, Brian, is that we are taking a look at our well design. We're looking at maybe changing our pipe program, which would give us some sustainable savings as well. We're looking at our completion design. We've gone from intermediate strength proppant to virtually all of just the sand. And that's obviously going to be sustainable cost reduction. So again, no stone left unturned. We're looking at it, what we can control and then what we can negotiate. We're working on it very hard with our service providers.

Brian Singer - Goldman Sachs Group Inc., Research Division

And, Doug, I mean, you've kind of spoken a little bit to this point, but when you think very big picture, with EXCO is more of a predominantly gas heat producer here. How interested are you in seeing the gas cycle through the higher prices, or when you think about whether it be participating in those JVs or in making acquisitions, the need to meaningfully add oil properties to your mix beyond the Permian position?

Douglas H. Miller

I think -- I get mixed reviews on that. I think when -- we were all excited when we are going private back there. Many of our partners were 100% totally behind us creating a company that accumulated all the gas we could, as fast as we could. And I was -- and everybody was kind of set in that. But I think if you gone around a public company, you've got to do the best for everybody, and that may include looking at oil plays where we can take some of our expertise and be drilling and completing those wells, too. So if we're going to stay public, which is not my desire, then we have to look at oil also. The ideal company is a company that's 50% oil, 50% gas. I think Devin [ph] is in perfect shape on that. So the one thing I really missed this cycle is I have never seen the gas to oil ratio get out to 40:1 or 50:1. And I just was shocked about that, and it killed us. And so I think that once we start exporting gas around the world, here we are producing at $2.50 and we've got countries paying for $10 to $20 an Mcf, once -- the one thing I missed was oil, the worldwide commodity, and gas is still captured in North America. And the power guys better get all they can because once this starts getting shipped, there's some people overseas who are going to pay a lot more than they're willing to pay.

Brian Singer - Goldman Sachs Group Inc., Research Division

And so if your preference is for not necessarily be a public company, but if you are a public company, then potentially, a greater -- a more material percentage of oil, say 50:50 as you mentioned, is required, where are you in the scale of I'm going to wait for what I want versus I can't -- we can't always have what I want?

Douglas H. Miller

No, no. We're looking. I can't guarantee we're going to be private, so we're out looking at oil plays right now. We have 2 significant ones that are probably pushing 10,000 barrels a day that we expect to be bidding on in the next 2 or 3 weeks.

Operator

Your next question comes from the line of Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just a couple of quick questions. In the Haynesville, as we look into '13, is there any continuous drilling clauses or take [indiscernible] from the gathering side that we need to be considering in terms of activity levels needed?

Douglas H. Miller

No. Well, the only thing we do have is we have some firm transportation on other pipelines. But we're producing enough. That's not a problem. But I mean all of our stuff in -- especially in the Holly area is all HBP. We have stuff outside, that we know we're going to have in proved reserves that is all HBP because of our Cotton Valley effort. And then down in Shelby, I'd say we're 90% HBP.

Unknown Executive

And we have one area where we have to spud a well, I think, every 180 days.

Unknown Executive

Two wells a year is the answer.

Unknown Executive

Yes, that's it.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

And then productions declining quarterly as you go along in the Haynesville. So if you get to 4 to 6 rigs at the end of the year, or I think you mentioned 4 rigs, what kind of decline rate should we think about heading into '13 over '12?

Douglas H. Miller

Flat to up, maybe as high as 10% depending on the activity in '13.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

From Q4 exit levels?

Douglas H. Miller

Yes.

Operator

Your next question comes from the line of Gil Yang with Bank of America.

Gil Yang - BofA Merrill Lynch, Research Division

Paul, you mentioned that DD&A are up [ph] high and you said a couple of things. I wasn't sure, was it high because of the curtailments and so your fixed costs jacked up your per unit [indiscernible] or was it because of the workover costs.

Paul B. Rudnicki

No, it's maintenance expenses. I mean, it's -- if we're going to have $200 million, $300 million a day curtailed in the field, Hal and Mike can kind of talk to this, but one of the things we did is we identified the wells that we're going to have to shut down and curtail for some period of time to do some maintenance on and identify those wells. So while we have wells down, let's go ahead and do some work on them. So instead of -- it's just kind of accelerating field maintenance.

Harold L. Hickey

We had some wells that were partially scaled up, and we clean those wells out. We removed some packers, so we could do some scale and have the chemical squeezes and some things like that.

Paul B. Rudnicki

One of the reasons we always have some level of shut in in the field is when you start getting to this kind of massive wells, you're maintaining the wells. So again, if you're going to have to curtail some production, why not do some work on the wells while you've got them curtailed? So accelerating the schedule.

Gil Yang - BofA Merrill Lynch, Research Division

So it wasn't less efficient fixed cost absorption. It was just actually bringing in accelerating cost from future periods you would have to do anyway.

Harold L. Hickey

Primarily additional work we did.

Paul B. Rudnicki

Kind of same thing with tubing. We tube up wells after a period of time, after they've been brought on. So again, while you're -- if you're going to have to curtail volumes because of that incident and the ability to treat, so you identify the ones that you can knock out 2 birds with one stone.

Gil Yang - BofA Merrill Lynch, Research Division

With respect to 2013, if you ramp up sort of exit rate, let's say, 10%, it sounds like overall volumes for 2013 might be sort of flattish with 2012, with the 13-rig program? Is that what you're saying?

Paul B. Rudnicki

Yes, could be. Let's get to '13 and see what happens. But I mean tell me what gas prices are.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. But when you talk about ramping to 13 rigs, how many -- what gas prices are you thinking of?

Paul B. Rudnicki

I think -- I mean, our $4 -- our budget for 2012 assumes $4 gas. So if we get to $4 gas, you could assume us getting back to what we plan to do this year. $5 dollar gas, 20 rigs. I mean , that's kind of back of the envelope numbers.

Gil Yang - BofA Merrill Lynch, Research Division

I'm sorry, your budget for 2012 assumes $4 or is it 2013?

Paul B. Rudnicki

No, our original budget...

Douglas H. Miller

Our first -- 2 budgets ago.

Paul B. Rudnicki

The first budget we put out, the $710 million assumed $4 gas, and that was a 13-rig program in the Haynesville. We're, kind of, looking at $2.53 gas for a 24-month period of time, and this is what we think the appropriate level is. But if gas gets back up, we could be marching back up to 13 rigs.

Gil Yang - BofA Merrill Lynch, Research Division

And given that you're getting a lot of very positive earnings and revenue from their hedges and the relatively small amount of gas you have hedged next year, you have, sort of, a hole you're going to have to address from a cash flow perspective? What are you contemplating in terms of how you fill that hole or how you adjust spending to meet that?

Douglas H. Miller

We're going to stay within our cash flow, a, and b, look everyday at the possibility of hedging. We're within about -- we're close and there are some ideas that we're working on.

Paul B. Rudnicki

I mean, keep in mind, when you look at 2013 with just staying at 4 to 6 rigs in the Haynesville, the completion level in there is going to be a much higher completion level than 4 to 6 rigs would imply, but again, you spend a lot of that capital in 2012. So what I'm getting at is 2013 capital is going to be reduced from this level just with the plan we've laid out so...

Douglas H. Miller

We've got flexibility, and we look at if gas were to go above $4, would we do some hedging? Probably. And if that happens, we buy and reserve rigs.

Operator

Your next question comes from the line of Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Just following up on the Permian here. Are the horizontal wells that you could potentially drill in the back half, is that included in your current CapEx guidance?

Douglas H. Miller

No. Maybe one. I think we have one in there and the second half out.

Harold L. Hickey

Yes. But there's no assurance we'll do it, but it would be [indiscernible].

Douglas H. Miller

We have options. There's been some activity around us, and we're monitoring that, and there's been some pretty good results in the neighborhood. And so if we can get our confidence level up, we might drill one. We don't have to.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And also you guys mentioned -- did I hear correctly in your remarks, that you currently have 2 rigs operating in the Permian?

Douglas H. Miller

That's correct.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

What is the second one related to? Was it a farm out, you said? And is that going to drop off?

Harold L. Hickey

Yes. The farm out is the one-well drill, and then we'll assess it and decide what we do from there.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

So you could add a second rig this year, potentially?

Douglas H. Miller

Oh, yes. I'd say we're leaning towards it.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

And the 70% to 80% IRRs you're talking about, is that pretax?

Douglas H. Miller

Yes.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

How does that compare right now to, say, the prices? You'd said as well that in the Marcellus, you had a largely -- your position's largely HBP, correct?

Douglas H. Miller

Yes.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

So why not shift more capital dollars if you're getting $10 an M in cash margin here?

Douglas H. Miller

The 2 shales are something that we're also working to try to figure out, especially we do have some HBP obligations up in Lycoming, but the rates of return are acceptable. And I think what we're doing is we're looking -- we're trying to get all of the detail out in the Permian that we can get. And if we found that we could spend $100 million there, would we take it away from one of the 2 other areas? The answer is yes. I think we're spending $40 million or $50 million there right this year.

Paul B. Rudnicki

I mean the other thing to keep in mind is what we're quoting on those rate of returns are those -- the vertical Canyon Sand wells. I mean it's order of magnitude just -- it's not a $5 million well.

Douglas H. Miller

These are not big wells. They just make a lot of money, the rate of returns aside. The thing about it is we couldn't put 10 rigs out there. We'd be out of locations in a month.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

No, no, I totally understand. I mean it's not a massive position.

Paul B. Rudnicki

Right. Well, depending on what happens with the testing we're doing this year, things could change.

Douglas H. Miller

The people have brought up the right questions. The Wolfcamp is potential, decline is potential. We're looking at them.

Operator

Your next question comes from the line of Agura Avavar [ph] with Nomura.

Unknown Analyst

Most of the questions have been answered. I just wanted to reconcile 2 things. With regards to the extension and discoveries in your release, you guys added 201 Bcfe. But I was just trying to reconcile it to the other disclosure you had, where you said you added 379 Bcfe to your proved reserves?

Paul B. Rudnicki

I'll take that one, it's Paul. The proved developed is -- also includes moving PUDs that were booked in prior years as we drilled them into the producing category. So we added new proved developed from wells that were not booked. We moved PUDs into proved developed that were booked before, and some component of that falls into the 200 Bcf. So the difference is really just...

Douglas H. Miller

[indiscernible] already proved that we moved into proved developed.

Paul B. Rudnicki

In our 10-K that we'll file I think on Monday, we put out our proved undeveloped walk-forward and I think it will make a little more sense when you see that. But when you book proved reserves, you're sometimes booking PUDs and sometimes booking new proved developed. So the 310 Bcf, we think it's the most relevant one because at the end of the day, that's the one that's actually creating cash flow, right? That's what it cost me to put a well online and produce.

Operator

Your next question comes from the line of Raymond Pirello [ph] with Pendulum [ph].

Unknown Analyst

Real quick, on the stock repurchase program, is there any updates there?

Douglas H. Miller

No. Well, first of all, we're restricted and I would say we have a board meeting next week and that will be a discussion point. But I would say as of right now, I would tend to not although it becomes a spirited debate. It's awfully cheap. And so I'm sure we have several board members that will want to buy. And it depends on the deals that we have. We'll kind of go over the array of deals that we're looking at. I sure wouldn't want to spend $200 million on stock even if it's half price if we could make a $1 billion acquisition out in the Permian.

Unknown Analyst

Okay. In terms of -- I know you said a couple of times that you would love to see this as a private company. We know the price of natural gas has come down a bunch. What do you think, based on your guys last offer of $18.50 would be a good starting point? What do you think the value is today, in your guys view, of the company?

Douglas H. Miller

Here's my only problem. I have a number, but I can't tell you. The lawyers have been choking on me. I mean, I've got an idea what it's worth, and I think it's worth more than it's trading at. Can I say that?

Unknown Executive

Less than last year.

Douglas H. Miller

But it is -- you're right about one thing, it is down in value from a year ago.

Operator

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

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

Doug, just in terms of the M&A discussion, so strategically what are you looking to do for EXCO?

Douglas H. Miller

Tell me if we're public or private.

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

Let's first assume public.

Douglas H. Miller

Then we'll be looking at diversifying into oil, which is exactly what we're doing right now. I'd say the M&A group that we have here is looking at probably 10 deals, 2 of which will probably bidden on in the next week or 2. They are oily. And so if we're going to stay public, the goal would be to get to a 50:50 mix. We're a long way from a 50:50 mix being at 5% today. So I'd like to make some progress this year to get it up to 10%, 20%.

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

So as a public company, would you be pursuing additional gas assets?

Douglas H. Miller

Yes, I think so. I think I'd probably turn around the oil markets if we start buying oil. But I think right now, with the joint venture partners that have approached us, we'd be a fool not to continue to buy gas at these prices.

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

So it sounds that right now, you're not very close to doing something, especially on the gas side. And you're going to bid on a couple oil-weighted assets over the next few weeks, is that correct?

Douglas H. Miller

That's true.

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

And then in terms of...

Douglas H. Miller

But we're looking at all of them. I'd say -- I can't think if we don't have -- We do not a bid ready to go on the gas asset.

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

Okay. And then in terms of taking the company private, you're making references to that here. So do you expect that between now and year end you might try another -- take private transactions?

Douglas H. Miller

No. I just wish we'd gotten private. I would love to be private, so I wouldn't have to do all this stuff. I'm not very good at it. But we have no intention or nothing's on the table to go private. Now, I have been approached by some big private equity guys saying, "Would you consider going private?" And I'm still limping from the last one.

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

And then in terms of the balance sheet, so with any kind of M&A you're thinking about, does it not concern you -- I mean is the balance sheet at a comfortable level now? Do you feel comfortable taking the debt up higher? Or do you actually think the balance sheet needs to get a little bit stronger?

Douglas H. Miller

Well, I think we have a lot of opportunities to create additional liquidity, pipeline being a main one. Do we sell 1/3, do we sell 1/2, do we sell at all? All that is unrestricted cash if we do a joint venture on the conventional, whether we get $500 million or $1 billion, how it would all go down. I see a pathway if we really wanted to pay all our debt off in the next 3 to 6 months. So we have a lot of opportunities, and we're working on all of them to create enough liquidity to do what we're talking about.

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

And then lastly, Paul, what was the exit rate you gave for year-end '12?

Paul B. Rudnicki

Our guidance shows 445 million to 465 million a day.

Operator

Your next question comes from the line of Mark Ferris with Yankee Cents Financial.

Mark Ferris

I have a couple of questions. Is the steep reduction in the natural gas price accelerating, speaking of Boone Pickens, conversions to -- on the truck engine industry and maybe -- and power production?

Douglas H. Miller

Yes. Boone's deal, he's been working on it since '08, and it was going slow. But I'd say here in the last 6 months, it's really accelerated because he said the hell with the government. They're not going to help him, and I think he's taking them out himself in clean energy, and they've made some deals. They're putting in gas stations right now. It works for sure. We converted -- we have our own gas stations. We converted 53 of our field trucks, and it pays out without any tax. So it for sure works, and at these prices, it really does work. And the problem is I can't go to St. Louis or Williamsport from here. I can only go out a hundred miles and come back. We need gas stations, and Boone's working on it right now. So it will accelerate. They have -- if you look at Clean Energy, they have a million announcements on guys that are reviewing it, some major fleets out in California. I think waste management's 100% on it. Several of the other companies are signing up. So it for sure works. That's coming, but I think the other part, the power side, we knew they were building gas power plants and shutting down coal, but we've had 3 or 4 of them in here looking for long-term contracts. I don't think any of them have hedged. But they're for sure using it, it's cheaper than coal right now. It's just a math problem. But it's damn sure cleaner, too.

Mark Ferris

I was just going to ask if there's any intel on the NATGAS Act, but I think you answered that question.

Douglas H. Miller

Yes. I think Boone has always had intel on it, but he's been working on it since '08.

Operator

Your next question comes from the line of Jack Aydin with KeyBanc.

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

Most of the questions were answered. I've got 2 or 3. Doug, what is your tolerance level in terms of leverage, assuming you stay public and assuming you're going to do, like, 15% to 20% oil-based company? What is your leverage tolerance in terms of your balance sheet?

Douglas H. Miller

Historically, when you get 2:1, I start getting a little bit nervous. 2:1 not on EBITDA multiple on an asset value. I consider -- we look at our total proved. But I think you've got to look at all things. We're comfortable here, but we're starting to approach what I consider the high side. So we're going to be looking at some deleveraging right now before we do any acquisition. But keep in mind, if we did an acquisition that had a bunch of PDP with it, which is the only thing we're looking for, we put a hedge in and include that in our debt schedule. If you're getting around how are we going to raise any equity, Jack, the answer is...

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

No, I'm not getting around that. I just want to get an idea what kind of a JV-type structure you might have in order not to leverage your balance sheet.

Douglas H. Miller

Yes. I'd say if we -- the right -- some of the deals we're looking at is where we put up 10% until they get a certain rate of return and then we go up to 25%.

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

Now the other question I have for you is this. Since your partners and, let us see, major shareholders are interested in natural gas and they're trying to buy natural gas, you've got a reserve base of 8 to 9 TCF in Europe, what is a better asset than your assets? So are there negotiations over there that they might -- you might be willing to give them some of your assets for certain kind of money?

Douglas H. Miller

We haven't done that. We're not willing to -- right now, I think the company, as it's constructed, is pretty solid. But I don't think we're going to be selling any of our gas assets to one of our shareholders just because they want them. That hadn't been discussed, and that would be a challenge. I think the lawyers would have a field day with that one.

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

And the other question. You do have a lot of acreage in Appalachia held by production on conventional basis. Are you guys doing anything to see what is at the lower level? And that's also the question to you had some acreage in the 3 counties. If anything, are you doing anything over there?

Douglas H. Miller

Yes, I'd say in 3 counties, we've had some recent pretty good success in our program. It's all HBP, so we're probably going to sit on it. We have some acreage down in West Virginia that all of a sudden some other operators are approaching us, and now there's a pipeline being built. We're watching what they're doing. We don't have to be in a hurry because it's all HBP. So we're monitoring what's going on around us, and our guys out there are doing a good job. We don't have to be in a hurry at $2 gas.

Operator

Your next question comes from the line of Howard Flinker with Flinker & Company.

Howard Flinker - Flinker & Company

If you're going to spend your EBITDA on CapEx, how do you pay interest?

Paul B. Rudnicki

We have $100 million cash reduction in our restricted cash balance. Howard, it's Paul. So we have $155 million of cash at year end in restricted cash. We've got over, I think, we're about $35 million or so of cash. And that essentially reflects a quarter's worth of activity with 22 rigs running as we go down in our rig count. We'll be at the $50 million restricted cash balance. So there's the $100 million.

Douglas H. Miller

Howie, I consider interest a part of capital, so we're going to figure out how to drill and live within our budget.

Paul B. Rudnicki

And part of our capital budget, Howie, is $25 million capitalized interest, the way we have to account for it. So part of it is already being paid for in the capital budget.

Howard Flinker - Flinker & Company

Second, as to arithmetic, different people have different definitions of 20% return. How do you -- what's your arithmetic on 20% return if you had $3 or $4 gas?

Paul B. Rudnicki

It's a pretax rate of return running the $8.5 million well cost using our tight curve, running flat-out gas prices at low levels.

Douglas H. Miller

What our net gas price is and when it comes out. We're using pretax because we have another asset in here that we consider very valuable. That's a $1.5 billion NOL.

Howard Flinker - Flinker & Company

And pretax pre-interest and pre-D&A, is that the way you do it?

Paul B. Rudnicki

The D&A -- the DD&A, as you consider it, is really included in your well cost on the front end. So you've accounted for it with the capital investment on the front end.

Howard Flinker - Flinker & Company

And your calculation of profits, you don't subtract D&A to get to the 20%?

Paul B. Rudnicki

No, because you're taking it all out on the front end.

Howard Flinker - Flinker & Company

Finally, if you're looking at oil and the seller of oil knows it's selling for $108 a barrel today or in the North Sea around $123, why is he going to give you such a bargain below the $108 or $123 adjusted?

Douglas H. Miller

They're not. That's what's -- they're absolutely not.

Howard Flinker - Flinker & Company

So you're just looking where the prices are...

Douglas H. Miller

We're looking but the thing about it is I think the premium you pay, you're paying the market for the PDP, whatever it is, it is, the current strip. There's different discount rates and different risking on that. The question is how much do you pay for the acreage and the opportunity to continue, and that's where our challenge is.

Howard Flinker - Flinker & Company

It's a large challenge.

Douglas H. Miller

It's a large challenge, no question.

Howard Flinker - Flinker & Company

The price is no secret today.

Douglas H. Miller

Exactly. It's a challenge, and we have to have a high confidence level. And in some cases, we're talking to people that only have 2 rigs running. And if you accelerate it, you might be able to make more money, and we can move capital from the Haynesville out there if we could find the right deal. Obviously, we haven't found the right deal yet or we would have done it.

Howard Flinker - Flinker & Company

I was just wondering because the price of gas could be $5 and the price of oil $50 and then where would you be?

Douglas H. Miller

Down the s******.

Operator

Your next question comes from the line of David Neuhauser with Livermore Partners.

David Neuhauser

I'm kind of disappointed actually because I think the last caller, it sounded like you guys actually don't have a crystal ball.

Douglas H. Miller

Right. Well, put this way, I think if we went around the room and included you and said what gas was going to be a year from now, we'd have 10 different answers. In oil, I guarantee I can get oil down. All I've got to do is go buy some.

David Neuhauser

I guess that's mainly question. I mean a lot of people were touching on the same thing, which was if you're looking to get more oily at this point and you're looking to do an M&A transaction, what basins are you focused on besides the Permian? And again, what is the pricing on those assets at this point in time? I mean like I say we're in $108 oil, and there's a lot of premiums going around now for PDP. So are you looking more at it opportunistically where maybe there's a land order [ph] that essentially doesn't have as many rigs or they're under duress? Or kind of what's your strategy there?

Douglas H. Miller

The answer is yes. After we decided not to go private, we had 35 people here do a study on all 30, what we considered, shale or unconventional plays, including up in Canada because we knew we would be looking at a lot of them. We're looking at deals in the Bakken. We're looking at deals in the Mississippi line. We're looking at deals in the Eagle Ford, West Texas, we're looking at, and it makes the most sense to us as of today. But we're looking at 4, 5 deals in the Utica, too. Because we're a driver and wedge away from the Utica. So the answer is we're looking at all of them. All of them have different math problems, and we want to know what we're doing because I think we're more likely to see downticks in oil than we are to see major downticks in gas.

David Neuhauser

And then also, you touched on -- obviously most of the assets here are gas, and you were looking at specific assets in acreage. But again, if you located a potential target, an actual company whether it be public or private, that, of course, had a mixed that weren't all oil or NGLs but they did have a mix but they were in -- their profile was such or maybe they were in distress where maybe a full out acquisition would make sense, is that something that's on the table or is that essentially what you're now focused on?

Douglas H. Miller

I wouldn't call it on the table, but we evaluate 9 to 10 public companies every quarter because they have assets that fit with ours. We are continually doing that. We don't own any of the stock. If the opportunity came up where they were trading at a big enough discount, whether they were in distress or not, we would have no problem talking to them. I mean, we're looking at public and private.

David Neuhauser

And then also, just touch on again with -- everyone's talking about leverage and you're talking about acquisition, and you're also talking about reducing the capital program and make sure it's in line with your EBITDA. If you find an opportunity, you bid on an opportunity, you close an opportunity in the next few months, does that essentially mean you're going to drive home further crystallization of the BG joint venture and bring cash forward to help pay for this acquisition and to continue to pay down debt and fund CapEx? Or, like I said, are you willing to take on further leverage if there was a strong asset that you could see sort of pay for in the next -- in the short run?

Douglas H. Miller

We're interested in doing deals. We are -- part of our plan is to reduce the existing debt and create cash so we can do deals. We don't have any deals that we're doing. And if we could create enough, I would love to have $500 million to $1 billion of cash available to do deals. That's going to take a transaction in the pipeline, and it may take a transaction on some of our conventional, and so we're working on those. We're not going to issue any more equity. And if we went up in debt, it would be because we had additional PDP hedged assets. And the banks would be very willing to do that if we have the right assets.

Harold L. Hickey

And capital would more likely be a shift, not necessarily an increase [indiscernible]

Douglas H. Miller

Yes, I mean, we're not going to -- we don't want to be overlevered. We've done -- I'm looking around the room, we have about 500 years of experience, and almost everybody here was around during the '80s except Paul, and cash is king.

David Neuhauser

You answered my question. My point was that you're going to sell assets if you find the right opportunity, or you'll look to maybe lever up a little bit, but that's only because you're going to bring some PDPs online with the acquisition.

Douglas H. Miller

There you go. If I did -- If I answered, that was good.

Operator

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

Alex Heidbreder

Some questions on TGGT. First, what is the -- I'm sorry if I missed some of this earlier. What is the current debt level at TGGT?

Douglas H. Miller

$450 million.

Harold L. Hickey

Yes, roughly.

Alex Heidbreder

And what is the 2012 CapEx budget?

Harold L. Hickey

$75 million -- it's about $75 million to $80 million.

Paul B. Rudnicki

In the end, they did about $120 million of EBITDA. Keep in mind that 2011...

Douglas H. Miller

They have positive cash flow in there, so that will be going down.

Paul B. Rudnicki

Our guidance of their EBITDA is about $135 million this year. They have $465 million of debt at year end, $30 million of cash and a $70 million, $80 million capital budget.

Alex Heidbreder

The $75 million is 100% basis?

Paul B. Rudnicki

Yes, all those numbers are 100%.

Alex Heidbreder

And then why -- on your Slide 13, why is Q4 EBITDA going down from -- why is Q2 peaking? Is that just -- is that reflecting your own volumes or is there something else going on?

Douglas H. Miller

Yes, keep in mind out of the 1.5 bcf a day that's going through there, 75%, 80% of that is us and BG. So as our capital program comes down, it affects throughput.

Alex Heidbreder

Okay. You're saying there's like a couple of hundred or 300 to 400 of third-party volume. What is the potential for third-party volume?

Douglas H. Miller

We're working on it. Ever since we did the joint venture with BG, we bought twice going out as we started in '09. Our operating guys, we overbuilt our pipes with the idea that we were going to go after the third parties. And then Chambers and his guys are coming in with 20 million a day wells, so we brought them back. Then when we went down to the Sabine trough, we again overbuilt our pipes and all of a sudden we started making 25 to 30 million so we brought them back. But we have just recently hired some people and gone out and just signed up our first 2. I think we have a deal with Encana and one with El Paso. Now that we're shutting the rigs down, I know you can't go out and make too much production, so we do have some available space, so we're out doing that right now.

Unknown Executive

And there are some opportunities, but most everybody that has been drilling in there is -- has already got a pipeline connection.

Alex Heidbreder

What would the max capacity on your pipes be?

Douglas H. Miller

2.5 to 3 Bcf a day.

Douglas H. Miller

Easily.

Alex Heidbreder

So you guys are running roughly 50% now or somewhere in that range?

Douglas H. Miller

Yes. We're running pretty full in a lot of areas. They keep telling me it's 2.5 to 3 Bcf a day, but that means we've got gas going 2 ways.

Alex Heidbreder

Understood. Well, I guess the last part is you guys are laying off rigs. Pretty much everyone else is off of laying off rigs. When is Haynesville overall supposed to peak in production and start falling? Is it -- this year, isn't it?

Douglas H. Miller

I think it's already peaked. It's already peaked. Stay tuned. I don't know what it was, whether it was 5 or 7, depending on which analyst you talk to, but I guarantee it's coming down today versus yesterday. Chesapeake's moved out. Encana's moving out. Everybody is slowing down. It's already peaked.

Alex Heidbreder

But that implies for TGGT going forward that until gas gets back up above $4, EBITDA's going down not up?

Douglas H. Miller

Probably right. But the thing about it is, our production, we think, will be flat '13 over '12. And I think we're going have some opportunities with some of these third parties. We're already signing them up. We've only been out there a month.

Unknown Executive

No question.

Douglas H. Miller

I mean, there's a lot of third parties. Keep in mind, the original system we had was Cotton Valley system and there are guys drilling some Cotton Valley wells because of liquids. I mean there's opportunities out there. I can't expect the cash flow there to be flat next year and start up.

Alex Heidbreder

That's what I'm trying to understand. I mean if everyone is shipping gas a day on their completed wells, they have to have something they're shipping it on?

Douglas H. Miller

Exactly.

Alex Heidbreder

If production is actually starting to go down, that's going to free up net capacity not create more demand.

Douglas H. Miller

Except there's 6 million acres in this play. We cover about, what, 100,000 of it. So the play is going down, there's no question, but there are opportunities. We have BP on our line. They're going to be drilling some Cotton Valley wells.

Harold L. Hickey

The other thing that advantages us on TGGT is the number of outlets that we have from our system. And you have some people that are flowing now only to one outlet where they're getting a disadvantaged price. We're going to present some advantages in that regard as well.

Douglas H. Miller

Yes, we've got 7 interstate pipes. So we'll be out talking to everybody, and there's a lot of opportunities there.

Stephen F. Smith

We're an alternative to a lot of different operators.

Paul B. Rudnicki

The other thing to think about is when you're looking at big picture, 7 Bcf a day going down, that doesn't mean that there aren't wells still being turned on and hooked up within that number. So you're zeroing in on a very small area of the Haynesville, and you're looking at activity around you and seeing -- a couple of wells mean a lot, basically, in this environment.

Alex Heidbreder

And your buildout is in the core, so presuming that's what survives and drives the longest.

Paul B. Rudnicki

Exactly.

Douglas H. Miller

Yes.

Operator

Your next question comes from the line Geoff Hulme with Porter.

Geoffrey Hulme - Porter Orlin, LLC

Two questions, one related to several of the previous questions. I mean, maybe at a really high level, could you just try to bridge the perception gap of how you see opportunity in doing selective M&A on the chassis of the EXCO entity as we see it today? And just maybe to address everybody's kind of surprise about the opportunity and EXCO as a vehicle to take advantage of it?

Douglas H. Miller

I don't understand the question. I mean, for the last 25 years, whether we're [indiscernible] or EXCO, we have been mostly M&A. And the only time we've really been more than 10% to 20% is since the shales showed up, we just accidentally -- we've always been an M&A. We look at 500 deals a year, as you know, and we typically do 5 of them.

Paul B. Rudnicki

Geoffrey, are you asking about the financing side of it?

Geoffrey Hulme - Porter Orlin, LLC

No, just how you see the opportunity. I think maybe that's the answer. I mean, the history and maybe not everybody is familiar with that, and just how you see, kind of -- I think people are struggling getting from point A to point Z.

Douglas H. Miller

People are struggling or you're struggling?

Geoffrey Hulme - Porter Orlin, LLC

No, I'm not struggling. I'm struggling with other things.

Douglas H. Miller

Okay, okay. I feel like we're on a stage, and I'm talking to an audience here.

Stephen F. Smith

When you have prices this low, Geoff, this is the time to be looking to buy. It's just a matter of opportunity. If you can buy some assets, whether gas or even oil, there's a lot of people out there that have oil properties that don't necessarily think this prices at this level are sustainable. So you've got to look at it from the seller's side as well as the buyer's side. And so this is just a really good time to be out looking.

Douglas H. Miller

There's a chain, and we're, kind of, in the middle of the chain. There's a lot of guys that accidentally had a ranch out in West Texas that 20 years ago had a Sprayberry well. And now all of a sudden they're finding deeper stuff and they don't want to spend $200 million drilling wells for the next 10 years, and so some idiot like us might have that interest. And the same thing on the sales side. There's -- larger producers sell assets that don't hit their radar, and they may hit ours. This has been going on for a long time.

Geoffrey Hulme - Porter Orlin, LLC

Okay, great. And just related to that also in a different arrangement, what does EXCO -- you've talked about these large pools of capital and maybe they're interested in conventional or other things and maybe they've approached you. I'm just curious if you could just tell us what EXCO brings to the table to the money side and why that's -- what you had that's attractive to them?

Douglas H. Miller

Well, I don't know. I answer the phone is one of the things. We have a history of doing a lot of deals. We have a history of doing some pretty good deals and good-sized deals. We have a history of doing conventionals, and we have a history of being able to operate. And a lot of guys, other than that, there's no reason for them to call.

Operator

Your last question is a follow-up from Alex Heidbreder with Millennium.

Alex Heidbreder

On the CapEx budget and on well completions in the Haynesville, you guys have $272 million for drilling and completion, and I think your press release shows 19.9 net wells drilled, 26.3 net wells completed, is that right? And so -- I'm trying to -- how did -- that shows 13.7 per drilled well, 10.3 per completed well. How does that math match up with the $9.5 million going to $8.9 million?

Douglas H. Miller

I'm sorry, what -- you stated a lot of numbers. Are you talking about fourth quarter spending?

Alex Heidbreder

This is 2012 outlook. You guys talked about setting $272 million on drilling and completion.

Douglas H. Miller

That's right.

Alex Heidbreder

And $285 million or $296 million total on the Haynesville/Bossier?

Douglas H. Miller

Yes, that's right.

Alex Heidbreder

And then on Page 7 of the press release, you guys talked about completing -- or drilling 19.9 net wells and completing 26.3 net wells?

Paul B. Rudnicki

Right. It's really a timing of -- I mean, you're drilling all those wells, you've got the capital coming in from last year to complete the wells that you're bringing in. A lot of it is just capital accrual timing versus the exact activity.

Alex Heidbreder

Even if we give you -- put the entire completed [indiscernible].

Paul B. Rudnicki

Let's take this offline. Would you mind if we just take this offline where I can actually get some details in front of me and walk you through it?

Operator

At this time, there are no further questions in the queue. I turn the call back over to the presenters for any closing remarks.

Douglas H. Miller

Okay, thanks. Again, this is Doug Miller, and that was a very interesting Q&A, and we're glad everybody had the questions. It has been a challenging year, as most of you know, and I hope we answered everybody's questions. If not, feel free to call us. We have plans for the rest of this year, and we have plans going into '13 and '14. And we have a great asset base, and we plan to exploit it. With that, meeting adjourned. Thank you.

Operator

Thank you for joining the EXCO earnings release conference call. You may now disconnect.

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