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EXCO Resources (NYSE:XCO)

Q3 2012 Earnings Call

October 30, 2012 9:00 am ET

Executives

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

J. Douglas Ramsey - Treasurer and Vice President of Finance

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

Michael R. Chambers - Vice President of Operations, General Manager of East Texas/North Louisiana Division and Vice President of East Texas/North Louisiana Division

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

Mark E. Wilson - Chief Accounting Officer, Vice President and Controller

Marcia Reeves Simpson - Vice President of Engineering

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

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

Jeffrey W. Robertson - Barclays Capital, Research Division

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

David Neuhauser

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

Operator

Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Resources Incorporated Third Quarter Earnings Release Call. [Operator Instructions] I would now like to turn this call over to Mr. Doug Miller, Chairman. Please go ahead, sir.

Douglas H. Miller

Thank you very much. I have with me today Mike Chambers; Harold Jameson; Lanny, our illustrious lawyer, to keep me to keep me straight; Steve Smith; Doug Ramsey; Mark Wilson; Marcia Simpson and Tyler [ph]. So we'll stick with you as long as we can. We really did debate on having this call today because of what's going on in New York. It turned out worse than we thought, but we have so many things on the agenda we thought it was appropriate. We basically do talk to about 75% of our shareholders in person and anybody that misses this, feel free to call me or Steve and we'll go over any questions you have. But we thought it was appropriate to go ahead and get it done. We're not sure when the New York Stock Exchange is going to open up, and after last night, I'm still not sure.

A little report from our operations, that thing hit Pennsylvania pretty hard. Our rig is still working this morning. All frac fleets are shut down. All of our flowback wells have been shut and all people are present and accounted for and on the job. So we made it through pretty well. But I would expect a lot of rigs and a lot of frac fleets for a while are going to be slowed down just because moving around -- a lot of water, a lot of wind and a lot of dangerous trees around. So I think it's going to slow down operations up there for a while.

With that, we're going to get kicked off. Steve only gave me one slide this time. He's trying to keep me quiet.

What we have done, over the last little while is, again -- oh, oh, sorry, Ramsey. I was skipping you, too. You better read that.

J. Douglas Ramsey

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

The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and derivative activities or other plans, forecasts and statements that are not historical facts are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Forward-looking statements are based on a variety of assumptions that may change depending on future events, which are difficult to predict. Actual results may differ materially from those in forward-looking statements. We caution you not to place undue, if any, reliance on such statements. Please refer to Pages 18 and 19 of the slide presentation for the complete text regarding our forward-looking statements, as well as the cautionary information set forth in our most recent Form 10-K, Form 10-Q and other SEC filings, which are available on our website at www.excoresources.com.

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

Douglas H. Miller

Okay. Did Lanny make that longer this time? It seems like it. I think what we've had going here the last 6 months, because of gas price, has been a real effort to maintain our capital programs within our cash flow and we brought down our drilling rigs and with that, our people count's gone down. So we'll get into that in a minute. But it's been an initiative that's been well done around here. Some of it's not fun and some of it's not happy. But that's happened and Harold will get into in a minute, cost reductions on some of our wells have been significant. So going from 22 rigs over in the Haynesville to 5 rigs was a challenge. They met it and what's happening over there right now is we've been spending time on cost reductions and maximizing the production out of those wells and they've done a great job.

We also, after weathering the storm of $2 gas, when gas popped up here a little a month ago, in the last few weeks, we did put some hedges in for '13, '14 and '15. Those are on the slides. We've been -- we'll look further. But right now, I think we're within 1 week or 2 of starting some peak demand and I think you're going to see, like we've been kind of predicting, that storage isn't going to get overfull and we're going to start having some cold weather coming in. I'd say we're 1 week or 2 away, although I'm starting -- we're starting to see some. We actually got down to the 30s a couple of times last week so the gas was on.

Again, cost reductions, Steve will get into that. Rig count, way down. We did have our bank meeting with all our banks in. It looks like it's going to be approved. We should know by the end of the week, that $1.3 billion. Most of the initiatives that we're working on, we're looking at a private MLP, a public MLP. We've actually had discussions about a public MLP on the pipeline and we're reviewing that with BG right now. But the probability is that's going to be a sale. Again, we're working with BG on that right now. That initiative should be -- all of these things we're working on and should be -- have some discussions if we sign purchase agreements.

We're looking at a lot of deals. Deal flow is the highest I have seen since the '80s. Many private companies that would like to close by the end of the year for tax, they're a little bit worried about who might become president, as I am. So I think there's a lot of those things and I'd say 15 or 20. We're focusing on the Haynesville. We're focusing -- we're looking at quite few deals then, the Eagle Ford, 2 or 3 that we're very interested in pursuing. 2 or 3 deals in the Haynesville and of course, we're looking at additional deals up in the Marcellus, a lot of activity. We're not looking in the Bakken. We're not looking in the Rockies, and we are looking at a couple deals in the Mississippi lime. I'm just not sure we've got it figured out yet, but we are looking there. But I'd say 15, 20 deals. Some very attractive if we can get them bought, and we do have partners lined up that are very interested in doing deals with us. And so we're in constant contact with them as we look at these things.

We're managing our base decline. With 5 rigs running after having 22 rigs, our Haynesville production is declining. We're doing the best we can on that, and although we are still choking it back -- there's no reason to run those things full out, but I think Marcia would agree that our EURs are probably going to be better if we manage it this way. We have signed a couple of processing deals over in the Cotton Valley that has liquids. One of them is -- Tyler [ph], both of them signed or just one? One signed; one of them in negotiations. One in East Texas; one in North Louisiana. Both of them will give us a fairly significant uplift in our cash flows.

With that, I'm going to turn it over to Steve and let him go through some financials.

Stephen F. Smith

All right. Let's take a look on Slide 5, the corporate highlights. Schedule, we're -- we had a quarter in which we exceeded our guidance by a little bit, and I think our midpoint was around 510 Mmcfe/d. We came in at 512 Mmcfe/d. Obviously, we're down some both from last year as well as from the second quarter. But we're down 6%. Luckily and fortunately, the gas price did go up in the third quarter and up to an average -- well, we have an average overall commodity price of $3.01 compared to $2.36 last quarter and $4.14 a year ago, so we're making headway there.

Our revenues were better than we expected and better than second quarter because of the price increases, offset, of course, by a small decline in production. Operating costs were, again, a high point for us. We got them further reduced between the first and -- I mean, the second and the third quarter and we're quite a bit less, 17% or so less, than we were a year ago. So that's a strong point at this juncture. On adjusted EBITDA, we exceeded our expectations there and that also was primarily a result of the increased average price for the quarter.

So overall, operating costs at $0.37 are down from last year -- I mean, from last quarter and from last year. Cash G&A is down 22% year-to-date and so overall, it was -- we did have, as we predicted, another noncash ceiling test write-down in the third quarter of $318 million. That's based on an average gas price -- or a 12 -- trailing-12 gas price of $2.83. So we're expecting we'll have probably some sort of write-down in the fourth quarter but hopefully, we're starting to gain on the price a little bit.

On page 6 is a schedule that shows where we are from an operating rigs standpoint and a cost standpoint. And Michael will get into this a little more, but we're down to 7 rigs overall, which is down 70% between years -- I mean, since the end of the year, with 5 in the Haynesville, 1 in the Marcellus and 1 in the Permian. On the bright side, our well costs are expected to reach $8 million pretty easily by the end of the year. In fact, I would say they're at $8 million now. And just to give you an example of how important that is, at the current strip, an $8-million well cost will be about a 32% rate of return. At a $3.30 flat gas price is about what it takes to get a 20% rate of return. So that gives you some feel. So it's an important fact that we have reduced those well costs as dramatically as we have.

Over on Page 7, Slide 7 there. It just shows you what we've done in terms of cost cutting on LOE, gathering and G&A, and all of those -- all of that progress has shown 27% reduction in LOE since the end of the year and 18% overall in all of those costs. So we're pleased with the progress we have made on our cost cutting efforts and continue to look for ways to be more efficient and further reduce those costs.

Page 8 kind of lays out our liquidity situation at this point. As Doug said, we're closing in on the borrowing base at $1.3 billion. With the cash that we have on the balance sheet, we had liquidity of about $333 million as of the 25th of October. And so we're -- again, we're still looking to monetize some assets and further reduce our debt. But we're in reasonable shape and we are operating within cash flow. So that gives us quite a bit of comfort from that standpoint.

There's a table on the hedging, and you can see it by year. We're about 40% hedged for '13, 30% for '14, and 17% for '15, with adding something like $110 million a day of hedges in -- since September. So in oil, were 54% hedged on oil.

Over on Page 9 is a comparison of the actuals for the third quarter with the guidance, pretty much in line all the way down on the -- to the midpoint. Our differentials to NYMEX were -- on gas, were much better than we thought and that was because we were able to sell more at higher rates on a daily basis during the quarter in a period of rising prices. So that was good.

The LOE we've talked about. In cash G&A, we're a little over guidance there and that was because of some severance that we paid. We did have -- we did reduce our force a little bit during the quarter and that was the impact of the severance.

EBITDA, as I said, because of price increases, primarily exceeded what we thought at the midpoint. And TGGT was much better than we thought, primarily because of reducing cost and also because there were more third-party Haynesville production coming online that had been shut in by some of our customers, so that was a plus.

Over on 10 is the overall quarterly guidance and the year-end guidance. We're -- we've improved at the expected year-end guidance a little bit, primarily because of price. We're using a $3.50 price for the fourth quarter, whereas we used a $3.25 pricing in -- predicted a $3.25 price last quarter. So nothing particularly dramatic there. We have increased, again, our expectation in the fourth quarter on the gas differentials and we're pretty much on what we've been expecting from a CapEx point of view. So all in all, a pretty decent quarter. I'm going to turn it over to Mike Chambers to handle the overview of our operations. Michael?

Michael R. Chambers

Thanks, Steve. I want to start off by saying that we're very proud of the work our staff has done to reduce our capital and operating expenses. We operate a little over 8,600 wells and if you look at our combined off and non-off [ph] gross production, we're just a little under 2 Bcf a day. So we move a lot of gas every day and we do it very safely and economically.

As Doug mentioned, in Pennsylvania, we're dealing with the effects of Hurricane Sandy. We've curtailed some completion and construction operations, as Doug mentioned. We're seeing some minor effect from flooding but overall, it shouldn't affect our production. We shouldn't be changing the budget, Doug, for it.

Okay, turning over to Page 12. On the capital side, you can see we ramped down very quickly from the 28 rigs we had about this time last year to the 7 we have today. In Appalachia, we've ramped down from 4 rigs to 1. We'll still complete about 42 wells, 8 in the central area and about 34 over in the Northeast area. We're focusing on our acreage appraisal in our Central Development Area, and we have currently 1 frac fleet running up there, but we're going to be adding another here shortly to work off some of our completion inventory. This is the best time of year to do it in our higher gas price window.

Similarly in the Haynesville, we dropped from 22 rigs down to our current 5, but we'll still spud about 56 wells this year and turn to sales about 84. And early in the first quarter of 2013, we should've spud our 400th Haynesville well to date. Our development is still centered in our Holly core area, where our best rates on return are. And we've delineated our Shelby acreage and don't have to spud another well there to continue to farm-out until late in 2013. Like Appalachia, we currently have one frac fleet running and we'll be adding a second here in a couple of days to work off our completion inventory here in the higher gas price environment.

On the Cotton Valley side, as Doug mentioned, we're hooking up our last 2 fields to processing liquids in the gas stream. We'll have the Holly field processing in the next couple of weeks and Danville field in the first quarter of '13.

On the Permian side, we've been running from 1 to 2 rigs. Currently, we have 1 rig running out there and we'll drill about 35 Canyon wells and 1 Wolfcamp well. We've continued to have great results in our Canyon production out there with greater than 50% rate of return on the projects we've seen. We've been coring and testing the Cline and Wolfcamp. We've done 3 Cline tests -- or we completed 2. We have 1 more to go. And we've done 3 Wolfcamp recompletions and all are looking very favorable. We've also had great response to our first waterflood in the carbonate mound out there and we're looking at doing several others.

In TGGT, we're wrapping up our major gathering and treating projects, releasing rentals, so we should much higher EBITDAs.

Flipping over on page 13, you'll see that we're spending about half of our 2011 expenditure and -- but we're staying within cash flow. We've devoted it almost entirely to development drilling. Our major capital and infrastructure projects like our road project down at Shelby, our water gathering distribution projects in Holly and up in Lycoming are pretty much in, as well as our seismic acquisition costs are. Also in 2011, we spent a lot of money on maintenance capital on our Cotton Valley and other conventional wells, so we don't have to do that right now.

Flipping over on Page 14, we get a little deeper into the East Texas/North Louisiana Haynesville and Bossier shales. We're still producing over 1 Bcf a day, gross operated production, and 1.5 Bcf a day if you add OBO. And as we mentioned, we're continuing to focus our activity in the Holly area, where Steve mentioned we're still achieving greater than 30% rate of return on our project.

We've been able to do that because we've been lowering our well costs. We've been seeing several sub-$8 million well costs here recently. A lot of that's due to our drilling efficiencies, where we're still knocking off days in the intermediate hole section of the well, but more on the completion side, where we've had -- seen some service cost reductions and we've been changing our frac design. In fact, we've just completed our first unit with a 100% normal white sand. We're very encouraged with those results that we're seeing versus using our historical, intermediate strength process [ph].

But a lot of that probably has to do with our choke management program that's working very well. We're sustaining higher pressures and much longer -- for a much longer time, which should result in additional reserves, and we're also seeing the benefits of lower temperatures where we've been able to eliminate coolers, which is helping our operating costs. And our serve times have translated into a lot less water hauling. In fact, we've done some work on our disposal systems and our trucking costs were about half of what they were earlier in the year.

We're also very happy with our control room, which is continuing to add value. It operates 24/7 here in Dallas. We've been doing a lot of work, scheduling our maintenance so that our downtime is typically less than 5% right now. But more importantly, their quick reactions to pipeline interruptions with our automated chokes have allowed us to quickly bring down our wells and bring them back up without having to send anybody out there to them.

Flipping over on Page 15, we'd take a look at Appalachia. We've scaled back the program to focus on appraisal and to be prepared for higher gas prices. By year end, we have spud almost our 100th horizontal well there in the Marcellus. Our major water gathering disposal, in Lycoming, system is in. We've laid over 28 miles of large gathering and distribution lines up there. We've also seen great results from our 2 recent wells in Armstrong County. In fact, their last 6 wells over there have IP-ed better than 7 million a day.

Our drilling costs have continued to decline through a combination of efficiencies and service sector pressure to we're now less than $6 million per well up there. We've been seasoning our wells or shutting them in for about a month up there and this has shown about a 90% decrease in water production. Where you have $20-per-barrel disposal costs, this is a huge cost advantage for us. And we're also continuing to modify our completion design up there. At one time, we used to pump as much as 750,000 pounds of sand per stage and we've been doing tests currently down around 250,000 pounds, which translates into huge monetary savings.

And finally, looking over on Slide 16 for TGGT. We've had excellent throughput through the system with very little downtime. Our major infrastructure projects are in. And in fact, we're wrapping up one of the last ones in -- over at Holly 3 right now. We'll spend a total capital of about $132 million over there this year, but most of that has been on these major projects so we should see much lower capital expenditures in the next years. These expenses have also allowed us to release a lot of our rental equipment. In fact, we're releasing 4 100-gpm new units in the next couple of weeks. We've had those units since the start of the Haynesville, so that's going to have a huge effect on our operating costs over there.

We're seeing just in this quarter an EBITDA of about $42.5 million and by year end, we're projected to be over $158 million. And obviously, we're still, as Doug mentioned, working on partner valuations to monetize the assets. With that, I'll turn it back you, Doug.

Douglas H. Miller

Thanks, guys. With that, we'll open it up for questions.

Operator

[Operator Instructions] Your first question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

A couple of questions. You've highlighted over the last few quarters the fall in costs in the Haynesville and your goal of $8 million. Can you just talk to how much of that you view as cyclical, as a result of 2-something gas, and how much you think will be secular and sustained in a $4-gas environment? And then I guess, as long as we're talking about a $4-gas environment, what kind of rig count should we expect you to run if these prices hold?

Douglas H. Miller

Well I'm going to answer a little and then Harold is going to answer a lot. I would say a significant amount of the cost is a result of too many frac fleets being built when they were making a lot of money. We are -- as we go out for bid on frac jobs, they have continued down and, I mean, it's unbelievable how many frac fleets are out there and how many people. When these guys put them out for bid, we're bidding 5 or 10 wells at a time and I'd say last time, one of the major ones came in significantly lower. Same thing out in West Texas. We went out for bid on the fracs out there and they came in significantly lower. But that's what I see and I do know there's rigs over there that have yards that don't want to move if they can help it. So drilling -- I mean, rig costs, day rates are down slightly in the East Texas and North Louisiana and fracs but more than that, Harold, you're seeing a lot of other stuff. Why don't you expound on that?

Harold Jameson

Okay. On the frac side, I guess, taking a look at our total cost reduction, the -- really the biggest driver just going from the largest drivers and working our way down the list, the market conditions on fracture stimulation, that's the single largest driver in terms of cost reduction. Just on the frac side alone, we're seeing about a $900,000 cost reduction just on the total frac market conditions and in our design changes. Out of that $900,000, I'd say about $600,000 of that is market adjustment and about $300,000 of that are attributed to design changes that we have made, programming changes and design changes we've specified. Working down the list, procedural changes that we've implemented regarding our tube-up [ph] procedure. We've changed our procedures in terms of tube-ups [ph] and the type tubing metallurgy that we use. That's about a $200,000 savings on an individual well. And then going down the list, our cuttings management, our overall rentals, that's about a $125,000 reduction; rentals in general, about a $100,000 reduction and then just our overall efficiencies. We're still continuing to see improvements on drilling times. We're currently around 37 days, spud to rig release. We've seen some wells lower than that, but on average, we're right at -- the 35 to 37-day range is the window that we're mostly in currently.

Douglas H. Miller

And I can always tell when we have one better because they bring in a chart on Monday morning, when they're down on the 32 range. So -- and they've had several of those lately. So the bottom line is the costs are there because of slow down and probably overbuild of some of the service companies, which happens every time it goes down. To answer your question on $4-gas, we're at $4-gas. We're not going to add any rigs. We think that -- I'd like to see the results of the power demand coming on and a normal winter to see what happens. It wouldn't surprise me with the supply coming down, because rig count has gone down and demand gone up and if we have any winter, we won't be seeing $4-gas. We'll be seeing $4.50 or $5. And if that happens, we still want running rigs. We're going to be very peaceful about this. We're looking for acquisitions. And we think that's an appropriate, if we can pull a couple of those off. So I'd say -- we haven't done it yet but I'd say we're going to forecast 5 rigs for next year regardless of price and concentrate on some of these acquisitions. And you're going to ask, "Are you going to concentrate on gas or oil?" We're looking at both. We've been on several oily ones and prices at $85. People aren't getting what they were hoping for last year's price. And we're bidding them right using an $85 flat price deck. The other thing that is a challenge when we're bidding on these things is liquids prices have crashed, where 6 months ago, 8 months ago, they were 60% of crude oil. We'd see them 30% right now and we think that's going to be a while before it rallies. So we're having a challenge and we've done a real study on when that should get better and it looks like it's about 2 years out. So we're not forecasting any significant increase there and we're bidding that way. Did I answer everything, Brian?

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, that's helpful. From a macro basis, we saw some of the state -- or some of the EIA data for Louisiana in June and July for gas production to be kind of flat to up versus May. Do you think we see the big drop many are expecting in Haynesville production? I mean, your quarter-on-quarter decline looks like we should, but I meant that's one of the things that people are really waiting for.

Douglas H. Miller

Yes. I think we had -- our gas production actually went up during that period because we were ramping from 22 rigs down and we were just bringing them on and it just took that much time to get them put on, and I think a lot of people had the same thing. But I think with Chesapeake, Encana and us and BHP over there, I have a feeling that you're going to see by the end of the year, we're going to see significant declines in the Haynesville.

Michael R. Chambers

We've seen Chesapeake and Encana and several others curtail production but they have brought that back on, so that's...

Douglas H. Miller

[indiscernible] Yes. So a little of it is stalled because they curtailed and brought it back on. But that's over with. So I think you'll start seeing some fairly significant decline.

Michael R. Chambers

But that's you're seeing in the EIA data, is their curtailment.

Douglas H. Miller

Yes.

Operator

Your next question comes from Leo Mariani with Royal Bank of Canada.

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

I just wanted to see if you had anymore color on sort of expected timing for the TGGT monetization.

Douglas H. Miller

Oh geez, Leo, it was about 6 months ago is when we have the timing. We're working with a partner on this thing and we have 4 offers in and we're working with somebody and we're in discussions with BG. BG still owns half of it. And we're in discussions with BG right now on how to do it. I think, expect an announcement within the next week on which approach we're taking, because I think I finally got an agreement with BG yesterday or we both agreed. So we'll be announcing that here over the next week. The bottom line is I told everybody July 4. I forgot to tell you which year.

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

Okay. Obviously, I think you did a good job kind of addressing how you're thinking about spending on acquisitions versus drilling here. Just wanted to kind of dig into a couple of the areas. You talked about going to a second frac crew in the Marcellus. Wanted to get a sense of what the backlog of wells there was, and I guess to be standstill [ph] and just say down the road, who knows when we get to the kind of right price on gas, would you see Marcellus ramping up first or Haynesville kind of ramping up first, any clarity?

Douglas H. Miller

Well, it depends. We're looking at some acquisitions. I would say better shot at buying some Haynesville deals right now. So $4.50, $5-gas, I bet Mike would like to drill a couple more, but we're not in a hurry on drilling because even at $5 gas, our F&D cost is probably $1.50 to $2 in both spots. And at that market, if you don't escalate too much, you're buying gas cheaper than that. I mean, it's just -- it's kind of a math problem. I would rather buy PDP in hedges than take the risk on drilling or paying for a bunch of acreage. Right now, we have quite a bit of acreage, especially up in the Marcellus. It's all HBP. We can be very peaceful and very managed.

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

Got you, okay. And what is that completion backlog in the Marcellus right now that you guys talked about working down?

Douglas H. Miller

Well not much, but go ahead. I think...

Michael R. Chambers

I'd have to pull the exact number.

Douglas H. Miller

Tyler [ph], do you have that number?

Unknown Executive

25 wells.

Unknown Executive

25 waiting on completion, Slide 15.

Douglas H. Miller

Okay. But I mean that's just the second fleet for the rest of the year.

Michael R. Chambers

We'll have that knocked out by first quarter, yes.

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

Okay, got you. And then I guess you talked about doing some science work in the Permian as well. When would we expect maybe if -- you guys to tackle the horizontal side and drill a couple wells horizontally here?

Douglas H. Miller

I think our West Texas group wants to spud tomorrow. We have done some science work. We're waiting on some cores, aren't we, Marcia, to come back from core labs. I think we want to do that first. It's mostly HBP. We have some opportunities on some acreage. We're watching other people's results, which have been pretty good in our neighborhood. Again, we don't have to be in a hurry on it. But I'd say first half of next year. We were kind of forecasting the fourth quarter this year but I'm going to delay it until next year. We don't have to rush the monkey, as Boone would say.

Operator

Next question comes from Joe Allman from JPMorgan.

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

So in terms of Haynesville wells, the costs are down to $8.2 million from $9.5 million at year-end '11. Are we talking apples-to-apples in terms of same depth, same lateral lengths?

Douglas H. Miller

Yes. That's unfortunate but the answer is yes.

Michael R. Chambers

Those are all DeSoto Parish.

Douglas H. Miller

Yes, that's all DeSoto Parish, which is the shallower of the 2 areas.

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

Got you. And you cite the AFEs, and so I just wanted to confirm that the AFEs match the actual cost when all is said and done.

Douglas H. Miller

Oh, you sound like me, Joe. Why don't you ask Mike how we go about that?

Michael R. Chambers

Oh, definitely, I've got to count it right here. He checks me every month.

Stephen F. Smith

Yes, the actuals are tracking...

Douglas H. Miller

The thing about it is early on we were higher, but what we do as we look at the last 10 wells, the last 30 wells and I would say we're on or below AFE over half the time right now. Mark?

Mark E. Wilson

That's correct.

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

That helpful, okay. And then your gas differentials actually looked better than what you had modeled and your forecast going forward is better. What's going on there?

Douglas H. Miller

We're marketing better. I'm kidding. I think -- we're marketing aggressively by the day instead of just signing up by the month and letting everything happen. So we have a group down there that's doing daily marketing. Somebody needs some extra gas and we can get an extra nickel for it. That's where it's going. We have -- TGGT has 17 different outlets, including Florida Power [ph] and Southern Houston [ph]. So on a daily basis, it varies. And so we're just spending a lot of more time doing a lot more marketing.

Stephen F. Smith

In a price -- rising price environment during the third quarter.

Douglas H. Miller

Yes, that helps too.

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

Very helpful. And then for LOE, you were down in the third quarter but then you're guiding up again in the fourth quarter. So what's the change there?

Douglas H. Miller

That's Steve just trying to look good.

Stephen F. Smith

Well, you know...

Douglas H. Miller

I think we've done about everything we can. We have lifted every rock -- we're still lifting rocks, but I don't know that there's much more -- I don't know what that -- I think that's probably more of a result of the Cotton Valley is going to be a slightly bigger percentage of our total production than it was this quarter, which is higher operating costs from an [indiscernible]. I don't -- we don't expect any changes but the Haynesville is like $0.10 and the Cotton Valley is like $1.50 and it's flat and the Haynesville is coming down. I have a feeling that's what's going on. Anybody have any other comments?

Michael R. Chambers

I think it's a little -- in fact, a little lower volume.

Douglas H. Miller

Yes, a little lower volume.

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

Got you. Okay, that's helpful. And in terms of your acquisition plans and your divestiture plans, so am I correct that one of the ideas behind your sales effort is to reduce debt and improve liquidity?

Douglas H. Miller

Oh, yes. Sure, yes, yes, yes. I mean we've been working on the proper MLP since 1991. And our conventional gas assets, especially the Cotton Valley, fit it like a glove because it's under a 10% decline rate and we've been working with several potential partners on putting into a private MLP. We continue to work on it. It isn't done yet but if we can get that done, that asset -- and that's about $700 million of total assets. If we get that done it will reduce EXCO's revolver significantly and give us a lot of dry powder. But that's not absolutely the driver. It's just the right spot for those assets to be in a low gas environment. There are several of those type of assets out there and I call this kind of a parking lot for conventional gas, if we can get it set up. We're seeing quite a few of those deals out there in the market. A lot of companies, even smaller than us, want to continue drilling shale and they're selling their conventional and we'd like to have a spot for it.

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

Okay. So Doug, so what do you -- so what is $700 million?

Douglas H. Miller

That's kind of the value of our conventional assets that we are thinking about putting in an MLP.

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

Okay. And then -- okay, so like if you're looking at selling the assets partly or maybe mostly to reduce debt and improve liquidity, what's the sense of, at the same time, looking to acquire assets?

Douglas H. Miller

Well that would allow us, if we put it in the proper MLP -- we'll keep an interest in that and manage it. That would have liquidity over there for those type of assets and whatever our equity, whatever we get will reduce our revolver on the EXCO side and maybe give us $500 million, $600 million, $700 million of liquidity. So potentially, that gives us the ability to buy $1-billion, $1.5-billion worth of deals without additional equity.

Stephen F. Smith

In the shale -- in our shale area...

Douglas H. Miller

In the shale area, we really would like to focus on the areas with the highest rate of return and the lowest operating costs, and we are trying to buy in both the Marcellus and the Haynesville. I do believe that 3 years from now, you're going to say the 3 areas that we're going to get 1/3 of our gas from: the Barnett, the Haynesville and the Marcellus. And we're going to be in 2 of the 3.

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

So as you improve your debt situation, improve your liquidity, by selling off assets, are you then going to ramp that back up and tighten liquidity again by acquiring assets?

Douglas H. Miller

We might.

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

I'm having trouble understanding you. Is that...

Douglas H. Miller

But you will. We'll try to explain it to you. Next time you come in to Dallas, call us. We'll explain it to you.

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

All right. Then you mentioned -- what's going to happen over the next week? You've said you made an agreement with BG. What in particular?

Douglas H. Miller

Now what we're going to try to do is make a determination whether we're going to sell TGGT or put it in a MLP.

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

But you said you've made an agreement and you're going to announce something over the next week.

Douglas H. Miller

No. We finally agreed to agree. And we haven't signed up yet. But I'd say by next week, we will have an idea of which way we're going.

Operator

Your next question comes from William Butler from Stephens.

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

One thing I noticed, you guys mentioned on the acquisition side -- or didn't mention the Permian this time.

Douglas H. Miller

Well, I didn't -- we have been on 3 or 4 deals out in the Permian. We are looking. We're not afraid of the Permian. There's obviously a lot of oil. But one of the things that's a challenge out there on a lot of the deals we're looking at is they work like a charm at $95 oil, not so good at $85 oil. I mean, it is right on the edge at $85. I would say that some of the deals that we've looked at that are for sale, we would do better buying in the Haynesville. High operating costs, a lot water in a couple of deals we've looked at. Now there's going to be some spectacular deals out there. We just haven't found the right one yet.

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

Okay. And then I noticed in the slideshow on the Appalachia, Slide 15, the current production seemed pretty low at 108 Mmcf/day gross. Where are we to make of that? It's below where the graph shows. And I think you were, like, at 146 last quarter. Is that just a blip? Or did something happened in...

Douglas H. Miller

That might have been total production. This is just Marcellus. I think what happens is we've got -- our total production, shallow and deep, is -- gross is about 200. And our net is about 100.

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

Then that's not the same number as last quarter then, compared to the 146.

Michael R. Chambers

I think the 146 is our Marcellus and our conventional, and I think it...

Douglas H. Miller

Yes. I think we just messed with you on that. We didn't compare it to the last chart. But I think that includes our shallow.

Michael R. Chambers

Right now, our Marcellus operated is 105 and our Appalachia conventional is 37. And our OBOs, another 57 on top of that. That gets you to the 199. That's what we were Monday.

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

And then are we to read anything into just thinking about your outlook on natural gas prices? I mean, you were talking, in theory, $4.50 to $5, but we're hedging at $4.20. I mean, what are we to make of that, I mean?

Douglas H. Miller

Well, like you said, we have a big debate in here like everybody does. We're hedging our debt. We're not hedging because we know what gas prices are going to be. We don't trade it. So because of our debt, starts at $4, it gives us plenty of cash flow for next year and we're comfortable where we are. If gas goes up a little, we'll layer in some more hedges. If we make acquisitions and put that on, we will put more hedges on. I mean, it's a debt deal with us more than it is thinking we know what gas price is going to do. We haven't been very good at predicting gas prices over the years.

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

Okay. And then one last point of clarity. You all mentioned you've got -- you've done 3 Cline tests with 2 that are complete. And how many Wolfcamp tests have you all done?

Michael R. Chambers

Three. We've done 3 recompletions on the Wolfcamp.

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

And then it's all 3 of those are done.

Michael R. Chambers

Yes.

Douglas H. Miller

And those are all vertical depths and they have positive oil in all 6 of them.

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

You all wouldn't necessarily release to us the results of that before you all drilled...

Douglas H. Miller

No, we probably wouldn't. There is a little bit of competition for acreage out in the neighborhood and before we start telling you what's going on, we'd like to get some more acreage.

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

Okay, and one last question. When could we have sort of a more formal 2013 outlook?

Stephen F. Smith

In connection with our year-end release.

Douglas H. Miller

Yes. Give us -- we were planning on having it by now. We've got a capital budget meeting with our board coming up. And we've got a couple of transactions that we hope we can get across the finish line here over the next little while. If we get both the capital budget and a couple of those things, we'll have another -- we'll put out a press release.

Operator

[Operator Instructions] Your next question comes from Jeff Robertson from Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

In the Haynesville, can you all talk about where the acquisition opportunities are? Are people willing to sell acreage in what you all believe to be the core area?

Douglas H. Miller

You're killing me, Jeff. The answer is we are looking at a few transactions in that neighborhood. Some potential trades, et cetera. We have land guys out there all the time. If we lease anything, it's going to be very small. There are some small companies out there that have some that we're looking at. It's tough to buy in the core area. And I think, Marcia, probably across the Haynesville, last I heard we have 21 different decline curves by area. And so there is some B+ and some B stuff that still works and so we're looking at those areas also. I'd say very tough in Holly.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. When you look at acquisition opportunities and relative economics, how would you compare what you see in the Haynesville or what might be available in the Haynesville versus oilier areas, if you're talking about bidding oil at $85 flat and continuation of relatively weak NGL prices?

Douglas H. Miller

I'd say it's starting to get where I think the oil price -- 6 months ago, I was saying I thought there was $2 down for every $1 up. I'd say it's getting to the place where we would have a little comfort zone. But I'd still say with everybody in the world drilling for oil, I think there's still some potential down for oil prices and we're looking for an asset that has enough production that we can hedge it and not have to drill 500 wells to hold the acreage. We're not a very good guy at buying 5 million acres and seeing what happens. That hasn't been our MO. We leave that to Aubrey.

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

And lastly, Doug, you all talked about doing some processing agreements in East Texas for I think the Haynesville and maybe the Cotton Valley. Can you talk about what kind of economic impact that might have on EXCO as you think about 2013, either gas realizations or greater NGL extraction?

Douglas H. Miller

Yes, not in the Haynesville. But in the Cotton Valley where we have liquids rich, Tyler [ph], $10 million to $20 million in each case should be added to us, -ish.

Jeffrey W. Robertson - Barclays Capital, Research Division

-ish?

Douglas H. Miller

Yes. It depends on what liquids prices but both of them, early on, look like somewhere at $15-million, $20-million uplift. But now liquids are coming down, so it's probably going to be half of that.

Jeffrey W. Robertson - Barclays Capital, Research Division

It is, I guess, that you all just weren't able to process previously.

Douglas H. Miller

No, we were selling it down the line and just getting an upgrade. We were getting -- instead of $3 gas, we were getting $4 because of the liquids. So now when we separate it out we get 90-something percent of it. It actually does make an economic difference by doing it that way.

Michael R. Chambers

It helps on the new plant right in the middle of the Holly field that wasn't there before, so...

Douglas H. Miller

Yes. It works and it -- long term, it's going to work great but we turned the liquids market around by signing those, [indiscernible] percent to 30% overnight.

Operator

You're next question comes from Amir Arif from Stifel, Nicolaus.

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

Just trying to get a little bit of color on '13. So without any acquisitions and just a run rate of Q4 in terms of where you are in terms of $80 million, $90 million a quarter, what kind of base production decline should we be thinking about in the Haynesville and the Marcellus?

Douglas H. Miller

That's for somebody smarter than me. We have 3 engineers sitting here and they're all looking at each other. Marcia, what do you think? You're talking about just Haynesville?

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

Well, Haynesville or just corporate-wide. I mean, your production started declining in 3Q, but you've kind of rigged further in 4Q. So I'm just wondering, at a current run rate, how would you see '13 without any acquisitions or any other changes taking place?

Douglas H. Miller

Well that's a challenge because Cotton Valley is at 6%. Haynesville is, what, 25%, 30% today.

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

With the drilling, with the 5, 6 rigs out there, it's still 25%, 30%?

Douglas H. Miller

No. I thought you said just base decline rates...

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

Oh, yes -- no, no...

Douglas H. Miller

Our drilling program -- with our drilling program?

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

Yes, just with Q4 run rate annualized, so the $80 million, $90 million a quarter that you're spending right now. Just at a corporate level, I'm trying to get a sense of what '13 looks like without any acquisitions or anything else.

Douglas H. Miller

It's going to be pretty -- it isn't going to [indiscernible].

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

Pretty flat?

Unknown Executive

[indiscernible] 12%, something that.

Douglas H. Miller

I'm not sure it's much more than 10% or 12% just because...

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

15?

Douglas H. Miller

Yes. It's sporadic because we're drilling units right now. And so you'll see it comes down and then we put 7 wells on, so it goes up. So it bounces around. Use 15%, and we'll try to beat it.

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

Okay. Sure, sounds good. And then just the second question on the -- in Marcellus, you talked about shutting in wells for 30 days. Was that just in the Northeast or the Central or both? And also, if you can just give some color if -- I understand you're doing it for the water dissipation, but does have any impact on the well IPs or EURs or anything else?

Michael R. Chambers

We've done it in the Northeast and in the Central area, and both of them have been very similar, both of them in the 90% kind of reduction range in water production.

Douglas H. Miller

I think we think it's adding both. The IP has turned out to be a little bit better and Marcia hasn't given us much more in reserves but she will.

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

Okay. But you do see an improvement in the IP relative to wells where you hadn't shut in.

Douglas H. Miller

Well, we think it's lasting longer.

Marcia Reeves Simpson

Yes. We just say that your water production is much lower so your apparent IP rate's higher, faster.

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

Okay. So it doesn't cause any swelling in the clays or other issues.

Marcia Reeves Simpson

No, we're not seeing any of that.

Douglas H. Miller

We're trying to stay out of the clays too, aren't we?

Michael R. Chambers

Yes, as best [ph] we can.

Operator

Your next question comes from David Neuhauser from Livermore Partners.

David Neuhauser

Really, a lot of my questions were answered. But I wanted to ask, again, regarding on the acquisition side, with all the movement of the commodity itself, with oil, like you said, being flat at $85 and NGLs kind of getting hammered here, and gas kind of basing and ticking up, is that sort of changing your mentality in the war room daily as far as which asset to attack and look to acquire?

Douglas H. Miller

No. We're looking at deals that are for sale. Areas that we're not interested, we pass. Areas that we have an interest, we continue. I'd just say I'm a little more comfortable with our oil forecast. And gas is -- we're very comfortable, especially if we can get it in our neighborhood. No, we're still looking. We're -- we had a company that was 90% oil 20 years ago, so we're not afraid of the oil and unfortunately, some of the stuff that we're looking at we used to operate.

David Neuhauser

All right. So is it safe to say -- are you being sort of opportunistic here and -- when looking at identifying opportunities?

Douglas H. Miller

Well, we're trying to get some in the Marcellus, but opportunistic, when they're at auction, is kind of an overstatement. When there's 40 deals for sale and the -- and they're broadly marketing them, we're going to have to be the high bid. But we've been there before. We bought $10-billion worth of assets over the last 10 years, most of them at some sort of competitive auction.

David Neuhauser

And are you looking at a company that sells -- I mean, companies that might be a little bit levered, that shut-in a lot of production or have underdeveloped acreage that you can maybe just acquire and take a bigger bite?

Douglas H. Miller

Well, we would. I'd say we're looking at a couple of companies. Right now, I'd say 5 or 6 of the deals we're looking at are private companies that just want to sell by year end for tax reasons. I'd say public companies that we've talked -- that would be a bigger challenge. Public company deals takes a long time. I would say we would focus -- we have looked at a couple. Investment bankers show them to us every day. They're probably not out loud for sale. But there are companies with assets in our neighborhood that we will for sure talk to, that have either quit drilling in the Haynesville or cut it way back.

Operator

The next question comes from Michael Hall from Robert W. Baird.

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

Just a couple quick ones on my end. I guess, first, just wanted to kind of come back on the cost side of things, on the capital costs. In the Marcellus, how would you characterize that relative to the Haynesville as it relates to cost-reduction initiatives? And how much additional cost do you think you could carve out of those wells?

Douglas H. Miller

Well, I'm going to say -- this is my opinion and then you guys do it. I would say we're 1 year to 2 years ahead in the Haynesville from where we are in the Marcellus from learning. Now keep in mind that Haynesville is 6 million acres and we focused on 600,000 acres. The Marcellus is almost 30 million acres, not counting the Utica. And we have a couple of focus areas. We're trying to figure out what the core areas are. So we haven't been able to sit down and really focus on cost because we're trying to figure out where we are. Now, you guys, anything added to that?

Michael R. Chambers

A lot of our Marcellus were appraisal acreage, so those are one-offs. And those are much more difficult to get down to a cost, and then...

Douglas H. Miller

Yes, we're not drilling pads -- we're not drilling units over there yet, although we have done a couple to see what it's done and it has helped, but it's such a big area and we have so much diverse acreage. We're trying to figure out -- and there is acreage available up there. If we can figure out a core area or 2 -- and I think there's going to be multiple core areas. There is acreage available and deals available up there. I'm a little reluctant to pull the trigger on a big deal up there right now because I would say we're -- our learning curve is not as great as it has been in the Haynesville.

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

Okay. It makes sense.

Douglas H. Miller

We're getting there. We're getting there.

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

It sounds like it. And I guess in the same region just while we're up there, the Utica, you haven't mentioned that as an area of interest necessarily. Is that a function of the fact that you probably wouldn't be able to pick up much production with those sorts of assets, and so...

Douglas H. Miller

Yes, right now, Aubrey has it as the best area on the planet because he's trying to sell some. So if you want pay -- we're not in the market to pay $10,000 or $15,000 an acre over there yet. We've done a study on it. We think there's -- it's kind of like the Eagle Ford. There's an oil window, a liquids window and a gas window. And so everybody's kind of focused on the liquids window and they're probably going to be a little bit disappointed on the price and availability of getting that to market. So we're watching. There's plenty of acreage for sale and plenty of deals over there. We have not focused there [ph] yet, again because we're not buying all acreage. We're just set in our game.

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

All right, okay. And then on '13 just quickly, closing to outlook, I guess, do you expect you can remain kind of balanced on the cash flow versus CapEx front in '13?

Douglas H. Miller

Well, we will for sure. If we're not, we'll cut rigs. I mean, one of the things you can bet on is where our capital program is going to be within cash flow.

Operator

I have no further questions in queue. Mr. Miller, I turn the call back over to you for closing remarks.

Douglas H. Miller

Shoot, I don't know if I have any closing remarks. I think we answered everything. Anybody has any further questions, feel free to call us. Everybody here is available. We are looking at deals. We will continue to look at deals. And, Joe Allman, you need to call me and we'll kind of go over the deal with you. But I appreciate everybody being on. Again, all those guys at New York, we're kind of praying for everybody to get back on their feet. It looks like a disaster and anybody needs any help from us, let us know. We'll be happy to do it. With that, thanks for everybody and meeting adjourned.

Operator

This concludes today's conference call. You may now disconnect.

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