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EXCO Resources, Inc. (NYSE:XCO)

Q4 2008 Earnings Call

February 25, 2009 12:00 pm ET

Executives

Doug Miller – CEO

Steve Smith – President

Lanny Boeing – VP & General Counsel

Hal Hickey – VP & COO

Mark Wilson – VP & CAO

Paul Rudnicki – VP

John Jacobi – VP Business Development

Justin Clarke

Analysts

Leo Mariani – RBC Capital Markets

David Heikkinen - Tudor Pickering

Joe Allman – JPMorgan

Brian Singer – Goldman Sachs

Ellen Hannan – Weeden

Unspecified Analyst – Stone Harbor

Operator

Good afternoon ladies and gentlemen. At this time I would like to welcome everyone to the EXCO’s fourth quarter year end earnings release conference call. (Operator Instructions) Mr. Miller, you may begin your conference.

Doug Miller

This is EXCO’s fourth quarter and year-end call. With me today I have Steve Smith, Doug Ramsey is in the hospital. I have Lanny Boeing, Paul Rudnicki, John Jacobi, Mark Wilson, and Hal Hickey and Justin Clarke. So we’re here to take any and all questions and go through this in as much detail as you would like.

I’m going to start, well let me do this, we have our forward-looking statements that Paul is going to read.

Paul Rudnicki

Thanks Doug, I would like to remind everyone that you can go to www.xcoresources.com and click on the Investor Relations tab on the left hand side of our home page to access today’s presentation slides. The first page that will come up has the presentation slides link, just double click on the link and it will launch the slide presentation that you can follow along with.

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

Please refer to pages three and four of the slide presentation for the complete text regarding our forward-looking statements.

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

Doug Miller

That was good Paul, that was really good. I’m going to quickly say something and then we’ll get into this. There’s a rumor going around Washington, DC, that Joe [Biden] was [inaudible] this morning because he had to stand up so many times last night. He had to stand up whenever Nancy stood up so he’s limping today. This company I think everybody that’s on here is a shareholder like everybody in the room. We set all kinds of records, we’re doing unbelievably, I’ve never done so well and lost so much money in my life.

I think you’ll see that we were setting all kinds of records both from a production standpoint, pipeline standpoint, EBITDA standpoint and I’m proud of our people, they have really worked ultra hard, we are in a couple of very exciting plays. We’ll be talking about the Haynesville here shortly, Hal will go over that with you but I think we spent the better half of last year doing a lot of science work as far as geology and coring and drilling vertical wells and figuring out how to, where to run the horizontals and how to frac them and our first two wells have been very successful.

We’re quite excited about it, I think Hal will talk about how we are booking reserves on that and our play. We have four rigs running out there today. I think we’ve got one well in completion stage, maybe what frac job are we on? Number 8, we’re on our eighth out of 10 so its moving along. So, it is exciting and of course as everybody knows gas is going to $2 and we’re hedged so we’re prepared for that. We’ve also heard that they are going to be shipping L&Gs into this country to store them here which makes a lot of sense.

So but, with that, its our anticipation that, and you’ll see when we get going through our budget that at $4 gas a lot of the areas where we have been drilling in the last couple of years don’t meet our economic criteria, that includes the shallow Appalachia, we will cease drilling up there. That includes the mid continent, we will cease drilling there. That includes west Texas, where we only have one rig down from four and we probably will cease drilling there. And the only two areas where we think at these prices there is still is at least a 20% rate of return would be in the Haynesville and the Marcellus.

So, those are the only areas and if gas goes down any farther I think we will consider reducing further. So with that I’m going to turn it over to Steve and get started on this and then we’ll open it up for questions. Thank you.

Steve Smith

We’re going to be speaking from the presentation that was posted last night on the website, we’ll start at page six, corporate highlights. We had a, as Doug said, we had a record year in 2008, we had $978 million of adjusted EBITDA which was 28% greater then the preceding year. Production wise EBITDA, revenues, all were at records for this company for the year. The fourth quarter was a good quarter, as good as it could be given what had happened to commodity prices. Our production in the fourth quarter was 403 million Mmcfe a day on average which is up from 397 in the third quarter and that was in the face of a dramatic decrease in rigs.

We had dropped our rig count by two-thirds between the third quarter and the fourth quarter and completed 33 fewer wells in the fourth quarter so obviously production was impacted by that statistic but yet we still were able to show a small increase in production. We continued to have a strong showing with our pipeline in the fourth quarter and for the year and we put our 57-mile extension on during the latter part of 2008 and it is then quite successful and we’re also working now on another 29-mile expansion of 36” pipe to haul the Haynesville gas and we’ll talk about that a little more.

So all in all, 2008 was okay. Obviously the stock price was not to our liking but operationally it was a good quarter. Page seven we’re just talking about some of the things I’ve covered. We’re starting to see some really significant decreases in both drilling costs and operating costs and we expect that to continue for quite some time. Probably on the Op cost side we’ve already experienced about a 10% drop. On the CapEx side probably, it depends on the area that you’re in, its anywhere from 10% to 30% and I think that its going to get, I think those prices and costs will go down further from here.

We, as Doug mentioned, we have completed two horizontal Haynesville wells that are outstanding. The first one, the Oden well which we completed on December 3, produced a Bcf of gas in the first 64 days, its been on production 84 days, its averaged 15 million Mmcf during that 84 day period so it’s a horse, no question about it.

The Lattin well, the second well is equally as strong. It [inaudible] 24.2 million a day. Its produced, when it was on a 26/64th choke, we were producing at that 20 million a day, its produced about three-tenths of a Bcf in 17 days and currently producing on a 22/64th choke at about 17 million. So its an equally strong well, we chart it along with the Oden and then track almost exactly. Thus far up through last week I think we had produced, we were at a production rate of 35 million gross a day and 26 million net from the Haynesville so obviously we’re making headway.

We’ve got one well that is completing now. As soon as it, we get through with it, in which will be in a few days, that frac crew is going to move over to complete an outside operated well and so we’ve got several things going along running four rigs in Haynesville right now. During the fourth quarter we refinanced the $300 million unsecured term loan. We’ll talk about that a little bit later as well. We also have launched over the past few weeks an asset divestiture program. We had started selling some assets in the fourth quarter, we’re continuing that and adding to some non-strategic type assets to the sale packages and we’ll talk about that.

Page eight is a slide that we always show to kind of give you a feel for what our net cash operating margin is including cash settlements on derivatives. Its $6.30 for the fourth quarter, we’re about where we were back in the second quarter of 2007. But its still, the hedging program is extremely important to our ability to produce cash flow and continue our development programs in a significant way.

Operating costs in the fourth quarter were $1.20, that included $0.17 of workovers so $1.03 per Mcfe of direct cost, that compares with the same amount for the third quarter and about the same I think as $1.02 in the second quarter. January at least a preliminary look, looks like $0.93 which would be about a 10%, 11% decline in operating costs so we can already see the impact of, if nothing else the diesel fuel prices would be one of the reasons for the cost declines in January and toward the end of the year.

Page nine is our capital budget, we spent about $989 million in 2008 of which $187 million was leasing. We spent a lot of money leasing in the Marcellus and in the Haynesville and I think as we will discuss we’ve got an excellent acreage position in both places. We’re budgeting $582 million as at the outside for 2009. If prices stay as they are, we will not spend that much money. Right now we’re kind of guiding toward a low point of $500 million to a mid point of about $530 million, just a 10% decline in costs and laying some more rigs down or not picking any more rigs up in the mid cont and west Texas kind of gets you to the low end of our budget.

If prices goes lower then we’ve got the flexibility to go even lower then that. We can lay some additional rigs down in the Cotton Valley that we’ve kept working due to some rig commitments, so we are pretty flexible when it comes to our capital budget expenditures. We think the Haynesville works down into the three’s but nothing works into the two’s.

Doug Miller

I think we ran a model last week, Cotton Valley well which we’ve been drilling for the last 15 years, in 2007 was costing us about $1.7 million, middle of last year the cost was $2.7 million, and we checked costs last week, we could drill that same well for $1.5 million. Which probably means that if gas went back to $6 we would look at it again but at $4 or $5 we’re not ready to go.

Steve Smith

But our capital budget in any event is going to be within our EBITDA, substantially within our EBITDA and we’ll produce free cash flow to reduce debt as we go along here and again we’ll get into a little more of that. Something like 60% of our budget I think is going toward the Haynesville, the East Texas and North Louisiana including the pipeline expenditures so that’s kind of where we are capital budget wise.

Page 10 just goes through the ceiling test write-down as you know, we’re on full cost accounting therefore we have to test the ceiling on a discounted cash flow basis at 10% using year end pricing and year end pricing was $5.71 for gas and $44-something for oil. Successful [inaudible] companies obviously have a little different test. They use an undiscounted number so you don’t see very many write-offs of their producing oil and gas properties but that’s the accounting method we selected and I think for a lot of the right reasons.

However the SEC has recently issued some new rules that become effective at the end of the year. They will actually be effective for the year ended 2009 and those rules just as they relate to using an average price versus a spot end of the year price, it would have, maybe not completely eliminated the write-down but it would have eliminated 90% of it. So, now that average price will be utilizing low prices in early 2009 and hopefully higher prices in late 2009. You don’t know how its going to turn out but on the other hand just with our hedges, if we had just used our mark-to-market using the ceiling test prices, our mark-to-market gain would have been $700 million as we’ve pointed out in this slide.

In any event that write-down is behind us. Our DDA rate will be substantially less and we’ll show you that in the guidance coming up.

I’m going to turn it over to Paul and let him pick up with the liquidity and financial position and hedging material.

Paul Rudnicki

Thanks Steve, pick it up on slide 11, as Steve mentioned we’ll go over the liquidity and financial position of the company today. As you can see from year end we had about $2.3 billion drawn under our $2.5 billion consolidated borrowing basis and we continue to kind of stay flat at that level. The borrowing base was reaffirmed in October and we are getting ready for our April 1 redetermination as we’ve been in close contact with the banks and running different sensitivities we don’t see any issues expected on the April 1 mainly as a result of just the reserve base that we have, the high EDP level and the hedges that we have in place.

The bank debt as you can see is LIBOR plus 1 to 175, at today’s interests costs on that bank debt is 2.25%. The senior notes that we have outstanding that are due January, 2011 are 7.25%, $445 million worth. The senior unsecured term loan that Steve mentioned we refinanced in December essentially carries an interest rate of 10% and all in all, our borrowing cost today is 3.75% and when you include some of the interest rate swaps we have its 4.07%, so its still very attractive cost of debt there for us.

Just to talk about the senior unsecured term loan for a second, with the free cash flow that we’ll generate with the program we’ve outlined and with either just using some of the liquidity under the borrowing bases or the asset sales that we’ll get off this year, we expect to have that paid off for sure by the end of the year and we’re targeting to try to get it paid off earlier depending on the asset sales.

Going on to slide 12, pick up with our current derivatives position, I think the key point on this slide is we have over $300 million a day hedged, slightly over $300 million a day hedged for the year which equates to just north of 70% of our expected production and you can see as we’ll go over the guidance in a second as we ramp up during the year in the Haynesville we go from 74% to 69% but it’s at an equivalent price of anywhere from $8.60 to $8.70 quarter by quarter. And we have a total of $191 Bcf hedged at $9.19 per Mcf and under today’s market price it would be nearly $600 million mark-to-market.

Picking up on slide 13, comparing our fourth quarter results to the guidance that we put out, we’ll touch on production for a second. We came in at 403 million a day versus the 405 to 415 we were guiding to and as Steve mentioned the main result there is from laying rigs off faster then we had anticipated during the quarter. Our gas differentials were wider then expected coming in at 93% versus the 97% to 100% of guidance and the main reasons there are as a lot of other companies have experienced as well, we’re [permi] and mid continent differentials had widened out through the quarter pretty substantially and the NGL volumes values that we record as gas price have gotten very weak during the quarter.

Lease operating expense was towards the higher end of our guidance as again as Steve mentioned mainly resulting from an increase in workovers. Those workovers were $6.2 million versus $3 million for the third quarter, so it was a $3 million increase quarter over quarter. Other income was a loss of $1.5 million and the main thing there is just some contracts that we terminated related to some, a couple of rigs and some pipe that we had on order. The midstream revenue, just want to take one second to point out there again, the way we record or midstream on the face of the financials we essentially only show the third party revenues and 100% of the midstream expenses.

So it does not account for any of the intercompany revenues that we generate on that system. Again as we talked about with the intercompany piece the midstream business itself is creating about $8 million during the fourth quarter of EBITDA. The other big thing to point out, on the interest expense there might be a little bit of confusion on the income statement, it shows $60 million of interest expense. The main difference there versus the $45 that we’re showing you here is $15 million mark-to-market on our interest rate swaps. Again as LIBOR was coming down and our swaps are roughly 2.66% that mark-to-market just gets reflected in our interest expense.

So adjusting for that we were at $45 million of interest expense which came in below our guidance again reflecting the lower LIBOR costs.

I’m going to finish up for me on slide 14 with the guidance for 2009, I’ll just kind of hit some high points here. This is a quarterly presentation but for the year we’re guiding towards 415 to 430 million a day production. Obviously ramping up as the Haynesville program for us ramps up during the year. The main risks to us on the timing of that ramp up is just the timing of the completions as they come online but we’re pretty comfortable with what we laid out. The other thing to point out is we have guided towards some better differentials then what we experienced in the fourth quarter as it relates to the gas.

Assuming kind of no improvement from what we’re seeing in January we would probably be towards the lower end of the range but I think when you look out on the curve the differentials definitely seem to be coming in. The other thing to point out on the lease operating expense as Steve mentioned we are guiding towards a decrease year over year and we are beginning to see that here in the first quarter and expect to see more of that throughout the year.

Production tax rate, I want to point out there again during Q3 and Q4 we expect that production tax rate to start coming down as more and more of our volumes are coming from the Haynesville which does have a severance tax holiday. Again we talked about the midstream revenues and expenses, we are showing a growth in just the third party piece, but when we include the intercompany piece, the midstream business on its own will do $50 to $60 million of EBITDA this year. And again the only risk to that volume there is just the timing of when we expect the header system to get built.

I think the rest of it is pretty self-explanatory. I do want to point out some new guidance that we have put out. We have guided towards some CapEx numbers for the quarters. The frontend loaded CapEx on Q1 and Q2 is mainly reflecting the pipeline expansion that we’re planning on there and Q1 pipeline might get, some of that might get put into Q2 just depending on how that shakes out but we’re pretty comfortable where that is. And as Steve mentioned the 2009 budget that we put out was based on the 2008 capital cost structure so there we expect to see some cost savings just from the current costs and again we’re guiding towards lower capital spending for the year again mainly reflecting the fact that we in today’s market just do not expect to spend all that capital.

With that said, we’re expecting an EBITDA of just under $900 million for the year and with the capital program we’ve laid out we’re expecting significant free cash flow on that. And with that I’ll hand it over to Hal to go over the operations.

Hal Hickey

Thank you, before I get into slide 16, just let me take just a moment and say that just as I said three months ago I was excited then about the future, I’m more excited about the future now following some of the results that we’ve had. I’m also excited about the future because of the way this organization has responded to the tough, tough times we’ve seen. Although we’ve ramped down rigs, we ramped down spending, we’ve gone in and we’ve negotiated with our suppliers and doing the right things to go forward. We’ve positioned the organization well for the future, exploitation and management of this great asset base we have.

So with that let me start on slide 16, last year we drilled some 475 gross wells, we completed 467 of those. Our usual very high success rate, we had a good drill bit finding cost of about $239, we replaced over 200% of our production, adding some 290 Bcf approved reserves through drilling. Record production, nearly 400 million a day, average for the year way up from 2007. And very, very importantly we’ve enhanced our position in two very, very important shale plays and the company is well positioned for both short-term and long-term growth.

We spent a lot of time leasing, we drilled wells like Doug said earlier, we spent a lot of time on the science and analyzing these plays. We’ve moved ahead a little quicker in the Haynesville then the Marcellus but we’re going to position ourselves in both of these plays for great future results. Acreage position has increased dramatically, we’re up to over 1.8 million acres on a net basis across the company. Haynesville shale as we’ve high graded our position to understand what we have, we’ve got over 92,000 net acres there and in the Marcellus some 395,000 net acres are in our portfolio.

Slide 17 and 18 I’ll talk for a moment about our reserves, we did increase them year on year from 1,865 at year end 2007 and that was at prices significantly higher, I think we were at $6.80 gas compared to $5.71 at year end 2008. I think oil was around $96 at year end 2007, its around $44.60 in the calculations we used in year end 2008. Now Steve mentioned how there are some new SEC guidelines coming out, sort of looking ahead, if we were to use in 2008 just for fun, the pricing that the SEC will allow you to use in 2009 looking at first of the month average pricing, our reserves would have been about 2.25 [Tfc].

With that said they are what they are, they’re 1,940 at year end. I will walk through this slide a bit, start at 1,865 year end 2007. We purchased about 180 Bcf, we discovered the 290 as I mentioned earlier. Because of the price we had a negative revision of about 107 and then we had some performance revisions as we classify them of about 137. Let me take a moment and tell you about the two main components of that.

One acquisition in Appalachia from calendar year 2006, one acquisition in west Texas that went over calendar years 2006 and 2007. in Appalachia we made an acquisition from a company who had identified some 12,000 to 13,000 locations. At the time of acquisition we have ramped that down to about 5,000 and as we said has been in our portfolio. We looked further and between topography, cultural issues which means we don’t to drill in a school yard, and land matters we’ve ramped that down and we’ve actually taken a big revision on that acquisition.

And in west Texas, the acquisition remains very, very economic for us. We have less EUR but the acquisition has had more of an oil component then a gas component and in turn that less EUR but with more oil then we forecast the economics have worked out very well when you look back at what prices have been over the development period.

Sliding over to page 18, you can see on the left hand side its sort of a walk forward similar to the slide on 17 but I will point out that our proved developed component of our proved reserves totals nearly 75%. Then you can see some of the specific numbers as we’ve calculated them for reserve replacement. In 2008 all in and you’ll note in the footnote one that includes extensions and discoveries, acquisitions and revisions other then price. We have a 230% reserve replacement, drill bit only, over 200%.

You can see our costs, again all in calculated with the assumptions noted below. We have a $3.90 all in cost, drill bit only about $2.39. Let’s move forward looking on slide 19, what we’re going to do in 2009 and beyond. We’ve said it over and we’ll continue to say it again, that we will manage our spending in this low commodity price environment. This is a tough environment that we’re in, we are going to react to it. We will protect our acreage position, we will protect our reserves position, we will meet our contractual commitments.

We are going to focus on the best opportunities for both growth and returns. We think the Haynesville is working well, we’re going to continue to delineate that. It gives us good returns down in the three’s. We think there’s a big opportunity in the Bossier shale that we’re going to look at from a science perspective. I’m not saying we’re going to do a lot of drilling there this year, but we’re going to understand it better and evaluate it. We will high grade our Marcellus acreage in preparation for a 2010 program.

What our guys are doing there right now is looking at the broad acreage position we have, nearly 400,000 acres, some 250,000 acres is what we’ve defined as the core which is 100 feet or more of thickness and geologically over pressured. We’ve honed in on some priority areas. We’re deciding where we’re going to focus and we’re going to start running with that next year.

We’re limiting our non-shale drilling very dramatically and we’re expanding the midstream more then we ever had in one sense, we’re just going to get nearly a quarter of our overall capital budget. Like Steve said we are initiating an asset divestiture program. We’re continuing the one that we started in the fourth quarter and we plan to sell certain assets in each of our divisions so its going to impact us across the portfolio. Now these areas where we’re selling these assets, we don’t have much capital dedicated, if any capital dedicated to them at all.

It won’t impact our capital program but it will, one, provide cash, two, allow our people to continue to focus on the better growth and return opportunities. Slide 20 is further detail on the capital budget. I think Steve started to give you some color on that a moment ago. Of course our land dollars are going to be dramatically, dramatically down. Drilling is going to get the bulk of our dollars. East Texas, North Louisiana is the biggest component of that both from a drilling side and from an overall side so you can see if you include the midstream in our overall budget its nearly 75% of our capital will be dedicated to East Texas North Louisiana between drilling completion, midstream, and our other activities.

Land like we said would be dramatically down. Slide 21, let’s talk a bit about the Haynesville shale. Two outstanding wells completed, both in Desoto Parish, both flowed very, very, very good rates on restricted chokes. We’ve got the one well that we’re completing now like Doug said, we’re on the eighth stage of a 10 stage frac. We should be flowing that well back over the weekend. The frac crew is going to move immediately to an non-operated well that we have 18% 19% working interest in and they’re going to complete that well. We will also be excited to hear those results.

We have four operated rigs drilling, we have three non-operated rigs drilling. Three of the four operated rigs are in Desoto Parish, one is in Caddo Parish. The technical team, our organization has done a great job taking us from where we were 10 or 11 months ago when we were just understanding we even had Haynesville to a play where we’re producing some 35 million a day gross in just a matter of months. Great teamwork, great focus on the right things looking at the technical expertise of our people, I’m proud of them. Engineering, geo science operations, very, very classy, very good, very intelligent, its working very well.

We spend a lot of time drilling and testing vertical wells, we understand the play much better then we did and we’re poised to move forward very dramatically. We’ve got 92,000 like I said, we think we’re in the heart of the play, I’m going to show you a map on the next slide, that really depicts where we are in and why we think its so good. Formerly in the public domain we’ve released that our potential is 2 to 5 Tcf, now with our science and our use of both internal and external third party engineers, we’ve come up that we think this is a 4.5 Tcf play for us.

And we think there will be very, very significant reserve adds during 2009 from the 34 wells we’re going to drill, 27 of which are operated. We think that our reserve replacement in 2009 will be better then the 200% that we saw for 2008 from the overall company, just from this Haynesville play.

So slide over to 22 with me, and you can see the red bubbles on the map and the pink bubbles on the map depict the sizes and relative sense of the various completions that have been announced in the public domain by either us or our competitors. We’ve noted where competitors are on the map. We think the core area that I’ve depicted here is likely to change. This is a dynamic thing. This is a core area based on both science and results that are announced to date. In fact if you go over to Greg County where we made an acquisition last summer, we believe that following the vertical well drilled there that there is some shale presence and we think that this thing has potential for shale development even farther to the west then we have depicted.

So that said the good results to the east, you can see the green areas depict the EXCO acreage holdings and the results that we’ve had to date are very exciting and we think that we’re just very, very strategically positioned in the core area of the play. Our guess is high quality gas, low CO2, minimal, minimal H2S if any, very good gas content, ready to be shipped down the pipelines and all of our gas has been tested to sales the day that we’ve been testing. The day we begin bringing those wells on line our marketing, our midstream people have been ready to go so very proud of the way the organization has responded to this.

Slide 23 talking about the Marcellus shale, the first two wells had shorter laterals, I’ll mention that in the third quarter, these are the same two wells we talked about earlier. We still feel like the results from single stage and four stage fracs are very encouraging. We are going to continue to drill in the same area where these first two wells were in central Pennsylvania and we did acquire some 3D seismic that’s going to help us with our geological characterization, our reservoir descriptions. We’ve also drilled two horizontal wells in northern West Virginia with better lateral links and we’re planning four and seven stage completions there and that will be completed late March, early April.

The shows in these wells were very encouraging so I’m excited to hear the results from them. Good acreage position, I’ve talked about, 2009 plans, drill some verticals, drill a few more horizontals, shoot the seismic, work the regulatory arena and make sure we’re high grading so that we’re focusing our efforts in 2010 and beyond on our priorities.

Slide 24 shows a map, the Marcellus shale activity. The green depicts the counties in which we have Marcellus interest. The black dots show wells that we have planned in 2009, the red dots are wells that we have drilled to date, some of which have been completed, some are not. These are both vertical and horizontals.

Finally I’ll talk on slide 25 about our midstream activity, continuing to be a growing business for us. Throughput has increased dramatically, 460 million a day at year end 2007. Monday’s in our weekly report we actually, we were over 600 million a day flowing through that system. The TGG pipeline expansion in mid-August, I’ve talked about in earlier slides, it continues to grow with throughput volumes and as we’ve said several times, we’ve begun work on the first phase of this $108 million Haynesville header system. Its going to enhance takeaway capacity from the Haynesville area for both our equity gas and will transport third party gas, good design capacity and we’re excited about getting that started.

We’ve actually, have received the pipe, a lot of the pipe that’s going to go in the ground and the construction is beginning.

Doug Miller

Okay, I think a couple of main points, with this environment one of our main focuses around here is to try to get our debt down. I would love to have this paid down by a billion dollars sometime this year just so we can have some dry powder in case some opportunity comes in.

Number two, we had a Board meeting in July, and we showed the Board locations inside the company ranging anywhere from 25 to 35,000 locations on our existing acreage. About half of those potential locations are in the Haynesville and the Marcellus so you can see that we have a lot of work to do and a lot of potential and I think, I think at year end we just booked the Oden well, and that was booked as a 6 Bcf well for these reserves and then we booked two offsets which is the way its being done.

I would say that the early results on that from a 6 Bcf well were significantly ahead of that. So although its too early to say, I would say there’s some betting going on around here that that could approach doubling that so, I think that’s what we’re hoping for. Again its too early to talk about but the results on the productions rates on these first two wells are very exciting and I think [Petrohawk] is having some of the same luck as far as down in Desoto Parish so hopefully we’ll be able to have some reserve adds on both us and Petrohawk down there.

With that I’m going to open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Leo Mariani – RBC Capital Markets

Leo Mariani – RBC Capital Markets

In terms of your asset sale program, you kind of said it was spread out, amongst some different areas, just wanted to see if you are still trying to sell that East Texas piece as well.

Doug Miller

We are, we have actually two little fields over in East Texas. I think we had somebody in, we’re actually exchanging PSAs on it as we speak.

Leo Mariani – RBC Capital Markets

In terms of some of your other small asset sales you talked about starting in the fourth quarter any idea on in terms of where you are at in the process, have you got data rooms, have you got them on internet sites, trying to get a sense of when you expect maybe some proceeds, do you think second quarter would be reasonable.

Doug Miller

I don’t think the second quarter, we’ve kind of scheduled it between the second quarter all the way through to the fourth quarter. There are 18 different packages, Jacobi’s group, we actually have four different bankers running four different processes. Have they started yet John?

John Jacobi

We’re just finishing up getting them the data and they should be opening their rooms in the next few weeks.

Doug Miller

The answer we’re going fast forward on those things, I think there’s 18 different packages some of which will end up being auctioned.

John Jacobi

Actually the auction process is April.

Doug Miller

Okay so those will close, but the other ones, estimated value, $5, $600 million, and we don’t have to sell them. We’re not going to take discounts but the bottom line is the market is changed. Those were probably worth a billion dollars six months ago and are probably worth $500 million today. So we’re going to go fast as we can and a lot of people think there are no buyers out there. That is not right. On our East Texas package we have 44 CAs signed, we had 22 visits to the data room and we had 14 bids. And now the one thing that is different then ever before is we had no public companies in the room.

There’s a lot of private companies out there, some of which are backed by the [Encaps] of the world, some of which are just private guys that have money. So that’s was kind of different from normal.

Leo Mariani – RBC Capital Markets

Jumping over to your production guidance for 2009, just noticing that your second quarter guidance and the third quarter guidance are kind of flat just wondering if that has to do with the timing of some of the infrastructure in the Haynesville and bringing those wells on.

Paul Rudnicki

Really its more of a reflection of the rigs ramping up during the year. That’s kind of the low and the high but we’re going to be drilling, I think that most of the rigs end up showing up by June, so we’re kind of ramping up through June.

Doug Miller

I think we have four rigs running today. We have some coming in May, June, July going to seven and then maybe another rig or two at the end of the year, but we have four operated rigs running today and keep in mind Paul is sandbagging you a little because the wells that he’s putting in there you’re estimating what?

Paul Rudnicki

Giving ourselves a good range.

Doug Miller

Okay, a good range. I guess that means he says he isn’t sandbagging you.

Paul Rudnicki

It really just reflects when you bring on these extra rigs, we’re looking at 60-day type rig to production, spud to production so when they come on its going to take a couple of months to 60 to 70 days before they start producing.

Leo Mariani – RBC Capital Markets

With respect to your Haynesville program in 2009 obviously you mentioned the fact that you want to drill wells that you can immediately bring to production, are you also going to try to test a lot of your acreage in some of the different areas, kind of test the four corners if you will.

Hal Hickey

We feel like we did a lot of the testing in 2008. We feel pretty good about where we are. Now there’s, to your point, there’s definitely going to be some testing involved but the drilling we’re going to do is going to do a couple of things for us. Its going to lock up some primary term leasehold and make it HPP and its also going to be drilled in areas where we definitely have market and in areas where we think we’ve got some great opportunities.

Doug Miller

We’ve drilled verticals and done coring already so hopefully the science fair is pretty complete.

Operator

Your next question comes from the line of David Heikkinen - Tudor Pickering

David Heikkinen - Tudor Pickering

Thinking about regional production first just for the fourth quarter, can you give us a breakdown of what was Appalachia, East Texas, mid continent and then I guess—

Doug Miller

I’m going to do it off the top of my head and you yell at me Hal, seemed like, we look at this every week and we ranged in Appalachia anywhere from 55 to 60 and I think that would be a good number and put one right in the middle of that and that’s where we are today. Mid continent we averaged anywhere from 65 to 70 during that time and you can put one probably on the low end of that today because we don’t have any rigs running. West Texas 30 to 35 million a day and we’re probably 32 today. And East Texas North Louisiana, 250, right at 250, increasing as we speak so I hope that added up to around 400.

David Heikkinen - Tudor Pickering

Looking at what you’re doing in the Haynesville and as you look at your acreage, I’m just trying to think through, you drilled the well up to the north I guess in Marian County, what are you seeing as far as different, that didn’t work, are you seeing any differences, are you concentrated in one area, your acreage is held, just trying to get an idea of—

Doug Miller

Yes, when we drilled in Marian County we found no shale, that was one of the main differences, or very thin. The thickest part with the highest pressures are what Hal outlined, Desoto Parish, Caddo, Harrison County. And that’s, we have about 55,000 acres in those two areas. That will be our concentration. To date all the great results that you’re hearing from Petrohawk and us happen to circle right around that Desoto area but we’re drilling one up in Caddo County right now and we’re actually in a partner with Petrohawk up there also in Caddo County.

The thickness is there, and the coring has been done so we’re excited to see how that works. Its actually thicker up in Caddo County then it is in Desoto Parish.

David Heikkinen - Tudor Pickering

One of the things that we’ve seen, I think the Chesapeake joint venture strategy has been a pretty effective way for them to secure capital, how do you think about that as an opportunity.

Doug Miller

I wish we had [Flories] paying for all our drilling. I’m kidding. We have had some discussions on some joint ventures. We continue to discuss it. We have not made a deal with anybody but we continue to talk.

David Heikkinen - Tudor Pickering

And then in the Marcellus, in the center of the state there’s been some discussion of whether or not you have a frac barrier between the shale and the [ariscany] that has water, are you seeing anything there that would make you think you could frac into water or any of the details.

Doug Miller

I’m going to let Hal answer but he’s shaking his head no, go ahead Hal.

Hal Hickey

We haven’t seen any big issues there with the results we’ve had to date with water at all.

Doug Miller

And we have drilled vertical wells in the center of the state, around Indiana and Center County and Clearfield. I don’t think so, I don’t think we have a problem with that.

David Heikkinen - Tudor Pickering

And so the seismic that you’re shooting and the geologic issues, that’s just faulting, [coughing] faults, that type of thing.

Hal Hickey

Exactly.

Doug Miller

The biggest problem that we ran into over in Center County which is why we got those short laterals is we went down and found the Marcellus and started drilling and all of a sudden we found 150 foot fault at 8100 feet, so we had to quit. So just finding those faults is going to really help us. These clearly are going to be more productive wells with the longer lateral you can get in.

Operator

Your next question comes from the line of Joe Allman – JPMorgan

Joe Allman – JPMorgan

In terms of the negative reserve revisions, first the price related negative reserve revision, what’s the breakout there proved developed versus [puds].

Hal Hickey

I’ll get that number for you.

Doug Miller

I think you stumped us Joe. I hate it when that happens. One of the big problems that both in the Cotton Valley—

Hal Hickey

The bulk of it is puds obviously.

Doug Miller

Puds go on economic.

Hal Hickey

I don’t have an exact number but its definitely, definitely dominated by the puds size, minimal PDP.

Doug Miller

But you always lose, any time gas goes down if you have a 40-year reserve life up in Appalachia, part of that tail is going to go away but none of the economics go away.

Joe Allman – JPMorgan

So how about on the performance related revision, same question, what’s the breakout there proved developed versus puds.

Doug Miller

I think a lot of that was puds.

Hal Hickey

It was, revisions on the acquisition in Appalachia, we had about 80 Bcf there, about 66 of it was due to the spacing, the cultural, the topography, and about 13 of that was due to pricing, and then on the pricing breakout the bulk of that is going to be puds for sure, probably 80% to 90%.

Doug Miller

We thought we had 8,000 locations mid year at $8 gas, I don’t think we have any locations we would drill up there on the [shelf] today, if you’re trying to make a 20% IRR. Just kind of the way they go.

Hal Hickey

West Texas, we had about a 64, 65 Bcf drop there, about 48 of that was due to the discussion we had earlier about oil, gas, and not being as productive as we would have liked on the gas side. We had about 16 Bcf of that 64, 65 was due to pricing.

Joe Allman – JPMorgan

So on Appalachia it sounds like that would all be puds basically right?

Hal Hickey

I think so, yes.

Joe Allman – JPMorgan

And then in west Texas it sounds like that would pretty much be puds too because you thought you were going to get gas and—

Doug Miller

You got a little oil. Let me have Hal detail that a little more and get back to you.

Joe Allman – JPMorgan

The PV10, I’m not sure I saw your PV10 in any of your documents, do you have a pre-tax PV10, overall company.

Paul Rudnicki

Again on the year end pricing we’ll be $2.5 billion PV10 pre-tax and $2.2 after tax.

Joe Allman – JPMorgan

Do you have a breakout of proved developed PV10 versus the puds.

Paul Rudnicki

Might have to get back to you on that one.

Doug Miller

Its going to be significant.

Joe Allman – JPMorgan

In terms of the Haynesville you’re now looking at 4.5 Tcfe of potential, what kind of EUR assumption are you using there and how are you risking the acreage there.

Hal Hickey

Well its specific to the well locations. We didn’t go in and use a blanket EUR we’ve actually got them from five to six up to 15 to 16. So its very detailed look that was based on some geologic and reservoir parameters.

Doug Miller

We hired an independent guy to do this and that’s how we came up with these numbers, so we’ve actually got them to go down to four.

Joe Allman – JPMorgan

How much of the acreage are you risking, are you assuming that pretty much all you acreage works or are you 50% or what.

Hal Hickey

We’ve actually honed in on about 70 to 75,000 of the acres that we think really work in this analysis.

Doug Miller

And keep in mind a 4 Bcf well is you spend $10 million doesn’t hit the radar. That’s a basically an uneconomic well today.

Hal Hickey

What you do there, is you actually drill the vertical and ultimately comingle that with the Cotton Valley so you’d have a different type of production but the [6,6] and above its definitely a horizontal play and that’s what we view this thing as, a horizontal play, 70 to 75,000 acres work economically right now.

Joe Allman – JPMorgan

You have 34 wells this year, most of those are really going to be in a concentrated area.

Hal Hickey

Correct, most of those are going to be on the Louisiana side, most of them will be in Desoto Parish.

Operator

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

Brian Singer – Goldman Sachs

On the Haynesville, what have you assumed in your production guidance in terms of maybe the rates that some of these well come on and to the extent that they, you see more of the wells like the first two that you’ve drilled, would you expect to beat production guidance or just spend less money and drill fewer wells elsewhere.

Paul Rudnicki

No I think that the guidance we’ve laid out is basically, if we get 20 million a day wells, we’ll be closer to the high end, if we get 10 million a day wells, we’ll be closer to the low end in terms of gross IPs.

Brian Singer – Goldman Sachs

With regards to debt coming due, the $300 million coming that you refinanced now due in early 2010, do you feel like you need the asset sales to pay that down or do you think internally generated cash flow can do that to the extent that you may cut a little bit from your current plan.

Paul Rudnicki

No I think it’s the latter, we’re looking to have nearly $900 million of EBITDA with the capital adjustments that we’ve talked about, if we can get that down closer to the $500 million we’re going to have $260 million of free cash flow.

Doug Miller

We plan on paying that off regardless if we have any asset sales and if we have an asset sale, the way that works is some piece of that will end up going to reduce bank and then the rest of it can be released to pay down on that note.

Paul Rudnicki

The asset sales will only accelerate it.

Doug Miller

Yes.

Brian Singer – Goldman Sachs

And so I guess implicit in kind of a $200 million free cash number is that you don’t expect any restrictions in terms of, or reductions in your existing credit facility.

Doug Miller

No we don’t.

Paul Rudnicki

Not at all.

Brian Singer – Goldman Sachs

What level of confidence do you have in that, I guess things are starting to move towards April 1.

Doug Miller

High. I think we have a high, the one challenge you have right now is we have 41 banks in our credit facility. We have two credit facilities and we continually monitor, we’re actually going to have an outing with them this weekend. The biggest challenge there is whose in business and who isn’t and whose merged and who hasn’t and who wants to reduce and who doesn’t. So that’s continually but I think the banks are still in business. JPMorgan leads our bank facility. There are several banks, [inaudible] etc. that have indicated, Wells Fargo, have indicated they’re not only happy, they’re prepared to go up subject to certain things.

We’re not worried. I think the biggest challenge we have is some of these mergers because sometimes a merger creates a little slightly larger facility then they desire, so we’re working that. I don’t think its going to be a problem. The other think that’s happening right now is we have had the guy that worked with the SEC in and if you see how some of these bookings can take place from our production standpoint I don’t think we’re going to have any problems.

And then you’re going to see proved reserves in these shale properties, its something that we’re already working on.

Brian Singer – Goldman Sachs

You seemed in your earlier comments, to indicate some greater bullishness on the East Texas portion of the Haynesville especially moving west, I think you referenced Greg County, can you talk about what’s driving that.

Hal Hickey

We’re just balancing the appropriate pressures and thicknesses that make us interested in looking at what the shale play entails there.

Doug Miller

We had some acreage over there on an acquisition we made last year, we went ahead and drilled a vertical well through the Haynesville. We got gas shows, we had good thickness and I think early returns are that’s something that we’ll probably look at. Now the question is, is it all Haynesville, or is it Bossier and Haynesville shales, but for sure its shales.

Brian Singer – Goldman Sachs

And when do you expect more details, or do you have a test—

Hal Hickey

We’re working on that as we speak.

Doug Miller

I’d say that would be a second half program.

Operator

Your next question comes from the line of Ellen Hannan – Weeden

Ellen Hannan – Weeden

On the Haynesville could you tell us what your completed well costs were on those first two wells, and also on the header expansion that you’re building, how much of that capacity are you reserving for yourself versus third party.

Doug Miller

Do we have, is all the cost in on that? I’d say $10 million.

Steve Smith

I think the [inaudible] cost is $10 million on the first two wells and we’re kind of budgeting over the next few around 9.5 and we are starting to get some good reductions in frac costs and other costs so we’re optimistic that over the period of a year or so we’d get that end of the 8.5.

Doug Miller

I think we’re trying to get it down to 8.5 by a combination of cost reduction and just fewer drill days but first couple of wells we did do a pilot hole and the first well we did a core so they were $10 million plus wells and as the science fairs finish I think the main reduction is going to be drill time.

Hal Hickey

One other thing that I will say is very encouraging too as far as looking at cost reductions on these wells, we had bid our first couple of 10 stage fracs and we’ve rebid since then and actually the costs have come down between 15% and 20% for similar fracs. So as we’re rebidding these things and as we’re, and profit become more available the costs are coming down significantly.

Ellen Hannan – Weeden

How much is the capacity are you reserving for yourself versus third parties.

Steve Smith

Right now we are currently are planning 30% to 40% reserve for us in the next two years.

Ellen Hannan – Weeden

On the Marcellus in terms of rates of return and also in terms of ultimate recoverable reserves to EXCO, that’s clearly your biggest play over the long-term, can you outline for us in terms of what are your biggest hurdles to developing that asset and in terms of priorities, is it seismic, is it drilling, is the fit for purpose rigs, is it a combination of the above.

Doug Miller

I think right now the biggest hurdle we have is there’s 40 different permitting groups that we’re dealing with. I think once, and I think, we’re two steps forward, one step back on that it seems like every month. We’re spending a lot of time I think we’re going to get there, there are permits being issued. I think the next challenge is going to be pipeline and gathering and we’re in discussions right now, Jacobi’s group is in discussions, on some joint ventures to put in some larger size pipe that has the [inaudible] connections with some of the inner states. I think that will be the second challenge.

And built for purpose rigs are available. We have one or two of them available. We’re probably going to hold one on them down here. But I think, you can see that [Range] is having some success and we’re kind of paying attention to what they’re doing there but I think what we would like to have before we start any significant drilling program is a pipeline available so we can sell the gas.

Hal Hickey

I think another one of the biggest challenges and you hinted at it when you talked about the permitting is the accessibility and use of water. That is going to be a major, major initiative that we have working with the governmental authorities and with our other competitors and figuring out the best way to access water, use water, dispose of water.

Operator

Your next question comes from the line of Unspecified Analyst – Stone Harbor

Unspecified Analyst – Stone Harbor

Just to clarify on the asset sales package, at one point there was a $5 to $600 million mention, is that just referring to the 14 packages in East Texas or is that the overall asset program that you talked about.

Doug Miller

That’s the overall asset program. East Texas probably is in the $125 to $175 range.

Unspecified Analyst – Stone Harbor

How much reserve are we talking about related to this.

Doug Miller

You’re killing me, hold on a second. How much? 75?

Steve Smith

Yes, 75 to 80 Bcf.

Doug Miller

And the total package, everything.

Steve Smith

Glade water—

Doug Miller

Oh, just glade water, how about the whole package. We’ll have to get you that, I’m not sure, I’ve seen it but I don’t have it on the tip of my tongue.

Operator

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

Doug Miller

I appreciate everybody being on. I hope we answered most of the questions. I think what you’re going to see this year is you’re going to see some, we have a lot of excitement around here, a lot of people working on rigs, especially in the Haynesville, a lot of people working on a few asset sales so we’re going to be getting debt paid off and we’re going to be growing this company at the same time. So we’re excited and stay tuned. We’re going to have a great year. Thanks everybody.

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Source: EXCO Resources, Inc. Q4 2008 Earnings Call Transcript
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