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EXCO Resources, Inc. (NYSE:XCO)

Q3 2008 Earnings Call

November 6, 2008 11:00 am ET

Executives

Doug Miller - Chairman

Steve Smith - Vice Chairman and President

Doug Ramsey - Chief Financial Officer

Hal Hickey - Chief Operating Officer

Mark Wilson - Chief Accounting Officer

Paul Rudnicki - Vice President

John Jacobi - Vice President

Analysts

[Leo Mariani]

[Catherine Cybulski] - Jefferies

Howard Flinker - Flinker & Co.

David Heikkinen - Tudor Pickering Hold

Shannon Nome - Deutsche Bank

[David Barberis] - Candy Tuck

Operator

Good morning. My name is Catherine and I'll be your conference operator today. At this time, I would like to welcome everyone to EXCO Resources third quarter 2008 earnings release conference call. All lines have been placed on mute to prevent in order to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator instructions) Thank you.

Mr. Miller, you may begin.

Doug Miller

Thank you, Catherine. My name is Doug Miller. I am Chairman of EXCO and we’re here for our third quarter conference call. With me today I have Steve Smith, our Vice Chairman and President. Doug Ramsey who's our CFO; Hal Hickey, our Chief Operating Officer; Mark Wilson, our Chief Accounting Officer; Paul Rudnicki, our Vice President of a lot of stuff and of course we have two lawyers here to make sure I don’t speak out of turn, Lenny Boning (ph) and Justin Clark.

With that, before we get started, I will turn it over to Mr. Ramsey to read what he has to read.

Doug Ramsey

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 slide. The first page that will come up after you hit the Investor Relations tab has the presentation slide 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 operating performance, structure and results, business strategies, market prices and future commodity price, risk management activities, plans and forecasts, and other statements that are not historical facts or 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?

Doug Miller

Okay. Thanks, Doug. And I know nobody’s having fun. We have been in a process here for the last two months of trying to prepare a capital program for ’09 for our board. We have a board meeting in two weeks to go over our capital program and it is going to be quite a challenge.

I have driven our engineers crazy over the last two months. We changed the price decks on them three different times which means I have to rerun all of our producing properties. When we went into it, oil was at 100 and gas was at 9 and so we gave an 80 and 8. Halfway through we gave them 70 and then 7 and two weeks ago we told them to run a model at 50 and 5 just so we could run some sensitivity across cases.

So and then last week we had an all hands meeting. We had 80 people off site going over each different area and do our own modeling and so I think what you’re going to see this year is we were prepared going in to increase our capital budget under an 80 and 8 scenario up to 850 million of drilling crude for ’09 but with the turmoil in the market, I think what we’re going to do is probably propose a variable rate and we’re going to go over that a little with you today. I think we’re already in certain areas with the current cost structure.

We do have areas were under $6.50. We will be shoring back drilling and I think Hal will share that with you later on but if we weren’t public, we’d be cheering. We had a record quarter. We averaged 397 million a day and that includes oil production of slightly over 6,000 barrels a day at 6 to 1.

We did get affected by the hurricane but it only averaged about 3 million a day so I think we reported 397 average for the quarter, which we’re very proud of. Everybody did a great job, even with effects of the hurricane, had to more with plants and liquids, so we had some of the third party plants were shut down so while they were shut down, we had to shut in some of our gas.

Currently, we’re drilling away and completing and everybody’s doing a great job. I think last week we were slightly over 406 million a day which included in excess of 6,500 barrels and so to get to 406, you got to do 6 to 1, but that was an all-time record on our oil production.

Year-over-year, production was up 24%. Our EBITDA which I think we forecast earlier in the year to be around 230 came in at 248 – 249, so we’re happy with that.

We have spent a lot of time during the year doing science work in both the Marcellus area and the Haynesville area. All of our people have been excited about the results. We’re going to talk to you about our first two lateral horizontal wells up in the Marcellus. We continue to be excited there. We still have challenges ahead on permitting and pipeline and water but we’re working through those and our first results are very encouraging.

We drilled several vertical wells across our acreage in the Haynesville play. We’ve had very, very good results on the verticals. We have drilled our first horizontal well and Hal will go over that with you. We do have a core analysis.

We have completed a well. Completed meaning we’ve logged, cored, and cased and we have to case that to 4,400 feet. We’re planning on a 10-stage frac, as soon as we can get the propent in, we’re struggling getting propent, and as soon as we get the propent in we will attempt the 10th stage frac and I think our guys are excited about it. I think we’ve uncovered rock and we’re very comfortable on how we’re going to attempt to do it and we’re encouraged with that.

With that, I think with commodities, I wish somebody could tell me what commodities were going to be. I can tell you this, across our portfolio at $6.50 NYMEX, we will be slowing down in certain areas at Cotton Valley over in northeast Texas and north Louisiana, has marginal economics at 6.50. So we’ll be at 6.50 and below, we’ll be slowing down there. Up in Appalachia on the shallow gas 6.50, it seems to be the number with current cost. So, we’ll be slowing down there.

But both the Haynesville and the Marcellus continue to work. The rate of returns still work, and I would say that you would see us active in both areas down to $5. We have started having meetings with some of our suppliers, both steel, drilling and frac. And prices, we sense they’re starting to come down, but they’re not down yet. So, we’re going to have meetings with them, and see if there’s anything we can do together to maybe lower rates, to keep some rigs going, but as of right now, I think we’re planning on going to the Board with kind of a $350 million to $850 million capital program.

Now, that’s going to be a challenge, we’ve never done that before, but I think with the talented people we have and the quality people, we’ve had these meetings in the last two weeks, I think they’re prepared for it, it is going to be tough, but everyday is a new day. I’ve seen a lot over the last four years, Boon has seen a lot over the last 50 years, but I don’t think anybody has ever seen what has happened in the last 90 days. We’ve seen commodities go up and down, we’ve seen oil go from 147 to 60. We’ve seen gas go from 13 to 6 in that 90 days, as you can tell by our hedge non-cash gain, almost a billion dollars quarter-over-quarter.

But what we haven’t seen, and we’ve seen commodities go up and down in longer order, but what we haven’t seen a total lock down in the financial markets around the world. And I think the equity markets have stopped, the debt markets are shut down, and I know the government is trying to deal with it, but it’s tough watching TV every morning trying to figure out what’s going on because rates are coming down. Two weeks ago we’re looking at LIBOR rate that was around 4.5% and I noticed this morning they set it at 238 – 239, so that kind of helps our bank credit facility.

With that, I know everybody has lot of question. So, we’re going to go through the charts that are on the internet, I’m on slide five. And I think I’m going to turn it over to Steve Smith right now, we’ll go through this and open up for questions.

Steve Smith

Let’s go at slide seven, we covered most of this already, but a couple of points that I wanted to make. Our adjusted EBITDA was 249 million for the quarter. Our guidance for the fourth quarter will be, I think around 230 million and that’s at 6.50 gas and $65 oil. And so we’re still expecting a good strong fourth quarter in terms of cash flows and EBITDA as well. As Doug said, oil is starting to become as semi-important part of our program, we were at 5,200 barrels a day last year in this quarter and we’re up at 6,400 barrels, so we’re pretty excited about that aspect.

Pricing of course had a little bit of impact on us compared to Q2 because the overall equivalent price is down $0.93 or so between quarters and so obviously that had some impact, but the increased production put us in pretty good stead.

Over on page eight, I’m not going to get in to a lot of details, because Hal is. Just bottom line is the Haynesville was going like we planned. We’ve spent a lot of money on science, we drilled a lot of vertical wells and done a lot of cores and tested a lot of different propents and I think we’re ready to roll.

Now if we can just get the propent we’ll be up and running with our Haynesville horizontal activity. The Marcellus is another area that we’re still very excited about, but the economics look good even at today’s prices and we’ve got some drilling going on there both in the horizontal wells and vertical. The Huron is about what we expected it to be, it’s still economic, but obviously the volumes they are not as strong as they are in Marcellus. The midstream we’ve got it where we want it. We’ve expanded our TGG pipeline by 50-some miles, so a 20-inch pipe and that’s starting to fill up, so that’s going well.

Doug Miller

We set a record on that last week also. I think we’ve moved 555 million a day through that. So a lot of activity in East Texas and North Louisiana in the pipeline and lot of potential there.

Steve Smith

Page nine is a slide that I always like to share because I think it’s important to explain. I mean it explains fully why we hedge our production. The Q3 cash operating margins is $7.29, the Q2 was 7.62 so in spite of the apparently dramatic light quarter drop in prices, we’re still holding our own.

Operating costs were $1.13 in the third quarter about $1.10 in the second. So again, we expect all of our costs including our drilling costs to start coming down as fuel cost and supplies and everything else is sort of adjust to the new pricing or a different pricing environment. But that had not started really to show itself in the third quarter.

On page 10 is the discussion of our ceiling test write-down that we discussed in the press release. That write-down was about 1.2 billion in the third quarter. It was largely offset by pre-tax mark-to-market gain on our derivatives. And an interesting point to make here, if you’d price our hedging gain, non-cash mark-to-market gain at the end of year, spot prices like you have to do to compute the ceiling test, it was almost a total offset. So again, that shows an important part of hedging.

When we make acquisitions and take on debt, we hedge. So that was an important factor. Another really very important factor is, as of September 30, the basis differentials in all of our areas including Appalachia had widened to the point where it was or about half of the write down, I think resulted in the widening basis and we’ve shown here by area what those basis differentials are.

One other thing is, there is some discussion now at the SEC about changing the ceiling test calculation. And one of the things that has been throwing out I believe is using an average price up through the reporting date. Had we used an average price up through 9/30 of 2008, there would have been no ceiling test write-downs.

So, in any event, it doesn’t affect our covenants. It doesn’t affect our liquidity. What it does affect is our DD&A rate going forward, it will be about 275 as opposed to north of three.

On page 11, just a quick liquidity update and where we stand on capital spending. We have reaffirmed our borrowing base on October 20 with all of our lenders. We are in negotiations and discussions with our lenders to refinance, renew and extend the $300 million term loan and we consider those negotiations to be going well.

We’ve got a sale pending in the data room right now, some East Texas assets. We got other assets that we’re looking at in our portfolio as we always do. We, as you will recall, have made sales of non core assets every year for several years so we’re looking at that at this point too.

Capital spending, fourth quarter is going to be much lower than the third. One of the reasons why is because our capital expenditures for leasing in Haynesville and Marcellus shales has come to an end. We just about got it done. Of course, you’re going to always have clean-ups to farm units et cetera. But we spend a lot, about $75 million in the third quarter on acreage acquisitions and that would be very low if this—in the low teens if at all, during the fourth quarter.

We got our midstream expansion done and so that capital will not recur in the fourth quarter. So, overall, we will be down about 35% of which 10% to 15%, I believe the number is, is due to laying down some rigs in the areas where economics aren’t quite so good at 6.50 gas such as the Cotton Valley and the Shale at Appalachia. So we are laying down these rigs and I’ll get into it a little bit more.

In ’09, as Doug said, is going to be a flexible budget depending on what commodity products is due, but the one thing that will happen is we’re going to be spending our time and money on horizontal shale and development. And we’re going to be spending both in the Marcellus and the Haynesville and we’re going to spend a lot of money on some exploitation projects. We’ve had good success in the past year in helping to hold our base decline at a minimum, due to work overs and many project we’ve done and Hal will get into it. But that will also be an area of emphasis for us.

So, on page 12, I’m going to turn it over to Doug Ramsey and let him talk a little bit about where we are on financial position has it been in the quarter and on more current date.

Doug Ramsey

Thanks, Steve. At the end of the quarter, we had $95 million of cash. Our debt position included 2.2 billion of revolving credit outstanding. Our bonds are still out at 445 million and then, we added the term loan of 300 million which funded our Danville acquisition on July 15 so total debt out is just under $3 billion. And then on July 18, our preferred stock was converted into common so we take up $2 billion in the common shareholders equity section. That gives us a debt to cap number of 53%.

As Steve mentioned, our borrowing base has been reaffirmed, it’s $2.475 billion. That leaves us availability of $238 million and when you add the cash, it’s $333 million of essentially dry powder. Fast forward to November 3, the only change there we’re just going through our normal revenue and expense cycles during the month, so cash is down a little bit to 53 million. No changes in the debt positions.

A couple things also to note, on the cost of our revolving credit, we have switched recently out of our LIBOR Tranches back into our alternate base rate which is our prime rate equivalent because that actually went up being most expensive for us and as Doug mentioned, with the LIBOR rate coming down, we’re now switching back into the LIBOR Tranches and we started doing that here in the last couple of days.

With that, I’ll turn it over to Paul Rudnicki who’s going to cover the derivative positions we have and also go over the guidance.

Paul Rudnicki

Thanks, Doug. As you can see on page 13, we’ve laid out our current derivatives as of November 3 and as you can see we’re pretty well-hedged for the rest of this year, based on our projected level of production, we’re about 78% hedged.

During the quarter, we did had a little bit of gas but really focused on the oil hedges and you can see that we’ve gotten a lot of oil hedges off over a $100, a lot of more in the $120 average down with some existing ones to get to about $80 for next year and $105 to $112 for the following years.

So as we sit today, we have 220 Bcf hedged at an average price of about $9.14. We do have some interest rates swaps in place as well, $700 million of our borrowing basis is swapped at 2.66% plus the usual margin and those will last through February of 2010. We have started adding some basis hedges in some of our areas focusing mainly on the Mid-Continent and we’ll continue to do so.

On page 14, it’s just a comparison of our actuals versus the guidance that we provided for the third quarter. As Doug had mentioned, our production came in right in line with what we expected. We were impacted by the hurricanes equivalent to $3 million a day which would allow us to be right in the midpoint. Oil differentials have narrowed, that was positive. Our gas differentials came in right on line.

LOE came in a little bit under our low end of the range and we hope to continue that going forward. Production tax rates came in a little below as we’ve been able to get some our tight gas sand credits in and the rest of it kind of pretty much is in line. Interest expense came in below, again during the quarter, LIBOR rates were in pretty shape. And again at the bottom line, our EBITDA came in at about $250 million versus the $230 midpoint of the guidance.

Going on page 15, just showing where our guidance is for the fourth quarter. We have not adjusted our production guidance. We’re sticking with what we had out before. We have adjusted our differentials to NYMEX to reflect two things. One of them is the widened differentials in the premium in the Permian and the Mid-Continent, and as well as an accounting change that we’re going to make in the fourth quarter which is to start reporting our midstream segment as a complete stand-alone.

So we will show what really makes sense, which is the true revenue and expenses of that system which in effect will lower our differentials a little bit because we’ll be reflecting the charges that we charge ourselves for moving our own gas.

Other than that, the only other major change we made was reflecting the lower DD&A rate going forward. And one other thing to point out on the interest expense, about $6 to $7 million of that will be non-cash, just amortization. And so the cash interest expense will be in the $40 to $42 million range. And again, we’re guiding towards about the $230 to $235 million EBITDA for the quarter.

With that, I’ll turn it over to Hal to go over the operational review.

Hal Hickey

Thank you. For those of you following along, we’re on slide 17 in your package.

Before I get in to the slides, I just want to take a bit of time and talk about what we’ve done over the last three months and what we’re doing in preparation for the future and then response to the current environment.

We had an excellent, excellent operational quarter. Our people are excited about the assets they’re working on. We’ve got a great set of assets and our people are learning more and more about them and we’re well positioned to move forward. We understand better today. Of course, how are we going to move forward to develop these assets?

And I’m going to give you some examples as we go through them, what we’ve done and how we prepared for the future. But that said, we’re working very diligently on a flexible capital budget. We’re going to present that to the board later this month and of course we’ll come out with an announcement immediately after the board approves our capital spending level for next year.

But what’s key is we’re building in flexibility, so we’ll be able to adapt our program to what the commodity prices tell us to do. And we’ve had quotes recently, we’ve been in discussions recently with some of our key suppliers. And one of the things about this industry that’s really exciting to me and our people is the way that our suppliers work with us to respond to commodity prices.

We’ve talked to our drillers. We’ve talked to our steel suppliers. We’ve talked to our completion of fracturing service providers. And we’re readjusting some of our costs and rates in preparation for moving forward in today’s environment, but that said, we’re well-positioned now to move forward in the shales and in a lot of our conventional drilling.

And one thing I want to point out that’s very, very important, while there are definitely areas where the economics start forcing you to question your activity levels going forward, even in a lot of those areas, there are specific wells that have very, very strong economics and we will continue to drill a lot of them. So we’re well-positioned to move forward.

Okay, let’s talk for a minute about the slides. Starting on page 17, again. East Texas, north Louisiana, our shale acquisition program is effectively done when it comes to spending money in leasing. We’re still going to be filling in some blanks and adding to our base position but any large or significant acreage acquisitions, we’re done with that. We’ve got a great position.

I think our drilling and our competitor activity tells us that we are in the heart of the play. DeSoto Parish, Caddo Parish, Harrison County, Texas well suited and that’s where you’re going to see our activity. And we’re going to continue to test in the future some other areas, but the bulk of our activity is going to be right there, okay.

In vertical wells, we’ve drilled eight wells in four counties and parishes, the bulk of those have been in Caddo, De Soto and Harrison. We’ve seen really good casing flowing casing pressures. And we’ve done some single-stage frac completions through this point. We’ve seen really, really good results from those and you’ve seen single stage flow rates up to 2.8 million a day.

Now, we drilled our first operated horizontal well, the Oden 6H #1 down in DeSoto Parish. We successfully cut 180 feet of core. We drilled that thing to over 16,000 feet. We cemented our 4,400 foot lateral section in place and we’re now preparing to complete that thing and we plan to complete it with ten frac stages. Standby for news on that but we’re excited about what those results will be. We TD’d our first non-operated horizontal well in DeSoto Parish, again with over 4000 feet of lateral section. And we’ve spud our second operated well as of this week. That’s going to be another horizontal well down in DeSoto.

Later this month, we’re going to receive the second of five 1,500 horsepower rigs that we’ll be using over the next two to three years. Most of these are three-year commitments. All these 1,500 horsepower top drive rigs that are going to be drilled in our horizontals and you’re going to see a lot of activity in this area.

Slide 18, talking about Vernon. Again, continuing to expand the field, the one to the South and the West, still doing some infield drilling. This week I’m happy to announce, we completed the well that’s producing an excess of 10 million a day. It’s not in our production numbers at this point, but it’s a very, very strong well. Now these things come off fast, we’ve always said that, they have large decline rates, typical for tight sand, typical for Cotton Valley, but a very strong well.

We’re reprocessing seismic as we look at some prospective acres just to the North of Vernon property. You’ve heard me talk about that before. And we’re seeing some flattening in our drilling costs, not only in Vernon, but really across the portfolio. We’ve had some bidding activities that had taken place that we’ve initiated. We’ve had some service providers actually come to us and offer some pricing that’s going to be compatible with today’s environment. So, very active here, we’ve had four rigs running, we’re probably going to reduce that to three. In fact not probably, we’re definitely going to reduce that to three, but still going to be an active area for us as we drill in Vernon.

Now one of the things you’re going to see not only at Vernon but across the portfolio, is we’re going to be very, very focused over the next year working on exploitation projects behind pipe projects, working on existing well bores, trying to get increase volumes and arrest the base decline. So we’re seeing a lot of that occur. We’ve completed a field compression project.

As far as setting compression, we’re working on finalizing the operation of that, but I got some data just the other day. One of our areas where we’ve set this new compression, we actually increased our production by between 4% and 5% as a result of lowering the pressure at the well head.

Slide 19 you’ll see other areas in East Texas, North Louisiana. In our Shreveport area, we drilled and completed some 25 wells in the third quarter. IPs of around 900 Mcf a day. Holly/Caspiana remains a big focus area for us there and we’ve continued to show good spud to rig release time here. This is the area where we’ve spend a lot of time drilling down to the Haynesville with vertical wells to both understand the play, delineate the area and increase our HBP position.

We’re working on our costs here. We’re working on our work overs re-completions to arrest our base decline and we’ve reduced our drilling rig down here from five to four, and continue to work diligently in this area.

Now East Texas area, as we’ve announced earlier, we closed an acquisition earlier this quarter in Danville. We’re very excited about our preliminary results there, and drilling in the Cotton Valley and some of our stronger Cotton Valley economics and you will see us drilling there with a couple of rigs.

Now like Steve said, we have initiated an asset sales program, particularly we’ve opened up the data room with some very encouraging results as far as attendance and interest in activity to this point for the potential sale of our Gladewater and Overton fields. And we’re looking at non-core asset sales across the portfolio not just in East Texas, North Louisiana, but this is the one that’s at the head of the bunch.

We maintained (inaudible) units and we just completed a micro seismic frac mapping at Danville to make sure we’re doing the proper things as far as development fracing orientation and such.

Midstream in East Texas, North Louisiana depicted on slide 20. Like Doug said earlier we’ve set records as far as our throughput, just this week we’re at 555 Mmcf a day throughput on our systems. We’ve completed the expansion as Steve said and this thing has a total system capacity of 390 a day without compression, over 530 with compression. And at our TGG system, it’s well situated for continued Cotton Valley development in East Texas and it’s going to continue to add to our bottomline as we continue to add additional volumes into this system but we have already added a significant amount of throughput as after this expansion.

And we started some initial work on the Haynesville header, as we call it, pipeline system over in Northwest Louisiana. This is going to be a 36-inch system. It’s going to connect with some takeaway pipeline capacity that’ll be operated by third parties. But this is going to be a significant piece of pipe that’s going to allow both equity and third parties to move gas out of the Haynesville area. We are very far along in securing rights of way on that. We also have our pipe order that’s actually being rolled and we’ll start taking delivery on that early next year.

Moving over to Appalachia depicted on slide 21. Again production has been in the 60 a day range, a large increase over the third quarter of a year ago. We continue to work on artificial lift enhancements in Central PA, as I mentioned in last quarter, with continued success. The drilling success continues, very much bread and butter Appalachia that’s depicted on this page but we have reduced the rig counts somewhat from 10 down to 6 or 7 in November. We do have a new 1,000 horsepower top-drive rig that’ll be delivered in the second quarter of ’09 that’s going be a long-term commitment drilling our Marcellus shale horizontals.

And speaking of the Marcellus shale going over to slide 22. We’re now drilling the third of our four well 2008 horizontal program. This third well is in Northern West Virginia. The first two were in Central Pennsylvania in the Centre County Area. Now we didn’t get the laterals sectioned out as far as we would have hoped. Typically in these wells, we’ll drill out some 3500 feet in our lateral sections. In one of these wells we got out 1700 feet and one of them we only got 500 feet. The one we’ve got 500 feet, we’ve completed with the one stage frac of course, flowed at a very good rate.

We had spot rate in excess of a million a day. The four stage completion, 1700 feet lateral, about half of what we would have anticipated or half of what we’ll expect going forward as we continue to understand what it’s going to take to orient these things in the most appropriate way and getting our land positions set up so that we can drill the full length that we hoped. But this flowed at a spot rate an excess of 3 million a day at selling well an excess of 2 million day to day. So we’re excited about that. We’ve completed several vertical wells in the Marcellus both in West Virginia and PA. Some of that have been done in normal pressured areas, some in over-pressured areas where initial flow back is on now.

In Huron, we’ve completed five wells to date. Those are all in West Virginia. Spot rates have exceeded 400 Mcf a day, in line with the expectations. We’re going to continue to focus on that frac and make sure that we’re doing the right thing there. But as of this point in time we anticipate to continue to drill there very actively in 2009. So some very active plans in ’08 and moving into ’09 for both the Marcellus and Huron.

And I’ll go over to slide 23 now to talk about some of our other areas. In the Permian-Canyon Sand area, which is predominantly in Irion County, Texas, we drilled 35 gross wells in the third quarter. We’ll drill some 121 wells there full-year. But what’s been a good story here is our oil production. We’ve taken that from just a little over 1,300 barrels a day, a year ago when we took over operations to more than 2,200 barrels of oil day-to-day, very significant piece of our oil growth.

We’re going to drill two wells here in early ’09, so we’re going to earn some contiguous acreage that we’ve acquired in a negotiation with a third party. We’re leasing out here, but that leasing is done now as well just as in the other areas. We’ve got huge position here. We’re going to continue to exploit that position. We’re working with 3D data now to identify the best opportunities on this new acreage we’ve acquired.

At Rockies, we’re completing the Birdseye prospect in the Wind River Basin this month. Mid-continent, another really good story here as far as our volumes in production. We’ve set records here approaching 70 million a day. And again this is another very oily area for us, very good oil, 2,200-2,300 barrels a day and some drillings are going to occur there.

Slide 24 which is the last slide I will talk about, gives a little more color to our capital expenditures. Through the third quarter, we spent nearly $750 million, fourth quarter we’re going to spend about $190 million. Our ’08 spending is going to be right about where we’ve forecasted our budget to be which was $943 million as a free cash flow, we’re going to be right at that number. Now this reduction in spending, $115 million global what we spent in the third quarter reiterate what Steve said, plus leasing, we spent some $75 million leasing in the third quarter that will probably be 10 or less in the fourth.

Our midstream expansion project was completed in the third quarter. So, through the year we probably spent $40 million to $45 million on midstream, we’ll probably spend 5 to 10 at most in the fourth quarter and then our drilling—we have responded, we’ve cut from 32 to 25 rigs and a lot of commodity prices, some of that is on operated rigs and others non-operated but that said is in response to commodity pricing. We will reduce our drilling dollars by some 10% to 15% of what we had forecasted.

So that’s spending here. You think it’s the right thing to do? Working very diligently on a capital budget that we’re going to come back to you with and it’s going to be a flexible capital budget that’ll be positioning us to respond to the commodity prices. With that, I will turn it back over to Mr. Miller.

Doug Miller

Okay, we have an appendix that’s included if anybody wants to go through that but we’ll save that for everybody to read through. Before we open up to questions, I just want to reiterate a couple of things. Most everybody in the conference call we’ve talked to before and I want everybody to understand the reason we have this flexibility going forward is we’ve been doing this the old fashioned way and that is our capital program has always been maintained within our cash flow and our EBITDA.

I know that hasn’t been invoked in the last few years but I think over the next couple of years, you’re going to see why we did it this way, I think we’re going to see somewhere between 300 and 500 rigs going down probably mostly by people that were way overspending their capital budget and is going to be forced to bring it back within. I’m not going to mention any names because a lot them are friends of mine. But because we’ve done that for years, we’re in great shape going in to ’09 and we will continue to drill inside of our EBITDA.

Sometimes we don’t have the explosive growth as everybody else but we will be growing this company and we will be doing it in a way that we’ve done in the past. With that, I’m going to turn it over to questions, I’m sure we have some. So Catherine, if you’re there, let them rip.

Question-and-Answer Session

Operator

Yes, sir. (Operator instructions) Our first question comes from the line of Leo Mariani (ph). Your line is open.

[Leo Mariani]

Good morning to you, guys.

Doug Miller

Good morning.

[Leo Mariani]

I wonder if you give us more color on your current loan negotiations to extend that the term of the $300 million bridge loan refinancing.

Doug Miller

Funny you should ask. We’re in good shape on it. I’ve been working on that myself. Keep in mind that a lot of people that took that were significant shareholders.

We’ve gone out to them and we have a lot of people that did not want to have a firm commitment until after the third quarter was out so they could discuss it. We’re in really good shape on it. I’ve been working with one of our banks—I thinkwe’re all but done. We had 30 people that had indicated an interest. The main 10 have already agreed to roll subject to the third quarter report.

And so, once we get this over with, I kind of expect that we’ll have it signed up next week and then we do have to go to the banks because it is underneath one of our credit facilities but it needs a 51% approval. We’ve already started those discussions so my confidence level is high and I’m acting a syndicate manager on this.

[Leo Mariani]

Okay.

Doug Miller

I mean, we’re going to get it done.

[Leo Mariani]

Okay. Question on your East Texas asset sale package that you guys have been marketing for a couple of months. Just give us a little color on kind of where that stands, did they even close, have you guys bid, that—

Doug Miller

We end our marketing after a couple of months. We hired Tristone to sell it a couple of months ago but in the interim, we decided to do a complete third party engineering review the data room opened last week. It went out, we got CA signed by 20 or 30 people and we had at least 11 signed up and I think four of them last week.

I kind of expect it to go for another week or two and we expect to have bids in by the end of the year. It’s a package that at normal times would bring somewhere between 300 million and 400 million and prices are that—we’ll just see what it brings. If the bids are too low, we won’t sell it.

I mean, it is 24 million a day of gas production with shallow decline rates, with a little bit of development, so it’s a high PDP. In normal times, it would be very easy to finance. In this particular moment in time, there are no banks financing so we’ll see what happens. I think, we’ve only been marketing it really for 2 weeks.

[Leo Mariani]

Okay. Do know what the reserves are associated with that?

Doug Miller

Hal, does.

Hal Hickey

Yes, it’s about 150 to 160 Bcf of crude reserves. More than 80 of that is PDP, some 30 or so is PMP and we've got about 70 or so Bcf of unproved so probably 240-ish..

[Leo Mariani]

Okay, last question for you folks. Just curious on your non-operating Haynesville program, kind of how many wells you participated in thus far and kind of whether or not you have a sense of what you’ll be doing on the non-op side the next three to four months?

Hal Hickey

Well, we’ve had one well like I said that's TD. It’s a horizontal well that was non-operated and it out got over 4,000 foot lateral. We've had a minimal number of vertical wells but we are starting to see some AFEs come in from other third parties besides this first non-operated party that we’re working with. So we’re seeing some AFEs that were proven now. So that activity is picking up and we’ll see more and more of that in the in a while.

Doug Miller

We don’t know exactly the budget is unclear on that. We do know where our partners are in our acreage and depending on who the partner is, we’re going to be very happy to participate. I think we just signed one up last week with Petrohawk so it’s a very small interest so we’re going cooperate. And if there are good operators, we’re going to work with them and give them all the science we have and try to spare these things.

These things are potentially very expensive wells and we have learned through watching Chesapeake and Petrohawk and some of (inaudible), etc cetera, and talking at the service companies. There's definitely some right ways and wrong ways. And so we’re going to share all the information we have with our non-ops.

[Leo Mariani]

Okay, great. Thanks guys.

Doug Miller

Alright, thank you

Operator

Our next question comes from Catherine Cybulski (ph) with Jefferies. Your line is open.

[Catherine Cybulski] - Jefferies

Hi, I know that you guys haven’t set your 2009 budget in stone yet, but looking forward, if you were to think about reducing CapEx below cash flow, I should say would you consider reducing CapEx below cash flow to positively repay some debt or would you rather put that capital into drilling in CapEx.

Doug Miller

That’s easy. If gas price goes down, we’re going to reduce it down to $350 million and with our hedge program, that will be a significant reduction and will pay off $300 million or $400 million of debt. We can pay off the term loan with cash flow next year without any asset sale.

The commodity price are going drive at this capital budget. It will remain underneath our cash flow and it will include free cash that will go to debt retirement.

[Catherine Cybulski] - Jefferies

Okay and with the term loan, it sounds like it’s well on it's way to being done. Do you have a backup plan if it doesn’t go through?

Doug Miller

I do. I do.

[Catherine Cybulski] - Jefferies

Okay. Would you share with us?

Doug Miller

No.

[Catherine Cybulski] - Jefferies

Okay, great. Also just the Cotton Valley and the shallow Appalachian gas, could you give a sense of sort of—just a rough ball park of what percent of PV-10 those reserves represent?

Doug Miller

That’s a good question. 60—I mean it’s about 1.5 Tcf of total proved.

Hal Hickey

I would say that Cotton Valley is going to be roughly half or PV-10 and I would say that Appalachia would probably be 20% or so.

Doug Miller

Yes, that’s about right.

Hal Hickey

For PV-10.

Doug Miller

One of the things you need to understand there is we have some 8,000 development locations in Appalachia shallow and we have 2,500 shallow development locations that we’ve got on the books between proved, probable, and possible in the Cotton Valley. And last year at this time when we were talking to you with the capital cost, we thought $6.00 was a break even, but steel prices have gone up 100%. Drilling prices are up in certain areas, 30% to 50% and frac jobs are up also.

So the Cotton Valley well that we spent $1.6 million on last year, we’re spending $2.5 million on it, it just change the math. Those locations are not going away. We either have to get cost down or commodity price up and we’re patient.

[Catherine Cybulski] - Jefferies

Okay, great. Thanks a lot.

Doug Miller

Thank you.

[Catherine Cybulski] - Jefferies

Great quarter, it's really nice.

Doug Miller

Thank you.

Operator

Our next question comes from the line of Howard Flinker with Flinker & Co. Your line is open.

Howard Flinker - Flinker & Co.

Thank you. Hi, Doug.

Doug Miller

Howie, how are you?

Howard Flinker - Flinker & Co.

I’m good. How are you?

Doug Miller

I’m medium.

Howard Flinker - Flinker & Co.

Nothing like volatility to make life exciting.

Doug Miller

Right.

Howard Flinker - Flinker & Co.

I’m asking for a gut feeling here under the assumption that people’s vocal promises can change overnight. Is your gut feeling that at least two-thirds of those lenders are within the $300 million of Oakley agreed enrolling in?

Doug Miller

Yes, sir.

Howard Flinker - Flinker & Co.

Okay.

Doug Miller

You're killing me. Quit asking these detailed questions.

Howard Flinker - Flinker & Co.

Yes. No.

Doug Miller

No, no, no. We’re in really good shape. We've talked to all of them. We have five or six other guys that have shown an interest and soon as we get off this, I’m going to start getting back on the phone with them and see what questions they have.

Howard Flinker - Flinker & Co.

You know it sounds like when worse comes to worse if all people decided to back out tomorrow morning, you'd still have $200 million committed give and take.

Doug Miller

Oh, yes, yes, yes, yes.

Howard Flinker - Flinker & Co.

And you could pay the $100 million out of your internal cash flow?

Doug Miller

Exactly. You nailed it.

Howard Flinker - Flinker & Co.

Okay, that’s clear enough to me.

Doug Miller

Thank you, Howie.

Howard Flinker - Flinker & Co.

Alright, thanks Doug. Thanks guys.

Operator

(Operator Instructions). At this time our next question comes from David Heikkinen with Tudor Pickering Holt.

David Heikkinen - Tudor Pickering Hold

Good morning, guys.

Doug Miller

Hey, David.

David Heikkinen - Tudor Pickering Hold

My question is you think about services cost going in to 2009, what are you building into your budget as far as cost reductions?

Doug Miller

None. That’s the challenge. I think we just did our off site and we had everybody use current cost and lower commodity prices and that’s why we've started blowing up at 6.50. Now, I will tell you this, 60 days ago, we’re begging for 1,500 horsepower rigs at 30,000 a day and last week, we got offered one at 15,000. You're starting to see it coming.

David Heikkinen - Tudor Pickering Hold

And then you’ve mentioned propane availability because you’re still in one-off well mode, you’re not really in a drilling program in the Haynesville.

Doug Miller

No, hell no. We’re using Carbo Ceramics all the time. Nobody uses them more than we do. But the difference is we use 250,000 pounds on the Cotton Valley and on a 4,400 foot lateral, we use 3 million pounds and we thought we had it. Don’t even buy or sell your Carbo Ceramics 'cause we’re waiting in line with everybody else.

David Heikkinen - Tudor Pickering Hold

Actually, I really appreciate that.

Doug Miller

The thing about it is, it’s coming. We’ve been offered it in three or four weeks’ availability. We have a million pounds secured today and Hal and his group are pounding the pavement.

David Heikkinen - Tudor Pickering Hold

Okay.

Doug Miller

It is in short supply and we’re not the only guy that wants it.

David Heikkinen - Tudor Pickering Hold

And then as you think about your midstream business and these taxes given where commodity prices are high and your sensitivities, how are you adjusting your EBITDA expectations for that business going into next year, the $6.00 price tag, I would say?

Doug Miller

Well, I think we’re working on that right now. Basically, significant amount of that is with BPs and Evans and things and we just use a straight. All we’re doing is moving their gas at $0.17 to $0.20. We buy very little gas over there although we have opportunities. I think the challenge we have and I don’t think it will be up slightly just on sheer volumes 'cause John Jacobi just walked in. He just got back from over there.

We have different operators have called us in the last two months asking to get hooked up or asked for firm transportation. So it’s just straight transportation agreement so it’s should be pretty easy. The challenge right now is forecasting growth there. We can grow a lot faster than we want to cause the main reason for the system is our gas but we’re getting a lot opportunities

And so I am positive that the pipeline guys are going to be coming to the board here with some opportunities to loop systems or increase us. I think of all the areas that we participate in, if this Haynesville keeps working like it looks like it is. And then Petrohawk has really had some spectacular wells and we’re talking of them about hooking some of their wells up, I think this activity even down to $5.00 gas will stay very active and we will be too, but getting gas out is going to be the challenge. You know there’s limited pipeline space and we have more than a share of it.

David Heikkinen - Tudor Pickering Hold

Yes, what I’m thinking about is you’ll have a good look at Cotton Valley decline versus Haynesville growth and just try to think about the balance of kind of what net volumes will be?

Doug Miller

Yeah, I think we still are going to have a semi-active Cotton Valley program because we have some – we still have acreage over there that have two and three years to run, and we get most of our stuff is HBP and keep in mind there are certain areas over there that still makes sense at $6.00. When we have behind pipe Austin or area where it's oily, we’re going to keep drilling those so. I can’t expect Hal to say instead of 14 rigs running, we’ll have three to five rigs running over there even in a worse case.

David Heikkinen - Tudor Pickering Hold

Okay.

Doug Miller

Is that right Hal? Kind of.

David Heikkinen - Tudor Pickering Hold

Thanks Doug.

Doug Miller

We’re seeing plenty of activity on the pipeline and that's something that's every week. You know John has had meetings with operators. Probably, we have opportunity to hook up 30 to 50 million a day right know, right John?

John Jacobi

Yes, sir. Let me tell you. I met with 10 producers this morning that normally in this exciting environment of the last year had pulled their horns in hadn’t done anything except just wait on the pricing some area that we just talked about with rigs, profits, services and there going to be a lot more active in this environment. There are small producers that might add as much as 5 million to 10 million a day to our system and may well be drilling when they’re weren’t drilling last year.

Also, something that you’re saying is with the current customers we have that do have Haynesville acreage. They have pulled back on their Cotton Valley, but just in the last two weeks, our volume – there’s less wells being drilled, but because of the Haynesville horizontal Cotton Valley that we see, the volumes were going up tremendously, I mean with this time going one year stated at 10 million to our system. That company would normally drill ten wells at a 10 million system. They drill one well, they have 10 million to our system.

David Heikkinen - Tudor Pickering Hold

Just one final question on your bank group, what commodity prices are they using in your current credit line?

Doug Miller

I don’t know. Who knows?

John Jacobi

Six and a half, kind of.

Doug Miller

Yes, you know first of all, all of them have differences. I think typically we’re looking at the tail is really what counts more than anything else and I think most of them of have $5.00 or—

John Jacobi

Less than $6.00

Doug Miller

Yes, less than $6.00 tail and we had out of 41 banks, we had 95% approval. In a normal environment, if there was capacity available we could have gone close to $3 billion with our third quarter engineer.

David Heikkinen - Tudor Pickering Hold

Okay.

Doug Ramsey

How’s that current price tag is—that would be indicated borrowing base we could have asked for in all.

Doug Miller

The tail really ends up being the difference and I think they’re using somewhere to 5 to 5-1/2 and it varies from bank to bank, but we’ve actually run a $5.00 tail across it and we would still have no problem. We expect banks to start lowering their price tag next year and I think our hedging is really going to be helpful if that happens. They give us credit on the hedges.

David Heikkinen - Tudor Pickering Hold

Okay. Thank you.

Doug Miller

Okay. Thanks.

Operator

Our next question comes from the line of Shannon Nome with Deutsche.

Shannon Nome - Deutsche Bank

Hi, Doug.

Doug Miller

Hi, Shannon.

Shannon Nome - Deutsche Bank

Forgive me if I spaced in business but I was trying to get a sense of bracketing in what the gross may look like at various CapEx next year and I know you’re not going to do that for me right away, but at $850 million at 80 and 8 which you said it was kind of your original thought process several weeks ago.

Doug Miller

That would have been explosive because depending on the Haynesville and the Marcellus which we’re going to focus on, we’re kind of hoping that we get to $500 million a day by the end of next year with that one.

Shannon Nome - Deutsche Bank

Okay.

Doug Miller

Down at $3.50, I think Paul, do you have that? I think it’s just slight growth. Flat from a reserve and from a production standpoint.

Shannon Nome - Deutsche Bank

At $3.50?

Doug Miller

Yes ma’am.

Shannon Nome - Deutsche Bank

Okay. Thank you.

Doug Miller

Okay.

Operator

Our next question comes from the line of David Barberis (ph) with Candy Tuck (ph). Your line's open.

[David Barberis] - Candy Tuck

Hello, gentleman.

Doug Miller

How are you?

[David Barberis] - Candy Tuck

Not bad. You know, we’ve watch this stock going from a $40 a share now I think it's trading at $6.50. Is there any chance we can see some resurrection in these things within the next 12 to 18 months?

Doug Miller

Well, we sure hope so. We own a lot more than you do.

[David Barberis] - Candy Tuck

Yes, I understand.

Doug Miller

We’re not trying to get it down, we’re trying to run the company as best we can and communicate with the public as best we can and all we can do over here is to keep our nose down and our ass up and keep working and as you can see, you've got – if you own stock, you own stock in the company that is doing pretty well.

[David Barberis] - Candy Tuck

Thank you.

Doug Miller

Thank you.

Operator

At this time, I have no further questions in queue.

Doug Miller

Okay. I sure appreciate everybody signing on and we’re doing everything we can here and so if anybody further questions, call anybody here. Thanks again. Meeting adjourned.

Operator

Thank you for using the conferencing services. At this time your conference has completed. You may now disconnect your lines.

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Source: EXCO Resources, Inc. Q3 2008 Earnings Call Transcript
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