EXCO Resources, Inc. Q4 2009 Earnings Call Transcript

Feb.25.10 | About: EXCO Resources, (XCO)

EXCO Resources, Inc. (NYSE:XCO)

Q4 2009 Earnings Call Transcript

February 24, 2010 10:00 am ET

Executives

Doug Miller – Chairman and CEO

Doug Ramsey – VP, CFO and Treasurer

Hal Hickey – VP and COO

Paul Rudnicki – VP, Financial Planning and Analysis

Mark Wilson – VP, Chief Accounting Officer and Controller

Mike Chambers – VP, Operations and General Manager, East Texas/North Louisiana Division

Analysts

David Heikkinen – Tudor, Pickering

Jack Aydin – KeyBanc

Neal Dingmann – Wunderlich Securities

Ellen Hannan – Weeden & Company

Brian Singer – Goldman Sachs

Leo Mariani – RBC Capital

Irene Haas – Canaccord

Seth Mannoff – Zimmer Lucas

Eric Anderson – Hartford Financial

Jeff Davis – Waterstone Capital

Brian Cusas [ph]

Operator

Good morning. My name is Sara, and I will be your conference operator today. At this time I would like to welcome everyone to the EXCO earnings conference call. All lines have been placed on mute 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 your conference.

Doug Miller

Thank you, Sara. This is Doug Miller, I’m Chairman of EXCO and I will be leading the conference call this morning. We’ll be going over our fourth quarter and fiscal year results. But before I get started, I’m going to have Ramsey do our annual disclaimer.

Doug Ramsey

Thanks, Doug. I would like to remind everyone that you can go to www.excoresources.com and click on the Investor Relations tab on the left hand side of our home page to access today’s presentation slides. The statements 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 are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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

Thank you. We have nine guys here with me, everybody, and we’re going to stick with you. We had quite a year last year. So including two lawyers, make sure I don’t lie anybody. We’ve everybody here and we’re going to stick with you and answer all the questions, because I am sure we’ll have some. We have a slide show and we’re probably going to focus on it.

As most people know, we had a wild year last year. We have totally changed the company. We have gone from really the strategy of an acquisition development company. We have sold most of our conventional assets and we have converted to a shale development company and we have probably hired 200 people to enable us to do that. Many of them were with the company before, had a lot of experience in deeper, high pressure, high temperature environments. So I think we put a group together that is second to none.

But the Haynesville shale has been our focus for the last year. We currently have 13 rigs running in the play. We have a 14th coming April 1st, Mike told me, so, and that will probably be it, although there are some opportunities if we make certain acquisitions we will probably be adding to that.

But right now we’re very comfortable with our assets over there and the 14 rigs should be enough. I would say on the acreage that we had when we did our joint venture we’re almost 100% HBP right now, so we’re very comfortable, we’re very flexible, and we’re looking for additional opportunities out there.

But through our asset sales and our joint venture, we received $2.1 billion during the year. Most of that was very tax efficient because of our tax basis that we have created over the last five years. So we were able to pay down almost $2 billion of debt.

Our balance sheet is very liquid. We’re in the throes of redoing our borrowing base as we speak. That should be out here over the next three weeks. We have plans in effect for the company, whether gas goes to $3 and stays there for three years or gas goes to $10, so, we have a very flexible Company right now with spectacular assets.

We did do a joint venture with BG during the year. It took us quite a while to figure it out. We had a lot of people, but I think we picked the absolute spectacular joint venture partner. They have been very cooperative through the process. They want to grow. We have bought another 25,000 acres in the Haynesville play with them, 12,500 acres net to us. But, there are opportunities out there in what we call the core area. How we’ll in a minute talk about what our production is and what our rates are, but I don’t want to underestimate that we have picked the right partner there. And we’re very happy with it. I think they’re very happy with it. We have made a lot of money so far, spectacular results, and they have actually brought in – how many people, Hal?

Hal Hickey

13.

Doug Miller

13 people from around the world that have added a lot to the process. So, it is a very cooperative effort. We plan on growing it additionally this year and next. I would say that we’re probably looking at another 25,000 acres to 50,000 acres in the Haynesville play as we speak, none of which are closed. But, our land people and our acquisition guys are working on trades, joint ventures, acquisitions, so we’ll get into that a little later.

The Marcellus shale is another play. We have been doing a lot of studying, a lot of coring, a lot of vertical testing. Hal again will get into that. We are in discussions on a potential joint venture. That’s about all I can say. Lanny is nodding his head already. It is a possibility that we would do a joint venture there. There is a lot of activity, a lot of people interested. It’s quite a debate at the board level whether we should do one or not.

I think we have focused on five areas. We’re probably in negotiations on another 40,000 acres to 50,000 acres up there right now in the five areas that we have chosen to be our core areas. We have drilled our first long lateral horizontal well there, which Hal was going to tell you about, but I will jump in and tell you. It is not completed. It is TDed and cased and we’re waiting on a frac. And that should be sometime late March/early April. And we’re quite excited about it because our guys did a great job drilling it and keep it in zone the whole time.

With that, I think we had a lot of activity, a lot of sales, and I think we formed a lot of people up and we’re going to try to clarify it here, but I think the idea of shrink to grow was something that we did. We did shrink our asset base. We did shrink our production. But what I’ll tell you what we’re in as good of shape as we have ever been and we expect explosive growth to continue for at least five years on just the assets we have.

So my target and goal is to continue reducing debt in this environment, where it looks to me like sometime in the near future we may have increased rates. We don’t see any particular real short-term influence on inflation, but it surely has to come over the next few years.

These plays and I know that everybody in the world has Haynesville and Marcellus acreage. I want to emphasize both plays are large. And I think both plays will shrink as we go, as the Barnett did. The Haynesville, I think, we still talk about 3.5 million acres to 4 million acres of the total. We think that somewhere between 800,000 and 1 million acres is going to be the core. The rest of it is going to be medium to marginal at best. We think the same thing will probably develop up in the Marcellus, where initially its 23 million acres to 24 million acres. We think at best it’s going to be 5 million acres to 7 million acres in the core areas, so I did learn a little fact yesterday Jacobi told me.

In the Barnett which has been supposedly the largest shale play in the history of the universe, over the last 10 years there has been in excess of 10,000 wells drilled. And I was shocked to learn that less than 200 wells, probably less than 150 wells have made 2 Bcf. As all plays, they start out huge, everybody has a piece of them and everybody is estimating certain things, but they all shrink as time goes by.

With that, I’m going to turn it over to Paul and we’ll get into the operational a little later. Paul.

Paul Rudnicki

Thanks, Doug. I’m going to pick up on Slide #7, if you’re following with the presentation. This is a slide that we have shown for some time during the year and I think it’s a good summary slide for kind of reiterating some of the points that Doug’s made.

We laid out our plan for 2009 with certain strategic goals and we’re very proud of the fact we’d achieved every single one of them, starting with the joint venture partner that we got with BG, with the $1 billion of cash that we received and the $400 million of carry. It’s going to make our results that much better for the next few years.

In addition to the joint venture, we also closed $1.1 billion of asset sales, spread around pretty much all of our divisions and exiting some divisions, where it allows us to focus on our assets with the upside that we’ve going forward.

Again, as Doug mentioned, we reduced our debt to approximately $1.8 billion. That’s a 60% reduction from where we were at the beginning of the year. And we have increased that liquidity to about $665 million today.

And most importantly, we have continued our shale focus, where in 2009, we spent over 60% of our dollars dedicated to our shale assets and we’ll continue to see that percentage at that level and higher going forward.

As Hal will get into, we’ve grown the technical staff to attack both of these plays, and as Doug mentioned again, the Appalachian joint venture is still an opportunity for us.

Going on to Slide #8, just want a high level look at what 2010 is going to look like for us. We’re starting the year off in a very well hedged position. About 50% of our expected volumes are hedged at $7.82 per Mcfe. And I just want to clarify a little confusion on what we think our production growth is.

In the fourth quarter – we’ll get into the results in a second we’ve showed 254 million a day of production and that did include some production from assets that we sold during the quarter. What we think is a baseline for this company is where we started the year, which is 234 million a day. And as you can see in our guidance that we’ll get into in a minute, we’re expecting to exit the year about 360 million a day to 380 million a day and that is 50% to 60% growth just in one year. It’s tremendous growth and it’s heavily laid towards the Haynesville.

With the growth that we’re having, especially, where it’s coming from, we’re also going to see a decrease in our operating costs. Direct operating costs for the fourth quarter were $1.10 per Mcfe and we expect that cost to decline during the year and average somewhere between $0.70 per Mcfe to $0.80 per Mcfe for 2010.

We’re also lowering our finding and development costs. We reported a direct finding and development cost last night of $1.24 per Mcfe and just looking at the Haynesville that equated to $0.71 per Mcfe. This equated to 242 Bcf of extensions and discoveries and Hal will get into more detail later on in the presentation.

And the big highlight there is we expect to see that continue to get better as we get more and more full year effects of the BG carry, which again, will reduce our costs by 75%.

And as we highlighted before, we got a strong balance sheet that’s going to help us take advantage of any opportunities that we see coming in our core areas here.

Going on to Slide #9, kind of pointing out the financial highlights for the quarter, we recognized $106.5 million in oil and gas revenues before the effects of hedges for the quarter. With the cash settlements of $124.3 million, our total revenues came in at $230.9 million.

And as we’ll talk about in a second, those revenues did include a $31.8 million cash settlement from hedges associated with asset sales for 2010 and beyond production.

Our adjusted net income came in at $62.2 million or $0.29 per share and our adjusted EBITDA came in at $168.4 million. Cash flow from operations was $142.7 million or $0.67 per share. And as I mentioned, our average daily production came in at 254 million a day.

And again, as Hal will get into this in a minute, our direct F&D cost was $1.24 per Mcfe including revisions other than price that equated to $1.59. And when you include the leasing that we did during the year that was $1.88 per Mcf.

Our cash to operating margin continued to stay strong, obviously, as a result of the hedges, came in at $6.88 per Mcf for the quarter. And again, as Hal will get into more detail, we continue to have great results in the Haynesville as we averaged over 20 million a day for the eight wells we brought on line, bringing our total average for the entire program in and outside of DeSoto Parish to 21.8 million.

Slide #10 is a great slide we like to highlight and it really graphically shows the effects of our hedging program. You can see that with the effects of our hedges, our cash operating margin has stayed relatively stable in these volatile price environments.

As I mentioned before, the fourth quarter came in at $6.88. When you look at this whole timeframe going back to the first quarter of 2007, when you include the effect of hedges, we actually realized a price of $8.30 per Mcfe. If it had not been for those hedges, we would have realized $7.08. That includes $12 gas and that includes $4 gas. Providing a stable cash flow to operate and deliver on our capital program is what the plan for the hedges is to do.

Going on to Slide #11, this is kind of sets out a little bit of detail on the divestitures and joint ventures and the cash proceeds we received during the year. The main highlight from the slide is that everything we did was basically right in line with the estimates we thought at the beginning of the year.

Our divesture program alone brought in $550 million. The midstream joint venture with BG brought in $269 million and the upstream joint venture from BG brought in $714 million.

The one asset that we didn’t lay out specifically, to sell at the beginning of the year, but had an opportunity to realize great price was the final Mid-Continent divestiture, which we closed in the fourth quarter, which brought in $531 million. Again, these proceeds were used to reduce our debt by 60% and provided us cash flow to make some acquisitions during the year in basically the Haynesville area.

The other big highlight from the slide is this divestiture program is behind us. We’re not having to worry about what the five-year strip is doing and trying to figure out what we’re going to get for any additional asset sales and not have to worry about the flood of assets that looks like might be coming to market this year. We got this all behind us and we’re looking to grow organically going forward.

Slide #12 just highlights our liquidity and financial position. We ended the year with $127 million of cash. Our bank debt was $747 million and our senior notes were $445 million, bringing our total debt to just under $1.2 billion. Our borrowing base is $1.3 billion. And when you include the cash, we have $664.5 million of liquidity today.

The next column just shows where we are on February 22nd. And one thing to highlight there is as many of you are aware in the oil and gas industry, we get our revenues at the end of the month. So, we should see that cash grow throughout the year.

Going on to Slide #14, want to highlight our derivatives position for the year. Some of you might have pulled these slides off earlier. We have broken out the 2010 hedges by quarter, as we have covered some of our hedges for the year and actually entered into additional hedges for '11 and '12. As I stated before, we’re very well hedged, over 50% and we’ll be looking to add hedges in 2011 and 2012.

Our gas price on an average basis is ranges from $7.16 to $7.50 per quarter and our oil price is about $115. As I mentioned before, during 2009, we recognized $49 million of proceeds from early termination of hedges. Of that $49 million, as I mentioned, $31.8 million was related to 2010 and beyond.

In the first quarter, we recognized an additional $37.9 million of early termination of hedges and those were all 2010. So, all we’ve really done is pulled second quarter, third quarter, and fourth quarter settlements into the first quarter.

Looking at Slide #15, which compares our guidance that we put out versus the actuals that we got in. Our production came in right underneath the high-end of our range at $254 million as compared to the guidance that we put out between $245 million to $255 million a day.

Our differentials, oil was $3.50 and the gas came in at 99% of NYMEX, which is a little bit higher than the midpoint. Lease operating expenses were basically right in line.

One thing I want to point out is our gathering did come in a little bit below guidance, as we have finalized our new accounting procedures post joint venture and we’re now including the results of our Vernon gathering system as a net reduction to gathering expense.

Production taxes came in lower than expected, mainly due to the ad valorem taxes resulting from the lower commodity prices. And our DD&A rate, another thing to point out, came in lower as we got benefit of the Haynesville additions during the year.

G&A came in a little higher than expected at $26 million versus our range of $23 million to $25 million. As we sold assets and closed some offices, we’re also consolidating our Appalachian group from Akron, moving them into a new office in Pittsburgh. We had some higher severance and relocation costs than we originally estimated.

Our cash interest expense came in below end of the range, while our non-cash interest expense came in at the higher end. As we reduced our borrowing base for some of the asset sales, we also wrote off a proportionate share of the deferred financing cost we had on the books at that time.

Our tax rate on an adjusted basis continues to be about 40% and we continue to have 0% cash taxes. CapEx came in a little bit below guidance, mainly, due to the effects of the BG carry and some completion costs that will be reflected in 2010. And again, the $168 million of EBITDA includes the $31.8 million that we received from the early termination of the hedges.

Going on to Slide #16, looking at our 2010 guidance, I want to spend a little bit of time here because I do think there has been some confusion into how we’re going to be accounting for some things.

As you can see, we’re guiding to 255 million a day to 265 million a day for the quarter and keep in mind we started the year off at 234 million a day. We recently were at 265 million a day, so we’re very comfortable with that range.

Our guidance for the full year is to average somewhere between 315 million a day to 329 million a day. As I mentioned before, that gives us an exit rate in the fourth quarter between 360 million a day to 380 million a day.

We expect our oil differentials to widen to $4.15 to $4.75 below NYMEX, mainly as a result of the final dispositions we made, the Mid-Continent oil that we had, which was nearly half the oil in the Company before the sale, had a very good differential to NYMEX. And the majority of our oil going forward is in the Permian Basin.

Our differentials on gas, you can see the estimates that we have for the year to average between 96% to 98% of NYMEX, starting off at a little bit lower between 93% and 95%.

As we’re selling a lot of our Haynesville gas on spot beginning of the year, that’s going to fluctuate daily prices versus index. But as we build up a base, we’ll start putting more and more of that gas on index.

Our lease operating expenses, as I mentioned, on a per unit basis will be going down as the production grows at a very low incremental cost.

And want to spend a minute talking about our gathering expenses. We have changed slightly the way we’re going to account for some of the gathering expenses versus the initial guidance we put out at the Analyst Day back in September.

On a net-net basis, we’re going to show a slightly higher gas differential. And this gathering expense will include all of our firm transportation costs and all the fees that we pay to our 50% owned subsidiary TGGT. And as we fill up our firm commitments with our produced volumes, we should see that go down a little bit during the year.

Our depletion rate, we’re holding steady at the fourth quarter level of $1.25 on the midpoint and we continue to see our depreciation rate per Mcf in the $0.20 to $0.25.

Our cash G&A reflects an increase during the year, as we expect to continue to add personnel to develop these shale plays. And our non-cash interest expense for the first quarter – just want to highlight that number, as Doug mentioned, we’re looking at a new credit facility to replace the two that we have today, essentially, just consolidating both of them, and it looks like again we will write-off the remaining deferred financing costs associated with the oil facilities and that higher number is reflected in the first quarter, but again, that’s a non-cash charge.

And finally, I just want to highlight the way we’re going to account for TGGT Holdings, which again is our 50-50% jointly owned LLC with BG. First of all, the LLC is a non taxpaying entity, so we get taxable income from it. What we will show on our income statement is our share of the taxable income from that subsidiary. You can see our guidance range for the year; you can see the growth as our Haynesville volumes grow. But you do need to include that in your pretax income and tax effective for the year.

Our capital spending, during the year, is basically right in line with the guidance that we put out at the end of the year, about $480 million in the midpoint.

And then looking at our adjusted EBITDA, the first quarter, we’re guiding to includes the effect of covering those hedges, which again are 2010 hedges and we’re just bringing the cash settlements in the first quarter versus when they would have occurred spread out between Q2 through Q4.

Our share of TGGT’s EBITDA will not be reflected in our reported EBITDA. So we are just highlighting what that 50% share net to EXCO is. And you can see the growth again during the year and we’re expecting that to come in at somewhere between $32 million and $39 million for the year and put us on a $50 million net to EXCO run rate by year-end.

With that, I will hand it over to Hal to go over the operations.

Hal Hickey

Thank you, Paul. We can flip to Slide #18, map of the U.S. You can see in red all the properties that we’ve divested this year. That was the $1.1 billion in sales and it took about 569 Bcfe out of the portfolio, but most importantly, it allowed to us now focus on our growth opportunities in particularly the Haynesville and the Marcellus shale.

Slide #19 depicts it of our portfolio today. And the proved reserves you see here are not the SEC case. These 1.2 Tcfe of reserves are based on strip pricing as of 12/31/09. And you can see that most of our proved reserves, about two-thirds of them are in East Texas, north Louisiana, which also has more than 75% of our production. Of course, this is where our Haynesville shale and Bossier shale activity is focused.

The bulk of our upside or potential actually exists in Appalachia with our Marcellus position. And we are at a current net production as of early February of about 265 million a day. Very important to note that we started the year at about 234 million a day. Last quarter was about 254 million a day, but early this year following our asset sales we’re at about 234 million a day, and that’s the baseline we’ll grow from.

Slide #20 starts to talk about some of our operational highlights and accomplishments. We’ve had phenomenal growth in the Haynesville. Our gross operated production has increased from about 7 million a day in average on fourth quarter of '08, currently totals about 340 million a day from 35 wells on line. Again, these are operated numbers.

We accomplished that while we averaged only having seven operated horizontal rigs running over the period of time from December of '08 through current data that’s reflected here. We exited '09 with 11 operated horizontal rigs in the Haynesville. Like Doug said, we’re currently at 13 rigs, we’re going up to 14 rigs April 1st and pending other acquisitions and such, where is a possibility we could increase that rig count.

We’ve had 100% drilling success rate in our Haynesville shale. We spud 43 operated wells last year. We have 25 completed and flowing to sales as of year-end.

On this slide we show that we have had nine additional completions. That’s continuing to grow. Of those 43 operated spuds from last year, only one is still drilling. We’ve got 25 plus nine or ten, so 35 or so online. And then the remainder either completing or waiting on completion. And we have had very good record with our people and our service companies being able to promptly move from the drilling phase into the completion phase. We’ve had no delays at all waiting on frac crews or other services.

We expect to average 20 to 30 operated Haynesville completions per quarter in 2010. First quarter will actually be 23 or 24 and the second quarter we’re anticipating 32. But again, the average will be somewhere in the 20 to 30 range.

This table on the bottom of Slide #20 is a very important table that shows how our drilling days that have come down and our IPs have been very consistent. Our drilling has actually gone from the initial three wells we’re averaging 72 days, 73 days, 74 days from spud to rig release.

We show in the fourth quarter we were down to 44 days from spud to rig release. We’re actually now seeing some recent three wells; we had 37 days rig release, so that number is down 45% to 50%. And our IPs have been very consistent.

Slide #21 again reiterates that we started this year at about 234 million a day to 235 million a day and we’re currently at 265 million a day. In the Haynesville, we had 100% drilling success rate, but across our whole portfolio it was 98%. We had 14 operated rigs at the end of the year. 11 rigs of those were Haynesville as we already talked about.

Significant reserve add. As we added 242 Bcf of proved reserves through extension in discoveries and we had direct drill bit F&D cost of $1.24. It’s very important to note that 67% of our proved reserves or proved development have been very conservative by PUD bookings. I’m going to get into some detail of that in just a moment.

Key to our success is people. I think we have put together a really outstanding staff that works very hard, is very capable, has a very good technical and commercial focus and we have grown the engineering and geoscience staff dramatically over the last couple of years.

We’re successfully implementing the integration with the BG group on the JV. And as we said earlier there are 13 Con Ds [ph] from BG that are in this office full time. And any given day you could assume there is several more that are here working with us as well. And it’s very complementary set of people to the skills that we have and the processes that we have in this Company. And they’re enhancing our focus on areas from environmental health and safety to procurement to drilling wells. They’re learning from us. We’re learning from them. It’s working out extremely well. Couldn’t ask for anything more.

I’m going to get into some detail on Slide #22 on how we transition from our reserves on an SEC basis at the end of last year or end of '08 of 1,940 Bcf down to 959 Bcf at year-end 2009.

We added about 242 Bcf, like I said, through our extension and discovery. That’s the best year we’ve had in our history. We produced about 128 Bcf. That’s about a 7% decline. Between the divestitures that I’ve already talked about and the JV, about 40% of the year-end '08 reserves moved out of the portfolio.

And finally, we have a significant revision number primarily driven by price; about 13% of our revisions were price revisions. About 3% or so were performance related revisions. Those were predominantly driven by some Appalachian reserve that went off the books. And frankly, what we did is went through a more conservative expense profile and it removed some tail reserves off in Appalachia. Also we have some conventional Cotton Valley reserves that we moved off the books because of some performance.

Using previous SEC rules, everybody remembers that price you use this year versus the price you used a year ago has changed. This year you are using the 12 month first day of the month average for your price assumption for SEC purposes at year-end, but year-ago you were using the spot price at last day of the year.

So last year, I think, we were at around $5.71 for our gas price, this year $3.87. If we would have used the same numbers or the same rules as we would have last year, I think we would have used $5.79; we’d actually had 22% more reserves than what we’re showing this year.

Here is more color on Slide #23 on our development costs. In the Haynesville, you will see on the first line of the table how our development cost was $0.71 per Mcfe. Conventional around $3.60, exploration over $5, but our total direct F&D cost was $1.24. You put in revisions other than price and it increases to $1.59.

We had some minor acquisition dollars and we had some significant leasing dollars. When you include that all-in-cost of nearly $370 million and our net reserves of over 196 Bcf, we come up with F&D cost of $1.88.

I know there has been a focus over the last 12 months to 18 months of looking at your proved developed reserved F&D. We’re beginning to look at that as well. And you can see that our proved developed reserves F&D has a same cost basis, of course, nearly $300 million for our development and exploration dollars and the reserves we added were nearing 96 Bcf and it resulted in $3.13 F&D.

#24 is an important slide. Our well costs have come down dramatically. First quarter of '09, our average well cost was between $12 million and $13 million and that’s an average. We had some higher than that as we were still doing a lot of science and frankly on a learning curve. Those dollars have come down dramatically through the year. Most recently, we had a couple of wells that came in at less than $9 million total costs, but on average, we’re looking in the fourth quarter of '09 at about $9.4 million.

We’re using a budget in the $9 million to $9.5 million range. But, very importantly, as we implemented the BG joint venture, our share of capital that we’re invested in these wells came down dramatically. BG carry only applies to deep drilling. So on all of our capital, BG has 50% and we have 50%. Then when you implement deep drilling, BG is actually paying 75% of our 50%.

So on deep wells, 87.5% of the dollars are actually going from BG for the investment, 12.5% from Mexico. So that’s why a lot of that capital share percentage dropped down. Remember we closed the JV middle of the third quarter and so it marks down thereafter.

Gross wells drilled were continuing to increase that. Our net capital come down. Our dollar weighted average well cost of $11.2 million, but again, we’re expecting $9.5 million if not better as we go through the year.

The teams have done a wonderful job in improving our drilling efficiencies as this cost has come down some 25%. Drilling efficiencies is a combination of team’s focus and the technology. Our days are down. They have improved their bid selection, they’ve looked at the mud program, they’ve done a better job geosphering as we learned how to improve our skills and our technologies and we just continue to set in these records.

Harold was telling me earlier today that a couple of days ago we actually drilled more than 1,200 feet of lateral in 24 hours. It’s ROP of over 200 feet, outstanding results we’re seeing in our guidance.

We finished our geological evaluations. We’re not doing the coring that we did before. We’re not doing the logs. We’re not doing the pilot holes, so that’s come down. And then we’re just seeing some cost reductions.

Now, I will say, we’re seeing some pressure on costs, particularly on some of the stimulation dollars. Those costs came down more than 50% from our initial wells and we’re seeing some pressure to go up another 30, 40, maybe even more on that. So there is some pressure on those stimulation costs and some of our other services.

Most of our rig costs are locked in. The rig day rates have actually come down dramatically from when we first started the program, as we have been able to secure some rigs at lower day rates than what we had when we initiated that effort.

Okay, get off that page. Go to Slide #25. We’re going to spend about $471 million in capital budget in 2010. I got a detailed slide on that coming up. We’re going to drill over 200 wells. Big focus, of course, is going to be in the Haynesville/Bossier, 102 operated horizontal Haynesville/Bossier. There will be 95 Haynesville, 7 Bossier. Our first Bossier well is in the lateral now. We’ll TDed over the next few days and will probably complete it in the second quarter.

We should have 15 to 17 operated horizontal drill rigs across the Haynesville/Bossier and Cotton Valley. We got one horizontal drilling rig on a long-term commitment that just arrived in the Marcellus and it’s getting moved in, rigged up. We’ll spud the first well with that rig in the next few days.

We have one operated vertical drilling rig in the Canyon Sand field area we have in the Permian. That’s where we have some of our oilier production and we see good rates return at current oil prices, so we’ve reinitiated that program there as of the fourth quarter.

We’re growing our acreage position in our shale areas. Doug talked about how we have grown in the Haynesville JV since the closing of the BG joint venture. We’re up about 24,000 net acres to 25,000 net acres there. We’re in various stages of negotiation, if not closed on some acres, on about 40,000 net acres to 42,000 additional net acres in the Marcellus.

Our midstream business, which is the 50-50 joint venture now between BG and EXCO is progressing very well. We’re seeing now records as far as volume throughput there at our midstream business. Recently we shopped off over 850 million a day of revenue volumes flowing through that system, up dramatically from a few months ago.

Our organizational effectiveness is improving. I talked about that some from our drilling team. But that’s across the portfolio. Our guys have a continuous improvement mindset. Things are working very well. The teams are clicking.

And we’re also working very closely with some of our service providers in ensuring that we have win-win programs set up, so that we’ve got the services at a fair price, the providers understand that they’ve got a commitment from us to use them. We work together and I am very happy on the drilling front, the stimulation front, the mud front, et cetera, that we’ve got some long-term alliances set up with these providers.

Here is the detail on Slide #26 of our capital program. I think most of you have seen this slide before. About $471 million this does not include any acquisition dollars at all. So as we acquire some of these leases from third parties that are already leased, look at that as an acquisition.

In addition to that, we have a significant amount of money set up, some $78 million for land or $80 million for land where there will be just pure leasing. Drilling completion is more than 40% of our dollars. And, of course, when you look at what that is net of the BG carry, that’s where a more significant number of dollars are going to be going into the drilling program, particularly, in East Texas, north Louisiana, and the JV.

Here is detail on Slide #27. The Haynesville, how we’re implementing our growth strategy. Nearly 54,000 net acres today. We talked about how that’s grown. What is in the gray shaded boxes of the parishes and counties is kind of behind our orange blob depicts our AMI with BG. The brown depiction is the acreage that we have, except for only extreme eastern side of the map is in the JV. On the extreme eastern side of the map, we’ll start to get into our burning area in Jackson Parish. And the orange depicts where we think the Haynesville and Bossier shale tends to be.

Current activity, 35 horizontal wells or 36 horizontal wells flowing to sales. We plan to run the 14 operated rigs to 16 operated rigs through the year and we’ll drill 125 horizontal wells. We’ve already talked about the 102 operated rigs. Outside operated number, obviously, is a number that you don’t control. Could go up, could go down, but that’s what we’re using in our capital budget assumptions.

#28 is the slide that shows, one, the dramatic growth we’ve experienced to-date to go from effectively nothing early in the fourth quarter of '08 up to 340 million a day in early February of this year. And you can see that we have some dramatic growth planned. We expect to exit the year with a gross operated gas rate of nearly 800 million a day. That’s our midpoint projection.

What we have done to protect ourselves going forward, you can see on Slide #29 is the JV, that’s EXCO’s marketing group and BG energy merchants that worked together and they’ve come up with more than 1.2 Bcf of firm transportation exiting the area, via several interstate and intrastate pipelines. These are the key ones depicted here.

Regency Haynesville line, Energy Transfer’s Tiger line, Gulf South line, Enterprise Acadian line, we’re still looking at additional FT. All of our current Haynesville volumes are moving through Gulf South, Crosstex or Centerpoint.

We’re continuing to work on our 36 inch Haynesville header system that you heard us talk about before. That will gather 1.5 Bcf or more dependent upon system management of gas that will flow into multiple gas markets.

The new interconnect with Regency will be fully on line in April of 2010, but we’ll actually be moving gas into that either late this month or early March on a partial service basis. You see we have over 400 million a day of FT there. It’s ready to go. Our guys had some hold up because of the weather.

It’s been a got awful season through the winter months with rain, snow, thunderstorms, lightning, hail, anything you can think of and it’s been a rough, rough go on our construction. But we’re catching up and we’ll be flowing there late March, early April, and like I said late February, early March with some partial volumes.

And as Paul noted, our FT charges going forward will be included in gathering and transportation expense on our future financials.

Operation snapshot on Page #30 of where we are in the Haynesville. I talked about the volumes on a gross basis and a net basis, it's about 92 million day operated. OBO [ph] we probably have some 18 or so wells that are producing that contain some interest, so gas net to us from those 18 OBO wells is a small percentage.

And drilling wise I have talked about how we got the rigs running 13, go into 14 soon and how we’ve had a decline in spud to rig release dates we’re real proud of. Very consistent results across our completions. I talked about our service partner alliances.

One big point I want to make is that we’re working diligently both in the Haynesville and our Marcellus area on water management. Sourcing it, running it through our fields and disposing of it.

We’re working on projects with suppliers, where we got local industrial plant that has a huge amount of waste water that we tested that works very well in our completions. We’ve actually done it on two. We worked with the state, we worked with the third-party, we’re nearing being a contract in place to use their waste water for our frac water.

We think it’s a good thing to do both on a cost basis, from a cost sense and from an environmental sense. Also we’re working on a 30 mile to 40 mile pipeline disposal project. Both of these projects are going to reduce local truck traffic and improve our operating costs.

Bossier is sort of the next frontier for us. You heard me say earlier we had our first horizontal well drilling there. Huge potential gas in place numbers, but we have absolutely nothing besides capital dollars in any of our plans or forecasts from the Bossier. No volumes, no reserves, nothing is reflected in any of our forecasts, but we’re optimistic.

We think this thing may prove to be two-thirds or 75% of the reserves on a per well basis or section basis as compared to the Haynesville. And as you saw, we’re going to drill seven wells in the Bossier this year with BG and we’ll let you stand by for news on that. But probably in the next quarter on so we’ll be announcing our Bossier results.

#32 is a new map we put together that depicts our TGGT equity Company. These are our midstream operations in East Texas and North Louisiana. In blue is our TGG system and in green is our TALCO system. We have throughput capacity in excess of 1.5 Bcf a day. And that could increase to 2 or more Bcf a day with appropriate system management, the ins and outs in compression.

We’re adding high pressure flow lines every day and going to have over 1 billion a day of natural gas treating capacity so, we can meet pipeline quality requirements. And all of this treatment capacity will be in place this year.

We actually have north of 400 million a day of treating capacity in place now. I will note that the TGGT company and our upstream JV worked very closely, worked very well. And to this point, all of our wells during the testing phase have flowed to sale. So, things are going very well on that front and proud of those results.

I’m going to shift now to Slide #33 and do a couple of slides on what’s going on in the Marcellus. Remains the largest aerial shale play. We have 343,000 or so acres in the play. You will see our number in the fairway is down to about 186,000. It was over 200,000. We have done some technical evaluations and commercial evaluations. We have high graded the acreage. And at this point we realize that we have about 186,000 net acres. We still have a huge HBP position, which is to our strategic advantage.

In our acreage in Pennsylvania, our key acreage is about 100% working interest and it has a high NRI. Massive reserve potential I’ve already talked about. And we did complete a sale in the fourth quarter that continued to allow us to continue to focus on the Marcellus. We moved our office from Akron, Ohio to Warrendale and we’re leased 56,000 square feet of office space there. The team is focused and we’re primed to begin our development program, talked about the rig that just recently moved in and is getting ready to spud.

We TDed our first long lateral horizontal, most originally for 4,650 foot lateral that we’re going to complete late first quarter, early second quarter. We have 70 drilling permits in hand. And we’ve done a dramatic review of core data and done a lot of science. These guys did a great job geosteering this last well, stayed in zone the whole way. We’re shooting a lot of 3D to add to the 3D we currently have, and we’re solidifying our land position.

Give you a little color on the land. If you see in the blue area, that’s some 67,000 acres of fairway that’s in the central part of the state. That’s where the bulk of our horizontal drilling is going to occur this year. Probably nine of the 11 wells will be drilled there. In the Northeast area, which is mostly term acreage, not necessarily HBP, we have about 12,000 acres.

The area in purple about 39,000 acres. So in central PA, which is our biggest position, we have some 106,000 fairway acres, about 12,000 acres to the southwest and northern West Virginia and other portions of West Virginia that we still believe are prospective for the Marcellus fairway, we have 26,000 acres.

We’re working hard on our gas marketing, we’re developing some infrastructure there. We’ll actually start some construction shortly. We’ll have some initial take away capacity of 200 million a day.

With that, let me take just ten seconds and digress for just a second. Steve Smith is not with us today. His wife has been hospitalized this week. I would like personally ask you guys to think about them in your thoughts and prayers, if you will, and he will be back with us soon.

With that, I will turn it back over to Doug Miller.

Doug Miller

Thanks, Hal. I think as everybody can plainly see, it’s been quite a year. I want to reiterate that the Haynesville play is something that our guys have figured out they’re probably doing as well as anybody. I claim they were lucky, but if anybody that’s been in here understands that, that is not the case.

We are seeing different technologies come in. I know everybody is talking about different mud programs away from oil base. We’re looking at it. I know people are talking about using different chokes for production. We’re looking at it. Different frac proppings, we look at it.

But at the end of the day, our first well that we put on was the Oden. It’s been on for 14 months. It’s made 3.4 Bcf as of yesterday and it’s still making 4 million a day. So at the end of the day from a production standpoint, I will take our guys. That doesn’t mean that there won’t be some changes and some improvements, but the way we’re producing them, we’ll take. We’re going to look at different things, and I will take our guys on that.

Anyhow, we’re looking at additional opportunities there. One of the advantages of having $4 gas or $5 gas is opportunities abound in all these plays. Like I said, we have had several increases in our acreage. We expect that to continue, especially, if gas prices stay down.

The Haynesville play is something that is going to increase our reserves and production explosively over the next 5 years to 10 years. The shale play that’s coming that I think will be number two is the Bossier play. It is something that we have capital. We have some initial early vertical testing results. But the reason it will probably be number two is pipeline system is all there. So, all of this stuff in the Bossier, if it does work, it does not have to be as productive as the Haynesville to have the same type economics.

The Marcellus, which everybody thinks is the largest play in the universe, and it for sure is acreage wise, I’ve been saying for two years that it’s going to take us a long time, and it will. Right now, the infrastructure is going to be the complication. Early on it was permitting, and environmental and everything else. That one is getting handled. A lot of rigs and companies are moving up there, so that will take care of itself. That’s just a math problem.

The big math problem and the time problem is going to be pipelines. It’s going to cost a lot more and take a lot more to get significant gas moving up there. Each one of our five areas we have approximately $20 million budgeted to move gas, up to 20 million or 30 million a day. But to be a large producer up there, and I am talking about several hundred million plus. There is probably going to be another pipeline joint venture in our future and we’re already in discussions on that.

Again, there is a lot of opportunities up in the Marcellus. You have seen several transactions. I expect you will see a couple more in the near future. We’ve been contacted by 31 people as potential joint venture partners. We’re going to make up our mind. If we’re going to do a deal or not, that should be out in the next quarter.

With that, I think we have some questions. So why don’t we open it up to questions? We’re here as long as you guys have questions. Sara? I think she went to sleep.

Question-and-Answer Session

Operator

(Operator instructions). Your first question is from David Heikkinen, Tudor Pickering. Your line is now open.

David Heikkinen – Tudor, Pickering

Thanks, guys. And lots of details in the prepared remarks. Have some kind of specific questions. As you look at the Haynesville first, you have 23 wells or 24 wells being completed in the first quarter. Just wanted to get how many have you done so far to get to your current or your rough, I guess, 265 million a day?

Hal Hickey

We got 36 operated.

Doug Miller

No, no, how many have we done in the first quarter?

David Heikkinen – Tudor, Pickering

In the first quarter, just out of that, halfway through?

Hal Hickey

10. We had 25 completed last year, one in '08 and then 10 this quarter, David.

Doug Miller

Turned on number 11 today.

David Heikkinen – Tudor, Pickering

And you gave your IPs have been pretty consistent at 20 million plus a day. What are you assuming in your guidance?

Doug Miller

Paul?

Paul Rudnicki

We’re using a tight curve. It’s actually 19.5 million a day.

Doug Miller

In DeSoto Parish.

David Heikkinen – Tudor, Pickering

And as we think about now on the leasing side, just wanted to make sure, I was reading this right, you added roughly 24,000 net acres last year and had $227 million in unproved properties. Is there any reimbursement from BG, because that was net acres and is that net dollars of acreage at –

Doug Miller

The way the joint venture works is actually we’re expanding it. If we see a deal, we talk to them before we start looking at it if it’s in our AMI. In practice, the joint venture says that once we close they have 60 days to fund their half. And I would say right now they have agreed on all 25,000 acres, and we’re probably expecting – Mark, help me, $100 million of that to be coming in here over the next 30 days.

Mark Wilson

We’ve already received just under $55 million and we’re expecting another $102 million.

David Heikkinen – Tudor, Pickering

Okay, so, basically $157 million in Q1 of cash from BG?

Doug Miller

Yes.

David Heikkinen – Tudor, Pickering

Okay.

Mark Wilson

What you will see going forward is we’ll be making acquisitions and we’ll be leasing and then we’ll show a sale somewhere 60 days after we close.

David Heikkinen – Tudor, Pickering

And on the cash flow side for TGGT, just you talked about, you’re going to report it as an equity method. And EBITDA won’t flow through EXCO EBITDA. How does cash flow come in from that business?

Doug Miller

You mean into EXCO?

David Heikkinen – Tudor, Pickering

Yes, exactly.

Doug Miller

I would say plan for the next two years to three years is not coming in, because -.

David Heikkinen – Tudor, Pickering

Is it the CapEx?.

Doug Miller

Yes.

Paul Rudnicki

Our current plan is roughly $8 million cash call this year and depending on certain projects that we’re looking at building out there, that could increase to $60 million.

Doug Miller

There’s some opportunities, David that we’re weighing right now that will connect all those systems and we have a lot of third-party producers asking us. And I think the decision right now is how much third-party do we want versus ours, because it’s limited on firm transportation. We want to make sure we produce ours and our partner’s gas.

Paul Rudnicki

Distributions and contributions will go through investing.

David Heikkinen – Tudor, Pickering

Okay, so come through cash flow from investing as you get into free cash positive on that business and growth CapEx declines?

Doug Miller

Yes.

David Heikkinen – Tudor, Pickering

Okay. And then just a specific question around reserve bookings, around the Haynesville with the 202 Bs booked and 2.5 PUDs to prove developed, just wanted to check the number of proved developed locations to make sure my math was working right with the 6.6Bs for PD? Can you give just the number of PDs at year-end?

Paul Rudnicki

We booked 25 proved developed, I mean PDP locations and we booked 92 PUDs.

Doug Miller

David, one other things we did and there was a debate around here, we’re using a B factor of one even though we think it’s going to eventually be higher than that. So 6.6 Bcf and like I just told you, in 14 months, our first well has produced 3.4 Bcf, so I would like to have over on the 6.6. But, I think we’re early on in a play. I think we’re booking at conservatively as they would allow us and we have potential upside, but I would rather have upside than downside. The debate inside here, we still have guys that think these things could be 8 Bcf wells to 10 Bcf wells, but we’re booking them at 6 Bcf.

David Heikkinen – Tudor, Pickering

And then just as you think about hedging 2011 and 2012, can you talk about structure, price targets for that and that will be it?

Doug Miller

We’re going to be doing some hedging. We would like to get 8, but nobody says 8. We’re just looking at it. We kind of expect the one thing that I think is demand is slightly more than everybody thinks and supply is slightly less. And I think as we get finished with storage here, if we get down to 1.5 or below, we might have some strong gas prices and we’ll look to hedge into it.

David Heikkinen – Tudor, Pickering

Okay. That was it. Thanks, guys.

Doug Miller

Okay, thanks.

Operator

Your next question comes from Jack Aydin from KeyBanc. Your line is now open.

Jack Aydin – KeyBanc

Hey, guys.

Doug Miller

Tell Sara, it’s Aydin, not Aiden.

Jack Aydin – KeyBanc

Yes, thanks, Doug.

Doug Miller

All right.

Jack Aydin – KeyBanc

I am looking at Slide #20 and you had 46 wells. The IP averaged over 21 wells. Do you care to give us what was the 30-day average or how is the decline curve shaping?

Hal Hickey

What we think the decline curve does, Jack, is we think over the first month we have about a 78% or 80% decline.

Doug Miller

First month or first year?

Hal Hickey

First month. Coming out of the chute, early on, you’re on 99% decline. After the first month, you start to settle down with 78% decline and we’re looking at a terminal decline in the 60% range.

Paul Rudnicki

Jack, we’re typically seeing the 30 day average about 20% less than the IP.

Jack Aydin – KeyBanc

I know, Doug, you mentioned people talking about restricting the choke and everything on some of those wells. Did you guys experiment with that, and if you did, how is the decline curve shaping?

Doug Miller

We have always managed our drawdown very diligently and we have marched it up, and we quickly marched it down. We have testing, like some other people are, holding our chokes at a maximum rate, at a maximum level to see what that does to our pressures and volumes over time. But frankly, I am still confident that the way we managed our drawdown program going up to 26 or 28 and quickly marching it back down to manage our pressures, our volumes and our water is the right thing to do. But we are turning some of those knobs, if you will, and seeing what different alternatives can do for us.

I know, again, out there people are saying they’re never increasing past 14 to 64s. We have one I think right now but we’re holding at, what, 20, and we’re monitoring that and pressure continues to build up. We’re looking at it, but they have done a pretty good job to date, but we’ll look at anything. We’re hearing all kinds of things and we’re looking at it. This is all about costs being done the most efficiently.

Our guys are doing a good job even though we’ve spent slightly more than – we haven’t drilled a $6 million well yet. We don’t plan on it, but the thing about it is from a production standpoint they came to us early on and said do you want to maximize production or do you want a high IP? And the answer is very clear, we want to maximize total production.

Hal Hickey

We’re still confident we’re using the right profit. We’re sticking intermediate straight to profit and we believe that’s going to hold up over time. All the results to this point like Doug saying on the Oden, we’ve got several other wells that have outstanding results over time. We’re confident we’re doing some of the rate things technologically. Again, we’ll continue to monitor both our results and our competitors' results and see what we need to tweak.

Jack Aydin – KeyBanc

Doug, as far as the acreage prices in the Haynesville, what is the range now that is going for?

Doug Miller

Jack, it’s all over the place. We bought acreage for $6,000 an acre right in the core. We paid $17.5 million. I would say on that 23,000, I looked at it the other day, its right around $12,000 average. It is going to be all over the ballpark. We can make a case if we have a rig that we can pay a lot more. Right now there is a lot of action. And a lot of this is small. When we buy 80 acres in one of our existing sections, it is very impactful for us going forward, but it is not a big number. We’re detailing.

We have three different groups out there. We have been able to buy some small private companies. We’re working on drill to earns. We’re working on everything. The advantage we have, and we have called Aubrey and Floyd, and when we are 100% HBP and have 14 rigs out there, and if somebody needs to hold acreage, we have volunteered and we have rigs available.

Jack Aydin – KeyBanc

One final one regarding the Marcellus. You drilled in horizontal wells and everything by now. Is the second half of the year, is it a tipping point for you guys to get some results going forward in the Marcellus?

Doug Miller

Oh, yes. We have one well ready to be frac-ed. It is just getting in the queue on the frac equipment and we’re enthusiastic and optimistic, but we got to find out where that is. While we’re waiting on that, we’re doing a little bit of acreage acquisition around it. But we have another rig without a joint venture partner, that’s all we’re going to use up there. If we did have a joint venture partner, I have a feeling that if we had the right one, we might expand the drill. Right now, I think because of our HBP, we can drill at it slow and learn from other people’s mistakes, which we did in the Haynesville.

Jack Aydin – KeyBanc

Thanks a lot.

Doug Miller

Okay.

Operator

Your next question comes from Neal Dingmann of Wunderlich Securities. Your line is now open.

Neal Dingmann – Wunderlich Securities

Good morning, guys. Great update. Doug, question first. What did you say on Marcellus? You mentioned Haynesville rig quickly. Want to know how actively you’re seeing acreage deals done in the Marcellus recently and kind of what range you’re seeing on acreage up there?

Doug Miller

All over the place. Well, we’re seeing the same thing you are. The Anadarko deal is killing us as far as buying things. There is quite a bit of acreage, as you can imagine. One of the things that we’re struggling with is a lot of small operators that went up there and leased two years ago, five-year term leases, and we’re a little bit leery of going out in a non-core area and buying something that only has three years left to go. So, we’re buying things. There is plenty of action. We’ve bought acreage up there for $400 an acre. We paid $5,250 within the last 30 days. So it’s all over the ballpark. I think if you go up to the Northeast where Cabot and Talisman and Chesapeake have had success, you’ll probably pay $10,000 to $12,000 an acre. In certain areas, where there hasn’t been drilling, you might get some for $1,000 an acre. It’s all over the place, it’s very active and we probably have 50 people working right now.

Neal Dingmann – Wunderlich Securities

Wow. I think we saw you all as one of the high bidders on one of the recent state of Pennsylvania deals. Do you see the state coming out with more lease sales like this?

Doug Miller

Yes, they’re slow, but they’re consistent and they have a lot of forest land and we’re drilling on it. We have spent lot of time working with the forest people, so actually there may be part of a trade in there. We have some surface that the forest would like and so we’re working with them, but we’ll be in the running. I hate to say it. I think we outbid Aubrey on a deal. That’s the first time in my life we have ever beaten him on some.

Neal Dingmann – Wunderlich Securities

And then you mentioned one of the updates the F&D cost for Haynesville is down to $0.71. Is there any way to get that any lower? That’s amazing.

Doug Miller

Go ahead, Paul.

Paul Rudnicki

I think there’s two things. Again, we’re using 6.6 Bcf.

Doug Miller

The easy way to get that down is if that we’ll make 8.

Paul Rudnicki

As we get more and more history on these wells and hopefully have more data to support higher URs, that will go down. Really in 2009, there is very limited effects for the carry from BG, which will really show up in the next two years. That should go down dramatically if we continue with the ratio of PUDs to PDP we’re booking.

Doug Miller

Another thing we didn’t talk about is this year we have booked all of these things on 160s. Because we’re HBP, we’re going to have the ability to maybe test 80s. We think this play could potentially go to 80s. I know Mike and Harold, we have plans to test that, and there may be techniques on that you want to drill all of them at once, so we’re going to even test that. I would say by the end of the year we’ll have a better idea what the proper spacing is. And if we’re right, you may see some development of full section all at once.

Neal Dingmann – Wunderlich Securities

Wow. And then last question, Doug, a bit of update on when you’re talking about Haynesville working with the fluids and the chokes. Is this something you will continue? Are you looking at the fracs as far as potential using some sand and some other profit and talking about the water base? Is this something you would consider that you’re looking at in the Marcellus as you’re sort of doing a lot of the tests up there? Are you testing the profit, the chokes, the fluid up there as well to see what the best combination is?

Doug Miller

The profit up there is just sand. Thinking about is what we’ll do up there is they’ll get all the data that we have in the Haynesville and what was right and what was wrong. We’re going to try to save them mistakes by one of the ones me made in 2007 and 2008, and we’re working close hand-in-hand. Mike and Harold are talking to those guys every day on the pros and cons of what we’re doing from a steering, from a profit, from what pictures do we have of Halliburton they might need, etc.,

So I think the changes, every play is evolving including the Haynesville, and we have meetings almost every week with the service companies with ideas. Some of them are great ideas, some of them are stupid. And we have to weigh those and we will test the smart ones.

Hal Hickey

We’re probably only 5% developed in this play.

Doug Miller

It is way early, and there is going to be a lot of changes and we are willing to change, but it has to make sense.

Neal Dingmann – Wunderlich Securities

Hopefully, you can weed out the stupid ones quick, Doug. Thanks, Doug.

Doug Miller

We’re working on it. Usually the stupid ones call me and I bring them into the meeting.

Neal Dingmann – Wunderlich Securities

Thanks, guys.

Operator

Your next question comes from Ellen Hannan with Weeden & Company. Your line is open.

Ellen Hannan - Weeden & Company

Thank you. Just a couple of follow-ups here. Based on the acreage position that you have today in the Haynesville, not excluding anything that you’re looking at buying, let’s say, and your current drilling plans, when do you get to the point that you’re HBP in the Haynesville?

Doug Miller

We are there. If you disregard acquisitions, we are there. We’re 100% HB. A lot of that has to do with the previous 10 years. That was the Cotton Valley play and a lot of Cotton Valley held the deal. Some of it didn’t. But we have made sure at least on the Louisiana side that every one of those sections has a well on it today.

Hal Hickey

Another point to grow on that, in turn, all of the Bossier is HBP.

Doug Miller

Mike, you had something?

Mike Chambers

I was going to say in 2009, our focus was HBP.

Doug Miller

Right.

Mike Chambers

On our DeSoto Parish acreage.

Doug Miller

Yes, we’re there. Now, some of these acquisitions that we’re bringing on, have some fuses that they’re not a 100% HBP, but they’re moving rigs over and we’re drilling on those right now. So, we are in such good shape from an HBP standpoint, we could take on another 50,000 acres and probably get HBP if you give us two years. Because we have a lot of flexibility on the 14 rigs.

Ellen Hannan - Weeden & Company

And my next question going on the Haynesville, lot of your peers and also the service companies really talking about cost increases just due to capacity utilization, particularly in the Haynesville. Any thoughts surrounding that?

Doug Miller

No, it’s for sure. If you look at what they’re projecting, they’re talking about 150 rigs to 200 rigs running in the Haynesville by the end of the year, which we think is slightly too many. And more importantly, the frac job schedule, I think that with the existing frac crews out there, they cannot handle any more than 150 rigs. So we either need more frac crews and frac equipment, but it is going up. When Halliburton comes in here, or Schlumberger or BJ, there’s a real tug of war on that type of equipment, and we’re working with them as best we can.

And we’re scheduled through the summer already and we’re doing a great job on that. But the thing about it is if gas goes up and the pressure stays like it is, we’re kind of looking at 30% across the board, at least from the frac and from the drilling. It’s out there and it’s no question about it.

Hal Hickey

We’re seeing new fleets will be built and brought into the area. It’s just a short-term.

Doug Miller

It’s a short-term deal here, but the Eagleford uses the same type stuff and if that grows, if they pay a little bit more, some of these frac crews are moving. It’s the same thing we always go through.

Ellen Hannan - Weeden & Company

One other, away from the Haynesville looking at your Marcellus position and thinking about how you have restructured the Company over the past year. Doug, do you need a JV in the Marcellus?

Doug Miller

No, we do not, but I mean we just had a Board meeting day before yesterday. We absolutely do not. We have the capital. We have the expertise, but look at what happened in the Haynesville. We teamed up with BG. We had 100,000 acres in there. And we were planning. Our plan without a joint venture partner was to have three rigs or four rigs running this year, 2010 and really not to participate in any acquisitions because we didn’t have the flexibility. With that partner, we now have 14 rigs run and we basically doubled our size. So we’re net back to the same thing and we reduced our debt. So, I think you have to take everything into consideration, some of the people that have called us do not speak English and so that would be a struggle for me and Hal, because we don’t want to learn a new language and I am kidding a little. If the right partner came along, which would enable us to go faster and they brought something to the party other than some pesos or some rubles or whatever those are, we would consider it. And that’s what we’re doing. Partner’s more important than cash, to answer your question.

Ellen Hannan - Weeden & Company

Right. That’s it for me. Thank you.

Doug Miller

Thanks, Ellen.

Operator

Your next question comes from Brian Singer, Goldman Sachs. Your line is open.

Brian Singer – Goldman Sachs

Thank you. Good morning.

Doug Miller

Hey, Brian.

Brian Singer – Goldman Sachs

Just wanted to go back to acreage acquisitions. Seems like you talked about three different buckets acreage that you believe is prospective but is discounted because others aren’t focusing on it, top acreage you might be outbidding others on and then good acreage that you might get at a discount because you have the ability to drill it. Since most of your acreage is held by production. Can you just break down how your acreage acquisitions are stacking up in each of those buckets? I’m just trying to better understand when you think about capital allocation acreage acquisition versus paying dividends, drilling, et cetera.

Doug Miller

Brian, we are going to have to get back to you on that, because in the Haynesville, we have bought three companies, small privates, that have acreage in the neighborhood and you know, some of them were because they didn’t want to drill anymore, some of them – I don’t think it has been a lot of competition, you know, I think our guys have proven that we will do what we say and we will drill when we say we are going to drill.

So that’s benefiting us a lot. I think one of them drilled a well and screwed it up and didn’t want to do it again, so they sold that, but as far as acreage purchases, we will have to get back to you, but it is less than 5,000 acres where we have actually leased, but I guarantee you there is another 4,000 or 5,000 that we are in negotiations on, because I have seen Hal go over to Shreveport. We have pictures of lone landowners.

Hal Hickey

Well, Brian, I will tell you there is one bucket we haven’t touched is the acreage with bad results. I mean, we are not looking for anything outside of where we are right now.

Doug Miller

You see any acreage in Mary Land County, don’t call us.

Brian Singer – Goldman Sachs

Thanks, and then secondly, you mentioned at the beginning, the negotiations regarding the borrowing base, can you just talk to where you think – how you think that will play out?

Doug Miller

Yes, we are expecting – we had a very productive meeting two weeks ago, a week and a half ago, we expect it is going to be $1.3 billion and we are getting comments and questions in. I expect, within two weeks, that will be approved and we will announce it. We are not asking anybody to stretch or do anything stupid. So you know, we are not even going to use it that much to start with, but I mean I kind of expect $1.3 billion, I expect the grid to be LIBOR plus 2 to 3, and I expect about 20 banks to participate.

Paul Rudnicki

And Brian, what we are really doing here is – all we are really doing is consolidating the few facilities into one. So it is not really a negotiation on the borrowing base, it is just bringing a few facilities together, now that we have got all those transactions.

Doug Miller

We are at 1.3 to start with between the two, and so this is kind of bringing them together and you know, them talking about how hard it is, if they have to work on it, so we have to pay for another fee, so you know how that goes.

Brian Singer – Goldman Sachs

Great. Yes, thank you.

Doug Miller

All right, thanks.

Operator

Your next question comes from Leo Mariani, RBC Capital. Your line is now open.

Leo Mariani – RBC Capital

Good morning.

Doug Miller

Hey, Leo.

Leo Mariani – RBC Capital

A question on the Haynesville for you here. I think you guys have talked little bit on the call today and differentiated a little bit in your press release your results in DeSoto versus mainly some of the other areas there in the Haynesville. Could you give us what your acreage position is in DeSoto versus the other areas and give a breakdown of what your average DeSoto IP is versus other areas?

Doug Miller

Let me give you gross acres in the JV and then you have to just cut it in half, because I think we started out with about 35,000 acres gross when we did the joint venture and I think we bought another 20,000 – so we are between 50,000 and 60,000 acres in DeSoto parish. I am getting some wild stares here.

Paul Rudnicki

No, it is all right.

Doug Miller

Okay, that is good. Gross, and what was the second question, IP?

Paul Rudnicki

$22.8 million.

Doug Miller

$22.8 million in DeSoto, and that is our main focus now. You know, we are actually buying some things in southern Cato that we think might be you know, in that $15 million range, I would call that B+. You know, we have got a good rank now, A+, AB+, B, and there are some Cs and Bs out there that we are trying to go avoid.

Outside of DeSoto, we have had two operating completions and they have been in the range of $9 million to $11 million a day.

Doug Miller

Yes. With reasons. So you know, it is not China is away from the area, but those are probably going to be B, C as well. We wouldn't drill them today.

Hal Hickey

Well we drilled early on in the program, we have learned a lot since then. If we were to complete it today, we would do it a little differently, if we were just drilling it today, we would do it a little differently. So we have learnt.

Doug Miller

I think it didn't condemn the area, because – and we don't think we did it exactly straight down the fairway.

Mike Chambers

In Harrison County, we are frac-ing Stage 4 today on our first well.

Doug Miller

Okay, and we are not expecting that to be – Leo, $22 million a day, we are expecting that to be $13 million to $16 million.

Leo Mariani – RBC Capital

Okay. So in terms of your drilling program, you have obviously got 14 rigs potentially and you know, potentially, it could go up as we get towards the end of the year. I mean, how many of those rigs are going to focus on the core and how many of those are going to focus on sort of this non-core B+ type acreage?

Doug Miller

Yes, one rig is going to be drilling Bossiers, so we have got 13 Haynesville dedicated rigs.

Hal Hickey

One roughly Texas rig.

Doug Miller

One rig will be doing ,Harrison and Northern Cato.

Hal Hickey

Northern Cato. So, better than half or so are going to be focused on the area.

Leo Mariani – RBC Capital

11.5? Okay. Just kind of jumping over to the Marcellus here, it looks like you guys have got your first well, just kind of curious as to what you think, you know, well costs are going to look like there, in terms of ASP for that well?

Doug Miller

Well, the AMV was huge, $7 million plus, because we did a lot of –

Hal Hickey

Cores, but what we are planning on going forward in our budget is $5 million to $5.5 million for this year and going down over time. And the lateral we are talking about here is 4,500 feet to 4600 feet, so it is a long lateral.

Mike Chambers

Versus the kind of 3500 foot laterals that I think is common for what everybody has been talking about up there so far.

Doug Miller

I think in our capital budget, we forecast a little bit more, because we have learnt from the Haynesville that you guys take a little extra time, the costs are going to be higher, you know, Range and Cabot clearly are ahead of us and you keep here and less than $4 million from them and hopefully we can get there. I think we can, but we are sure not budgeting it for this year.

Hal Hickey

In another way, that cost is going to come down dramatically and on our first two or three wells are going to run pipe through the curve. We will not be doing that on our development wells.

Doug Miller

Right. We think a lot of things we are going to – again, now is the term that we are going to do to bring down that cost.

Hal Hickey

We think it is probably similar to what we saw in the Haynesville, you know, in one year’s time going from $12.5 million a gross well down to $9.5 million.

Leo Mariani – RBC Capital

Okay, great. I guess you guys, the well that you are drilling, is that all going to be based on your seismic up there, you are drilling from the – obviously, from longer laterals there?

Doug Miller

Yes, they are. Seismic is going to be very critical in certain sections because of the fall thing and et cetera.

Leo Mariani – RBC Capital

Okay, and I guess in terms of your strategy in the Marcellus, you know, obviously you are talking about 11 wells. Sounds like you are kind of starting to put the pedal to the metal, you got that rig showed up, rigging up right now, and you are going to start drilling was continuously. Just trying to get a sense of production contribution in 2010, are you guys expecting anything, are the wells you are drilling going to be in your pipeline?

Doug Miller

I have called this ramp-up a girlish-type ramp up for us, can I say that?

Paul Rudnicki

You already did.

Doug Miller

Sorry. One rig out there, you know, we probably – you know, with the permits, et cetera, we could probably go faster but I think one for right now, could that change if we have a partner and these first couple of wells come in? I am positive there will be a tug from Pittsburg to go faster. So the flexibility is there to go faster if the equipment is available, and most importantly, the pipeline. We do not believe in drilling wells and not producing them. Steve told me that was a bad rate of return. So we won't do that, but permit production, how much do you have –

Paul Rudnicki

Leo, if you remember, back from our Analyst Day presentation, you know, with our plan of one rig this year, three rigs next, five, six, seven, kind of our five-year ramp-up, the real meaningful contribution starts showing up in the back half of 2011 and really 2012.

Doug Miller

But we do have some production.

Paul Rudnicki We do have some, but we are not, not meaningful. I mean, if we drill 11 wells this year, by the time you complete them, get them online, you know, it is more of a back third or fourth quarter for sure.

Doug Miller

Yes.

Leo Mariani – RBC Capital

Okay, thanks guys.

Doug Miller

All right, thanks, Leo.

Operator

Your next question comes from Irene Haas, Canaccord. Your line is now open.

Irene Haas – Canaccord

Thank you. My question is on Marcellus. You guys have gone in and systematically and methodically high-graded your acres to 186,000 acres. Can you tell us the key reason why the acres got weeded out? That is question number one. Question number two, on Marcellus, do you have a preference for dry gas versus wet gas? And thirdly, in West Virginia, why does the transition between high pressure to low pressure, since you guys have done quite a bit of work in West Virginia?

Doug Miller

Okay, let us start with number one. We have done a lot of seismic, and there will be areas with faults, significant faults, where we will not drill, we don’t think the acreage is available. We have done some vertical testing with minimal results in certain areas. So we have taken that off the sheets. And by the way, as we take this step up, we are high-grading and leasing more. So that 40,000 acres will more than replace the stuff we are dropping. You know, we have shallow wells on some, there are some wells that are – you know, we can’t get a location on the side of the mountain, and it is just going to be continual. Okay, what was the second?

Irene Haas – Canaccord

Preference for dry gas versus wet gas?

Doug Miller

I would say right now we don’t care, but dry gas is probably the areas where we are. Wet gas means we will have to do a joint venture to put in a plant and strip it, which we are not afraid of. We have plenty of guys here who have done that. Al used to do that down in New Orleans and he is prepared to open a plant and work it.

Hal Hickey

I would love to, but we really do not have any wet yet that we are going to have to –

Doug Miller

We don’t really have any – all of our tests vertically, where we are focused, are dry gas.

Irene Haas – Canaccord

Thanks. Third question is the West Virginia portion rise. Any thoughts on why the system went from high pressure to transitional to low?

Doug Miller

Northern West Virginia is higher pressured, then you get into central southern and it is more kind of normal pressure. It is actually the place is kind of going away down there in the middle and south. But I think we have some very high interest and we are pursuing some acreage acquisitions in West Virginia as we speak. So we think it is going to work, and we are going to participate in that.

Irene Haas – Canaccord

Great. Thank you, gentlemen.

Doug Miller

Okay, thank you.

Operator

Your next question comes from Seth Manoff, Zimmer Lucas. Your line is open.

Seth Manoff – Zimmer Lucas

Thank you very much for the time today. Could you provide any color on the oil potential in the Northwest portion of your Marcellus acreage? That is it.

Doug Miller

Northwest. Put it that down to zero for us.

Seth Manoff – Zimmer Lucas

Put it at zero?

Doug Miller

We are not even looking at it, but we were probably not leasing in the Northwest, and if somebody wanted to buy anything we had over there, we would love to sell it.

Paul Rudnicki

We don’t really have much acreage in that area.

Doug Miller

We are not a player, but if we did have some, it would be for sale.

Seth Manoff – Zimmer Lucas

All right. Well, thank you, that is all.

Doug Miller

Thank you.

Operator

Your next question comes from Eric Anderson, Hartford Financial. Your line is now open.

Eric Anderson – Hartford Financial

Thanks. Doug, I apologize, I had to jump off the call for a few minutes, so if this question has been asked, I apologize, but have you guys talked much about the work that Petrohawk has been doing in terms of choking back some of their wells to try to get a better EUR?

Doug Miller

Yes, we did talk about that briefly, but our people have worked – actually the Petrohawk group and our guys work very closely. I would say, of all the companies there, our guys are most impressed with what Petrohawk is doing, and their ability to share. We have been in discussions with them. I think that they believe that it has helped in their EUR and we are looking at – we actually are doing one right now, it is flowing back, and I have noticed this, you know as of yesterday, it was continuing to rise. So there are some merits to it. We think – and we are looking at them and talking to them and trying to learn and we are open, but to make them very open in – you know, we share data with them and they share data with us, and it has been great.

Hal Hickey

So I will add we are continuing to be very supportive of the program that our guys have developed. It has worked very well. We are going to attempt the alternative. But to this point, we think our managed drawdown program as we ramped our choke size up and brought it quickly back down and looked at all the parameters of production, we are confident that we are doing a good thing.

Doug Miller

Keep in mind, we typically ramp these up to 2864, so then we have been producing them at 24, and it has worked fine, thank you, but the last one, we ramped up to like 26, and now we are producing that 20 and it is holding the production level down and you know, we are weak if the pressure keeps building, so that is all we have got.

Eric Anderson – Hartford Financial

So you ramp them up to try to clean them out?

Doug Miller

Well, yes. What we do is, we kept opening them up as long as the pressure was building and we are producing frac water, and as soon as the pressure stabilized, we start bringing it down immediately before. I mean, our guys have been doing it. Sorry, Mike.

Mike Chambers

Yes, we have been controlling our drill down in entire time. We calculated bottom hole flooring pressures the entire time we are doing this as our water rates change and we change to adjust our chokes as our water rate changes, to hold the costs of drawdown.

Doug Miller

These guys, we came up with that early on, we did that on our very first well. So, –

Mike Chambers

We did learned that from vertical well testing, how important choke

Doug Miller

We opened a couple of verticals wide open and our toes were very stubbed.

Eric Anderson – Hartford Financial

So is Petrohawk doing a similar thing or are they just trying to restrict it more?

Doug Miller

No, I think they are doing a similar thing and I think they have been doing it. I think they are probably not ramping it up as high and then they are going to produce it on a lower rate, and it looks pretty good so far. I mean, I would say they know what they are doing and we are monitoring and churned out of it.

Eric Anderson – Hartford Financial

Okay.

Mike Chambers

As well as everybody else in the play. You know, we have working interest in almost every operator’s production out there, and everybody is doing things a little bit different, and we are watching what everybody is doing, not only Petrohawk.

Eric Anderson – Hartford Financial

Okay. Appreciate you taking my call.

Doug Miller

Thanks.

Operator

Your next question comes from Jeff Davis, Waterstone Capital. Your line is now open.

Jeff Davis – Waterstone Capital

Thank you. I am curious what your conventional asset base production looks like, perhaps kind of where you entered the year versus where you see exiting the year. Is there a big decline going on there?

Doug Miller

Well, the only conventional that we have left is our 50% interest in the Cotton Valley and our 100% interest in Vernon, which is deep Cotton Valley, and then our Slugg Ranch stuff. So

Mike Chambers

And the Appalachian conventional. Appalachian Conventional will be down 5%, because we are not drilling. The other areas will be down roughly 10%, because we are not drilling. So, our Permian assets will be maintained to slightly up as we are drilling with one rig out there. But basically, our Vernon and our Cotton Valley and East Texas, you know, we haven't drilled much there in over a year, and the base decline is really come off a lot of the big flush declines, and we are doing some re-frac works on the Cotton Valley, we are doing a little bit of stuff over at Vernon. So it will be down a little bit to flat will be my low high.

Jeff Davis – Waterstone Capital

Okay.

Doug Miller

And then there are opportunities in each area. We probably won't drill conventional Cotton Valleys. We did have on the budget to test some horizontals. I think that should do on the budget, I do not know.

Paul Rudnicki

Horizontal cotton valley.

Doug Miller

So, you know, and over in Vernon, I know they have some opportunities that we are looking at over there. We do have some – as costs have come down, you know, we are getting real close that we might drill some verticals, but now costs are going back up, that is probably back up in the shale.

Paul Rudnicki

On a basic line though capital, I guess throughout the steep initials, we are probably in the low-teens.

Jeff Davis – Waterstone Capital

Okay.

Mike Chambers

To build what Paul said, we have an active recompletion program going on in our DeSoto Parish Cotton Valley program, where we have, I think we are doing a couple of recompletions a month.

Doug Miller

Yes, when we drilled these wells initially, they cost an up hole and we chose to complete only the lower Cotton Valley with the idea coming back in two or three years, where some people were completing them together off the tee. We are coming back in now and completing the Austin and we have had some spectacular results there, almost 100% return, yes.

Mike Chambers

You know, I was in the field yesterday and we had well reviews going on in DeSoto parish that we are actively adding artificial lift and doing those. As you mentioned over in the Vernon field, we have had a very aggressive program battling salt over there, and they very much flattened the decline in Vernon, so we have had some excellent results there, in all our conventional plates.

Jeff Davis – Waterstone Capital

Okay. And what is the current plans for the outstanding notes?

Doug Miller

We will pay them off on time.

Jeff Davis – Waterstone Capital

At maturity.

Doug Miller

We are looking – you know, we are going to have plenty of room under our borrowing base that we could retire. I talked to a bond trader and said we would be interested in buying some at 98, and he laughed at me. Once the borrowing base has been determined, you know, if the buy market is available, we might consider doing another bond offering. We are looking at everything. We have plenty of cash available just to retire them, but we will be looking in the second and third quarter, should we do a bond offering or not? There will be underlying, no equity offering is coming.

Jeff Davis – Waterstone Capital

Okay. All right, appreciate it.

Doug Miller

Thank you.

Operator

(Operator Instructions). Your next question comes from Brian Cusas [ph]. Your line is now open.

Brian Cusas

Good morning, guys.

Doug Miller

Hi, Brian.

Brian Cusas

One thing I just wanted to say thanks for putting in that proved developers have had is actually very helpful. Thank you for just giving it to us rather than make us calculate it.

Doug Miller

Well, we are trying to differentiate ourselves from our competitors, and we thought this was a first step.

Brian Cusas

Yes, and I think it makes – I think that is the way to evaluate you guys. And I was curious, you guys usually give out like your PD10, do you have that split?

Doug Miller

We have it available, it is in the 10-K which will be filed today, but we will give it to you right now. PV-10 developed is 642 million, and PV-10 undeveloped is 105 million.

Brian Cusas

That is great. That is it from me. Thanks, guys.

Doug Miller

Thank you, Brian.

Operator

There are no further questions at this time. I will now turn the call back over to you.

Doug Miller

Thank you very much everybody. We appreciate you guys tuning in. I hope we were able to clarify the activity that we had.

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