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TXCO Resources Inc.
Q4 2007 Earnings Conference Call Transcript

ENERCOM

Moderator: Bob Thomae
March 11, 2008
10:00 am CT

Operator:	Good morning. My name is (Vonda) and I will be your conference call facilitator today.
	I would like to welcome everyone to this quarterly call of TXCO Resources to discuss the company’s 2007 earnings and to review current operations.
	All lines have bee placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question and answer period as time permits. If you would like to ask a question, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, press star then the number 2 on your telephone keypad.
	I would now like to turn the call over to Mr. Bob Thomae, Vice President — Capital Markets.
Roberto Thomae:	Good morning. Thanks for joining us today for our 2007 yearend conference call.
	Joining me this morning are Jim Sigmon, our CEO, Jeff Bookout, our Chief Operating Officer, Mark Stark, our CFO, and Gary Grinsfelder, our Vice President of Exploration.

Today we will be discussing our 2007 financial results and current operations based on the earnings release we published last night for you, for your benefit. After some prepared comments, we will have time for just a few questions this morning.

I’d like to remind you that this conference call is being recorded and will be available for replay approximately an hour after its completion. The archived conference calls, press releases, and other investor information can also be found on the conference call page of our TXCO Resources web site at www.txco.com for your future reference and convenience.

And please be advised that our remarks, including answers to your questions, may include statements that we believe to be forward looking within the meaning of the Private Securities Litigation Reform Act.

Now these forward-looking statements are subject to risk and uncertainties that can cause actual results to be materially different from those currently anticipated.

Now these risks include matters we have described in our past filings with the SEC, including our annual report on Form 10-K for the year ended December 31, 2006, and our Form 10-Q for the quarter ended September 30, 2007. We will file our 2007 yearend 10-K in just a few days. We disclaim any obligations to update these forward-looking statements.

Now during this conference call, we also may reference to EBITDA, EBITDAX, or other non-GAAP financial measures. Reconciliations of these non-GAAP measures to the applicable Generally Accepted Accounting Principles measures can be found with our 2007 earnings release.

Also please be aware that TXCO has filed a preliminary proxy statement with the SEC as of March 10, 2008, yesterday, in connection with the election of directors and other actions to be taken at our upcoming 2008 annual meeting of stockholders, which is now set for May 9 here in San Antonio.

TXCO will soon be filing with the SEC a mailing to its stockholders, a proxy statement, and a WHITE proxy card concerning the solicitation of proxies by the board of directors in connection with the election of directors and other actions to be taken at the 2008 annual meeting.

As required by the SEC, stockholders are urged to read the proxy statement when it becomes available because it contains very important information. And after it is filed with the SEC, stockholders will be able to obtain the actual proxy statement free of charge at the SEC web site at www.sec.gov or the proxy statement will also be made available for free to any TXCO shareholder who makes a request of me here at the office.

TXCO, its directors and executive officers and other members of management and employees may be deemed to be participants in this solicitation of proxies in connection with the 2008 annual meeting of stockholders.

Information regarding the names, interests, and affiliations of these persons in connection with the election of directors and other actions to be taken in the 2008 annual meeting will be included in the proxy statement filed by us in connection therewith.

	In addition, the company files its annual, quarterly, and special reports, proxies, and information statements and all other information with the SEC. These documents are always available free of charge to you at the SEC web site or from TXCO at www.txco.com.
	And with that in background, I’d like to turn things over to Jim Sigmon, our CEO.
James Sigmon:	Thank you, Bob, and good morning, everyone.
	As you can see from our press release yesterday, TXCO had a good year. In fact, we think it was a great year. It’s a year that saw fundamental changes in who we are, and even in the areas that we operate, with our Output acquisition.
	I hope everyone has a copy of that earnings release in front of you. If not, it’s available on the news release page of our web site. You may also want to refer back to our February 12 press release in which we discussed our 2007 production volumes and drilling activity.
	We’ll update a little bit of those — of what activity we’re doing now at the end of the conference call. It’s available on our web site, that information of that press release, if you don’t have it now.
	But first I’ll ask Mark Stark, our CFO, to discuss our yearend financials.

Mark Stark:	Thanks, Jim, and good morning, everyone.
	As Jim mentioned earlier, Q4 marks the third consecutive quarter of 2007 that includes the results of our acquisition of Output Exploration, and as such, comparisons to the prior year will be less meaningful.
	With that said, let’s take a few moments to review some key metrics. Let’s first focus on the fourth quarter.
	Looking at revenues, oil and gas sales, as well as total revenues more than doubled over the fourth quarter of 2006, while gas-gathering revenues remained even.
	Looking at — discussing product pricing for just a moment, you know, average realized prices for oil for the quarter were $86.72 per barrel, excluding hedges. That’s up $30.27 per barrel compared to this quarter a year ago.
	The average realized price for natural gas for the quarter was $7.60 per Mcf, excluding hedges. That’s up $1.16 per Mcf compared to a year ago.
	In terms of sales volumes, quarter four was a good quarter. We produced and sold on a gas-equivalent basis of 2.4 Bcfe on an equivalent basis.
	You know, taking a look at costs and expenses for just a moment, total costs and expenses increased 15% above the fourth quarter of a year ago. This increase in total costs and expenses is consistent with the acquisition and current activity levels.
	Looking at interest expense for the quarter, we incurred $3.3 million for the quarter related to our long-term financing.

When you take all that down to the bottom line, we had net income available to common stockholders of $1.8 million, or 5 cents per basic share for the quarter.

You know, shifting over and recapping the year, oil and gas sales rose to $81.8 million, a 45% increase over 2006, and total revenues reached the level of $93.9 million, which is a 30% increase over 2006.

Again, just reviewing product pricing for just a moment, average realized prices for oil for the year were $71.11 per barrel excluding hedges. That’s up $8.55 compared to all of 2006.

The average price for gas for the year was $7.26 per Mcf excluding hedges and that’s up 8 cents compared to a year ago. For the year, our sales volume, again, on a gas-equivalent basis was right at 8 Bcfe

Working our way down to costs and expenses, total costs and expenses increased approximately 35% over a year ago. Again, this increase in total cost is consistent with the acquisition and our current activity levels.

Interest expense for the year, we incurred $9.7 million in interest expense related to — again, related to our long-term financing.

Again, boiling that all down to net income, when we take everything down to the bottom line, we had net income available to common stockholders of right at $900,000, very close to $1 million dollars or 3 cents per basic share for the year.

But I want to turn to our liquidity metrics, which as I’ve said for many quarters now tell a much more compelling story about our company. You know, net cash provided by operating activities for 2007 — for all 2007 was right at $69.4 million dollars. This compares to $24.7 million dollars for all of 2006.

From a — taking a look at EBITDA and EBITDAX for a moment, we had a record quarter and year. We eclipsed all other quarters in these metrics. For example, for all of 2007, our EBITDA was right at $52.9 million and our EBITDAX was $54.162 million. For the quarter, EBITDA was $20 million, in round numbers, and EBITDAX was $20.339 million.

This compares to EBITDAX — EBITDA and EBITDAX for 2006 of $37.305 million and ($40.273) million respectively, and for the fourth quarter of 2006 EBITDA and EBITDAX were $6.2 million and $8.2 million, respectively.

Also for Q4, our EBITDA and EBITDAX margins were 62.5% and 63.4%, respectively. So, again, we had a record quarter and which translated into a record year.

I just want to walk everybody down through the balance sheet for just a moment.

Our balance sheet remained very, very strong. At December 31, we had total assets of $354.6 million, more than double yearend 2006. Current assets stood at $35.7 million, current liabilities $59.7 million, our long-term debt was right at $100 million, debt to assets was right at 28%, and our line of credit was totally unused at yearend with a borrowing base of $45 million.

And with those comments, I’ll turn the program back to Jim.

James Sigmon:	Thank you, Mark.
	And as you can see, it was indeed a great year monetarily for the company. But we’ve taken a lot of this cash flow that we’ve done and put it into our operations for the last year.
	During that period of time, we had a record amount of drilling activity, 87 wells, and we’re on pace to exceed that this year. We currently have ten rigs running: seven in our core Maverick Basin area, one in East Texas, and two in Oklahoma.
	I want to talk a little bit about what we’re doing in some of those areas. You notice that yesterday we made an announcement of an acquisition in the Fort Trinidad area, where we’ve increased our footprint in the East Texas Basin.
	We acquired — we nearly doubled our net acreage in the area and also acquired about 8 Bcf of reserves at $2.06 per Mcf. We anticipate that the Fort Trinidad area will become more and more important to the company over the coming year. To that end, we have one rig running now and we have a second rig scheduled coming in about the middle part of April.
	Our first well, which we announced a short while ago in the Glen Rose formation, is still producing about half a million cubic feet of gas a day and its production is about up to 90 barrels of oil per day now — as we produce back the — some of the 38,000 barrels of water that we lost in the well while we were drilling.

As I’ve mentioned before, we anticipate that over time this area will continue to — this well will continue to increase and the production will get better. To that end, that’s why we spent the additional dollars, because we were encouraged by the first well and encouraged by what we’ve seen so far to increase our footprint in the Fort Trinidad area.

And in addition to that, many of you have been watching our Pearsall play in South Texas. We are excited about what’s happening there. We’ve been disappointed not to’ve already fraced the wells and done some things already, but we’re getting closer to that time frame.

I think we’ve announced earlier that we’ve rigged up on our first horizontal well in the area to frac in five stages. Unfortunately, the service company in the middle of that job is — as we started it, pumped the wrong sand — too high of quantities of sand at too high a size, and it caused the well to screen out prematurely right at the very start of the first stage.

We then went in with coil tubing to clean it out and as things happen in the oil business the wash tip on the bottom of the coil tubing came off. And then we’ve spent the last three weeks or so cleaning out that well bore, getting all the sand out, getting the — fishing the wash tip out, and getting ourselves prepared to frac this zone again.

We’re rigging up this weekend and anticipate now continuing with that treatment and be able to do it - get it concluded.

But what really excites us about it is what — while we were cleaning the well up, in the first stage that we got a partial frac on, did not get a complete crack and virtually no sand in the well bore, that well came back and was flowing for two of the three days at rates of over a million and a half per day, 1-1/2 million cubic feet of gas per day.

Now this gives us an indication of what the Pearsall zones might be able to do if you get a good frac treatment on a zone and then you screen four or five — as we got in this well bore — of these stages together.

So we anticipate and are excited about seeing what the results might be and how good they might be once we get this frac treatment off. Hopefully this weekend is the time scheduled to do that.

Others of you have been watching closely the tar sands and what we’re doing in that area.

As you may well know, more and more people are — with $100-plus barrel of oil are more interested in the resource plays. We’ve put it on the market to see whether or not someone at this time at the stage that we’re at would be willing to pay and what they might be willing to do with the tar sands with us.

To that end, we’ve engaged (unintelligible) and are going through a process at the present time to - with the data room to determine whether or not there is interest with the stage that we are today.

At the same time, we’re not slowing down anything else that we’re doing. We have drilled two — a SAGD pair, two horizontal wells, and are now hooking up a 25 million Btu steam generator that we have. It is being hooked up to start that injection of steam into that pair.

In addition to that, we have another 25 million Btu steam generator that’s being built — that was built in China and is on the road to be delivered shortly. It should be landing at port in Houston shortly. And then once it clears Customs, we will be bringing it out to the field and hooking it up.

In addition to that, we’ve moved into that pilot, it’s a SAGD pilot we have going on. We’ve now — we moved our rig and are drilling I believe a second or a third of our FAST project, Fracture Assisted Steam Technology.

We’re drilling those wells, preparing for the steam generators that are coming, being built there. So we anticipate, we have two steam generators that are coming, two 50 million Btu steam generators, should be built and arrive late in the second quarter.

Our goal is to have the wells drilled, tank batteries built, wells hooked up, just waiting on the steam generation equipment. When it arrives, then we can start that Pilot.

So the tar sands is moving along rapidly and we’re excited about what might come. We may get some activity very shortly from our (Scotia Waters) project.

If we don’t see anything that we think the shareholders ought to be doing in that, ought to be to their benefit quickly, then we will continue in the project that we’ve got going on.

Many of you, the others, are watching closely our Glen Rose porosity zones. We’ve had a — we’ve hired Schlumberger to help us in evaluating this reservoir and determining the best method to locate wells, drill them, and complete them to maximize oil production out of this zone.

Unfortunately, we — as many oil companies are, we have very, very good personnel in-house, but because we have so many rigs running and equipment running, we haven’t had the time to maximize these kind of things, so we’ve hired Schlumberger to take care of that for us.

The reservoir was a little more complicated as they reported to us than what they anticipated. Consequently, our last meeting with them they were estimating it would be approximately the end of April before they would be in a position to make some recommendations to us.

We now have, I believe, four drilling rigs working in the Glen Rose while we’re waiting on that study to be concluded, which we anticipate will help us maximize oil production and methodology and quantities of oil.

In the Marfa Basin, just as a quick note, we are planning some additional activities in the Marfa Basin. Our present thought process is to run some 2D seismic to help us avoid faults in the area.

Once we get the 2D seismic done, then we would anticipate being — proposing a horizontal well in the area, particularly focusing on the Barnett shale.

	As you recall, we’ve had about 300 Mcf a day plus a little bit that came out of the well from a vertical fracture re-entered well that we did. It was very encouraging to us and we’re ready to go to the next step of horizontal drilling, (but it) will not be until such time we can make sure we don’t drill horizontally and get some faults as we go down that will bring in water from the Ellenberger formation.
	So, as you can see, we’ve got a lot going on. We’re spending Mark’s hard-earned cash flow that he’s provided us with and we think that when we finish these projects they will be very good for the company.
	With that, Bob, let’s take some questions.
Roberto Thomae:	Very good.
	Operator, if you’d like to bring the first question on. We’ve got a few minutes. We’ll take a few questions and we certainly appreciate your participation.
Operator:	Your first question comes from the line of Neal Denman with Dahlman Rose & Company.
Neal Dingmann:	Good afternoon, guys. Or morning I should say.
All:	Good morning.
Neal Dingmann:	Say, Jim, you gave a lot of good color. I’m just wondering now, I guess, on what you’re seeing now, sort of service costs, rate costs, as far as you seem to be in a pretty good cash position — does that make - do you have to see I guess is what I’m asking is more results before you would decide say let’s add a few more rigs in different regions.

	And as far as adding rigs in some of the — some of those around that, would you decide to lock those in here at these rates for a longer period? Or do you still going to continue sort of on a day-rate basis?
James Sigmon:	Well, we plan on a day-rate basis. We think that the rigs have pretty much flattened out as far as the cost and escalations that we saw last year early on. They were increasing rapidly. We think that, Neal, that they’re going our way right now.
	Now we know that with oil prices going up and with gas prices staying up that the activity levels will increase for everybody, which may make them tight again. But at the present time, I mean, that’s all I can address, where I’m at today, we’ll just continue with what we’re doing.
	Now, you mentioned about how fast can we ramp up on activity. We just lack a little more production and a little more information. We’re excited as you can tell by our Pearsall well.
	The first indications are it’s very good, but we just have the one vertical well that’s been producing for a few months and this is our first horizontal well. So we need just a little bit more time on that before we ramp up activity strongly on Pearsall.
	In addition, in the Fort Trinidad area, we — you can tell we’re already excited. We’re bringing in a second rig. So we’ve got a little bit of indications there. But before we bring in a third rig, we’d like to get some production online for a little bit.

Neal Dingmann:	So I think you’ve kind of answered my next question, Jim. It sounds like still that CAPEX in a lot of your plans this year obviously intentionally are somewhat flexible depending on how some of these results play out the next couple to few months. Is that fair to say?
Jim Sigmon	That’s very well. I liken it, Neal, to the ads you see on the car dealers when you try to sell a car and try to sell your used car. It’s a balloon. It’s just — you squeeze it and it goes from different areas and that’s where we’re going to use our CAPEX where we get the maximum bang for the buck for our shareholders.
Neal Dingmann:	And last question and I think I know the answer. As far as — I haven’t asked you this in a while — the permitting process, any issues as far as the permitting process or (unintelligible) the down spacing on some of these?
James Sigmon:	Not so far. Everything’s been — you know, because we have large acreage positions as a general comment and we control it, there’s not any major problems with going down-spacing with the (unintelligible).
Neal Dingmann:	Okay. Thanks, guys.
Operator:	Your next question comes from the line of Chris Pikul with Morgan Keegan.
Chris Pikul:	Jim, could you give us a little more insight? You know, from where we’re sitting, you know, we’ve seen your first East Texas well, and you know, maybe it’s doing a little better, but arguably maybe not quite what you wanted initially.

	You know, it was my understanding and perhaps you’ve stated before, you’ve been looking to consolidate bigger working interest in the East Texas play anyway, so was the acquisition really a direct result of what you’d seen from the first well? Or was this something you’d been trying to work on for a while and just give us a little more perspective there?
James Sigmon:	Sure. And I’ll correct — it’s Chris Pikul, for those of you that don’t know Chris, as opposed to Mr. Pickle.
	But, Chris, no, it was. We have been working — in fact, we delayed working in this area trying to increase our working interest in the Fort Trinidad acquisition portion that we bought from Output.
	Initially we had something in the neighborhood of about 44%, 45% interest and now we’re up in the 95%-plus and 100% in most of the interest. So we consolidated that interest. That’s the reserves that we purchased.
	It was simply just getting back up to that 100% so we weren’t waiting on partners and having to make decisions delaying us on how fast we might be able to develop these properties. Now that’s part of it.
	The second part of it had more to do with the success that we’ve had with the first well and what we saw. And that was the reason why we made another acquisition.
	It was actually two acquisitions here. One had to do with increasing our working interest. The other had to do with increasing our acreage in the area. And that was a direct result of the results we saw on the first well.

Chris Pikul:	Can you share a little more about what you liked so much from the first well? I mean, should we be looking at the production so far as indicative of what you expect going forward or...?
James Sigmon:	Well, one of the things that, you know, you always have your models, Chris. And we go back to look at wells and we have a model about what we think’s going to happen and what we’re going to find when we get there.
	And as you may recall, our model said that this Glen Rose shoal, in particular we were looking at the B shoal at this time, would cover a large area and we ought to be contiguous and ought to go — ought to see them going between wells, still be there.
	But you don’t know until you go drill the well. You don’t know what’s going to be — what’s going to happen on that particular time.
	But one of the things that we saw, the one, the B zone was indeed there. As we moved away from this location, the other wells that’ve been drilled in an area that didn’t have anything, to make sure it was there, indeed the B zone was there as we postulated.
	A second thing that was there is that it had fractures on this thing so that we saw fractures, which means that the wells will be able to drain a little larger area. We offset an 8 Bcf well and got a little bit of depletion on this well. That caused us to loot 30,000 barrels — 38,000 barrels, I think, of oil on it.

	But the FMI logs — water in a well, the FMI logs we ran showed fractures with it. So what it’s telling us is that one, the reservoir covers a big area, which is what we wanted; two, the porosity and permeability of the reservoir is better than what we anticipated; so three, it probably is going to take fewer wells to drain the same amount of gas out of this thing than what we anticipated.
	So that’s what makes us a lot more excited about it than what we were when we first started.
Chris Pikul:	Okay. I see where you’re coming from.
	And if I could just ask real quickly, just looking at the Glen Rose porosity reserve adds, you know, I don’t want to split hairs with you guys, but, you know, if maybe you did 30 wells, or, you know, we can back into some kind of average number, we know what you produced there because you’ve given us that data.
	Is there anything you can tell us on just the Glen Rose program in ’07 and whether it added the kind of reserves that it has historically or what you thoughts are on that?
James Sigmon:	Well, it’s a good question.
	One of the things that — we’ve slowed down a little bit, so therefore you don’t see the reserve adds that we slowed down in the fourth quarter while — particularly part of the third quarter and the fourth quarter and it’s continuing on in the first quarter this year while we’ve been waiting on Schlumberger to get the reserves up.

	We can’t tell the difference between a good well and a poor well as we’re drilling them. So therefore it’s becoming a statistical play with what we’ve got today.
	That’s why we’re hiring Schlumberger and having them go through all the exercise to be able to determine better places to drill so we can anticipate where the better production might be on these wells.
	We think that the average has come down a little bit. I think we were in the 140,000 barrel average and we’re in the 120,000 barrel average now. So we’re seeing over time as we’re drilling them that the average of all of the wells are getting down.
	So that means that we’ve obviously had some that were a little poorer (unintelligible) we had some very good wells, too, but as far as an average, they’re a little poorer.
	So that’s why we really think it’s important that we get the numbers from — get the study from Schlumberger finished as quick as we possibly can.
	In the meantime, we’re not slowing down. I mean, we’re still drilling. We’re ramping up. Remember, we got down to one rig, I think, running in the area and we’re back up to four rigs running and increasing that as we go, as rigs become available and we can move them from one area to another.
	So we’re increasing the Glen Rose, but we’re trying to do it in such a manner that it’s prudent.
Chris Pikul:	Okay, thanks a lot for your candor, Jim. I appreciate it.

James Sigmon:	Thank you, Chris. Mr. Pikul.
Operator:	Your next question comes from the line of Phil McPherson with Global Hunter Securities.
Phil McPherson:	Yes, great job on the year. A few just housekeeping questions.
	Jim, can you talk about this steam generator? You said two different numbers. I just want to make sure I got it right. It’s two 25 megawatt ones that are coming in, right?
James Sigmon:	No, we have — we already have one 25 million Btu generator there now. We have a 25 million Btu generator that’s on the water, that’s built on the water, that’s being shipped. It will be here, you know, within the next couple of weeks.
	And then we have two 50 million Btu steam generators that will be here late in the second quarter.
Phil McPherson:	Okay, great.
	And can you give us an idea of what the capacity on a steam generation capacity is on these? Like how many barrels of steam you could expect to generate from one of these?
Man:	(Unintelligible).
James Sigmon:	I believe that the number — again, I’m a little bit out of my own, but I believe it’s about 3000 barrels a day for a 50 million Btu steam generators at the pressures and the temperatures that we’re talking about.

Phil McPherson:	Okay, great.
	And — what was I going to ask on? Going back to just the — like more — this might be more towards Mark — on the LOE, it seems to be jumping around quarter to quarter. Do you have any kind of guidance what we should be looking at going forward?
Mark Stark:	You know, just — I would just take a — or Phil, I would just take a, you know, rolling average of that, you know, going into, you know, future quarters.
Phil McPherson:	So you think it’s going to smooth out now more? I mean to jump from, you know, 7 bucks a barrel to $11 back to $7 or, I mean, it’s a big difference. I was just wondered if you had any coloring on it.
Mark Stark:	Yeah, I think it’s going to smooth out. I think a lot of it had to do with our absorption of the Output acquisition. And I think that’s probably the lead reason as why it kind of jumped up in some of the mid quarters.
	But I think as we move, you know, fourth quarter on, I think you — its — it will smooth out.
Phil McPherson:	Okay.
	And while I’ve got you, Mark — there’s a line out on the balance sheet, the abbreviated one in the press release with other payables for $39 million. Can you give us a — some color on what that is?
Mark Stark:	Yeah, that’s just at — we — that’s purely trade payables.

Phil McPherson:	Trade payables?
Mark Stark:	Yes.
Phil McPherson:	Okay.
	Is there a reason it’s listed as other and not just in the straight payables, or.
Man:	(Unintelligible).
Phil McPherson:	Unless I’m reading it wrong. And I can follow up with you later on. It’s not a...
Man:	(Unintelligible).
Phil McPherson:	...huge point.
Mark Stark:	Why don’t we do that offline.
Phil McPherson:	Yeah. I’m sure when the K comes out, there’ll be some clarity on there.
Mark Stark:	Yeah.
Phil McPherson:	All right, great. That’s really all I had, guys. Great job.
James Sigmon:	Thank you, Phil.
Roberto Thomae:	And Operator, I think we’ve got time for at least one more call. And bring it on and before we end the conference.

Operator:	Your next question comes from the line of Adam O’Laughlin with BMO Capital Markets.
Adam O’Laughlin:	Good morning, gentlemen.
	What kind of results, response do you hope to get from the three oil sand pilots by yearend? And any chance you’re going to be able to book those proved reserves?
James Sigmon:	Well, booking proved reserves, to take that, has a lot to do with what the SEC does and they’re right now, you know, reviewing how they’re going to handle oil sands and being to book those reserves.
	So right now, as you well know, booked reserves on the — from an SEC standpoint would just be the offsets for the wells that you’ve got drilling. So that would be a limited number on booked reserves by the yearend.
	We would anticipate — but not giving numbers or what numbers might be at this time, we would anticipate that we would have all five of these wells, the drilling, plus the other three, about eight wells we’re drilling on the FAST technique, would all have steam going on them and anticipate some response by yearend from all — from that pilots to the north and we certainly expect some response from the pilot to the south.
	I would guide you — the only guidance I would give you a little bit on the FAST technique would be that Conoco showed in about 18 months on their pilots that they recovered about 170,000 barrels of oil in 18 months period of time and that 18 months was — included heating the reservoir, steaming the reservoir, getting it going, before they got the production coming out.

	So that — that’s -without giving any guidance, we’ve just told you what’s been done in the past and what’s been done in the past, you know, the best that we can look at right now.
Adam O’Laughlin:	All right, great. Thank you.
	And one last question — what kind of a steam ratio do you expect, are kind of looking at?
James Sigmon:	Well, that’s — those are the things that we’re trying to determine right now.
Adam O’Laughlin:	Okay.
James Sigmon:	That’s the reason that we’re doing what we’re doing, is to determine those actual numbers. We have simulation programs, which we’ve gone through based upon the cyclical information we gained earlier at modeling that we’ve done, but we’re trying to identify exactly what it’s going to be and determine which is the best method to get the tar out.
	It could be the SAGD method or it could be the FAST technique. Those are the two that we’re seeing, or even a modified FAST that we’re going to put in. But those processes are the ones that we think are the most probable to get the maximum amount of oil out at the lowest steam/oil ratio.
Adam O’Laughlin:	Thank you very much.
James Sigmon:	Thank you, Adam.
Roberto Thomae:	I think that’s about all the time we’re going to have for today. Jim, do you have any closing comments you’d like to share before we head for our road?

James Sigmon:	No, Bob, I just — I’m just excited about where we’re going. I think this was a great, great year and I just see these — several of our projects are right on the cusp of where we can really go forward in the coming year.
	So I just ask for people just to watch what we’re doing because I think it’s going to be a very, very good year this year.
Roberto Thomae:	Well, with that we’re going to conclude the call. We thank you for your patience and for listening in.
	We certainly ask you to tune in and continue watching our web site for additional information on all the issues we’ve got going forward, as well as operations and earnings going forward.
	We’ll be filing our 10-K here in the next few days. There’ll be a lot more detail available for you. And certainly Mark, myself, the rest of the staff, and Jim will be available in the future to answer those questions.
	We thank you again. And, Operator, that concludes our call.
Operator:	Thank you. This concludes today’s conference call. You may now disconnect.

END

Important Information

     TXCO Resources filed a preliminary proxy statement with the Securities and Exchange Commission (“SEC”) on March 10, 2008, in connection with the election of directors and other actions to be taken at the 2008 Annual Meeting of Stockholders. TXCO Resources will soon be filing with the SEC and mailing to its stockholders a definitive proxy statement and WHITE proxy card in connection with the 2008 Annual Meeting of Stockholders. As required by the SEC, you are urged to read the preliminary proxy statement and the definitive proxy statement (as well as any amendments or supplements thereto) relating to the 2008 Annual Meeting of Stockholders when they become available because they contain important information. After being filed with the SEC, you will be able to obtain the preliminary proxy statement and the definitive proxy statement (as well as any amendments or supplements thereto) and other relevant documents free of charge at the SEC’s website, www.sec.gov. In addition, copies of the definitive proxy statement and other relevant documents will be made available for free to any TXCO stockholder who makes a request to TXCO’s Corporate Secretary and Vice President-Capital Markets, Roberto R. Thomae, at (210) 496-5300 (ext. 214) or 777 East Sonterra Blvd., Suite 350, San Antonio, Texas 78258.

     TXCO Resources and its directors, executive officers and other employees may be deemed to be participants in the solicitation of proxies in connection with the 2008 Annual Meeting of Stockholders. Information regarding the names and interests of these persons in connection with the 2008 Annual Meeting of Stockholders was included in the preliminary proxy statement, filed with the SEC on March 10, 2008, as such information may be supplemented or amended by the definitive proxy statement. In addition, TXCO Resources files annual, quarterly and special reports, proxy and information statements, and other information with the SEC. These documents are available free of charge at the SEC’s website at www.sec.gov or from TXCO at www.txco.com.