TXCO Resources Inc. Q2 2008 Earnings Call Transcript

TXCO Resources Inc. (TXCO)

Q2 2008 Earnings Call

August 7, 2008 11:00 am ET

Executives

[Bob Chermais] - Vice President, Capital Markets

James Sigmon – Chairman, Chief Executive Officer

Mark Stark – Chief Financial Officer

Gary Grinsfelder – President

Jeff Bookout – Chief Operating Officer

Analysts

Neal Dingmann – Dahlman Rose

Philip McPherson – Global Hunter

Chris Pikul – Morgan, Keegan

[Chris Bray – Jeffries]

Tom Laird – Mulholland Capital

[Bill Harrison – Janney]

Neal Fagin – Fagin Consulting

Presentation

Operator

I would like to welcome everyone to this quarterly call of TXCO Resources to discuss the company's second quarter and first half 2008 earnings and to review current operations. (Operator Instructions) I would now like to turn the call over to [Bob Chermais], Vice President, Capital Markets.

[Robert Chermais]

Joining us this morning are Jim Sigmon, our Chairman and CEO, Gary Grinsfelder, our President, James Bookout, our Chief Operating Officer and Mark Stark, our Chief Financial Officer. We'll focus this morning on the financial results we announced Wednesday and we'll further update you on our latest operation status. After some brief prepared remarks, we'll have time for a few questions as well.

I want to remind you that this conference call is being recorded and will be available for replay approximately one hour after we're done. The archived conference call, press releases and other investor information can be found on our TXCO Resources web site at www.txco.com for your future reference.

Please be advised that all remarks including answers to any questions may include statements that we believe to be forward-looking within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks, including matters we have already described in our past filings with the Securities and Exchange Commission including our annual report on Form 10-K for the year ended December 31, 2007, and our first quarter 2008 10-Q. We will file our second quarter 10-Q in just a few days.

We disclaim any obligation to update these forward looking statements. During this conference call we may also may make references to EBITDA, EBITDAX or other non-GAAP financial measures where considerations of these non-GAAP measures be applicable. GAAP measures can be found with the earnings release. With that background, I'd like to turn things over to Jim Sigmon.

James Sigmon

I'm pleased to report that TXCO had another excellent quarter and first half. Record oil and gas sales coupled with high commodity prices gave us some very strong financial results. I hope everyone has had time to read yesterday's earnings release as well as the operations announcement we released this morning. If not, both are available on the news page of our web site, TXCO.com.

We won't take time here to repeat all of those numbers for you, but they're available for you readily on the web site. To start off, I'd like to invite Mark Stark, our CFO to provide some background on our financials.

Mark Stark

In a review of our second quarter results, I'd like to take a few moments to review some key metrics. Let's first focus on the second quarter. In looking at our revenues, oil and gas sales more than doubled and overall, our total revenues more than doubled over the second quarter of 2007. [inaudible] about product pricing, average realized prices for the quarter were $111.89 per barrel of oil. That is inclusive of hedging up $50.71 per barrel compared to this quarter a year ago. Average realized prices for natural gas for the quarter were $10.81 per NCF inclusive of hedging up $3.96 as compared to a year ago.

Touching on sales volumes for just a moment, in quarter two we had 308,000 barrels of oil and gas production of 813 million cubic feet of gas. On a gas equivalent basis, that's 2.66 bcfe for the quarter which is up significantly from the same quarter a year ago or the first quarter of 2008.

Cost and expenses – total cost and expenses increased 46.5% over the second quarter a year ago. This increase in total cost and expenses is consistent with our current activity levels, the current commodity price environment and higher DD&A costs.

Interest expense – we incurred $2.3 million of interest expense for the quarter related to a long term debt financing. By the time you boil that all down in terms of net income of the bottom line, we had net income of $10.129 million. After paying preferred dividends, we had net income available to common shareholders, common stockholders of $8.71 million, or $0.24 per share diluted, on a diluted basis or $0.25 per share on a basic basis which is within the range of expectations.

Moving on to liquidity metrics, all of these results obviously will lead to extremely strong cash flows. Net cash provided by operating activities was nearly $24 million for the first half of 2008 compared to approximately $7.5 million for the first half of 2007. However, when you adjust for certain changes in operating assets and liabilities such as increases or decreases in current receivables and payables, pre-paid expenses etc., net cash provided by operating liquidities for the first six months was $47.2 million compared with $18 million for the first half of 2007.

Looking at our cash flow metrics as measured by EBITDA and EBITDAX, we had another very strong quarter and are on pace for another record year. We're very proud of the ability to maintain our financial discipline as we continue to grow as evidenced by our growing EBITDA and EBITDAX margins.

For example, for the second quarter, we had $33.6 million in EBITDA and $34.167 million of EBITDAX for the quarter. On a year to date basis, we're right at almost $52.8 million for the first half versus $53.9 million for the first half of EBITDAX. In terms of EBITDA margins and EBITDAX margins, our EBITDA margin for Q2 was 69%. Our EBITDAX margin was 70.2%, again, evidencing the continuing financial discipline of our operations.

I'll take a few moments and review our balance sheet. Our balance sheet remains very strong. At June 30, we had total assets of $424.9 million, more than double Q2 of 2007. Current assets were right at $49.6 million. Current liabilities were $71.6 million. The large increase in that was due to derivative hedging. Long term debt was right at $117 million. Debt to assets, right at 28%. Our line of credit balance on our revolving credit facility was at $17 million with a borrowing base of $60 million leaving $43 million available at June 30.

That concludes my highlights of the financial review, and at this point, I'll turn the program back to my colleagues.

James Sigmon

It does make me feel good whenever the financial numbers are in line with what our operational numbers are, and with said I'd like to turn the operational update over to Gary Grinsfelder, our President.

Gary Grisfelder

I think we'll begin right off with a discussion of our most recent Pearsall activity. With that, I'll turn that over to Jeff Bookout, our COO who has his hands on what's going on out there in the field.

Jeff Bookout

Myers 2683 well has mentioned in our press release this morning is currently flowing at a rate of 3.5 million a day with 3,875 pounds flowing tubing pressure and it's still unloading pipe crude at a rate of about 2,500 barrels a day. This fract simulation and subsequent flow rates are very significant to TXCO as we go through an evolution to find the correct completion techniques required to unlock the Pearsall shale potential under our leasehold.

The Myers well has completed a little differently from our first two Pearsall completions in that we cemented a four and a half rider in place and perforated all five stages for limited entry into the formation. All five stages were successfully stimulated with 750,000 lbs of sand and 59,000 barrels of fract fluid placed in the five stages in aggregate. The use of real time micro [sadelling] monitoring in an off set well allowed us to observe and modify the stimulation as we were pumping, giving us the opportunity to try some different things on site.

The Myers well deviated from our first two stimulation attempts in that both the Comanche 341 and the Cage 26-2 wells were completed and stimulated open hole with multi stage packers and sleeves. In both of these wells, mechanical difficulties prevented us from achieving successful stimulations on all five stages. Consequently, these wells have not performed as expected, initially producing only about 1,000 ncf per day each.

The Myers well gives us an extremely valuable data point on which to build going forward, as we currently have two additional Pearsall wells drilling in horizontally. As our geoscientists and engineers get a chance to study the data and results from the Myers completion, we should have a much better understanding of how the Pearsall shale responds to stimulation. We are currently in a learning mode with this vast resource that we have under our control, and each data point we acquire puts us one step closer to unlocking the Pearsall.

I'll turn it back over to you now Gary.

James Sigmon

As you can see, we're perhaps on our way to as Jeff said, unlocking the potential of the Pearsall. I might mention that we've completed seven wells recently, or drilled seven wells recently here in the Pearsall and the Eagleford and five of those seven are Pearsall wells, two are Eagleford wells. Four of those wells are on the [Anadarco] farm out acreage and three of those wells are on the [Incana] farm out acreage. Those were the required wells under the initial phase of each of those farm outs. TXCO will be making a decision here shortly to move ahead to phase two in each of those farm outs.

Moving ahead we'll discuss now the Glen Rose porosity plane. As mentioned previously, we enjoyed record sales for the second quarter. We've drilled 21 wells to date, 10 of which were operated by TXCO and the remainder by other operators. We continue to run five rigs in the field and will continue to do so until forced to reduce our drilling due to the annual hunting season moratorium. As you can see we expect to keep the production up as best we can in that very key field to the company.

Moving to the San Miguel oil sands, we consider the next six months to be exciting for our heavy oil development pilot projects. On the Sag D pilot, we will begin injecting steam sometime this quarter, and we hope to have some indication of the results of that injection by year end. On the two fast pilots, we're finishing the installation of the two 50 million btu generators we recently received from China.

All wells necessary for the fast pilots have been drilled, five vertical wells in a five spot pattern and three horizontal wells which we are calling a modified five spot pattern. We expect to begin the pre-heating phase this quarter and then move to steam injection later this year. We expect to see preliminary results from these two pilots sometime during the first quarter of next year. We're on track with those two pilots and there's a lot of excitement between us and our partner to see what results we might get from those two pilots.

Moving to East Texas, and our Fort Trinidad field, we are continuing the development of our lease position. Five wells have been drilled to date and a sixth well should spout soon. Currently we have one well producing at modest rates, one well drilling horizontally in the Glen Rose B, one well preparing to begin drilling horizontally in the Buda formation and two wells in various stages of completion. That East Texas field is moving ahead as predicted.

I think that's all I have for now, Jim. I'll throw it back to you.

James Sigmon

I hope that everybody can see the excitement in our voices and even on the press release that we sent out this morning about the development of the Pearsall formation. I want everybody that's on the line and those that listen to us later to understand that we've been drilling and developing this clay methodically. We've been getting cores, we've put organic carbon in place, we've got the gas in place over a broad areas and getting wells that are scattered across this block. Many of these wells are over 10 miles apart from one another.

We've been modifying, completing these fraction techniques in each well in an attempt to maximize the production results. As good as the results are that we're reporting this morning, we do not believe by any stretch of the imagination that we have gotten the maximization point. We would expect to be increasing lateral links and even the number of stations of what you finding done in other places such as the Haynesville clay that's newly developing also.

When you keep that in mind, Haynesville acreage as everyone knows that's following the clay has gotten pretty outrageous in my point of view, but gotten very high. If you consider what we've been able to do over the last year while people have complained about our slowness and our methodicalness, what we've been able to do in bringing this clay forward, at the same time we've increased our net interest in the Pearsall by over 150,000 acres. We find ourselves with this newly arriving shale clay in a great position with a large acreage position to go forward and we're finding what we believe to be the keys to unlock the potential for this formation.

With that said, I would turn it over to any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Neal Dingmann – Dahlman Rose.

Neal Dingmann – Dahlman Rose

On the Pearsall, does that flow in line with your production as far as the plans and the way that this should play out? Does that make you more excited to add another rig or so there?

James Sigmon

Obviously Neal, we are excited about it. We would plan to start adding more rigs as we get more information. One well does not give us all the data we want. We know that we're not maximum rates to full development scale, but at these rates, with a three million a day kind of numbers are in line with what we expected when we went in here, and what we're seeing is we're probably going to be able to improve on that a lot as we go forward based upon this new information we're getting from the micro seismic.

Neal Dingmann – Dahlman Rose

As far the way you see now as far as commodity prices, for the remainder of the year, do you see your CapEx staying about what you had already anticipated?

James Sigmon

We'll obviously discuss it at the Board level, but with these kind of results it's going to impact most likely what we would plan to do with our financial results. Our cash flow is strong. Everything looks like we could probably increase it.

We've told the market, and I've told the market, and I think we're still on line with that. We plan to have five wells horizontally drilled by the end of the third quarter, and fractured and stimulated at that point. We've got three of those wells down now. We've got two more that are in the horizontal drilling phases and we should be able to get those fracted barring scheduling conflicts by the end of the third quarter. So it's at that period of time after we get those five wells done that we'll be talking about what we might want to increase or not or just how much we might want to increase the CapEx metric.

Operator

Your next question comes from Phil McPherson – Global Hunter.

Philip McPherson – Global Hunter

Could you give us an idea in the difference in drilling costs when you do the cemented liner and the five stage fract and what you're looking at in future drilling costs?

Gary Grinsfelder

There's not a lot of cost difference per se. The sleeves and the ball multi packer stage equipment is very extensive as a lot of people are using it so it's just in short supply. Actually the liner, cement and placer's is probably cheaper overall as far as a completion technique as opposed to the fract point system or the packers plus or whatever monogram you might want to put on it.

Philip McPherson – Global Hunter

We still make that $4 million to $5 million range per drill complete cost?

Gary Grinsfelder

You're looking at right about $5 million by the time you do five stages of fract and all the different flow back and probably going to even look at doing some production logging on this one once we get some more data.

James Signon

Those are the kind of things that we will see. Remember, we're drilling pilot holes and logging those wells and taking cores and a lot of extra science that we're doing on these scattered wells across that block. And we will continue to do as we go into development phase later.

Philip McPherson – Global Hunter

Is it safe to assume that the cemented liner methodology is what's going to be going forward on the rest of these wells now?

Gary Grinsfelder

After the results of this Myers well, it definitely stands to do a couple more like that and do comparative analysis. I think that an important part of this thing is limited entry perforating where you actually initiate a point in the Pearsall to put your fract stimulation through.

Philip McPherson – Global Hunter

It's kind of like those surgical fract that we used to call them, is that kind of the term?

Gary Grinsfelder

Kind of, sort of. Not really, but you and I can talk about that offline somewhere. I'll give you some more detail.

Philip McPherson – Global Hunter

On the East Texas stuff, you went through it kind of fast. Can you give us a little more color as far as – I know that one well was pretty good and then the second one was kind of mixed results. Can you just review that again for us?

Gary Grinsfelder

We're being somewhat methodical on how we're acquiring information on these wells. You might recall that this is a 40 year old field, and our running the drilling is really the only new drilling in the last 40 years, so we're taking our time to run a full suite of open hole logs including fracture identification logs. We also have made the decision to test the vertical part of the hole where we see it shows or obviously fractures Glen Rose shoals, some of those tests have not been worthy of a vertical completion but I think it might be correct to say that we see evidence that most of those other Glen Rose shoals, B, D and E are probably future targets for horizontal drilling.

What we've elected to do, I think you might be referring to the 3H, it had relatively poor results in the vertical test, but we're going horizontal on the B section right now, and we expect that well to be a fairly good deal. We're following that procedure with the 4H and the Maples well, testing the vertical section to collect that information before we decide which zone to go horizontal in which will most likely be the B. We consider the B to have the most upside, at least right now we do.

And of course, don't forget up at the Meyer location on our acreage we acquired earlier this year, that we are going horizontal in the Buda which as you might now is a redeveloping play in the area, horizontally. So I guess we're kind of in the middle of understanding what the horizontal drilling is going to do for us. We've drilled one well with the results I indicated previously and we're only on our second one.

Philip McPherson – Global Hunter

I remember looking from this clay, there's five or six different shoals to look at, so you drill through them vertically and then are you basically testing each one of those to see what kind of rock quality you have?

Gary Grinsfelder

We test based on the open hole log response. That's correct. Some zones have better porosity than others and of course porosity is significant here, the key maybe to which zones might sustain a vertical completion. And then we come back to the B, because the B in every case has seen multiple fractures in the fracture identification log and usually has a very good mud lock show as we drill through it. So we're just collecting information I guess is the way to put it for future horizontal targets in the field.

Philip McPherson – Global Hunter

I assume that you're lateral is like 1,000 or 2,000 feet?

Gary Grinsfelder

They're 3,000 to 3,500 feet long.

Philip McPherson – Global Hunter

So it's depending upon how many fractures you encounter?

Gary Grinsfelder

Correct. We stop as soon as we're making signification rates.

Philip McPherson – Global Hunter

Did you push out the first production number on the San Miguel? On the previous press release I thought we were talking fourth quarter and now you guys said first quarter. Have things just gone a little slower?

Gary Grinsfelder

You remember, there's two separate pilots; Sag D which we'll see fourth quarter results from steam injection, and the Fast we'll see either late fourth quarter or early first quarter results from steam injection on that pilot. You have to remember there's two separate pilots.

Philip McPherson – Global Hunter

As far as the sale of assets, is that going to be a gain that's booked in the third quarter that we should put into our numbers? Can you put a little color on that and does your quarter end debt number have any pre or post sale or anything like that?

Mark Stark

Yes the asset sale is a third quarter event. It occurred in July. In terms of the relative gain on the sale of the assets since, it is a July event. I can't really speak to that at this moment in time. In terms of our debt, we would anticipate those results are from the sale, our debt would actually tick down for the month of July.

Gary Grinsfelder

Just as a follow up to that, the divestiture in our mind, remember that these were 15 different fields. We had small interest in them. I think we only operated one of them, and they were not our focused areas. We're just trying to bring our company back to more focused and concentrate in the area where we really think have potential and we're always limited in people and personnel, and we don't need to be diverting ourselves too much.

Operator

Your next question comes from Mr. Chris Pikul – Morgan, Keegan.

Chris Pikul – Morgan, Keegan

Jim, help us understand if this Pearsall well has been on a couple of days. Do you have any internal guesses or can you offer a rate that you might expect this well to peak out at?

James Sigmon

We started flow back late Sunday and we had gas break through sometime late Monday which was out of the ordinary for the other two wells that we did. We did not see gas breakthrough that quickly. The well has been steadily increasing in rate since that time all the way up to the 3.5 number that we saw this morning, and then actually a later result that we got in this morning at about 9:00 am, it was already up to 3.85, or 3.88 million, almost four million.

So as we get more fract fluid off it, it seems to be just getting stronger and stronger. Without much history that we have on how these wells clean up after these fracts, today I couldn't tell you where that's going to top off at.

Chris Pikul – Morgan, Keegan

It sounds like we could be still cleaning that up for one to two weeks?

Gary Grinsfelder

We put about 59,000 barrels in the formation in aggregate and only recovered about 15% of that as of this morning.

Chris Pikul – Morgan, Keegan

Do you have any insights into why the pressure differentials encountered between this well and the last one would be so different?

Gary Grinsfelder

It's mostly a function of the reservoir is tight. It's all basically has the same pressure. It's how much conductivity I can provide that [inaudible] with my fract re-stimulation. The pressures are there, it's just how I communicate those pressures into the well board.

James Sigmon

What we're seeing is that we're using a different technique, and I think that's very, very important that we are cementing these liners in place and then fracturing in stages. But within those stages, we're burying the number of entry points within each stage, and with micro seismic we were able to see how increasing the various points within that stage, we would get more complex fractures. So think it's purely and simply just that we're using a better technique and we're going to be able to improve on it.

Chris Pikul – Morgan, Keegan

Can you redefine or run through what you believe you're net Pearsall acreage would be if you follow through on the performance with the [Canadarca].

Gary Grinsfelder

I'm just remembering that we have 341,000 net acres. Out of 848,000 total acres that's under each farm out so if we do follow through with all three phases of each farm out, we would have 341,000 net acres out of 848,000 total acres in the play, so that might give you an idea if you look at how many sections that is, is a way to maybe get down to what might be the potential here. If you get down to how many net sections those net acres give us, it's 533 net sections.

These shale plates are developed usually on 80 acre spacing, sometimes by 160, so that's quite a few wells per section. Again, we're so early on in the development and understanding of what each wells accumulative production can be it's hard to say. It depends on how many wells we drill per section.

Chris Pikul – Morgan, Keegan

You guys have told us you believe at a 20% recovery factor you get 8 to 12 tcf net. Is that correct?

Gary Grinsfelder

Correct.

Chris Pikul – Morgan, Keegan

So that 341,000 number includes your 100% acreage?

Gary Grinsfelder

Correct.

Chris Pikul – Morgan, Keegan

If this clay really develops in a way that meets your expectations, what do you have to do in terms of infrastructure or other investment to begin moving more significant volumes?

James Sigmon

We will have to lay extensions to our system pipeline. Remember it's a very large acreage position over a large locks in area and our 90 miles of pipeline system that we own ourselves, just covers a portion of that acreage. We will probably have be laying 10 or 20 miles worth of 12 or 20 inch line going down to the heart of it as we develop the field.

Chris Pikul – Morgan, Keegan

As far as the reserves go for the first half, did that include the 8B's from the East Texas acquisition as well? Didn't you acquire APCS from the East Texas acreage?

Gary Grinsfelder

If you're referring to the reserves when we increased our working interest at Fort Trinidad?

Chris Pikul – Morgan, Keegan

You did an acreage acquisition.

Gary Grinsfelder

The acreage acquisition didn't add any reserves. What we did when we acquired the working interest in Fort Trinidad field, we did acquire additional reserves which were booked at year end '07.

Chris Pikul – Morgan, Keegan

So we shouldn't expect to see that in the 90 number you just reported?

Gary Grinsfelder

That's not in there. That's correct.

Chris Pikul – Morgan, Keegan

Can you give us a sense in broad terms, nothing specific, what you expectations are for production from these pilots? Numbers of barrels would help, but is this something that comes on very slowly and then ramps up, or do you get flush production right away once you do the steam? Can you walk us through what kind of data points we might be getting from there?

James Sigmon

These things come on slowly and gradually walk themselves up. The Sag D well will start out anywhere from – should start out slowly and come up to 600 to 2,000 barrels a day.

Chris Pikul – Morgan, Keegan

How long would that take?

James Sigmon

I forgot our simulation models, but I'm going to say over about a year. They will ramp up with an increase, and then it'll fall back, and then on the other pilots, the fast pilots, just gradually increasing, as you go through the heating phase to stage. Those wells should only be maybe 200 barrels a day, even when they get to their maximum rates they won't be much more than 200 to 400 barrels a day maximum.

Chris Pikul – Morgan, Keegan

How long would that take?

James Sigmon

The experience we have, we have a little bit better handle on it, I think Conoco is developing recovering 6% of the oil in place, took them a little under two years to recover all of the 50% of oil in place.

Chris Pikul – Morgan, Keegan

So we're getting data. We're expecting a modest 10 to 15 barrels a day, kind of thing and then we're expecting to see these volumes move higher as we move through '09?

James Sigmon

That's correct. And they ought to just gradually increase to where we expect 200 to 400 barrels a day of oil.

Operator

Your next question comes from [Chris Bray – Jeffries]

[Chris Bray – Jeffries]

I had a question in regards to the Myers well and the proximity to infrastructure there. Are you guys able to hook that in?

Gary Grinsfelder

What we've got is our existing system that in our 90 mile pipeline that we own. We can get into that system approximately 6,500 feet from this well. And it's on our leasehold so we've already initiated as of Monday, get started on getting our right of ways done and getting pipeline lined up and all that stuff that we need to do.

[Chris Bray – Jeffries]

And what is the primary gas market for that particular gas?

Gary Grinsfelder

The primary gas market, we'll sell to Enterprise at the end of our system. This gas is typically very dry so it doesn't have much facilities or refining processes that need to be done to get it into the mainstream.

Operator

You next question comes from Tom Laird – Mulholland Capital.

Tom Laird – Mulholland Capital

This is dry gas, and you're selling into the local system there. If we were trying to model this, what kind of pricing structure should we assume off an [inaudible] or a Henry Hubb? What kind of differential?

Gary Grinsfelder

Normally after transportation and compression costs and all the things that are involved, you're looking at a percentage of use to ship channel type pricing. And so you're in the neighborhood of 93% to 94% of use to ship channel by the time it gets to the mainstream.

Tom Laird – Mulholland Capital

I was a little unsure what you meant when you were talking about the ultimate price of the well here and you said, "Obviously this early well is more expensive with all the science work." Down the road are you still suggesting that maybe these wells could move from a current $5 million towards $4 million, or they might over the long run be at $5 million?

James Sigmon

I kept everything the way I'm doing it today, we could probably cut these wells back about $4 million but you've got to give me a little bit of slack in that prices are increasing for pipe and tubulars and service companies and everything else. But if everything is being constant we would be able I think to get these down closer to the $4 million range.

However, the other side of that equation says, as I mentioned earlier, we'll probably drill longer laterals. We'll probably go more fract stages to get them done. As we're finding out like the Angel for example, as they're successfully doing that, I think they're up to 12 stages rather than the five we're doing today. And if we add those then those costs may increase a little bit also.

Tom Laird – Mulholland Capital

It's very early to make judgments and estimates, but you mentioned the Haynesville and clay and all the concerns maybe discussion on weaker gas prices going forward, do you have any sense of $6.00 to $7.00 gas, what kind of economics you might run on these wells?

James Sigmon

We don't have a good handle. We're obviously using models that are in the $5.00 to $6.00 range at the low side to make sure that they work fine. And they look good at that point, if we get the kind of rates that we're doing now and they hold up. It's just early. We just don't have enough history yet.

Tom Laird – Mulholland Capital

The only other question I had relates to the Glen Rose porosity. Those wells that you've been reporting, you've been migrating down the ultimate recovery on those wells. Do you have a sense where, I know those wells are all over the map, but if you have a sense where you might think the average ultimate recovery in those wells would be?

Gary Grinsfelder

I wish we did. The one reason we did, was you made me remember there's a [inaudible] study to try to get a little better handle on that stuff, and we just couldn't do it. We think it's going to be a statistical play and the more of them you drill the more you're going to have good results. The internal rate of return on these wells, even if we get down in the $50,000 range, it's still excellent internal rate of return. So right now, your observation is correct. The more of them we've gotten, the average has actually moved down a little bit.

Operator

Your next question comes from Bill Harrison – Janney.

Bill Harrison – Janney

I noticed on your web site you alluded to the idea that you have somewhere above 1,000 prospective drilling locations in the Pearsall range. And you mentioned that you have 533 net sections on the call this morning and alluded to the fact that you could probably do quite a few wells per section. Are we talking about significantly above 1,000?

James Sigmon

All acreage is the same, and right now we have no reason not to see the way we scattered our wells. The potential is there. You can get 80 wells per section. With 500 locations, 80 acres per well, you're talking somewhere in the neighborhood of 4,000, something over 1,000. It remains to be seen right now.

Operator

Your next question comes from Neal Fagin – Fagin Consulting.

Neal Fagin – Fagin Consulting

Are you guys doing anything differently with the most recent Glen Rose porosity wells as a result of the [inaudible] study? I think I remember there was some discussion about maybe producing them at higher rates initially and if you have experimented with any of that, has it shown any potential?

James Sigmon

What Neal is referring to is one of the comments that we said, that as you're ready to cool down where you're getting 90% water, if the water cut appears to be holding, then we could increase the rate and dispose of the water. We're in the process of getting permits to be able to handle that much volumes of water and dispose of it. We have not gotten those done, so we've not been able to institute that process. It is something we are going to try, but we have not been able to do.

The major thing that we've done on the [inaudible] study is simply trying to stay in the highest top portion of the reservoir as we identify from seismic and by doing that, it seems like the wells are coming in potentially a little bit better than they were than when we were going just someplace within the reservoir.

Neal Fagin – Fagin Consulting

Two quick questions on the tar project; to the best of your knowledge with your modeling, do both of those pilots now have the optimum number of both producing wells and injections wells so that the results we start to get next year would be looked at as more or less definitive based on the spacing pattern you're on? Or, is there a high probability that the results we might get next year would lead you to think, well, we need to expand these pilots before we're really going to have definitive results and know what the ultimate recoveries and so forth might be.

James Sigmon

On the fast technique, on the fast pilot, all we're doing is confirming what Conoco's done and the fact that we have one injection well in the middle and four wells outside that. And you're projecting what you're getting but if you had other injection wells coming in from those producing wells, you're actually going to get more wells. So it would be to get ultimate production, which we think will increase on every well you would need more wells to be dug.

Neal Fagin – Fagin Consulting

And that's a very important point, isn't it Jim, because if we were to fast forward nine months, and you put results out on that fast pilot program, we should not look at those and say, "Okay, that's the definitive ultimate recovery from those five existing wells."

James Sigmon

That's a very good point. We're going to have to go through one stage at a time. You do the initial pilot and you expand out from that pilot. And the same goes through for the Sag D where you just have one Sag D pair, as you get more Sag D pairs parallel to them you get some benefits from the heat driving the oil to these producing laterals.

Neal Fagin – Fagin Consulting

If these pilots go as hoped, let's say upper middle of the road, do you get to a point maybe in the middle of '09 that you start expanding off the pilots? Would you have enough data to potentially by summer of '09 to start moving rigs in and adding wells and are you already in the process of looking at infrastructure and processing facilities so that if you get out a year and all this is working, you're ahead of the game with respect to how you're going to be able to handle the kinds of volumes that might come within the next two to three years?

James Sigmon

Obviously, we are not sitting on our thumbs while we're watching this San Miguel play. We are doing an awful lot of work on looking forward to what we're doing and all of it in play includes the anticipation of expanding this process to commercial production. And we think you'll be able to hear more about that in the future without getting too much, too many details right now.

Neal Fagin – Fagin Consulting

Is it theoretical that you could have an update by the middle of '09 to want to be in there with rigs and expanding these pilots?

James Sigmon

I'm going to give you a concept. Typically, if you're going to go to let's say a 10,000 barrel a day commercial facility that you're talking about, you don't get 10,000 barrels a day. It takes awhile to build a plant that allows you to get that kind of steam. But while you're building that plant to get you that kind of steam, you're going to have to drilling the wells to bring on it. So we're doing some modeling and doing some things at the present time to allow us to bring them up together.

Gary Grinsfelder

That's our last caller so we can wrap it up. Are there any closing comments you'd like to share with our shareholders.

James Sigmon

I'm happy to report as you can tell the exciting things that we've got going on. The Pearsall is just one of several plates that we're investigating. I think Gary alluded to the Eagleford sale. It's an oil shale that we're drilling. I think that that's going to bear watching as what the results are going on the two wells that we've got going now. With that we should have some idea a little closer by the end of the year what those wells might do. The Tar Sands, we're just at the point of starting to put steam in. That's an exciting time and so we think the market has pulled back from energy, as I know people have done. It's caused stock prices to drop in energy companies, and so the market is going to be looking for specific more special opportunities.

We think we're one of those special opportunities that people need to be taking a look at us, and we think we're going to continue to grow with that. And with that said, we sure appreciate everybody listening to us today.

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