SM Energy Co (SM) 2009 Q1 法說會逐字稿

Good morning.

My name is Erica, and I will be your conference operator today.

At this time, I would like to welcome everyone to the St.

Mary Land & Exploration Company first-quarter 2009 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).

Mr.

Collins, you may begin your conference.

Good morning to all of you joining us by phone and online for St.

Mary Land & Exploration Company's first-quarter 2009 earnings conference call.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance.

These statements involve risks, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the information about forward-looking statements in our press release from yesterday and the risk factors section in our 2008 annual report on Form 10-K and subsequent quarterly reports filed on Form 10-Q.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Additionally, we may use the terms probable, possible, and 3P reserves, and estimated ultimate recovery, or EUR, in this call.

Probable reserves are unproved reserves which are more likely than not to be recoverable; possible reserves are less likely to be recoverable than probable reserves.

Estimates of probable and possible reserves, which may potentially be recoverable through additional drilling or recovery techniques, are by their nature more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of not actually being realized by the Company.

EUR means those quantities of petroleum which are estimated to be potentially recoverable from an accumulation, plus those quantities produced therefrom.

The Company officials on the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; and Brent Collins, Director of Investor Relations.

I'll now turn the call over to Tony.

Good morning, and thank you for joining us for the St.

Mary quarterly call.

After a few brief remarks, I'll turn the call over to Wade Pursell, our CFO, and Jay Ottoson, our COO, for their respective financial and operations reviews.

St.

Mary is on track and executing well on the business plan that we laid out for 2009.

We had higher production and, in most cases, lower costs than expected, although lower natural gas prices had an impact on our financial results.

I think that after you analyze the numbers, you'll see that we performed as well or better than we had guided for the quarter.

Our testing of the emerging resource plays that we have exposure to is progressing as we had planned for this year.

We recently completed a new credit facility and were able to increase our commitment amount from the bank group by over $175 million.

The Company continues to focus on being flexible in this very volatile market.

We have slowed down our development activities, given our view of the economics of many projects at these commodity prices and well costs.

We have the flexibility to adjust our capital program, given the fact that we had no long-term rig commitments and very little acreage that is at risk of expiring near term.

We believe this ability to slow down or ramp up quickly is a very meaningful advantage in this very challenging business climate.

I am pleased to announce that we are raising our production guidance range for the year to 103 Bcf to 106 Bcf equivalent from the previous range of 101 Bcf to 104 Bcf equivalent.

From an operational standpoint, we are seeing some stronger-than-expected performance in a couple of regions that are helping our production rate performance.

With that, I'll turn the call over to Wade.

Good morning, everyone.

Yesterday afternoon, we released our first-quarter earnings press release and financial highlights.

I'll touch briefly on the more important aspects of yesterday's announcement.

Our reported net loss for the quarter was $87.6 million, or negative $1.41 per diluted share.

The loss reflects non-cash impairments and higher DD&A.

Adjusted net loss for the quarter, which adjusts for unusual and significant non-recurring and non-cash items, was $448,000, or negative $0.01 per diluted share.

At first glance, this looks like a miss when compared to first call, but as I'll explain in a moment, our operating performance was actually in line with first-call estimates.

Discretionary cash flow for the quarter was $107.4 million for the quarter, or $1.72 per Mcf equivalent.

This was above first-call estimates.

Production for the quarter was 28.4 Bcf equivalent, which beat the high end of our production guidance of 28 Bcf equivalent.

The outperformance was driven by our Mid-Continent and Permian regions, which Jay will elaborate more on in his operations review.

Turning to the cost side, LOE, transportation, production taxes, and G&A were all within or below guidance that we had provided.

DD&A for the quarter came in at $3.23 per Mcfe, which is clearly much higher than the high end of the DD&A guidance that we provided.

As many of you are aware, natural gas prices declined dramatically throughout the first quarter of '09, with Nymex prices dropping from $5.71 at the end of '08 to only $3.63 at the end of the quarter.

Additionally, differentials widened in many parts of the country.

The result was that the price in effect for natural gas at the end of the first quarter was significantly lower than the price at year-end '08, particularly in the Mid-Continent.

This had a negative impact on the internal proved reserves, which are the denominator in the calculation of DD&A.

And as a result, we recognized higher DD&A expense for the quarter.

This higher DD&A expense, compared to what we had guided, is the difference between our adjusted net loss of $0.01 per diluted share versus the first-call estimate.

We had non-cash impairments in the quarter of $159.6 million.

The largest part of this related to an impairment of producing properties of $147 million.

Of this amount, $97 million related to properties in eastern Oklahoma, which includes our Woodford shale program, and $37 million related to the CBM project at Hanging Woman Basin.

Again, natural gas prices drove this charge.

For example, the netback price in the eastern Oklahoma at March 31, 2009, was $2.01 per Mcf, which was less than half the $4.08 netback price in effect just three months earlier at December 31, 2008.

We also had an impairment of materials inventory of $8.6 million, which related primarily to tubular goods purchased late in 2008.

These goods were required to be presented on the balance sheet at the lower of cost to market.

Prices for tangible equipment have declined with the slowdown in the industry and, accordingly, we had to write down this inventory to market, even though we still intend to use these goods in our drilling program.

We adopted FASB Staff Position APB 14-1, which is accounting for convertible debt instruments that may be settled in cash upon conversion, on January 1, 2009, as required.

This required us to change how we accounted for our 3.5% senior convertible notes.

Based on this adoption, we will now have an additional amount of non-cash interest related to the amortization of debt discount and the interest expense caption of the income statement.

And in first quarter, as we had previously guided, this amount was $2.1 million, which should be added back in your cash flow calculations.

The adoption resulted in us recording a debt discount for the convertible notes, which nets down the reported amount on the balance sheet, which becomes $261 million at March 31, 2009, versus the $287.8 million, which is the par amount.

So in summary, while the reported results don't look great at first glance, we believe there are positive takeaways for the quarter related to the parts of our business that we have the ability to influence.

For instance, exceeding expectations on production volumes and production costs.

With respect to the balance sheet, we are in great shape.

Our debt to book cap is 34% with no debt maturities until 2012.

As previously announced, we recently completed a new credit facility and we are able to increase the level of commitments to $678 million from $500 million.

As of yesterday, we had $376 million of available borrowing capacity under the facility.

We feel really good about the deal we were able to execute on the new credit facility, particularly when you see some of the recent industry news regarding other credit facilities.

We also increased our hedge position slightly in the first quarter.

Based on the revised guidance that we provided yesterday, we are about 50% hedged on expected production for both oil and natural gas for the remainder of 2009.

We haven't provided production guidance for 2010 and 2011, but we have solid hedge positions in those years as well.

Our estimated equivalent PDP production that is hedged in 2010 and 2011 is 56% in 2010 and 44% in 2011.

The details of our hedging position are included in yesterday's press release, and will also be included in our 10-Q, which will be filed later today.

With that, I'll turn the call over to Jay.

Good morning, everyone.

As mentioned earlier, production for the quarter came in at 28.4 Bcfe, which was higher than our guidance.

This was driven by strong performance in the Mid-Continent and the Permian regions.

In the Mid-Con, we have two programs that are working very well.

The horizontal Woodford shale continues to perform at or above expectations from an operations perspective.

We are also having good results in a program targeting the deep Springer formation in the Anadarko basin.

While these Springer wells are more conventional targets, which don't really fit the profile of a typical resource play program that we tend to talk about most of the time, we have been having very good results and the wells are making a meaningful contribution to our current production rate.

We operate most of the wells we have been participating in with about a 30% net interest, and the last several wells we drilled have had IPs around 15 million a day.

Our production rates and our Wolfberry tight oil assets in the Permian have also continued to perform above our expectations, and we expect to get back to drilling our 40-acre wells there soon.

Our operations and guidance update from yesterday provided a brief update of our current and planned activity.

We still anticipate investing within or near operating cash flows for 2009.

The $340-ish million number for capital investment that we have previously provided is still a good number to assume.

We also still believe that in the current environment, it's appropriate to defer most development activity and focus on exploration and the value-adding exercises that will add long-term value and inventory.

I would note that we have seen significant decreases in cost to drill and complete wells in some of the areas where we operate, particularly in regions with more exposure to oil.

We continue to actively monitor the service cost environment and may reallocate some of our remaining 2009 capital to oil development activities, such as the Wolfberry 40-acre work I mentioned just a moment ago.

Speaking of development, in the Woodford shale we recently completed a four-well simulcrack pilot, which resulted in five horizontal-producing wells in a 640-acre session, or roughly 120-acre spacing.

We are presently flowing back load water, and the early pressures and rates on the wells we completed look very good.

Of course, the real measure of a down-spacing pilot program is a longer-term look at how the wells perform relative to our tight curve and EURs, and that data is not available (multiple speakers).

Getting this pilot test done this year is an example of the type of long-term value spending we are doing in the current difficult economic environment.

Turning to our exploratory efforts, I'd like to spend a few moments discussing our emerging resource plays.

In south Texas, we are currently drilling our first operated Eagle Ford horizontal well in Webb County, Texas.

We've cored Eagle Ford section and are now drilling the lateral.

We expect the lateral to be approximately 3,500 feet and have planned for a 10-stage completion.

We plan to drill a total of four Eagle Ford wells outside of the TXCO Anadarko JV this year.

We also plan to participate in the JV with TXCO and Anadarko, where we expect an additional four Eagle Ford tests this year.

I know one of our competitors has talked a lot about the Eagle Ford recently, so I thought I'd just provide a little of our perspective on the play.

If you look at the presentation on our website, you'll see that the acreage we now have is all north of the Edwards reef trend.

We selected that acreage because it gives us shots at both the Eagle Ford and the Pearsall shales at drilling depths above roughly 10,000 feet.

On the south side of the Edwards reef trend, the Eagle Ford and Pearsall get quite a bit deeper and the wells will be significantly more expensive, especially for the Pearsall.

There have been some good results announced in the deeper portion of the play, which is certainly very encouraging, and our hope is that we will be able to generate reserves at even lower cost and potentially from both shales because of our acreage selection.

In the Haynesville shale, we are currently drilling our second operated well.

It's located in northern San Augustine County, Texas, in the middle of the biggest portion of our Haynesville acreage, 30,000 acres or so.

We've cored the James lime and we'll core the Haynesville shale section, and we'll then drill through the Haynesville Cotton Valley lime section to evaluate that deeper formation.

We expect, at this point, to complete the well as a vertical Haynesville shale well.

We'll plan to drill one additional well targeting the Haynesville shale in 2009 in this same area.

I should note that we are also participating with a material working interest in a co-owner operated well currently completing in Louisiana.

In the Marcellus shale, we plan to begin testing activities in the third quarter of this year.

We currently expect to drill two horizontal wells in 2009.

With that, I'll turn the call back over to Tony.

Looking at the remainder of 2009, I think St.

Mary is very well-positioned.

We have a very flexible program, which I think is key in this volatile market.

And with our new revolver in place, we have a lot of dry powder at our disposal, should we see very compelling opportunities going forward.

The Company is continuing to execute on the business plan that we laid out at the beginning of the year, and in spite of adverse conditions confronting our industry, we have managed to stay on track with that plan.

With that, we'll turn the call over for your questions.

(Operator Instructions).

Subash Chandra, Jefferies & Company.

First question on the Eagle Ford is -- are you drilling into the pressure at Eagle Ford there?

The Eagle Ford is over -- slightly overpressured in most places down there.

As you get deeper into the basin where some of our competitors are drilling, I think it's more highly overpressured.

But it's slightly overpressured pretty much in that whole area.

And do you have an AFE on this well?

Yes, we have an AFE.

It includes microsize [mick] and a bunch of testing work, so it's not really -- it doesn't represent what we think we can drill the wells for.

I think the initial AFE for this one was $6.8 million.

Great.

And the Woodford just topped off a call -- one of the Woodford -- other one of the other Woodford operators sort of upsized the reserve outlook because of lower decline rates versus expectations.

Kind of give a flavor on what you have them booked as, at the moment?

I just can't recall.

And then, if you are seeing similar-type surprises in your Woodford volumes.

On our last 15 wells, our EURs were about 4.2 Bcf.

We haven't looked at the long-term decline rate in terms of that tail decline for a while.

I assume that's what you are referring to.

You can make the reserves significantly different on these wells if you take it from 7% to 6%.

I've heard people talk about numbers even lower than that.

But I think we're using about a 10% decline right now in terms of our reserve forecast.

It may be 8%, but it's fairly high relative to most of our competitors, from what I have seen.

Perfect, thank you.

One final one, do you have exposure to the Granite Wash and any commentary on horizontal development of the Mid-Continent?

We have a very large position in the Granite Wash.

In fact, we've got about a township worth of acreage in far western Oklahoma, the Mayfield area, northeast Mayfield.

We also have quite a bit of acreage in the Anadarko area, in the Granite Wash, and have participated and drilled a couple of pretty good wells in the last year, which we haven't talked much about.

I think it's one of those cases where most of our acreage is HPP.

There's not a lot of incentive for us to go out and drill it right now.

We think there is a ton of potential in the horizontal Granite Wash and we are actively participating.

Great.

Thank you.

Joe Allman, JPMorgan.

Good morning, everybody.

Jay, in terms of the Haynesville shale wells, what's the purpose in drilling a vertical well with this [volure] drilling, instead of horizontal?

And in the second well that you plan sometime later this year, is that contingent upon the success of the first well?

And is that a vertical or a horizontal plan?

I'll take the first question first.

We decided to drill it vertical because we didn't have any data down in here.

After we looked at it, we decided we really wanted to get some core -- we knew we could hold the acreage with a vertical well.

That vertical well is probably half the cost of a horizontal.

Just seemed to us like it was good risk reduction way to pursue things in this economic environment.

So we'll get the Haynesville cored, we'll get a good look at it, we'll get logs.

There hasn't been a lot of data released in this particular area.

Everybody talks about this northern San Augustine/southern Shelby area like it should be good.

But there isn't as much data down there as there is in some other parts of the play.

So we just looked at it and said this looks like a good risk-reduction method.

The other well we have to drill down there will also be an acreage-saving well.

Right now, we're thinking it's going to be a horizontal well.

It doesn't have to be, I don't believe.

But we haven't made a decision yet as far as whether we'll go horizontally or not.

To some extent, it will depend on what we see in this well.

But there's a lot of interest right now in that southern Shelby, northern San Augustine, Nacogdoches area.

There's been a lot of rumors about good logs and big wells, so we are very encouraged.

We have a very -- that's the biggest part of our acreage position is right in that area.

About 30,000 of our 50,000 acres is right there.

So I think it makes sense for us to take some time.

The other thing that's going on there is there's a 3-D shoot that's going to be done later on this year.

We'd really like to have that 3-D in hand before we drill a significant number of wells down there.

It just makes sense to us to have the data and be looking at it as we pick locations.

With this vertical well, we are also going to be taking that into the deeper interval, the Haynesville Cotton Valley lime.

So we can get a look at that interval as well.

That's helpful.

That 3-D shoot, is that a joint effort amongst different parties?

Yes, it's a big shoot.

There's a bunch of people participating.

And I think it was originally supposed to get shot a little earlier.

It ended up getting delayed.

But the data should be available to us in 2010.

So I think, if anything, we are probably leaning toward having that data in hand before we commit large amounts of money to horizontal drilling in the area.

That's very helpful.

And then, on your borrowing base, have the banks given any signal that they might reduce the price deck they are using between now and the fall, redetermination, and what are you thinking about -- are you thinking you might get a reduction in your borrowing base in the fall?

Too early to estimate on that.

I will tell you I've got no indications from the banks that they would lower the borrowing base in the fall.

I'm sure they're watching the gas prices, just like all of us are, and those decisions will come later in this summer.

Got you.

(multiple speakers) That's very helpful.

Lastly, in terms of -- are you curtailing any production at this point because of low prices?

What are your thoughts about curtailing production, either high-rate production or mature production below a certain price for gas?

Curtailing production, generally the economics doesn't work for that unless you're convinced that you're either big enough that you can move the market, such that prices will come up really quickly, and then you can bring it back on.

But just shutting in production because price is low, unless you really believe price is going to come up fast, the economics really don't work.

So that's really not part of our strategy.

I know some people do it, some of the bigger players do it because they -- I think they honestly believe they can move the market when they do that.

We are not big enough to do that.

So we are not curtailing.

Don't have any intention to do so.

Don't really think for a company our size it makes a lot of sense to try it.

I guess there's some places where you probably have some mature production, where the LOE is relatively high versus other places.

And when you look at the variable cash operating costs, there's a certain point where the price -- if the well head price goes below that, if it's mature production, it would make sense to shut that in because you're losing money for every --

Well, sure.

Yes.

Those are really -- for us at least, those are relatively rare.

We don't -- we are not out with a whole lot of uneconomic production at this point.

There's always a few places in the Rockies where you may shut in a few wells because it's just not cash flowing when prices get really low, but generally that's on the oil side of our portfolio, where our LOE is higher.

And oil prices have come back a little bit.

So we don't have a lot shut in right now.

Very helpful.

Thank you.

David Heikkinen, Tudor, Pickering, Holt & Co.

Securities.

Question on your vertical Haynesville, trying to think about completing in the lime versus completing in the shale, and how your schedule of how you're going to produce the well.

Could you talk about -- what type are rates -- or what would you need to see in the lime to make you want to complete there versus the shale, or do you test each interval, or just doing a lot of science on the well and trying to get a prognosis?

The last that you -- we are going to do a lot of science on the well and try to learn as much as we can.

We haven't made a commitment to completing in the lime -- frankly, I think the lime production that we see off to the west down there is probably somewhat unique.

I doubt very much -- this is just a cheap way for us to get a look at it.

I doubt we will be completing in it.

I think that's probably more structural in nature.

But we may get a surprise or two.

We'll see.

Our intention right now is to make a Haynesville shale well out of a vertical Haynesville shale well, and make the completion.

We will see if -- if we see some really interesting, we may do something else.

I mean, that's the advantage of drilling vertically.

You have some opportunities.

We could even complete the James lime if we like that well, like that interval best.

So we'll see how it goes.

Thanks, guys.

Mike Scialla, Thomas Weisel Partners.

Morning, guys.

A question for Wade.

If oil and gas prices stay about where they are now, would there be any additional impairment in the second quarter, or would you see a reverse of that impairment?

And what would happen to your DD&A rate if that happened?

As far as whether they'd be any more impairments, I would estimate now that there would not be.

But it's too early to tell.

The other thing, at mid-year, we go through a full mid-year reserve analysis, so that would obviously have a big impact.

But at these prices, maybe not impairments.

As far as the DD&A rate the rest of the year, I think if we stay at these prices where we are right now, I think the DD&A rate will be somewhere in the range of what we've guided, probably toward the high end, if the prices stay where they are right now.

Okay.

When I say prices stay where they are right now, I mean the current mine, not the strip.

That's what I was referring to, as well.

With the Wolfberry you mentioned, you want to get drilling there again.

Is the plan to go back to one rig?

And what kind of completed-well costs are you anticipating now, compared to where you were last summer?

Yes, I think we'll probably try to get a rig up here by mid-year or so, so at the end of the second quarter, we will have a better idea.

We are looking at rig bids right now and I'm pretty pleased by some of the changes we've seen there.

Our well costs were as high as $2.1 million for one of these wells, say mid-year last year, when costs were really high.

We are thinking right now that we can probably drill them for about $1.3 million.

I've been pushing for lower numbers than that, but the guys are pushing back a little bit.

I think we'll probably AFE them for about $1.3 million.

So just gives you a sense -- we've seen some dramatic decreases in all lines of service in Midland.

Just this last week, we saw -- I saw -- it was one of the fracs we had planned, was on another well.

It was a $2 million frac originally, and now it's half of that.

We've seen some really big reductions on frac costs and on rig rates.

And that's what's going to put us back to work.

If it wasn't for that, we'd still be deferring.

Are you seeing enough cost reduction in the Williston yet to want to get active there?

We've been participating a little bit in some co-owner operated wells.

We haven't made a commitment to our own stuff yet.

I still think deferral makes some sense there.

Unless you've really got expiring acreage, I think it makes sense to wait a little while.

Your differentials are a little higher up there, so you need -- you've probably got $6 or $7 more differential in the Williston than you do, say, in Midland.

So I think Midland probably comes back first in the pecking order, but we would love to get back to drilling in the Bakken.

We have some good opportunities there.

We'll see how that goes as the year goes along.

And your Haynesville oil, you have not taken a core in the Haynesville yet, is that correct?

No, we cored the first well we drilled.

This will be our second core.

We are contributing those to the core consortium.

And so, yes, we will have two cores.

And this one, the big advantage to this one, of course, is it's right in the middle of our biggest acreage position, so it will be really interesting to see what it looks like.

Okay.

Last one on the Eagle Ford.

Are you still adding acreage in the play?

I'm not sure we should really say.

We have added a little, yes.

And we continue to look, but obviously, that's a competitive situation right now, so we don't talk a whole lot about it.

Got you.

Thank you.

[Christa Choi], Raymond James & Associates.

Good morning.

Going back to the Wolfberry, can you go over what you saw in average wells in terms of EURs?

The Wolfberry well is having about a two-thirds of a B for an EUR.

That's pretty much how they come in.

And that's oil, obviously, but we can convert -- I'm converting it to Bcf for you on an equivalent basis.

If you can drill the wells for 1.3, and you got two thirds of a B, you are in that $2 type finding cost for an oil prospect, which is a pretty good number.

(multiple speakers) That's kind of how we see it.

What is your hurdle rate here in terms of return?

Our hurdle rate for forward-looking drilling is what's called a 1.2 discounted present worth to investment ratio, calculated at 15% discount rate.

So, basically, you have to have well above a 15% rate of return in order to drill a well on a forward-looking basis.

On a full cycle, we -- again, we use a 15% discount rate, so it implies over 15% hurdle on a full-cycle basis.

But for forward-looking drilling, and because you've got land costs in this thing, you need to have better economics than that in order to be able to make that 15% full-cycle return.

So the 1.2 dpi is our hurdle for forward-looking drilling, and we have a corporate call price that we use, which is not the strip.

Which is a little more -- right now, it's a little more conservative than the strip, at which we run those economics.

Thank you.

[John Healy], [Forrest Investments].

I saw on your new credit agreement, I didn't -- haven't had a chance to read it yet, is there -- I noticed that at the convertible notes are puttable in April of 2012, and the credit agreement matures in July of 2012.

Are there any restrictions in the credit agreement with respect to that put feature on the convertible notes?

No, not meaningfully.

And we are also allowed to repurchase the converts, if we would like.

And then, on your -- the pricing of that, the spread over LIBOR, I see it's based on a percentage utilization.

Is that based on percent utilization of your borrowing base, or of the $678 million commitment amount?

It's at the borrowing base.

The $900 million.

Okay.

Thank you very much.

Subash Chandra, Jeffries & Company.

A follow-up here, East Texas versus Louisiana.

I guess it's pretty common now to use the Bossier Haynesville as interchangably.

And I was curious what your perspective is.

Are we talking apples, oranges, or are we talking oranges, tangerines, I guess?

With some respect to -- that the two rocks are different, geologically different, how easy is it for an operator to tell the difference between the two when placing the lateral?

You're talking to a guy who is just drilling his first well in Haynesville and East Texas, so maybe that's -- I am probably not the best guy to ask.

But the logs I've seen, it's -- Haynesville is pretty obvious.

You see this same kind of stacking at the [perosti] curves there that you see in Louisiana, at least the logs I've seen.

So I don't think there's a lot of question about where you're at.

There is a lot of terminology issue there, and I've read a lot of the things people write about -- well, you know, it's different.

Clearly, the rock is different all over the Haynesville play.

I don't think -- one of the things you figure out when you start actually looking at the rock is how unique the rock is, even from foot to foot in a lateral.

So there's a lot of differences in the rock, and that's part of the reason we wanted to get the core and look at this East Texas area a little more and get the seismic.

I think our experience so far in the play is it's not quite as uniform, not quite as easy, maybe, as it seems.

There have been some tremendous success in the play and everybody down, I think, makes this assumption that it's going to be consistent and relatively straightforward.

I think we are going to take a fairly cautious approach to spending a lot of money here, because most of our acreage is held.

Have you seen any logs from any legacy wells, however old they might be, down in that area?

My G&G guys, obviously, have looked at a bunch of logs.

I can't tell you -- I'm not going to make a lot of comments about log analysis here because that's not my area of expertise.

Yes, we have logs down there, and we've looked at them, and I think most people, if you look at the maps that most of the major competitors are putting out, kind of show this pork chop-looking thing, where it kind of sticks out, the good-quality Haynesville sticks out across this area of Shelby and San Augustine, sort of into that Nacogdoches area.

And again, those maps are commonly being shown.

And that's based on all the logs we all have.

So I guess -- I don't want to come across like I know a lot here, yet, because I just don't.

We don't have a log, we don't have a core, and when I've got logs and core, we will be a lot more happy to talk like we know something on this.

Every little bit of insight is helpful.

Thank you.

Sure.

No problem.

Sunil Jagwani, Catapult Capital Management.

Actually, my question has been answered.

Thank you.

Joe Allman, JPMorgan.

Actually, this isn't Joe.

This is Anne Cameron.

That 15% rate of return you guys referenced with respect to the Wolfberry, is that pre- or post-tax?

All the numbers we run -- and let me back up and say that 15% return is a full-cycle number.

To get to a drilling decision, we have to have the economics significantly better than that forward-looking.

It's going to be more like 25%, okay?

All those numbers are pre-tax.

But we don't really pay cash taxes, so it's -- that's the right way to make that decision.

Okay, great.

Thanks very much.

You bet.

By the way, most people, most independents use a 15% hurdle rate, pre-tax.

If you go around the industry, that's very, very common.

Got it.

[Gordon Dubed], Wachovia.

A quick question regarding the timing in the Eagle Ford.

Just wanted to get some information when we might be able to expect results for the one that's currently drilling, and then to get an idea of the other three operated tests that you plan for later in the year.

We are not scheduled -- we are going to practice -- well, we have a frac date of June -- I think the last date I heard was June 1.

So it's going to be -- we won't be announcing results on this well, probably, individually anyway.

We'll probably wait until we have a couple of wells done.

But it will clearly be the end of the second quarter before we really had results.

So you probably won't hear much until the third quarter about our first couple of wells.

We'll probably announce them in groups.

Unless there is something really unusual that we feel is so material we just can't not say it.

I think we'll probably do a couple wells, and you'll probably hear about it -- third-quarter call is probably a reasonable time period.

All right.

Thank you very much.

(Operator Instructions).

There are no audio questions at this time.

Thank you, Operator, and thanks to everyone for your interest in St.

Mary.

We are on track with our business plan for the year, and I believe we are well positioned for long-term success.

Thank you for joining us this morning.

This concludes today's conference call.

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