SM Energy Company
Q1 2009 Earnings Call Transcript

Published: 5 May 2009

[Operator:]

Good morning. My name is Erika, and I will be your conference operator today. At this time I would like to welcome everyone to the St. Mary Land & Exploration Company's 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). Thank you. Mr. Collins, you may begin your conference.

[Brent A. Collins:]

Thank you, Erika. 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 discussion of these risks, you should refer to the information about forward-looking statements in our press release from yesterday and the Risk Factor 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 risks of not actually being realized by the company. EUR means those quantities of petroleum, which are estimated to be potentially recoverable, from accumulation plus those quantities produced there from. 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.

[Anthony J. Best:]

Good morning, and thank you 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 have no long-term rig commitments and very little acreage that is at risk of expiring near term. We believe this ability to slowdown 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 a 103 to 106 Bcf equivalent from the previous range of 101 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.

[Wade Pursell:]

Thanks, Tony. 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 those call estimates. Discretionary cash flow for the quarter was $107.4 million for the quarter, $4.72 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 out performance was driven by our Mid-Continent and Permian regions, which Jay will elaborate more on 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 571 at the end of '08 to only 363 at the end of the quarter. Additionally, differentials widened in many parts of the country. Result was that the price in effect of 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. The higher DD&A expense, compared to what we have 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 net back price in the Eastern Oklahoma at March 31, 2009 was $2.01 per Mcf, which was less than half the $4.08 net back 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 lower cost to market. Prices for tangible equivalent have declined with the slowdown in the industry and accordingly we had to write-down its inventory to market, even though we still continue 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. This adoption will now have an additional amount of non-cash interest related to the amortization of debt discount and the interest expense cash into the income statement. In the 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 us in 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, '09 versus the $287.8 million, which is the par amount. So in summary, while our reported results don't agree with (ph) first plans, 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're 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 were 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 our positions slightly in the first quarter, based on the revised guidance that we provided yesterday, we were about 50% hedged on expected production for both oil and natural gas for the remainder of 2009. We haven't provided production guidance for '010 and '011 but we have solid hedge positions in those years as well. Our estimate equivalent PDP production that is hedged in 2010 and 2011 is 56% in '010 and 44% in '011. 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.

[Javan D Ottoson:]

Thank you Wade, and 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-Continent 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're 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 result and our wells are making a meaningful contribution to our current production rate. We operate most of the wells we've been participating in with about a 30% net-interest. And the last several wells we drilled had IPs around 15 million a day. Our production rates in 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 340ish 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 value adding exercises that will add long-term value and inventory. I would note that we have seen significant decreases in cost to drilling 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 simul-frac pilot, which resulted in five horizontal producing wells in a 6400 acres session, or roughly 120 acres spacing. We are presently flowing back load water and early pressures and rates on the wells we completed look very good. Of course, the real measures 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. 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 would 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 the Eagle Ford session and are now drilling the lateral. We expect the lateral to be approximately 35,000 feet and have planned for a ten stage completion. We plant 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 competitor's has talked a lot about the Eagle Ford recently. So I thought I will 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 acres because it gives us shafts at both the Eagle Ford and the Pierce Hall shales at drilling depths above roughly 10,000 feet. On the South side of the Edward Reef trend, the Eagle Ford and Pierce Hall are quite a bit deeper and the wells will be significantly more expensive, especially for the Pierce Hall. There have been some good results announcement, at 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 in the biggest portion of our Haynesville acreage, 30,000 acres or so. We've cored the James Lime and will core the Haynesville Shale section and will 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 plan to drill one additional well targeting the Haynesville Shale in 2009 in the same area. I should note that we're also participating with the material working interest in a currently (ph) 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 will turn the call back over to Tony.

[Anthony J. Best:]

Looking at the reminder 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 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:]

(Operator Instructions). Your first question comes from the line of Subash Chandra with Jefferies.

[Subash Chandra:]

Good morning. First question on the Eagle Ford is, are you drilling into the pressured Eagle Ford there?

[Javan Ottoson:]

Well, the Eagle Ford is slightly over pressured in most places down there. As you get deeper into the basin, where some of our competitor drill, I think it's more highly over pressured, but it's slightly over pressured, pretty much in that whole area.

[Subash Chandra:]

Okay. And do you have a AFE on this well?

[Javan Ottoson:]

Yeah, yeah, we have an AFE, it includes microcosmic 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.

[Subash Chandra:]

Okay, great. And the Woodford, just topped of the call when the Woodford, other one of the other Woodford operators sort of upsized the reserve outlook because of lower decline rates versus expectations. Can you give a flavor on what you have on book as at the moment I just can't recall. And then if you're seeing similar type surprises in your Woodford volumes?

[Javan Ottoson:]

Well, last 15 wells, our EURs about 4.2 Bcf. Yeah, we haven't look at our long-term decline rate in terms of that tail decline per well and I assume that's what you're referring to. I mean, 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 maybe 8%, but it's fairly high relative to most of our competitors from what I have seen.

[Subash Chandra:]

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

[Javan Ottoson:]

We have a very large position in the Granite Wash. In fact we have about a township on the acres in far Western Oklahoma, the Mayfield area, the Northeast Mayfield. We also have quite a bit of acreage in Anadarko area in the Granite Wash and have participated and drilled a couple of pretty good wells in last year which we haven't talked much about. I think it's one of those cases, where most of our acres is HPP, there's a not a lot of incentive for us to go out and drill it right now. But we think there is a ton of potential in the horizontal Granite Wash and are actively participating.

[Subash Chandra:]

Great, thank you.

[Anthony Best:]

Thanks, Subash.

[Operator:]

Your next question comes from the line of Joe Allman with JPMorgan.

[Joseph Allman:]

Hi, everybody.

[Anthony Best:]

Good morning, Joe.

[Joseph Allman:]

Hey, Jay in terms of the Haynesville Shale wells, what's the purpose in drilling a vertical well, which is what you're drilling, instead of horizontal. And then 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 horizontal plan?

[Javan Ottoson:]

Well, I'll take the first question first. We decided to drill a vertical, because we didn't have any data down in here and after... we looked at it, we decided we really want to get some core. We knew we could hold the acreage with a vertical well. That vertical was probably half the cost of the horizontal, just seemed us like it was a good risk production, the way to peruse things in this economic environment. So, we get the Haynesville core, we get a good look at... we'll get logs (ph). There has been 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 in the play. So we just looked at it, and said this looks like a good risk production method. The other well we have to drill down and will also be an acreage saving well. Right now we're thinking it's going to be a horizontal well. Doesn't have to be, I don't believe. But we haven't made a decision yet, as far as whether we will go horizontal there 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 have been a lot of rumors about good lands (ph) and big wells and so we are very encouraged. We have a very... that's the biggest part of our acreage position, it's right in that area, about 30 of our 50,000 acres is right there. So, I think it make sense for us to take some time. The other thing that's going on there is, there is 3D shoot that's going to be done later on this year. We'd really like to have that 3D 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.

[Anthony Best:]

Joe, with this vertical well, we're also going to be taking that into the deeper end of the Haynesville Cotton Valley Lime. So we can get a look at that as well.

[Joseph Allman:]

That's helpful. And that 3D shoot, is that joint effort amongst different parties?

[Javan Ottoson:]

Yes, it's a big shoot. There's a bunch of people participating in and I think it was originally supposed to get shot over earlier, ending up getting delayed. But it will be... the data should be available to us in 2010. So, I think, if anything we are more probably leaning toward having that data in hand before we commit large amounts of money to horizontal drilling in the area.

[Joseph Allman:]

Okay. That's very helpful. And then, on your borrowing base, have the banks given any signal that they might reduce the price factor, using between now and the fall re-determination and what are you thinking about, I think you might get a reduction in your borrowing base in the fall.

[Wade Pursell:]

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 at all. I am sure they are watching the gas prices just like all of us are and those decisions will come in later in the summer.

[Joseph Allman:]

Got you. Okay. It's very helpful. And then lastly, in terms of... are you curtailing any production at this point because of low prices and what are your thoughts about curtailing production, either high rate production or material production below a certain price for gas?

[Anthony Best:]

Curtailing production, generally the economics doesn't work for that, unless you're convinced that you can... 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 that some people do it, some of the bigger players do it. Because I think, they honestly believe they can move markets when they do it. We're not big enough to do that. So we're not curtailing. We 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.

[Joseph Allman:]

I guess, there is 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 cost, I mean there is a certain point where if the valid price goes below that, if its mature production, it will make sense to shut that, because you loose the money for every

[Anthony Best:]

Yes sure Dan (ph), those are really... for us at least those are relatively rare.

[Joseph Allman:]

Okay.

[Anthony Best:]

We're not out with the whole lot of uneconomic production at this point. I mean there is always a few places in the Rockies where we may shut in a few wells because its 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.

[Joseph Allman:]

Okay, very helpful. Thank you.

[Unidentified Company Speaker:]

Thanks, Dan.

[Operator:]

Your next question comes from the line of David Heikkinen with Tudor Pickering Co.

[David Heikkinen:]

Question on your vertical Haynesville, I'm trying to think about, completing in the lime versus completing in the Shale, and how you're scheduled, how you're going to produce the well, can you just talk about what sort of rates would you... want to see in the lime to make you want compete there versus the Shale or do test each one just been a lot of filing on the wall. I'm trying to get a prognosis.

[Anthony Best:]

Well, I think the last two... we are going to do a lot science on there 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 up to 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.

[David Heikkinen:]

Okay.

[Anthony Best:]

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 the Haynesville shale roll-out the vertical Haynesville shale, where we are the completion. We'll see it. If we see something really interesting, we may do some more and that's the advantage of drilling vertically, you have some opportunities. We can even complete the James Lime if we like that well, like that in a robust (ph). So, we'll see how it goes.

[David Heikkinen:]

All right. Thanks, guys.

[Anthony Best:]

Thank you.

[Operator:]

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners.

[Anthony Best:]

Hey, Mike.

[Michael Scialla:]

Good morning, guys.

[Javan Ottoson:]

Good morning, Mike.

[Michael Scialla:]

A question for Wade, if oil and gas prices stay about where they are now, would there be any additional impairment in second quarter or would you see a reverse of that impairment, and what would happen to you DD&A rate if that happens?

[Wade Pursell:]

Yeah, as far whether they'll be any more impairments, I would estimate now that there would not be -- but, it's too early to tell. I mean, the other thing, at mid-year we'll 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 right where we are right now, I think the DD&A rate will be somewhere in the range at what we've guided, probably towards to the high-end if prices stayed where they are right now.

[Michael Scialla:]

Okay. And you

[Wade Pursell:]

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

[Michael Scialla:]

Right. That's what I was referring to as well. Okay, with the Wolfberry, you've 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?

[Wade Pursell:]

Yeah, I think we'll probably try to get a rig up here by mid year. So, we're prepared... at the end of the second quarter we'll have a better idea. We're looking at rig bids right now, and pretty pleased by some of the changes we've seen there. If well costs was as high as 2.1 million for one of these wells, say mid year or last year when costs were really high. We're thinking right now that we can probably drill them for about 1.3, I have been pushing for lower numbers in that, but you guys are pushing back a little bit. I think, we'll probably end up for about $1.3 million. So, it just gives you a sense. I mean, we've seen some dramatic decreases in all lines of service in Mary Land. Just this last week we saw -- I saw, it was one of the fracs we had planned was on another wells, a $2 million frac originally and now it's half of that. So, I mean, we've seen some really big reductions on frac cost and on rig rates. And that's what's going to push us back to work if it wasn't for that we'd still be deferring.

[Michael Scialla:]

Have you seen enough cost reduction in the Williston, yet towards to get after there?

[Javan Ottoson:]

Well, we've been participating a little bit in some common or operated wells. We haven't made a commitment to our own staff here. I still think deferral make some sense there unless you've really got as far in the acreage, I think it makes sense the way a will allow. Your differentials are a little higher up there, so you need -- you probably got 6 or $7 more differential in the Williston than we do at St Mary Land. So I think Mary Land probably comes back first in the packing order. But yeah, we'd love to get back to drilling in the Bakken. We have some pretty good opportunities there. We'll see how that goes as the year goes along.

[Michael Scialla:]

Okay. And your Haynesville where you have not taken the core in the Haynesville yet. Is that correct?

[Javan Ottoson:]

No, we cored the first well we drilled, this will be our second core. We're contributing those to the core consortium. And so, yeah, we'll have two cores, and this one, the big advantage of this one is of course, it is right in the middle of our biggest acreage positions. So, it will be really interesting to the see what it looks like.

[Michael Scialla:]

Okay. And then last one on the Eagle Ford, you still adding acreage in the play?

[Javan Ottoson:]

Well, I'm not sure we should really say, we've added little, yeah. And we continue to look, but obviously that's a competitive situation right now. So we don't talk a whole lot of that.

[Michael Scialla:]

Got you. Thank you.

[Anthony Best:]

Thanks, Mike.

[Operator:]

Your next question comes from the line of Christine Floyd with Raymond James (ph).

[Unidentified Analyst:]

Good morning. Going back to the Wolf area, can you go further what you saw in arbitrals, in terms of EURs?

[Anthony Best:]

Well, the Wolfberry wells have about two-thirds will for an EUR. That's pretty much what how they come in, and that's oil obviously, but we can convert it to Bcf for you on an equivalent basis. So, if you can drill the wells for 1/3 and you got 2/3 of a B, you're in that $2 type finding cost per oil prospect which is a pretty good number. That's where they kind of how we see it. I am sorry?

[Unidentified Analyst:]

I am sorry. What's your hurdle rate here, in terms of return?

[Anthony Best:]

Well, our hurdle rate for forward-looking drilling is let's call it 1.2 discounted present work 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 15% discount rate, so it implies our 15% hurdle on a full cycle basis. But for forward-looking drilling, because you got land cost in this thing you need to have better economics then that, in order to be able to make that 50% full cycle return. So, the 1.2 DPI is our hurdle for forward-looking drilling. And we have in corporate call price that we use, which is not the strip, which a little more... right now it's little more conservative than the strip at which we run those economics.

[Unidentified Analyst:]

Okay. Thank you.

[Anthony Best:]

Thank you.

[Operator:]

Your next question comes from the line of John Healy with Forest Investment.

[Anthony Best:]

Good morning, John.

[John Healy:]

I saw on your new credit agreement, I didn't have another chance to read it yet, is there... I know that's should be convertible notes are portable in April of 2012 and the credit agreement matures, I think in July of 2012. Are there any restrictions in the credit agreement with respect to that put feature on the convertible notes?

[Wade Pursell:]

No, not meaningfully. And we are also allowed to repurchase the converts if we would like.

[John Healy:]

Sure. And then on your price pricing of that, right, the spread over LIBOR. I see it's based on a percent utilization, is that based on percent utilization of your borrowing base, or of the 600 and what is the 70 million commitment amount?

[Wade Pursell:]

It's at the borrowing base, the 900 million.

[John Healy:]

Okay. Thank you very much.

[Wade Pursell:]

Sure.

[John Healy:]

Thanks.

[Operator:]

Your next question comes from the line of Subash Chandra with Jefferies.

[Subash Chandra:]

A follow-up here, the East Texas versus Louisiana, I guess it's pretty common now to use the Bossier Haynesville as interchangeably. And I was curious here, what your perspective, I mean are we talking apples, oranges or are we talking oranges, tangerines. I guess, like with some, respect to that the two rocks are different and geologically different. And how easy is it for an operator to tell the difference between the two when placing a lateral?

[Anthony Best:]

Well, you are talking to a guy who is just drilling his first well in Haynesville in East Texas side, maybe that's... I'm currently not the best guy to ask. But the rocks I've seen, it's the Haynesville's pretty obvious, you see the same kind of stacking at the porosity 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 things people write about its different. And clearly, the rock is different all over the Haynesville play. I don't think, one of the things you've figure out when you started actually looking at the rock is how you need the rock, even from foot-to-foot in a lateral. So there is a lot of differences in the rock. And that's probably 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 that, it's not quite as uniform and not quite as easy, maybe as it seems. There's been some tremendous success in the play and everybody then I think makes this assumption that it's going to be consistent and relatively straight forward. I think we're going to take a fairly cautious approach to spend a lot of money here, because most our acreage is held so.

[Subash Chandra:]

All right. Have you seen any logs from any legacy wells, how have all they might be down, down in that area?

[Anthony Best:]

My G&G guys obviously have looked at a bunch of logs. And I can't tell you... am not going to make a lot of comments about log analysis here, because that's not my area of expertise. But, yeah, 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 shop looking thing that where it kind of sticks out to good quality, Haynesville sticks out across this area of Shelby and St. Augustine and sort of into that Nacogdoches area. And again, I mean that those maps are commonly being shown. And that's based on the all logs we all have. So, I kind of guess, I don't want to come across like I know a lot here, because I just don't. We don't have a log, we don't have a core and when I'll get logs and core, we'll be a lot more happy to talk like we know something on this.

[Subash Chandra:]

Right, every little bit of insight is helpful. Thank you.

[Anthony Best:]

Sure. No problem.

[Operator:]

Your next question comes from the line of Sunil Jagwani with Catapult.

[Sunil Jagwani:]

Actually my question has been answered. Thank you.

[Anthony Best:]

All right, Sunil. Thanks.

[Operator:]

You have a follow-up question from Joe Allman with JPMorgan.

[Unidentified Analyst:]

Yeah, actually this isn't Joe, this is Ann Cameron (ph). Just that 15% rate of return you guys referenced with respect to the Wolfberry, is that pre or post tax?

[Javan Ottoson:]

All of the numbers we run in, 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 economic significantly better than that forward-looking. It's going to be more like 25%, okay. So, all those numbers are pretax, but we don't really pay cash taxes. So, it's -- that's the right way to make that decision.

[Unidentified Analyst:]

Okay, great. Thanks very much.

[Javan Ottoson:]

You bet. By the way most people, most independents use a 15% hurdle rate pretax. I mean, if you go around the industry, that's very, very common.

[Unidentified Analyst:]

Okay, got it.

[Operator:]

Your next question comes from the line of Gordon Dubeck (ph) with Wachovia.

[Unidentified Analyst:]

Hi, guys.

[Anthony Best:]

Hi, Gordon.

[Unidentified Analyst:]

How you doing? A quick question regarding the timing of the Eagle Ford, just wanted to get some information when we might be able to expect results for the one that's correctly drilling and then to get an idea of the other three operated tests that you plan for later in the year?

[Javan Ottoson:]

Well, we're not scheduled, we're going to... the fact is, where we frac date 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 anywhere. We'll probably wait till we have a couple of wells done. But it will clearly be the end of the second quarter before we really have results. So you probably won't hear much till the third quarter about our... first couple of wells. We'll probably announce some in groups, unless there's something really unusual that we feel material, we just cannot say it. I think we'll probably do a couple wells, and you'll probably hear about it in third quarter call is probably a reasonable time period.

[Unidentified Analyst:]

All right. Thank you very much

[Anthony Best:]

Thanks Gordon.

[Operator:]

(Operator Instructions). There are no audio questions at this time

[Anthony Best:]

Thank you, operator and thanks to every one 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

[Operator:]

This concludes today's conference call. You may now disconnect.