SM Energy Co (SM) 2009 Q2 法說會逐字稿

Good morning.

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

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

Mary Land & Exploration Company second-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.

Brent Collins, Director of Investor Relations, you may begin your conference.

Thank you, Rachel.

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

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

Before we start, I would like to advise you we'll 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 of our 2008 Annual Report on Form 10-K and subsequent quarterly reports filed on Form 10-Q.

We'll 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 on 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 that are estimated to be potentially recoverable from an 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.

Thanks, Brent.

Good morning and thank you for joining us for our second-quarter earnings call.

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

St.

Mary had a strong second quarter and we are executing well on our 2009 business plan.

Production for the quarter was stronger than we had anticipated, and we met or beat all of our cost guidance for the quarter as well.

Operationally, we continued with the testing of our emerging resource plays which was a stated priority for St.

Mary this year.

Jay will discuss the Eagle Ford in more detail in a moment but I want to say we're encouraged with the results from our first well on our 100% acreage.

For those of you that regularly follow the Company, you've heard us share our progress in the transformation of St.

Mary into a resource play focused company.

And the Eagle Ford is a great example of the things we're doing to meet the strategic object.

We'll be doing more testing in Eagle Ford in the second half of the year, and we'll also be testing the Marcellus and Haynesville during that period as well.

We're ramping up activity in the oil weighted part of our portfolio as well, namely in the Permian basin and in the Williston basin.

Based upon the solid economics that we're seeing with higher oil prices and reduced well costs, we're increasing our expected capital investment forecast to $411 million for the full year, which is up from the $341 million that we had discussed previously.

We expect to be at or near cash flow, and we remain focused on maintaining a flexible capital plan.

We have the ability to throttle our activity up or down so our drilling activity will be driven by our goal to grow net asset value per share.

I'm also pleased to announce that we're increasing our production guidance for the year to a range of 107 to 110 Bcf equivalent; that's up from 103 to 106 Bcfe.

This is due to the solid results we have seen in our drilling program as well as the increase in capital investment that I referred to above.

St.

Mary is a company undergoing a strategic formation -- transformation, resulting in a growing multi-year drilling inventory that can support consistent and organic economic growth in both production and reserves.

I'm very pleased with the progress we're making as we set the stage for our long-term success.

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

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 announcement.

Our reported net loss for the quarter was $8.3 million or $0.13 per diluted share.

Loss is primarily due to various non-cash impairments and other charges.

Adjusted net income for the quarter, which adjusts for unusual or significant non-recurring and non-cash items, was $15.2 million or $0.24 per diluted share.

This is a strong result compared to First Call, which was $0.02 per share.

The outperformance was driven by strong production and lower cost.

Discretionary cash flow for the quarter was $117.7 million or $1.89 per Mcfe; this was also up from First Call.

Production for the quarter was 28.2 Bcfe, which beat the high end of our production guidance of 28.

LOE, transportation, production taxes, G&A and DD&A were all at or below the guidance we had provided.

With regard to LOE, we're seeing more decreases related to recurring LOE, which is clearly a reflection of the slowdown in activity across the industry.

Additionally, property and ad valorem taxes have been declining in jurisdictions that base the taxes on reserve values.

G&A came in below our guidance due primarily to cash payments related to the legacy NPP program being lower than we initially estimated.

You'll remember these payments are influenced significantly by oil and gas prices that we receive.

DD&A for the quarter came in at $2.49 per Mcfe, which is lower than the range of $2.90 to $3.10 per Mcfe we provided for guidance.

The variance is due to three key factors.

First, we're currently marketing certain assets for sale.

These assets have higher DD&A per Mcfe than the Company's average DD&A rate.

Accounting rules require these assets to be pulled out of the DD&A calculation, which resulted in overall DD&A rate coming down.

Secondly, higher prices at June 30, compared to March 31, resulted in price-related additions to proved reserves used in the calculation of DD&A.

The effect is the denominator, the reserves, gets larger and the DD&A directionally goes lower.

Then thirdly, the impairments we recognized in the first quarter of this year and the fourth quarter of last year lowered the cost basis in our producing properties, which, in turn, lowers the DD&A rate.

Speaking of impairments, we had non-cash impairments in the quarter of roughly $20 million.

This was a $6 million impairment of proved properties relating to our relinquishment of our ownership interest in properties in the Gulf of Mexico.

There was an $11.6 million charge for the abandonment and impairment of unproved properties, the largest portion of which related to the acreage in the Floyd Shale in Mississippi.

And lastly there was a $2.7 million-related impairment of materials inventory.

With respect to the balance sheet, we're in solid shape.

Our debt-to-book cap is 35%, with no debt maturities until 2012.

As previously announced, we've completed a new credit facility in April and we're able to increase the level of commitments to $678 million from $500 million.

The ability to bring in new commitments was rewarding, and I think says a lot about how St.

Mary is viewed in the credit markets.

Our credit facility balance outstanding was $299 million at March 31, and is $275 million at June 30, so you can see that we're doing a good job of staying well within cash flow.

Actually, as of July 28, the outstanding balance was down to $255 million, which leaves $420 million of availability on our facility.

Capital expenditures for the six months ended June 30 were $186.3 million and were $81.5 million in the second quarter.

Based on the revised guidance that we provided yesterday, we're about 47% and 57% hedged on expected production for both natural gas and oil, respectively, for the remainder of 2009.

We haven't provided production guidance for 2010 or 2011 but we have a solid hedge position in those years as well, about 56% and 46% of PDP, respectively.

In fact, during the second quarter, we began layering in some hedges for 2012, with some oil swaps in the $81 per barrel range.

It is worth mentioning that our hedging program is driven by the amount of debt we have and our level of long-term commitments and lease expirations.

Details of our hedging positions are included in yesterday's press release and will also be included in our 10-Q, which will be filed later this afternoon.

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

Thanks, Wade.

As mentioned earlier, production for the quarter came in at 28.2 Bcfe, which was higher than our guidance.

Although we've significantly slowed our capital spending over the last several quarters, our capital program in early 2009 included completion of a group of Woodford and Wolfberry wells drilled earlier, a number of which exceeded our expectations.

Year-over-year, we actually grew 4% in the second quarter of 2009 compared to the same period a year ago when you adjust for property sales that occurred in 2008.

Sequentially, from the first quarter of this year, production was essentially flat in the second quarter.

We do anticipate that the impact of our reduced capital spending will become more noticeable in the second half of 2009.

We expect to see production decline sequentially over the next two quarters and we anticipate that our exit rate in December will be 3% to 4% lower than our average rate for 2009, not including any impacts of potential divestitures.

Most of you are aware of our test in Eagle Ford shale and our 100% acreage position we announced late in the second quarter.

We were encouraged by the results of this well, the Briscoe G1-H, and have learned a great deal from it.

That said, there is still a fair amount we need to know and won't know until we have more wells drilled.

As a reminder, we have approximately 225,000 net acres in the play; 159,000 of those are high and in most case, 100% working interest acreage, and we have roughly 66,000 net acres earned to date in our joint venture with Anadarko and TXCO.

As we mentioned in our guidance update from last night, we're currently completing our second well on our 100% acreage and we're currently drilling the third well.

We've revised our original plan which was to drill a four-well test program on the 100% and are now planning to keep an operated rig running for the remainder of 2009, which will allow for the drilling of six additional wells by year end.

Our extended testing program will allow us to develop better correlations between IP and EUR versus lateral length and completions techniques and gather some data in areas where we don't have as much geologic data as we would like to have.

With respect to the joint venture acreage, St.

Mary took over the drilling of the last three earning wells from TXCO during the second quarter.

Those three wells are complete -- are done but need to be completed and that will be done in the third quarter.

All of the wells required to earn acreage in Phases one and two have been drilled at this point, and Anadarko will now operate the joint venture, both drilling and production, going forward.

I would like to talk a little bit about a couple of items on the Eagle Ford we're fielding a lot of questions on.

First, there is a lot of interest in whether or not the Eagle Ford Shale is a dew point or a retrograde condensate reservoir, and what we think the impact of that might be on EURs and economics.

Pressure versus temperature or PBT testing performed on recombined samples of the Briscoe G1-H produced fluids indicate that in that area, a small amount of condensate will drop out in the reservoir as pressure is reduced during production.

In the southern portions of our acreage, where we're currently completing a well, we expect we will be in a dry gas reservoir with no liquids dropping out in the reservoir and relatively low amounts of condensate production at the separator.

To the north, in the JV area, the wells we participated in could really be characterized as high GUR oil wells with liquid yields in excess of 100 barrels per million of gas.

All of the gas we've encountered so far in the play has been very NGL rich with wet gas BTU contents around 1300 BTUs per standard cubic feet.

At this point, we cannot say with certainty whether the heaviest content of portions of the Eagle Ford reservoir fluids will have a negative impact on ultimate recoveries although liquids in the reservoir may interfere with gas production to a greater or lesser extent depending on location.

One can make the argument that in a highly fractured reservoir, significant liquid blockage is not that likely.

Certainly, wells in some portions of the play will likely require an artificial lift at some point during the life of the well, which will raise operating costs down the road.

On the positive side, the value of the production stream from these wells is considerably higher than for a dry gas well of equal EUR at current gas and oil prices.

Using the production from the Briscoe G1-H well as an example, at a $4 per million BTU NYMEX gas price and $70 NYMEX oil price, roughly yesterday's close, our production stream from the Briscoe G1-H has a value over $7 per Mcfe netted back to the well head, more than double the net back for a dry gas stream.

This higher net back value translates to significantly higher margins and lower break-evens EURs.

It should also be noted most of the discounted economic value of a well occurs in the first year or two of production.

And if liquids are not a problem in production during that critical time period, the economic impact of such problems will be small.

At this point, we're cautiously optimistic that on the bulk of our acreage, the rich gas and liquids content of our production will prove to be a competitive advantage.

The other issue that we get a lot of questions about is transportation and processing capacity in the area.

The simple answer is that if this play really works in a big way, there will need to be some infrastructure built out over time.

However, I'm pretty comfortable that we'll be able to make suitable arrangements for enough transportation and processing to allow us to thoroughly test the play initially, and there are a number of reasonable looking options for the long-term as well.

Our increased drilling program is specifically being designed to help us learn as much as we can about the play and give us confidence to make necessary long-term infrastructure commitments.

So, that's the Eagle Ford.

We have some great potential here and it could be really big for the Company.

Now, I'll touch briefly on our activities in the Marcellus and Haynesville and make a few comments on the emerging horizontal Granite Wash play.

In the Marcellus, we're drilling our first well in McKean County, Pennsylvania.

It is a horizontal well that's expected to be drilled to a measured depth of 9600 feet and will have a 3900 foot lateral.

We've already cored the well and run a full suite of logs in the pilot hole.

We've also spud our second well in the area, also in McKean County.

We're planning ten stage hydraulic fracture completions on both wells and we'll be completing microseismic data -- collecting microseismic data on the first well from a monitoring well we drilled nearby.

The completions are currently scheduled to begin in September.

We have over 40,000 net acres leased or optioned in the Marcellus.

In the Haynesville, we're about to complete our second operated well targeting the Haynesville Shale, the USA BL#1 in northern St.

Augustine County, Texas.

The well is a vertical test and holds some key acreage.

We plan to drill a third well to be located in Shelby County, Texas targeting the Haynesville Shale by the end of the fourth quarter.

The Company has also participated in several successful partner operated Haynesville tests in Louisiana.

Given how gas prices have worked out this year, we decided to minimize our drilling activities in the Haynesville, while we shoot 3D seismic over the bulk of our leased acreage and collect additional production data from offset of operators.

We still have time on our leases and we expect to have all of our 3D in hand by mid 2010 to guide our subsequent drilling efforts.

Jumping into another play with significant potential liquids production, in the last couple of weeks, there has been a lot of news about the horizontal Granite Wash in the panhandle of Texas and western Oklahoma.

We have roughly 31,000 net acres in the play, the core of which is our Mayfield acreage in Beckham County, Oklahoma, which is just across the state line and on trend with the Styles Ranch area in Texas; all of which is held by production.

We have believed for some time there was great potential for horizontal development in that area but given the HPP status of our acreage, we chose to focus our exploratory activities elsewhere and let others prove up the play.

We think our acreage is highly prospective.

And I would not be surprised at all to see us operating wells in the play in late 2009 or early 2010.

In fact, we are participating right now in some co-owner operated drilling.

This play is another example of the opportunities that can result in holding onto acreage in multi pay basins.

The last thing I'll talk about is our capital investment outlook.

You will note from yesterday's release that we have increased our estimate to $411 million.

The change is primarily related to two things, first, maintaining a rig in the Eagle Ford through the rest of the year to accelerate our program there, and second, increasing development activity in oil projects, notably the Wolfberry and the Bakken.

There are some other small things moving around but those are the big changes.

Consistent with what we've said all year, we intend to invest at a level, at or near our cash flow and exit 2009 with a deep inventory of projects to choose from in the future.

With that, I'll turn it back to Tony.

Thanks, Jay.

We had a strong quarter and I'm proud of the work that our employees have done in a very challenging economic environment.

To reiterate what I mentioned before, we are very clearly a company that's continuing its significant transformation.

A couple of years ago, we made a strategic decision to focus St.

Mary on North American resource plays, and I think it is obvious that we're making significant strides towards that goal.

We now have exposure to some of the most exciting resource plays in the country that have the potential to be very impactful to the Company.

On the financial side, our strong balance sheet and solid hedge position allows us to continue to test and advance these resource plays.

In summary, I think that we have charted the right course and we're making significant progress in our transformation.

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

(Operator Instructions).

Your first question is from the line of Scott Hanold with RBC.

Yes, thanks, good morning.

Good morning, Scott.

In the Eagle Ford, can you talk about the Briscoe well.

I mean what is that producing like at this point in time?

Where do you start seeing from initial declines on that well?

Yes, the well is currently making about 2 million a day.

It is about 80, almost 100 barrels a day of the condensate.

So it's hanging in there pretty well.

It's fitting in our type curves pretty well at this point.

We're still really early.

I think I should note since we drilled that well, we took our next lateral on the next well that we're drilling out to about 5,000 feet.

So, we've extended laterals, I think we just finished -- I haven't seen this morning's report but we just finished a 17 stage FRAC on the next well.

So I think our perception is we needed to get our lateral length out a little bit, pump a little bigger job.

But we're really encouraged.

What we're really focusing on is trying to come up with the correlation between what we call stimulated rock volume and EUR.

As we drill more wells, we'll get a better feeling for what that means.

Our costs have been coming in real well with respect to drilling wells.

We're getting to depth.

in the appropriate number of days.

I think the drilling part is going very well So again, we're cautiously optimistic; I think we're fairly encouraged with the results so far.

Okay.

And as far as like drilling days, on the 5,000 foot lateral, how long does that take and can you talk in terms of what costs would you expect without the signs in the 5,000 foot lateral 17-stage FRAC well.

Well, I think, again, the play varies in depth quite a bit as you go north to south.

We start out probably 7500 feet; that far south, we're probably at 9500 feet EVD, so that adds some.

I think in the far southern areas, my expectation is we can drill these wells with a 5,000 foot lateral for about -- we'll get to about a $5 million cost, maybe $4.5 million to $5 million including some infrastructure.

In the northern areas, I think we'll probably be able to drill these wells for $3.5 million to $4 million.

Days to depth, I don't have an exact number.

The well we drilled right now, we took a kick-up hole and it took us a little longer.

But it is going to be 20 days or so.

In the lateral section, you're drilling 1,000 foot a day.

The Eagle Ford drills like a dream when you get into it.

We've looked at days to depth curve -- compared days to depth curve with some of our competitors, and we're all drilling really fast.

So, again, I think it is going to be pretty easy drilling.

Not setting intermediate pipe, it's going real well.

Okay.

When you look at sort of the different positions in the Eagle Ford, I know you kind of gave some color on some differences across here.

But when you look at sort of really some of the key geological aspects like depth and permeability, can you talk regarding your core position in that play versus say some of your competitors a little further to the east?

I haven't looked that much uptrend.

I can tell you from the logs I have seen, say like the Petrock wells are terrific.

They've got some great looking stuff.

I've seen sections we run across there.

I think our position is very good with respect to what we've seen.

We like where we're at.

We like being as far south as we are and some of our acreage, I don't know.

We haven't been as enthusiastic about some of the stuff farther up to the northeast, but we're not a big player up there either.

So, I don't want to characterize somebody else's acreage.

I'll let them do that.

Ok.

Appreciate it.

And one last question.

Just kind of looking at your assets as a whole, obviously, Tony, I think you've said it once before.

You like to have a lot of lines out there to try to catch some fish, but with this Eagle Ford which could be a pretty big project and Haynesville and Woodford and Granite Wash and Marcellus, is there some thought of continuing to streamline some of the operations and divesting some things that have become maybe non-core at this point?

Yes, Scott, that's something we'll look at every year.

In fact, right now, we've got a divestiture package on the market for some of our assets in the Rockies, primarily it is a Wyoming gas package.

In addition to that, we may have additional divestiture packages coming out before long, later this year.

But again, it is absolutely focused on those nonstrategic assets, which will allow us to core up, as you say and to really focus on these resource plays.

And while we're very pleased with the position we've got in some of these resource plays, it really has increased our focus.

For the most part, each of our five regional offices has a single or maybe two resource plays that they focus on primarily.

And that's something we couldn't say just a short time ago.

So, we really have increased the focus on these key plays.

Okay.

Appreciate it.

Congratulations on the nice quarter.

Great.

Thanks.

Your next question is from the line of Mike Scialla at Thomas Weisel Partners.

Hey, Mike.

Good morning, guys.

Good morning, Mike.

Congrats on the quarter.

Just want to follow up on Scott's last question.

Maybe a little bit more direct in terms of any thoughts of maybe bringing in a joint venture partner on some of your resource plays say like maybe the Haynesville; would that be a possibility at this point?

Yes, Mike, one of the things we're going to do is we continue to test these emerging plays is obviously look for the optimal development and capital plan to go along with success in each of these plays.

So, right now, we've got plenty of dry powder.

We have the ability to ramp up these plays on our own.

But having said that, we'll look at other options as well in any of these plays in the event that we have multiple strikes, so to speak.

To me, that's a great situation to have.

And like I said, we would look at the full menu of options at that point, including joint ventures, drawing on additional capital capacity.

All of those kinds of options come into play.

So, to me, those are great questions to respond to these days compared to where we were just a short time ago.

So, but that's the reason why we have a strong financial position, strong balance sheet.

We've got a lot of optionality to fund these programs with success.

Sure.

Can you remind us of the size of the package you have for sale right now maybe in terms of proved reserves and the reserve mix and where those are generally located?

As I mentioned earlier, these are in the Rockies; it's somewhere in the order of 50 Bcf.

19 million a day net production.

Okay.

And on your Shelby County Haynesville well, is that going to be a vertical test as well or are you going to take that one horizontal?

We haven't decided yet, Mike.

It kind of depends on where we end up cash flow wise to be honest.

We'll look at it.

We need to get a horizontal test in there, but I don't want to do a lot of drilling until we get our 3D either.

So, we're just getting that.

We won't have that data in until the first half of next year.

So, the bulk of our acreage is in that Shelby County, St.

Augustine area.

I think it is a part of the play that is starting to get a lot of interest from people.

I think the rock quality is good.

But we're sort of coming at it from the stand point look, we've got quite a bit of time here.

I would really like to have the 3D to guide the drilling program.

It doesn't take very many mistakes in this program to end up with an uneconomic outcome.

We don't want to make mistakes.

3D is cheap relative to drilling wells.

So, that's kind of been our approach.

We may drill that well horizontally.

We may take it vertical.

We haven't made a decision yet.

Okay.

And then skipping over to the Granite Wash, you talked about participating in some wells there.

How far is your -- the bulk of your operated acreage from say Styles Ranch or some of the prolific wells that have been posted in that play?

Well, it is really -- the bulk of the operated stuff is literally right across the state line from Styles.

If you look at the Styles Ranch stuff, and it is right on trend.

The Mayfield area is right on the border in Texas and Oklahoma.

And that's -- I think we have 17,000 operated acres there if I remember the number correctly.

It is a big chunk of acreage.

We've looked at the -- we've been looking at this for quite some time.

In fact, our exploration manager has worked both for Newfield and Apache.

We have quite a bit of actual understanding of the play.

I will tell you that the Mayfield area in terms of total section in the Granite Wash is actually thicker than a lot of the stuff that's being completed over in west Texas.

It is very similar to Styles Ranch in terms of log quality and thickness and the various wash sections.

I think it is a highly prospective play.

We don't have -- we have plenty of well control but not -- we haven't drilled it up to the extent even some of the stuff in west Texas has been drilled.

So, yes, I think it is -- there is a lot of potential there for us.

Obviously, we're getting after it.

It was nice, we were in a position where we had essentially 100% of our Granite Wash acreage is held by production.

We had participated, actually drilled a couple of wells farther to the east last year and made a couple of decent wells but they weren't super.

They were in a more distal position.

The well we're drilling right now, we expect pretty good things from it.

It is a little farther to the west, but we'll be tackling the Mayfield area pretty soon with some operating wells.

That's terrific.

Thank you.

Thanks, Mike.

Your next question is from the line of David [Etta] with Jefferies.

Hi, guys, my questions have been answered.

Thanks.

All right, David.

Thanks.

Your next question is from the line of Anne Cameron with JPMorgan.

Good morning, guys.

Good morning, Anne.

I have a question about the leasing in the Eagle Ford; first, are you continuing to lease?

And then sort of what's the schedule for when those leases expire?

Well, we have been doing some leasing.

In terms of lease expirations, a lot of our acreage is actually held by production.

If you look at the bulk of the center of our asset position, we bought that in an acquisition here a couple of years ago for the [Almos] and [Almos] all of the acreage is held by [Almos] production.

As you get to the far south, what we've determined is we can hold almost all of the southern acreage with one rig running.

We have three big leases down there.

We have to drill a well every 120 days on each of those leases.

So, one rig would hold all that.

The JV acreage, which is operated by Anadarko, they have much -- there's more lease expiration issues there.

We anticipate having to drill quite a few wells next year in order to hold that together.

Probably -- I don't have a number here but it is a fairly substantial amount of money.

But on our own, 100%, it is either HBP'd or we can hold it essentially with one rig.

So a lot of time for us to work things.

I think we have an opportunity here to optimize this very well.

And again, not -- we don't have to drill a lot of wells in a hurry.

So, getting back to that question about JV'ing and other things earlier and the pressure to fund all of this.

We do have the opportunity here to pace this such that we can fund it within our cash flow.

But Anne, we continue to look for leasing opportunities and obviously we began quietly leasing well before this play ever broke.

And so we have been able to build a very substantial position.

But we'll look for opportunities to head on bolt-on acreage as well.

Great.

Thanks.

That's helpful.

That's it for me.

Thanks, Anne.

(Operator Instructions).

Your next question is from the line of Gordon [Dolent] with Wells Fargo Securities.

Good morning, Gordon.

Good morning.

Quick question for you, just wondering on the timing of your second well that you have in the Eagle Ford and perhaps the third well, as well.

Second well is literally finished in completing today.

Okay.

We should be flowing a well back here within a week or so.

But we're not going to announce one day numbers or anything like that.

We don't do that.

It will be awhile before we start giving out numbers on that, until we see some numbers.

I think it kind of depends on what we have to release from a Texas state rule standpoint.

The third well is just -- we're just drilling right now, we were just setting a plug to kick off and start our lateral section.

It will probably be later in the third quarter.

I think people ought to be thinking in terms of all of these wells, both in the Eagle Ford and the Marcellus are third-quarter events for us.

The Marcellus may even drag into the fourth quarter before we have a lot of results there.

So, third quarter is a big quarter.

And we'll have probably three completions in the JV area.

Probably a couple more in the 100% during the third quarter.

In the Eagle Ford.

In the Eagle Ford, yes.

And then in the Marcellus, we're going to complete those wells probably in September.

We'll see if we have data to release by the third-quarter call.

Very good.

That about covers it.

Thanks.

Thanks, Gordon.

Your next question is from Mike Scialla from Thomas Weisel Partners.

Hey, Mike.

Again, guys, just want to follow up on the infrastructure you talked about, Jay.

The needs there in the Eagle Ford.

Are we looking at -- would next year require some significant infrastructure build-out or would that be three years down the line?

Well, it depends on how fast we ramp.

I think there's adequate capacity out there, you know, there are a limited amount of competition in the area.

There is adequate capacity out there to handle probably $50 million a day kind of numbers if we need to get to that in the next 12 months.

I think the real issue is how big does it get and how fast I think we need to get big inch high pressure pipe in there.

The nearest place is probably 20, 30 miles away.

By the time you work through hunting season and land pipe, it is probably eight to ten months out before you really have any pipe in the ground, even if we committed today.

I'm thinking it is going to be -- we have to get enough information here to be able to make some early commitments on some of that infrastructure.

It depends to some extent where we drill as well.

In the northern area, the JV area, I think there's probably a little closer to infrastructure.

As you get farther south, we're a little farther away, but there's some pretty good early options.

We talk to just about every pipeline operator in all of south Texas at this point.

And all of them are making proposals on how they can get to us.

Obviously our competitors are out there as well, talking about this and there's a lot of discussion about how big this can be and how much infrastructure needs to get built.

I think if you say to yourself look, there is enough out there right now for the next 12 months, if, within the next four or five months, we can start to make commitments on some of the bigger inch pipe, I think we're in pretty good shape.

Okay.

Good.

And then any update on the Bakken?

It sounds like you're going to get active in the Bear Den area again.

I did notice EOG had a pretty good-looking well in Burke County.

Any plans to do anything up there again?

Yes, we're going to pick up a rig here pretty quick.

If you remember, we had a long-term rig commitment.

We farmed that rig out to one of our competitors.

We're actually going to pick that rig back up.

We get the rig back in September.

We're going to start drilling again in September.

We have a Three Forks test we're going to drill up in Dubai County and then get back down into the Bakken and the Bear Den area.

We'll be drilling essentially from September on through the rest of the year, hopefully beyond that.

That's sort of our plan.

We want to get the rig we're already committed to back and then start our drilling program in September.

Mike, remember, long-term rig commitment for us is like 11 months.

Right, so the rig commitment expires in November.

We didn't want to end up with two rigs for two months and then end up having to work that out.

That makes sense.

But no plans to do anything in Burke at this point?

Nope, we don't have any plans in Burke County.

Okay.

Thank you.

Thanks, Mike.

(Operator Instructions).

Your next question is from the line of Christa Choi with Raymond James.

Good morning.

I just had one question on the Wolfberry, I was wondering how many unbooked locations you have here and what the differences are if any between the 40 end acre space walls.

We're going to look here real quick to see what's -- when we say unbooked.

There is about 150-some 40-acre locations left to drill as I recall.

We don't have all of those booked.

Hold on just a second.

Okay.

And in this area, what's the breakout between the oil and gas components in these wells?

Well, they're oil wells.

They have a reasonable GOR with pretty high value gas.

But they're all oil essentially.

Okay.

The number we've got is 128 prove and poss locations.

Roughly 200 total locations left at Sweetie Peck.

And [Hoffies].

And yes, you got to throw in, yes, I'm sorry.

That's total Wolfberry.

Yes, you throw in -- that's the total Wolfberry.

Some of that is operated by others.

Okay.

And sorry, just to clarify as a follow-up to the Bakken question.

I was wondering how you're choosing your sites.

And is the well in Divide County, have you already identified a specific location there?

Oh, yes, we've permitted them.

We have several locations permitted up there.

Ok.

What's the proximity to the closest producing well there?

It is real close.

Samson has a number of three, [forked] wells just to the east of us.

The difference here, we're going to be drilling a long 1280 lateral which hasn't been done in that particular area.

We're partial to that style of completion up there.

And actually Samson, I believe, is going to be a partner in the well if they participate.

So, it is kind of a prove and producing area but nobody's drilled one of the really long laterals up there yet.

We want to see what that will do.

Okay.

That's helpful.

Great quarter.

Thanks.

Thanks, Christa.

Your next question comes from David Tameron with Wachovia.

Hi, good morning.

One follow-up question to Gordon's.

If I look at your CapEx budget, you have an other component.

In there it's, I think, $26 million as I look at the press release.

Where is that -- where are those dollars headed?

Where are they going?

Is that in the other drilling portion?

The other portion in the development activity.

Development activity?

You have Wolfberry, Bakken, Woodford, Cotton Valley and James Lime.

Largely Springer in the -- what we call the [Broxton] area of Mid- Continent.

We still have two rigs running there.

It's deep Springer, 22,000 foot, 130, 140-day well stuff.

We operate there with about a 35% working interest on a couple of wells.

And we've had two rigs run there essentially constantly for the last couple of [years].

They're just such long lead wells and actually very economic even at these gas prices.

We've had some really nice wells.

But we don't highlight it much because it is not what you would call a classic resource play.

But it has been pretty good for us.

Okay.

And then Tony, or maybe Jay, but as I think about the rest of the portfolio, I know it is boring to talk about.

Kind of the heart that's getting that 26 Bcf, can you talk about as you've reduced the well count or rig count in some of those plays, is one holding up better than you expected?

Can you just talk about your base foundation of production?

Can you repeat that question?

I didn't understand the reference to 26 Bcf.

I'm sorry.

If I look at your total oil and gas or total production for the quarter.

Oh, okay.

I'm just trying to figure out what the -- outside the resource plays, what the rest of the portfolio is doing.

And just trying to figure out what assets are -- I'll just leave it at that and let you run with it.

Well, Tony, do you want to --?

I would say you know, in terms of our conventional production, Jay talked a few minutes ago about the deep Anadarko, the Springer play, has come on very well.

The latest wells there continue to produce at significantly higher rates than expected.

So, that's really a significant boost to our production year-to-date.

In addition to that, the Wolfberry wells have continued to produce and come on strong.

You know, we talked about our [simul-frac] program pilot test up in the Woodford.

The latest four wells associated with that have come on very strong.

Three and a half to over 5 million a day, kind of average production.

So, we're really getting some nice bumps from some of our ongoing plays.

And you're right.

A lot of which we don't spend a lot of time talking about because we're focused on our resource plays.

But clearly, it is some of these legacy programs that continue to contribute to cash flow and allow us to help fund some of these new tests and emerging plays.

And Tony or Jay, what kind of underlying decline rates on that foundation right now as you've backed off some of the rig count and allocated it elsewhere.

I think we've talked about what?

26% to 28%, Jay, somewhere --?

Not quite that high anymore.

If you just stop drilling, okay, just stop drilling today, our annual decline rate in the first year would be about 24%.

Okay.

In the second year, it is considerably lower than that.

Obviously, it flattens out over time.

It is a little tough in market -- in this kind of an environment where you're slowing your drilling activity, you're not stopping but you're slowing, it is a little hard to project what your decline rate is going to be.

You're going to burn off some of that early decline and you're replacing some of it but not all of it.

It is a little hard to -- that's why sometimes it is hard -- it is actually kind of difficult to figure out exactly what your exit rate might be for a year like this what next year looks like because you're not exactly sure -- the mix of your production and what you're drilling is a little different than what your underlying PDP looks like, versus your underlying PDP.

If you just stop drilling and run it out at 24% for a year and then take it down to about 18, 17, 16 over time, then that's not too bad a number.

Okay.

And if I think about -- let me ask you industry questions if you guys want to take a stab at it.

Natural gas rig count today, 700, sub 700.

A year from now, where do you think that number is?

Natural gas US rig count?

Tell me what gas price is going to be.

I think it really depends on how fast demand comes back at us and what happens with the economic recovery.

Obviously, I think there's -- on the supply side, a lot of projections right now could point to oversupply.

But I think we really need to see what happens on the demand side and with economic recovery to understand what that looks like longer term.

So, I couldn't even hazard a guess at this point in terms of rig count because it is going to be dependent I think both on the supply and demand side.

Let me try one more time.

Over or under 1,000 rigs, what do you think?

Oh, I would say under.

Just looking at the overhang and kind of what's going on right now.

I hope I'm wrong.

If we took a poll in the room here, we might get two different answers.

I guess one point, and I appreciate why you asked the question but, if you look at what we're doing with our drilling portfolio, we're specifically emphasizing plays that have a lot more liquids associated with them because they have higher margins.

That is the value of having a fairly diverse portfolio to choose from.

We like the Eagle Ford for that reason.

I think the Granite Wash has a lot of potential for that reason.

We have the Wolfberry.

We think the higher margin plays add a lot of value to the portfolio.

So, people ask us all the time how cored up do you want to get?

Couldn't you focus more, focus more, some of these opportunities that we have that have this liquid subside would be things a lot of people would have told us we should be not in.

So I think again it points out the value of a having a diverse portfolio.

Okay.

But even talking about that, we're talking about half-dozen significant resource plays, and we have a mix of oil and gas like Jay mentioned.

So, I really like that optionality.

Especially when you don't know what the market is going to give you.

All right.

One more.

I promise.

Tony, do you look at your portfolio, where are you at as far as assets that you have under the umbrella today.

Obviously, everybody always wants opportunistic acquisitions.

But if you look at your portfolio today, how do you -- how comfortable are you with it?

Where are you at in your mindset?

Two words, David.

Living large.

I really like the size of the opportunity slate we've got in front of us right now.

Man, I look at the resource plays that we're in and they are some of the highest potential in the country.

And that has been absolutely by design.

There's a couple we talk about today that weren't even on the radar screen hardly a year ago.

You look at where we are today and we're poised on several of these key plays that with successful tests this year, which was by design in a difficult economic environment, but I can tell you with success and with market recovery, you're going to see St.

Mary looking at ramping up in a number of these plays with success.

So, I'm very pleased with our position today and I just see incredible potential in front of us.

All right.

Good, thanks.

All right.

Thanks, David.

At this time, we have no further questions.

Thank you, operator.

And thanks to everyone for your interest in St.

Mary.

As I just mentioned, I think we're right on target with our business plan for this year and very well-positioned for long-term success.

We look forward to our next quarterly call with you.

We hope to have some updates on our testing program.

And with that, we wish all of you a good day.

Thank you.

This concludes today's conference call.

You may now disconnect.