SM Energy Co (SM) 2009 Q4 法說會逐字稿

Good morning, my name is Therese and I will be your conference operator today.

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

Mary fourth quarter and full-year 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).

I would now like to turn the call over to Mr.

Brent Collins, Director of Investor Relations.

Go ahead Brent.

Thank you, Therese, and thank you for joining us on the phone and online for St.

Mary Land and Exploration Company's fourth 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 risk 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 cautionary information about forward-looking statements in our press release from yesterday, the presentation posted on our website for this call and the risk factor section in our most recent 10-K and 10-Q filings with the SEC.

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 on this call.

You should read the cautionary language page of our slide presentation for an important discussion of these terms and special risks and other considerations associated with these non-proved reserve metrics.

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, Brent Collins, Director of Investor Relations and Kelly Sutton, Senior Reserve Engineer.

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

Good morning and thank you for joining us for our fourth 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.

As noted in our press release from yesterday, we have a presentation available on our website that we will be referring to during the call this morning.

Let's begin with page three of our presentation which I'll use to address some of the highlights that I'd like our listeners on the call to walk away with.

Concerning our quarterly results, we had a solid quarter to finish out 2009.

Production was in the upper half of our guidance range and costs were largely within or below or cost guidance for the quarter.

I think it's easy to forget just how challenging the environment was just a year ago.

I believe that we responded appropriately by cutting back our capital spend, deferring development projects until costs were lower to improve our economics and focusing more effort on our expiration projects.

Obviously, those decisions have impacts to your production rate and reserve bookings.

And I'm pleased with how we responded this year, all things considered.

Our reserves at December 31, 2009 were 772.2 Bcf equivalent, which is 11% lower than the 865.5 Bcf equivalent we had at the end of 2008.

The decrease reflects downward revisions for the year as well as sales of roughly 44 Bcf equivalent, most of which related to Hanging Woman Basin.

We were able to replace our production through the drill bit for 2009 which is noteworthy given the decreased level of capital investment in 2009 and the fact that it was weighted to the back end of the year.

For the year our reported production came in at 109.1 Bcf equivalent which was about 5% lower than our reported 2008 production.

However, if you adjust for the divestitures of non-core assets that we have sold over the last two years, our production actually only decreased 0.5 Bcf equivalent, which we feel good about given the 62% decrease in development capital in 2009 compared to 2008.

One of the resource plays that we focused more attention on in 2009 was our Eagle Ford shale program which we advanced significantly in the course of last year.

In yesterday's press release, we provided an update on activities on our operated Eagle Ford program and Jay will spend quite a bit of time this morning talking about the Eagle Ford.

But I will say that I am very pleased with how the program is performing.

We now have 250,000 net acres in the play which is an increase of roughly 10% from our last acreage update.

We continue to run two rigs in our operated portion of the Eagle Ford and we are seeing some great gains on our drilling efficiency which Jay will talk about.

As many of you who follow the St.

Mary's story know, we have been transforming the Company over the past few years.

In spite of the challenges that we faced at the beginning of the year, we managed to execute well in our business plan for the year, and have significantly repositioned ourselves.

Today we now have a successful program up and running in the Eagle Ford, exposure to the Haynesville and Marcellus shales that are becoming better understood every day and several emerging plays that have the potential to add significantly to our project inventory.

I'll turn the call over to wade to provide some color on our financial performance for the fourth quarter.

Wade.

Thanks, Tony.

Good morning.

I'm going to start on slide five.

Late yesterday we released our fourth quarter earnings financial highlights and I'll briefly go through some financial highlights this morning.

So looking at slide five, you can see some of the items that we guide on.

Production 26.1 Bcf equivalent was near the top of our guided range of 24.75 to 26.25.

LOE and transportation were at or below our guided range.

Production taxes came in at $0.51 for Mcf equivalent which was above our guidance.

This caption is driven by pre-edged gas and oil prices.

G&A was below our guidance and that was due primarily to compensation related items.

DD&A was higher than we had guided as a result of lower proved reserves at year end which decreased the denominator in the per unit depreciation calculation and this resulted in a higher per Mcf equivalent DD&A rate.

The effective tax rated for the fourth quarter was nearly 61% and that was due primarily increased to IDC deductions generated in the fourth quarter.

Due to that, we were able to carry back an NOL from the current year to realize a significant income tax refund.

But, this resulted in a change in permanent tax deductions of about $600,000.

These changes occurred in a period where we had small amount of pretax book income causing the effective income tax rate to spike up.

This had minimal impact on the full year 2009 effective rate which was short of the 38% as expected.

Couple of comments on some unusual items that we had during the quarter.

We had a gain of $22.1 million related to divesture activities, this primarily related to the sale of Hanging Woman Basin coalbed methane project which closed during the fourth quarter.

Back in 2008 we recognized roughly $17 million in bad debt expense for receivables with Sims Group, which was a purchaser of some of our oil production, and they declared bankruptcy last year.

In the fourth quarter of '09 we recovered $5.2 million related to a portion of the receivables that we had written off and we think realistically that our collection effort is dead at this point.

I do want to point out that we back out both of these gains when presenting our adjusted net income due to their effect on the comparability of our operating results.

And I'll talk about adjusted net income in a minute.

We had approved property impairment during the quarter of $21.6 million that was related to Cotton Valley properties in our ArkLaTex region.

We also had a $25.2 million charge related to the abandonment and impairment of unproved properties.

About half of this related to acreage in the Anadarko Basin that is either expiring or will not be pursued.

The balance relates to other acreage across the Company that will not be developed given current capital investment allocations, or is viewed as not perspective.

So looking back at slide five, we reported net income for the quarter of $990,000 or $0.02 per diluted share.

Adjusted net income for the quarter which adjusts for unusual or significant nonrecurring and non-cash items that most analysts do not consider when making their estimates is $20.1 million or $0.31 per diluted share, which was higher than Wall Street's consensus.

We provided an adjusted net income numbers because we believe it is the most directly comparable to the estimate in the financial analysts calculate and publish.

Cash flow from operating activities was $83.1 million for the quarter, discretionary cash flow for the quarter was $144.2 million or $2.25 per diluted share which was better than Wall Street consensus numbers as well.

Moving onto slide 6, you'll see that the balance sheet is in solid shape.

We have no debt maturities until 2012, our debt to book capital ratio at the end of the year was 32%.

As we've previously announced we have sold or entered into agreements to sell packages of non-core properties that are expected to close during the first quarter.

We plan to pay down a revolver with these proceeds.

Using some rough assumptions, the pro forma debt to book cap after adjusting for those divestitures would be around 20%.

The main point I want to make with this slide is its balance sheet (inaudible) and we are pleased with our current leverage levels given the opportunities in front of us.

Slide seven is a summary of our revolving credit facility at year-end.

Our cash flow has been a little bit stronger than we had forecast and we have been able to pay down the revolver.

Our credit facility balance at the end of the third quarter was $235 million and is $188 million at the end of the year.

As we receive proceeds from the divestitures we just discussed we will pay down on the revolver and then draw on it later in the year.

Our plan for 2010 is for CapEx to approximate divesture proceeds plus cash flow, so I think directionally we will end up the year with around $190 million drawn given what we know today.

At the end of 2009 we have nearly $0.5 billion of availability under the credit facility and that's the dark blue box in the middle of the slide.

As we look at our redetermination that will be taking place in late March we are in good shape with respect to our covenants.

Given the size of the divestitures I mentioned earlier it is logical to assume that our borrowing base will be coming down from the $900 million that we currently have from the bank group.

We're currently working with them on this so I don't want to speculate too much on the outcome, but I'm very confident it will be sufficient for our needs this year.

Moving onto slide eight, based on the guidance that we cited yesterday we have about half of our total production for 2010 hedged at an equivalent price of $8.64 per Mcf equivalent.

About 47% of our gas volumes and 53% of our oil volumes are hedged in '10.

We also have a solid hedge position that covers a good portion of our PDP in 2011 and 2012.

Details of our hedging positions are including in the appendix of the presentation for today and also be included in the 10-K which we will file later today.

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

Thank you, Wade.

I'll provide a quick overview of our year-end reserves report and then an update of our operations.

In particular, I will spend a fair amount of time on the Eagle Ford this morning.

I am on slide number 10.

Our approved reserve estimate at year-end 2009 is 772 Bcf equivalent.

This is a decrease of 11% from last year's estimate of 866 Bcf equivalent.

Our PUD percentage increased slightly to 18% from 17% and our natural gas percentage decreased from 64% to 58%.

The prices used under the new SEC methodology, which requires the use of an average 12 month price in the calculation of reserves, were $3.87 per million BTU for gas and $61.18 per barrel of oil.

These were 32% lower and 37% higher respectively than the prices used in last year's preparation of our estimated proved reserves.

The before income tax PV10 value for 2009 year-end is $1.3 billion which is essentially unchanged from our PV10 last year.

If you were to use the same calculation methodology as the SEC required last year, we would have seen proved reserves increase 4% to 897 Bcf equivalent and our before income tax PV10 increase 93% to above $2.4 billion.

The different outcomes from the old versus the new SEC method in our case is almost entirely a function of the low 12 month average gas price used in this year's SEC calculation versus the year-end price we would have been using in the past which was essentially unchanged from year-end 2008.

I'll now briefly discuss the proved reserve roll forward shown on the next slide.

Production for the year was roughly 109 Bcf equivalent.

This included a little over five Bcf equivalent related to sold properties that closed in 2009.

divestitures for the year were approximately 44 Bcf equivalent.

The vast majority of this, roughly 39 Bcf equivalent, related to our sale of the Hanging Woman Basin CBM project which closed in December 2009.

As a point of clarification, proved reserves of 71 Bcf equivalent associated with our announced Rocky Mountain oil divestitures and other minor divestitures were still in our reserves ledger at year-end since those transactions had not closed at that point.

Our reserve revisions totaled a negative 50 Bcf equivalent.

This 50 Bcf equivalent number is the net of a large positive revision due to oil price improvement, a large negative price revision due to much lower gas prices and a 62 Bcf equivalent downward engineering or performance-related division.

As detailed in our 10-K, which is being filed later today, revisions in two areas accounted for most of this performance-related revision.

In the Wolfberry trend, we moved 19 Bcf equivalent of proved reserves to the probable category and removed a further 21 Bcf equivalent of proved reserves.

A number of our older PDP wells in the play are exhibiting a lower decline of hyperbolic decline behavior than we anticipated.

This data from our most mature wells, has caused us to adjust our forecast curves for a number of additional wells to ensure that our ultimate recoveries are, as the SEC guidelines say, much more likely to be higher or the same as our estimates.

It should be noted that our budgeted drilling program for the Wolfberry meets our hurdles for continued investment and that these reserve changes did not result in any financial impairment.

We also reduced our reserves estimates for a number of Cotton Valley wells in the ArkLaTex.

Changes to our declined curve forecast for a number of wells, and elimination of some proved developed nonproducing cases accounted for 12 Bcf equivalent of our total revision.

Our revision include the loss of four Bcf equivalent due to the new PUD aging rules, the remaining six Bcf equivalent of negative revisions this year were the net result of minor positive and negative forecast changes across the Company.

We had no acquisitions in 2009, so there are no reserve additions to report there.

Drilling additions for the year were roughly 110 Bcf equivalent replacing our 2009 production.

About 60% of these drilling adds were proved developed.

The majority of these adds came in the Mid-Continent region where we had active drilling programs in 2009 pursuing programs in the deep Anadarko and the Horizontal Woodford shale, and the south Texas and Gulf Coast region which was focused on the Eagle Ford shale.

As indicated on slide 12, we booked roughly 44 Bcf equivalent in new PUD reserves at year-end 2009, the majority of which were the result of our operated Eagle Ford program in south Texas.

At year-end, we had seven Eagle Ford wells producing.

So far we are only booking two parallel offsets to each PDP well when booking PUDs and accordingly had only 14 Eagle Ford PUDs booked at year-end 2009.

We booked those PUDs at an average of 1.75 Bcf equivalent net to St.

Mary.

If you move to the next slide, slide 13, you can see that using our announced Eagle Ford drilling program for 2010 of 34 net wells, a net EUR to St.

Mary of 1.75 Bcfe and two parallel offsets per producing well we should have approximately 119 Bcfe of PUD additions in 2010 in addition to the proved developed reserves we will book.

These are all on our 100% property not including the non-operated piece.

Clearly these numbers get a lot bigger if we are able to feel confident about booking higher EURs per well or book more than two offsets per well.

With respect to the number of PUDs that we book, I know that one of our competitors in the play has said that they are booking five PUD locations on average for each producing well.

We certainly think that with more well penetrations over a wider area on our acreage, that we will be able to demonstrate that a larger part of our acreage is proved and we expect that we will be able to move the number of offset bookings up over time.

With respect to the 1.75 Bcf equivalent EUR we are showing, I want to point out a couple of things.

The first point that I want to make is that we are still very early in the life of this play.

Our actual expected reserves estimate is somewhat higher than our approved booking.

However, our longest producing well has only been online for eight months and we simply need more production data to have reasonable certainty for higher approved reserve bookings.

Secondly, our EUR is based on a wet gas methodology which means that we are not including any of the volumes that would be stripped out of the rich gas stream as NGLs.

We do get the value of those NGLs but don't count the volume since we technically sell the gas at the well head.

As a result, our realized price at the well head is much higher than for dry gas production.

To help further illustrate this point, on slide 14 we have put together a little diagram that depicts the value stream from these Eagle Ford wells.

This particular example is of a well in the Briscoe portion of our operated leasehold which is roughly in the center of our operated acreage.

Our data so far indicates that in the northern areas wells are going to make material amounts of condensate and higher BTU gas, say 1200 to 1300 BTUs per standard cubic foot.

And as you move south the condensate decreases and the gas generally becomes leaner.

I should mention that we had a test recently in the southern part of our acreage block that had higher BTU gas than we expected.

So our understanding of the NGL yield across our acreage is still evolving.

Our drilling program this year is specifically designed to provide us with NGL yield data across our acreage so that we can design our gathering and transportation systems appropriately.

While we are on the subject of transportation, we already have the ability to move roughly 80 million cubic feet a day of gas out of the Eagle Ford and processing is currently not an issue.

We are actively working with our midstream partners and potential future partners on plans for increasing our outtake capacity and I am sure we will have some announcements about longer-term arrangements we are making later this year.

I am now on slide 15.

This slide shows our drilling activity and results in the Eagle Ford to date.

The items highlighted in red are new from our last quarterly call in November.

I am not going to go over each new well, but we have been pleased with results from our most recent activity, the wells seem to be performing in a very consistent manner which is certainly encouraging.

I would like to mention that we are going to be restricting rate during the flowback period on a number of our upcoming completions.

Based on data we are seeing from the Haynesville and some of our own experience in the Eagle Ford with wells that were restricted due to temporary infrastructure limitations, we believe that going a little easier on the wells early on may actually result in better long-term performance.

We will be comparing well head pressure versus cumulative production data for restricted wells to some of our existing producers in order to see if this practice should be generally adopted for our new wells.

Moving to slide 16, I would like to brag a little bit today on our drilling folks who have done a great job in the Eagle Ford.

The last five wells we drilled in the Briscoe area, which are at vertical depths of 7000 to 8500 feet and have total measured depths of 11,000 to 14,000 feet have been drilled in an average of 15 days, measured at spud to rig release versus 30 days or so when we started this program.

Our times in the Galvan Ranch area which is deeper than the Briscoe have also been improving.

I should note that we really needed this improvement on the drilling side because our completion costs have been heading back up with the pickup in activity and pressure pumping in south Texas.

As Tony mentioned, St.

Mary's current exposure to the Eagle Ford shale is 250,000 net acres, about 10% larger than our previously released acreage count.

We operate 168,000 net acres at a very high working interest in most cases 100%.

The data on slide 17 shows that we have more exposure to the play than any other public company if you look at acreage on a per share basis.

We entered the play early and built a large position at much lower cost than some of the later entrants.

The wells we drill and participate in during 2010 will tell us a lot about how much value we have really captured in the play.

That's a lot of information on the Eagle Ford.

I think you can tell by the amount of time we spent on it today that this is a play that we are very excited about.

I'm now on slide 18.

In the Marcellus shale program in north central Pennsylvania, St.

Mary has leased or optioned approximately 42,000 net acres in McKean and Potter counties.

The Company flow tested its first two wells in McKean county and based on that data we believe that wells in this area of the Marcellus will likely IP to sales in the three million to five million standard cubic foot per day range.

A trunk line through our McKean county acreage that will allow for connection of our first two wells to the sales pipeline as well as service future planned development is currently under construction.

The connection to the first well which is on the north end of our acreage has been completed and we expect to get the well turned over to sales soon.

The second well is on the south end of the line and is expected to be hooked up around midyear.

The Company plans to drill a total of four horizontal wells in Pennsylvania in 2010, two each in McKean and Potter counties.

A seismic chute over a portion of the acreage is also planned for this year.

We want to see some long-term production tests on our wells in the Marcellus before we get too excited but so far things are looking pretty good to us.

On slide 19, there is an update on our Haynesville shale potential.

We have 41,000 net acres that are perspective for the Haynesville, 31,000 of which are in Shelby and San Augustine counties Texas in an area that is now being called the Shelby trough.

We believe a large portion of this area will also have potential for the Bossier shale.

We have begun drilling in San Augustine county where we are going to drill the vertical section of our first well and then move to the second well where we will drill the entire horizontal well.

We will then move back to the first well and drill the horizontal lateral.

We wanted to have our 3D seismic data in hand which we just received and are evaluating before drilling the lateral section of the first well.

And this schedule helps keep us on track to avoid any lease expiration issues.

We plan to drill seven horizontal wells in the Haynesville this year all in east Texas.

If we are successful in proving up our acreage, we will be drilling a pretty sizable program requiring about 20 wells in 2011 in order to keep up with our leasehold expirations.

I should note that we are also participating in a number of non-operated wells during 2010.

Moving to slide 20 in our Woodford shale program, data from two increased density simultaneous fracture stimulation or simul-frac pilots that were conducted in 2009 have been analyzed and the results are very positive.

The Company's first tests involved simul-fracking four wells on 128-acre spacing, or five wells per section.

Positive initial results from this test led to a four well test on 64-acre spacing, or 10 wells per section.

The Company believes that it will be able to book proved reserves on these infill wells at a range of 2.7 to 3 Bcf equivalent per well, which is consistent with the range seen on lower density drilling earlier.

I should note that St.

Mary intends to test the impact of downspacing and simul-fracking very early on in both the Eagle Ford and Marcellus plays where we think it has the potential to add significant reserves.

St.

Mary has roughly 34,000 net acres in the Arkoma Basin in Oklahoma with the potential for the Woodford shale.

The Company's drilling plan of six horizontal wells for 2010 is designed primarily to preserve its acreage position in this dry gas play.

Moving to our operations in the Williston Basin, we now have 70,000 net acres in North Dakota that we believe are a perspective for development of the Bakken and Three Forks intervals.

This is an increase of roughly 17,000 net acres during 2009.

Approximately 48,000 of our net acres are located in McKenzie and Williams counties.

The Company also has roughly 21,000 net acres in Divide County, North Dakota where testing is focused on the Three Forks interval.

The Company recently completed a simul-frac test designed to test the Bakken and Three Forks formations in a portion of our acreage west of the Nesson Anticline.

Two horizontal wells were drilled, with one targeting the Bakken and the other targeting the Three Forks.

These wells were then simul-fracked together.

The combined 24 hour IP of the two wells was roughly 2800 barrels of oil equivalent per day.

We will be monitoring the performance of the wells over a number of months to determine the extent to which the two wells may be producing incremental reserves beyond what could have been attained through a single zone completion.

The Company plans to drill 17 operated wells in the Williston basin in 2010, the majority of which will be Bakken wells.

Slide 21 briefly summarizes some of our other activities.

In the Permian Basin we have two operated rigs running.

The Wolfberry Title L program continues to be the primary focus there.

The Company is currently drilling a horizontal Granite Wash well in its Mayfield area in Beckham county, Oklahoma.

St.

Mary has roughly 32,000 net acres that are perspective for the Granite Wash and that acreage is all held by production.

St.

Mary also is engaged in an exploratory program targeting the Niobrara formation in southeastern Wyoming.

We have 24,000 acres in that play in that area.

We are in the process of drilling out the lateral and completing our first well in the play.

Regarding our previously announced oil divestitures in the Rocky Mountain area, the first transaction with legacy for the Wyoming properties closed on February 17, 2010.

The transaction on the North Dakota properties is scheduled to close by the end of March.

I'll remind you that the two packages together sold for $267 million.

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

Thanks, Jay.

Looking at the last slide in our presentation, you'll see a summary of some of the key takeaways from this morning's call.

Our transformation is on track and will be shifting into high gear with our 2010 program.

I'm pleased with our progress and excited about the opportunities for growth in front of us.

This should be an exciting year for St.

Mary.

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

Thank you.

(Operator instructions).

We will pause for just a moment.

Your first question comes from Scott Hanold with RBC capital.

Good morning.

Good morning, Scott.

Good morning.

Hey, on the Eagle (inaudible) I understand why you all are taking somewhat of a conservative approach in how you book on those reserves given the limited amount of data that you see so far on it, but when you look internally at, you know, these wells, you know, what kind of internal estimates do you have on the EURs in some of these wells versus the one and three quarters that you're booking on the PUDs?

Scott, the numbers are in the twos.

You know, we sat down with our reserves auditors at year-end and looked at all of the data we had and, you know, this is, as I said, this is very early in the play.

We have type curves that we built for various areas of the play.

It's not all one type curve.

We have three or four depending on where we are.

As you know, the central part of the play where we are drilling most of our wells this year, a lot of that is going to be in an area where we have retrograde -- potential retrograde condensate.

Mm-hmm.

So even our internal estimates on what we expect on a P50 kind of basis are pretty conservative.

We're just -- You probably won't see the impact of retrograde for maybe two years out so you want to be pretty conservative about how you book them.

The good thing about them is these wells in the central part of the play pay out in less than two years.

So from an economic standpoint, we feel pretty comfortable with where we are at.

We just want to make sure that we are doing what the SEC says here, which is we are booking something that is more likely to go up or stay the same than come down on the reserves side.

I think economically, we feel pretty comfortable but, you know, our expected P50 numbers are in the twos.

Varies from low twos to high twos depending on where you are across the play.

Honestly even that number I think has potential to go up over time as we see, you know, where we really -- where that hyperbolic exponent really comes out and where we flatten out and what those ultimate declines are.

There's a lot of variability at this point.

Okay.

Appreciate that.

And in terms of infrastructure, you somewhat addressed that you're looking at some options right now.

You know, is infrastructure such that it could limit some activity here for you guys over the next couple of years or do you think you're going to have ample opportunity to scale things up?

I think we are in pretty good shape.

We are in great shape through the end of this year.

I think what we are trying to understand right now is, do we need a dry gas pipeline into this play on the southern end.

Or are we going to be able to -- do we need to assume that most of the gas is going to be wet and end up with wet gas pipe.

It's a big difference in potentially the economic returns you might have on a dry gas play if you have a dry gas system versus a wet gas system so we need to do that testing this year to understand how much of the acreage could be dry gas and then look at the economics associated with bringing in a separate dry gas line.

On the wet gas side, I think we are pretty comfortable that we can get as much capacity as we need.

We have a strong relationship with our midstream partner in the central part of the play.

They are committed to meeting our needs there in the southern part of the play as I mentioned, we need to understand this dry gas issue a little bit.

But we have a number of people there who are very anxious to do business with us and I think we will probably have some announcements later this year on which way we are going to go with the southern portion of the play.

Okay.

Okay.

Scott, bottom line, we don't see any facility constraints immediately in front of us and continue to have very good conversations and discussions with midstream partners to build out the rest of the infrastructure going forward.

Okay.

Excellent.

Appreciate that.

Thanks.

You bet.

Thank you.

Your next question comes from Mike Scialla with Thomas Weisel.

Good morning, guys.

Good morning, Mike.

Good morning.

On your Bakken and Three Forks simul-frac, can you say what the split was between the two formations in terms of the production?

I don't have it right in front of me.

The Bakken was a little higher than the Three Forks.

I think it was like 1500 and 1300 on the IP, but, you know, IP -- I always hate to even quote those numbers because the wells make them significantly less than that now, okay, and they always do.

But I think what's going to be interesting with those wells over time is to watch how they compare to stand alone Bakken and stand alone Three Forks wells to see if you're actually getting any incremental benefit from drilling stand alone wells versus drill them together and simul-fracking them.

Or could you, you know, just drill a Three Forks well and frac it and get basically the same reserves as we got on these two?

And that's really the issue we need to discover and that's going to take some time.

It will be production over a longer period of time to be able to understand that.

And those were, if I remember right, long lateral wells and how many stages did you put on those?

Oh, I think they were 10 to 14, in that range.

About 10,000-foot laterals.

Yes.

And we pump a lot -- you know, we pumped a lot of fluid and we diverted on all those so, you know, I think, they were good size fracs.

They were long laterals, yeah.

And are you still adding acreage in the play at this point?

Well, you know, we generally don't talk about our acreage activity but, yes I think you can infer from the numbers we just released that we are still interested in buying acreage in the Bakken and Three Forks.

And then in Divide County, what's prompted you to want to test the Three Forks up there?

Has there been industry activity up there that has led -- has encouraged you?

Yes, there's a number of historic Three Forks wells with shorter laterals up in that area and so we wanted to try the longer lateral wells up there.

Don't have any material results to release yet, but, you know, I think the longer -- we think the longer laterals are going to work as they do in the rest of the play.

We have also been observing some of the offset operators that have been active in the area.

We have got a good acreage position, Sampson, for example, has a lot of experience in the area and we have been monitoring some of their performance.

Great.

Thank you.

Thanks.

Thank you.

Your next question comes from Ellen Hannan with Weeden and Company.

Good morning.

Good morning, Ellen.

Good morning.

Two questions.

One, on the engineering revisions that you described, could you run through us again -- or run through again for me what your changes were on the experience that you have seen in the Wolfberry that caused you to move some of these reserves and or eliminate some of the PUD categories?

Sure.

In general what we saw was on some of our more mature wells, the wells now that, you know, we bought this property in 2006.

When we bought the property, there were about 70 wells producing, 23 of which were used to develop a type curb for the play.

As we have looked at those 23 wells over the last three or four years, in the last year or so they have started to fall off the type curve that we used for the play.

And so they are not performing as we expected.

Essentially they have a lower hyperbolic exponent than we expected at the time of the acquisition.

Don't know what their final decline will be, but certainly the lower hyperbolic exponent drives a lower reserve recovery.

As we look at that then, we take that information and we look at all the newer wells that we have drilled and we say, wow, you know, that -- we need to make adjustments based on that performance to newer wells as well to reflect the differing type curve.

In that calculation when we do that, we say, well, you know, we may very well get some of those reserves ultimately if our final declines, we have been fairly conservative about that, if our final declines aren't as low as we think.

There's also some GOR increases over time on these wells that we might see some benefit from, so we moved 19 Bcf of that to a probable category, meaning we think there's a 50% chance or so that we will get that back over time.

And we moved 21 Bcf in total, and almost all this is PDP, to -- and we just removed it from the books based on the fact that we just don't think these wells are going to produce as much as we thought.

When you look at why that occurred, we really believe that's a result of geologic variability across the asset area that -- the assets we bought that simply were not recognized in the initial evaluation.

The 23 wells we used as a type curve didn't cover the entire acreage position at the time and there are parts of that acreage we just think are not as good as the rest and as we started to see this degradation performance, most of that is happening in areas where, you know, where we don't have as good a performance as others.

So clearly we don't like having revisions, but this was a necessary thing, the numbers are the numbers, our reserve auditor and us are in very close agreement on this.

There were no financial impairments associated with it and the economics of the wells we are drilling this year are still very strong.

And so again, why we don't like to see this, the economic impact of this has been relatively small to us.

Great.

Thank you.

I got a bigger picture question for you, I think.

In terms of your entry into emerging plays, you know, last couple of quarters, Tony, you've alluded to while you've been through this divesture and repositioning process, that you continue to look at some emerging plays and I'm curious as to whether the acreage position that you have in the Niobrara is that something new or was that a legacy position?

And also how do you think about when you go forward, how much of your capital are you comfortable with sort of committing to, you know, lease acreage or entries into emerging plays that you really are not really talking about today?

Good question, Ellen.

First of all, specifically relative to the Niobrara, that's a relatively new entry so we are in the process of doing some initial -- our initial tests there.

With some reasonable running room.

In addition to the broader question, what we are focused on with a lot of our plays, and I'll point out that a lot of these are at the same relative starting points.

I mean, right now we have a sizable portion of our capital program focused on exploration and testing in these new plays as you would expect but I think what you'll see long term is that what we want to do is move to a position where maybe 20%, 25% of our total capital program is focused more on exploration, the rest will be on development.

So I think directionally that's where you'll see us moving.

I think the Eagle Ford is probably a very good example of that where we are very active right now.

You know, by the end of this year, we'd like to have a lot of these technical questions answered and a lot more of our testing completed so then we can move that program into more of a full development mode.

But I think longer term, you know, somewhere in the 20%, 25% range on exploration would be I think the direction where we are going.

Great.

Thanks very much.

All right.

Thanks, Ellen.

Thank you.

Your next question comes from Irene Huff with Canaccord Adams.

I have a question for you.

We have been hearing it from both Eagle Ford Marcellus and some of the Haynesville player and the point you make earlier about early producing these wells at a restricted rate.

I guess it's somewhat accidental for most folks that stumble into it.

And my question for you is really what's the mechanical explanation for (inaudible) these wells and ending up having them perform better?

And the second part of this question is, does this help you really basically extract a higher amount of reserve or is it simply just really retarding the decline rate?

Great question.

And I think there's a -- let me make sure I answer it in a couple of parts.

First of all, the rationale for why technically it might make sense to do it.

You know, those of us who have been around a long time and worked in conventional reservoirs, conventional sandstone reservoirs, where we used to frac a lot of wells, you know, the wisdom there was you never try to pull a well too hard because you would produce your frac back, right?

We were always trying to preserve the quality of the completion.

In the shale side of the business, it's a really interesting thing we do.

We actually overflush literally flush fluid past our sand on all these jobs as we are doing these plug and curve arrangements.

So a lot of people have taken the view that you don't have a lot of sand near the well bore anyway, we are scouring, we're making all of these fractures so let's open these things up and rip them, and shouldn't make any difference.

I think what people are seeing in the Haynesville is with those very high closure stresses you have there and the rock, the shale is actually much softer, this shale is much softer than, say, the Barnett shale.

You know, I've heard people compare the Barnett to peanut brittle and the Haynesville to peanut butter.

It's a lot more likelihood of embedment.

Closure stresses are a lot higher so likely to be more crushing.

All those things argue for, you know, not pulling these wells too hard right up front, letting that -- letting those things heal back, not crushing the prop pack, not ruining your completion essentially by plugging the well too hard, too early.

I think it makes a lot of sense in the Haynesville.

In the Eagle Ford, there's less pressure, there's less closure stress.

Directionally from that standpoint doesn't seem like it should be that big an issue.

However, it could be some of an issue, the Eagle Ford is softer, more calcite in it, it's not as hard a shale as some of the other shale plays.

Clearly in some of the wells we had, with announced one last quarter, where we were rate restricted for some period of time and coincidentally that's the best well we have made in the play.

And we hear this -- I think the guys who are in the deeper parts of the Eagle Ford it makes a lot of sense to rate restrict these wells.

What should happen is you should end up actually producing more reserves out of those wells because you're preserving the quality of the completion.

So it's not just an issue of early time data.

It's really -- it should have an impact on your EUR per well.

Now, it may mean that you're draining a bigger radius and that, you know, your overall completion from the reservoir may not change that much because otherwise you may have to do more infilling.

But it should reduce your cost so in the long run it should improve your F and D.

So I think it's a test that's well worth doing.

It won't impact the economics that much.

Although we do benefit from that early flush production, we are going to get it over the first year or so anyway, and I think it's the kind of testing we need to do.

I think what you'll see is that it's going to be different in every one of these shale plays.

Some of the shales which are very hard and have low stress, or low closure stresses probably won't benefit that much.

I know in the Barnett, I've been told we don't operate there, but I've been told they pull those wells very hard and that it really doesn't make any difference.

But clearly in the Haynesville, I think it does and I think in the Eagle Ford certainly has the potential to, to be -- to make a difference.

Great.

Thanks.

All right.

Thanks.

Thank you.

Your next question comes from Anne Cameron with JPMorgan.

Good morning, guys.

Good morning, Anne.

Can you talk about what you -- what your last couple of Eagle Ford wells have been costing?

Sure.

You know, our costs are up a little bit.

I mentioned that in the talk earlier, our completion costs are up substantially.

In fact, if you look at from the low of last year, which is probably August, September, our frac costs are almost doubled on a per stage basis in Eagle Ford, so what we are -- our drilling costs are down, our frac costs are up, the last AFEs I just signed were five -- were right above $5 million for Briscoe wells.

So I would expect we are going to see costs between $5 million and $6 million depending on depths.

Okay.

Great.

That's helpful.

What about across the rest of your operating areas?

What are you thinking in terms of service costs this year in 2010?

Well, the area that, you know, we talked about this last fall that we had a lot of concern about what would happen if the horizontal rig count didn't stop going up so much, but clearly pressure pumping costs are way up in almost all the basins where we are active, the Williston, the Permian, south Texas, east Texas, haven't seen as much increase yet in the Mid-Continent but that's I think largely a function of the dry gas production up there and a lot of HBP.

But you're seeing significant increases in pressure pumping costs everywhere in all the basins we operate where we have material operations this year.

That's been explained to us as being a lack of personnel and a lack of equipment.

Clearly all these big slick water fracs that everybody is pumping, it's hard on equipment, uses a lot of it.

The more stages we all pump, the more time we all use.

I understand all those things.

But costs are way up and the completions now are on an Eagle Ford well on more than half the cost of the well.

So it's a big cost driver.

Okay.

Great.

That's helpful.

Thanks, guys.

Thank you.

Thank you.

Thank you.

Your next question comes from Welles Fitzpatrick with Johnson & Rice.

I was wondering if you guys could give a little bit more detail on the first four Eagle Ford wells and how they are holding up relative to their 30-day rates that you guys had released?

Any detail on the Briscoe G1H in particular would be helpful.

You know, I don't have the rate today but I can tell you the Briscoe G1H as of a few weeks ago had made over a third of a Bcf already.

Several of the wells in the third quarter call have already made more than 0.5 Bcf since, you know, in a quarter's production or so.

So they are holding up well.

The condensate rates, condensate yields are still where they were initially, so we haven't seen any declines in condensate yield which obviously would be a concern.

So, I think the wells are holding up real well.

They do have steep early declines and then they let -- you know, they are starting to make that bend.

Really the critical thing on reserves is, you know, how steep is that bend and how do they flatten out?

It's going to be a while before we know that.

But so far, so good.

Okay.

And when you talk about paying out in less than two years, what pricing are you using for that?

?

(inaudible)

Best way to look at that is take our sheet that's in our slide deck that shows you that Briscoe, central Briscoe area well.

I think it's got an $8 per MCFE net back kind of number.

Slide 14.

If you use those numbers, that's about a two-year discounted payback.

Okay.

Okay.

Perfect.

Thanks, guys.

That's all I got.

-- (inaudible) All in there for you.

Thank you.

Your next question comes from Subash Chandra with Jefferies.

Hi, it's actually Dave [Yedid].

I just had a question about your reserve price revisions.

I know you gave us a net number but could you just break out the positive versus negative revisions and where those came from?

Kelly, do you have the net gas, oil?

Well --

That number is 12 Bcf, okay.

Right.

And so the oil revision was slightly larger than the gas revision.

Kelly is doing math here.

It may take us a couple of minutes to do this, to get this number for you.

Do you have any other questions I can answer while she's doing the math?

Yes, I guess could you give me your initial impressions of your Atlas 119H well in Wyoming, if there's any kind of initial thoughts and what you are seeing, you know, production-wise and, you know, on stimulated, et cetera, from that well?

We haven't released any results from the well yet.

The well is not done yet.

We are still -- matter of fact, we're moving a rig back on it to finish lateral.

We had some problems in drilling the well and we had to move the rig.

The rig we had on it was not capable of dealing with the issues.

Okay.

Because it wasn't a capable rig but because it was just -- we needed more room on the rig floor so we moved that rig off and we are going to move another rig on and that rig will actually finish the well.

So we don't have production data to share with you at this point.

Okay.

And that's in the Niobrara formation?

That's right, in southeastern Wyoming.

If I understood your question correctly if you're asking for the breakout between the oil regions and the gas regions, our oil regions were actually up to the tune of 77 BCFE.

Okay.

Though the impact is the downward revision in the gas regions.

65.

Right.

Which gets you to your 12 total positive price revision.

Okay.

Thank you.

Great.

That's it.

Thank you.

Thank you.

Your next question comes from Derrick Whitfield with Canaccord Adams.

Good morning, guys.

We are hitting you with a double barrel this morning.

A few additional questions on your Eagle Ford and Bakken.

On the Eagle Ford first, you guys picked up another 25,000 net acres.

Could you offer any insight on your acreage strategy and area of focus?

Our acreage strategy is to not pay too much.

I hate to be flippant but I think part of what we are doing there is we're trying to core up around our existing position in a reasonable way without, you know, we have a big position, we are not going to chase very expensive brokered acreage and we have a pretty strong view of what we think is productive and isn't at this point.

So other than that, I'm not going to make a lot of comments about specific counties or specific targets but clearly we want to be as contiguous to where we are as we can to facilitate good operational practice and we are not going to chase some of this flip three times brokered acreage to high acreage values.

Other than that, Tony, do you have any other comment?

No.

I think, you know, the general neighborhood where we are like Jay said, we are trying to core up, continue to add bolton acreage and look for, you know, reasonable acreage costs in the area and we have been very successful.

A lot of our strategy also relies on our strong relationships in south Texas and in the Maverick Basin where we have had good success dealing with large landowners that had these large ranches and so we continue to pay very much attention to the relationships in the area.

Okay.

Just in terms of the JV wells, I know you guys haven't commented but we have had a chance to look at some of the public data of results using public data.

And those appear to be fairly solid wells with nice condensate yields.

Is there anything else you guys can offer as color on the JV acreage?

Not really.

We have been participating with Anadarko in their wells since late in the year.

Don't have a lot of production results on those yet.

I think in a general sense, you're right, they are going to have very high condensate yields than wells to the northwest are going to be very high condensate, the wells to the northeast are going to be more similar, we think, to our Briscoe wells.

And we under- -- you know, we are pretty confident in the productive capacity of that.

So we think again it's a huge -- if you look at Anadarko's acreage spread it's a huge spread of acreage and it spreads across very big distance east to west and I think there's going to be a lot of variability.

What we are seeing so far is very encouraging.

But we -- it's very, very early in our participation in their well so we don't have any comments on EURs at this point.

Any comment on costs there?

Yes.

I think Anadarko has done a great job.

I compliment them.

They have come a long way in their drilling.

I think on drilling days they are very close to us.

It's a little shallower than we are so ideally their drilling costs should be lower.

Completions I think is an area that we are all -- we are collaborating with Anadarko on how to do the completions and trying to make sure we absolutely put the best completion in the ground we can.

I think the biggest challenge Anadarko has is really infrastructure which I know they are working very hard.

That area up there is huge.

There's really no power out there.

The pipelines that are out there are largely all low pressure wet lines so there's some significant infrastructure commitments that are going to be needed to make that thing work Anadarko appears to be well on top of that and I'll let them comment on the development.

Okay.

And then on the retrograde condensate comment made earlier, I think Jay mentioned it will take two years for that to come to bear.

Wouldn't you guys expect to see something earlier than that if it in fact did come to bear?

You know, I said two years.

What I really meant by that is it takes even in a normal play it would take a couple years for you to really understand what that decline curve looks like and frankly we are just not sure what -- when or how that retrograde issue will start to appear, if it does.

I was talking to the head of Netherland and Sewell the other day and he and I had the same feelings about it.

We are not sure exactly how that's going to play out.

We both I think have the sense that it may not be an issue but at some point you could start to see some of that issue.

You know, right now in most of these wells we are not below -- in most of the reservoir we are not blow the dew point pressure.

We probably are near the well bore so, you know, you're argument that, well, maybe you'd see some of that earlier, that may be true but you're dealing with a massively fractured stimulated reservoir here that doesn't -- may not perform at all like your typical retrograde condensate sandstone reservoir so it's not clear to us what will happen.

What I think you would see if you start to see some of this impact is you'll see degradation in your flowing performance over time that will tend to look a lot like you won't get as high as hyperbolic D factor as we might project.

So what we are going to be looking at, and we look at it all the time, is okay how are these wells laying on our type curve, what's the type curve shape look like, and the more and more information we can gain on that, the better off we are going to be.

Back stopped by the fact that these wells pay out pretty fast so, you know, you're comfortable going at a pretty aggressive pace here because you can get to payout.

Ultimately, you know, it may be three, four years before you really know the shape of these type curves.

Thanks a lot for the extra color on that.

And then just one quick last question on the Bakken.

You guys mentioned an increase of roughly 17,000 net acres from 2008 year-end so that brings you up to 70 net.

Does any of that include acreage from your Bar Trend?

No.

In fact, we took out -- you know, we have a lot more acres than that in the Williston.

I think we are at 197,000 acres.

We have a lot of it but we didn't refer to that because people can get confused and they think the Bar Trend acreage is not respective for this new North Dakota kind of Bakken wells we are doing.

We have already drilled it up, we're looking at recompletions, re-frac type things.

so we kind of separated out this 70,000 just to say, hey, that's what we want you to think about in terms of perspective new Bakken.

long lateral, three fourths Bakken wells.

Got it.

And do you think any of the -- sort of the Bar Trend on the North Dakota side will be perspective for Three Forks?

I think (inaudible) is playing around with the concept on there.

Yes, there may be some potential in there.

We are -- we will watch what other people do, I think.

We have farmed out a little bit of that acreage in not the too recent past and, you know, I think when you rank our acreage, it's probably not on the top of our list.

I guess I'll put it that way.

Okay.

We have got a good situation, though, because most of that acreage is HBP.

So we have the the luxury of being able to watch a lot of the offset operators do their testing there while we are busy in North Dakota and then certainly if there's some learnings there that we can apply, we can come back into more of our legacy acreage position.

Thanks for your time this morning, guys.

You bet.

Thank you.

Thank you.

Your next question comes from Joe Magner with Macquarie Capital.

Good morning, just one quick question.

Looked like there was a reduction in the number of prospective acres in your Haynesville play.

Was that due to any sort of performance revisions or lease expirations?

Shed a little more light if you can.

Yes, Joe, we have typically been talking about around 50,000 net acres, 10,000 kind of in the Louisiana side, 40,000 or so on the Texas side.

I think our area of focus and what you may be referring to is more the 30-acre -- 30,000-acre kind of position we have in Shelby and San Augustine.

We have another -- you know, we still have the 50,000 net that we have always had.

I think some of that is in areas that we, you know, right now we don't rank as having high potential.

We still have the same acreage position but we would probably say that, you know, some of that stuff is out farther to the west and then some of the Panola and Harrison County acreage which a lot of people are drilling it, we just right now we are really focused on this 31,000-acre block that we have.

Okay.

So you're sort of high grading based on what you want to focus on?

Right.

Okay.

That's all I have.

Thank you.

Thanks, Joe.

Thank you.

Your next question comes from Andrew Coleman with UBS.

All the acreage you have in a variety of different plays there, where would you spend the incremental dollar?

I assume it's Eagle Ford first but could you rank the next plays after that?

Yes, I think obviously the focus right now is on the Eagle Ford.

I think the additional capital going forward is going to depend on some of our current testing in some of the other plays.

You know, but we are very well positioned in the Granite Wash.

We are encouraged by what we have seen so far in the Marcellus so, obviously, more running room there.

The Bakken area is another area that continues to be very encouraging with some of our recent tests so I mean, the good news is we have got a number of opportunities to deploy additional capital with success in our testing program.

And as you look at, I guess, building up the positions in the various areas, I mean, is there some magic number that you guys shoot for in terms of acreage size or just kind of whatever comes at the right price?

I think first of all it depends on the economics of the emerging plays and the acreage costs that we are seeing but clearly our strategy going forward is to find opportunities after a lot of technical work to enter some of these new plays, but then to do so in a more compelling way, which means, you know, you want to have an acreage position that can provide you the scope and scale going forward to continue the growth for St.

Mary.

So there's not a magic number.

It depends on the acreage costs, what we see as the economics in the play and then our ability to have the scope and scale to ramp up and provide the growth.

Okay.

I would say -- let me just add, I think over time, you core up as a consequence -- just naturally as you tend to focus on things that are working, so, you know, you get more and more cored up.

As Tony mentioned, I think the other thing we are careful of is we don't want to start paying PUD values for acreage where we don't have a good sense of what the ultimate reserves of these wells really might be because that's where the risk really comes in is when you start overpaying for acreage.

Okay.

Do you think as you go through the evaluation process that the 2010 would see more high grading and divestments of some of that -- those smaller positions or do you think 2010 is just going to be a whole lot of testing across a lot of different positions and see kind of where gas price and oil price ends the year before we decide what'll happen in 2011?

I think what you'll see is as we learn more about these plays, we complete our testing programs, remember, we have a higher percentage of our capital devoted to the exploration side of our business this year so we are going to use that to learn as much as we can and then make those decisions going forward in terms of do we core up, do we look at JVs, do we divest going forward.

But I think quite frankly we need to test those plays and understand the relative valuations.

But certainly all those options are open to us going forward.

As Wade mentioned earlier, we have got very, very strong balance sheet, a lot of dry powder so we have the ability to fund and pursue a lot of these plays.

With success.

The other comment I would throw in, people ask all the time about the small acreage positions and, you know, I'll take an example of the Marcellus where we have 40-some thousand acres in the Marcellus.

If you throw out some other company names that are 10 times our size, the EOGs of the world for example, if they had a 400,000-acre position in the Marcellus people would say that's a big position.

We are 10% of their size and we have 40,000 acres.

To me that is a big position and if it's -- if you pay for it right, it can make a lot of money.

So, you know, we hear that -- we hear this a lot about small positions.

Well, yeah, they are small relative to our much larger competitors but they are not small for St.

Mary and they are material and we can put a lot of locations at very economic locations on it if we pay for it right.

So I just thought I would throw that in.

No.

I think that's definitely a fair comparison to make.

The last question I had then was, you know, I'm guessing part of the reason that it looks like PDP bookings were kind of low this year was a reflection of that ramping that started, you know, as you tested those areas in 2009..

And that as you think about maintenance CapEx going forward, is it fair to assume that as the plays gain half and more wells that you'll -- that the reserve confidence around those offsets and, you know, PDPs coming up more substantiated, we could see lower maintenance CapEx going forward and higher bookings?

Yes, I think that's very -- a very accurate depiction of how we see this going forward.

Great.

Thank you.

Thanks.

Thank you.

Your next question comes from David Tameron with Wells Fargo.

Couple of questions.

Tony, just as a follow-up, you mentioned a joint venture, you know, potential for joint ventures.

What is your preference?

Obviously you have more opportunities in CapEx today.

And then second part of that question would be, with the revolver available, at what point do you go and tap that to accelerate some of these plays?

What do you have to see in the back half of the year or, you know, kind of what conditions before you would raise CapEx?

Yes, David, our preference is obviously and you've seen us doing this over the last couple of years as part of our transformation.

And it is to acquire acreage and opportunities in these plays where we have a higher working interest and where we operate, and we've clearly been moving in that direction.

Relative to the plays, you know, with success in these plays, we have significant dry powder and capacity to go forward.

We are not opposed to looking with significant success in several of these plays to go into the market, if that's the right answer, and it allows us to continue the testing and development for these large plays.

We will consider joint ventures.

You know, if we get in a position where some of these plays dramatically ramp up, which we are hopeful of, certainly we are not opposed at all to taking partners where that makes sense, or if we want to layoff some risk in some of the plays that maybe have higher exposure for St.

Mary.

So, I mean, what -- I really like the position we are in because now we have sizable positions in a half dozen or so or more key plays and with success so a lot of financial options in front of us to fund those.

Wade, any -- okay.

No thanks.

That's some color there.

Jay, going back to the Niobrara, can you talk about what kind of kick started the play?

Was it just the EOG well?

Is it just taking the same concept you used on the gas side where you're applying (inaudible) people are doing the same thing with the Bakken?

Could you just talk about the evolution of that play?

Well, sure.

You know, I think everybody really I think what kicks off all these oil-side type long lateral fracture place is really the Bakken experience.

People looking for rocks that could have that kind of potential across all the United States and I think some of the larger players are -- you know, they are drilling wells in a lot of places around the United States looking for opportunities to make oil-side resource plays similar to the Bakken and I think that's really what drives this.

Niobrara has been a target of interest in the powder river basin not only in the southeast corner of their basin but farther north, Chesapeake and EOG and some of the guys have drilled wells and without a lot of information released in the deeper portions of the basin farther north.

So the Niobrara is being kicked around for quite some time.

Obviously the guys in the DJ who played the Niobrara for years, 20 years ago people were talking about Niobrara completions but at that point in time they were all vertical and I don't really know that they did very well.

It's been around a long time as a potential oil target.

I think everybody has woken up to the idea that some of these oil site targets can work on long laterals, you know, but they need to be drilled and tested.

These wells are -- it's -- they all have their own little challenges associated with them and I'm sure the Niobrara is not going to work everywhere either and so there's a lot of acreage being bought.

I mean Noble and EOG obviously have amassed peek positions from what I've been told.

But that's really what kicked it off I think is really the whole Bakken -- and then, of course, oil price moving the way it's moved relative to gas has just made it more and more important for the bigger companies to get into the oil side and so they are spending more and more money there.

I think that's really the driver.

Is there any reason the same technology wouldn't be applied to like the Permian, similar acres down there?

Obviously the Wolfberry is working, but other horizontal --

I think what you're going to see that Niobrara is all going to be horizontal development.

It's going to look an awful lot like the Bakken in terms of the completions or at least the lateral links.

I think there's a lot to be learned on how you actually do pump the completions, what the cocktail is for making that work, but I think what you'll see is it's going to be long lateral multi-stage frac-type completions similar to what you're seeing in the Bakken.

All right.

And then one final question I'll throw out there and I don't know who wants to answer it or how you want to answer it, but there's a lot of struggle on this side, or on Wall Street side, about everybody's trying to -- looking at PDPs versus PUDs and reserve bookings, and everyone is over-analyzing everything.

How -- the board comes to you, Tony and says, what are we worth today?

How do you guys look at your portfolio?

How do you put numbers or figures -- you know, detail analysis behind the numbers?

I think first thing is to be sure that we do a complete and thorough evaluation when we review our current asset slate relative to reserves and, you know, that that is very typical St.

Mary.

As you know, we are going to focus on the technical aspects and do our technical homework, especially relative to reserves.

A lot of noise right now just relative to the SEC changes that we have seen.

But we have worked through that.

I think we have made the appropriate calls.

You'll see the same thing going forward with our new plays and as Jay mentioned earlier, a lot of these plays are still, you know, in the early stages.

So I think you're going to see us be very deliberate, very methodical in terms of our technical work, to be sure that we fully understand these plays before we, you know, get strong in terms of booking additional reserves.

One of the slides that was provided in the presentation this morning shows the potential upside, for example, in the Eagle Ford.

So, I mean, with success in these plays, we've got an awful lot of running room and capacity to add reserves when we get comfortable and we are more confident and we have enough wells and production under our belt to better understand that.

So I think you'll see us take an approach where, you know, let's book the reserves that we see based on the information we have at hand at the time and then lever that up based on additional learnings in each of these plays.

Now, Dave, one of the financial highlights in the press release, if you look at the numbers there, 98% of that $1.3 billion PV10 that we laid out is proved developed.

98% of the value of that company at that level is proved developed.

That's a pretty extraordinary number.

It implies only 2% of our company is in our PUD bookings right now.

Now, I think anybody who is listening to this call or followed us over the last year recognizes that there's a lot more upside in the company than 2% of $1.3 billion.

And when we look at the value of the company internally, we certainly recognize there's a lot more value there than that.

However, I think, you know, when you buy St.

Mary, you're buying a very high PD percentage at this point based on the valuations we have given.

So I think there is a lot of upside.

We certainly look at it and value it when we do our internal evaluations.

But from an external perspective, you're getting a lot of PD in value for us.

With a lot of potential upside.

To me that's where the excitement is, Dave, is you know, seeing the upward trajectory with our plays and the advancements we have made with our exploration efforts thus far.

Great.

Thanks.

That was -- yes, Jay, you hit on part of my question which was that very low PDP percentage, or very low PUD percentage in your, in your PV10 value, so --

You know, a lot that is just driven, as Tony said earlier, a lot of the plays we're in are, funny thing, they all come along at the same time or in the same kind stage.

At the end of the year we just weren't at the point to say in the Eagle Ford where you could book a lot of upside.

Because we just didn't have the data.

Now, as you go into 2010 and we drill a whole bunch more wells, things change fast and I think when you get into the end of the year it's a much different story.

So it's somewhat a unique time for us and we are sort of at that same place in the Haynesville and sort of at that same place in the Marcellus and that's how it's all stacked out for us.

That's been very deliberate, part of our strategy and part of our transformation, Dave.

Yeah, all right.

Very good.

Thanks.

All right.

Appreciate it.

Thank you.

Your final question comes from Michael Jacobs with Tudor Pickering Holt.

Good morning.

Point of clarification on the Bakken.

Was that 10 to 14 stages per horizontal or in aggregate?

That's per horizontal.

We basically pump, I think -- I don't remember the exact number, I apologize, but I think it was in that 10 to 14 range.

And then what we did is we pumped, we pumped -- we had two frac spreads on location and we were literally pumping the same stage in each of those two wells at the same time as we went back.

So simul-fracking the two wells.

And the key thing is, is that frac barrier between the two -- between the Bakken and the Three Forks, is it really a barrier?

Or are the wells going to communicate?

Could you get to the same reserves over time by just doing a really big Three Forks frac?

And that's what we are trying to understand.

If they were truly unique reservoirs and you didn't get Bakken reserves out of the Three Forks when you fracked it, then potentially you would have twice as many wells you can drill and get unique reserves.

If not, then you probably should just drill the Three Forks well, put as big a frac on it as you can and try to get the Bakken reserves that way.

And how far were the well bores offset laterally?

Essentially right on top of each other.

Any thoughts on the prospectivity of the Three Forks as you moved further west away from the Nessen?

I haven't looked at that much.

I don't think I'll comment on that.

I don't want to make a misstatement.

It's out there.

I'm not sure -- I'm not sure.

I guess I'll just leave it at that.

Okay.

And just a follow-up, I believe, Ellen asked a question on the Wolfberry.

Can you tell us what B factor you were originally using across your acreage and what you're assuming now?

You know, I don't recall the numbers, so I think I'll just leave that one.

It was too high.

I can tell you that.

You might follow up with Brent later or if you wanted more commentary on that but --

Okay.

Great.

Thank you.

All right.

Thanks a lot.

Thank you.

And at this time there are no further questions.

Are there any closing remarks?

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

Mary.

We will talk to you again next quarter.

Thanks a lot.

Ladies and gentlemen, thank you for joining today's St.

Mary fourth quarter and full-year 2009 earnings conference call.

Thank you for your participation.

You may now disconnect.