SM Energy Co (SM) 2008 Q4 法說會逐字稿

Good morning, my name is Cynthia, and I'll be your conference operator today.

At this time I'll like to welcome everybody to the St.

Mary Land & Exploration Company's fourth quarter and full year 2008 earnings conference call.

(Operator Instructions) I'd like to turn the call over to Brent Collins, Director of Investor Relations.

Please go ahead, sir.

Thank you Cynthia and good morning to all of you joining us by phone and on-line for St.

Mary Land & Exploration Company's fourth quarter and full year 2008 earnings conference call.

Before we had we start 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 results expressed or implied in our staples in our forward looking statements.

For discussion of these risks, you should refer to information about forward looking statements in our press release from yesterday and the risk factor section from our 2008 form 10-K which we expect to file later today.

We'll also discuss certain non-GAAP financial measures that we believe that are useful in evaluating our performance, reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

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

Probable reserves 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 uncertain to estimates to crude reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

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

We may also discuss proved reserved volumes calculated under different pricing assumptions that is currently allowed in filings with the SEC 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 VP and Chief Financial Officer, and Brent Collins, Director of Investor of Relations.

I'll now turn the call over to Tony.

Good morning, everyone, and thank you for joining us this morning for our fourth quarter 2008 earnings conference call.

Before turning the call over to Wade and Jay for their respective financial and operational reviews, I have a few opening remarks.

2008 was an interesting year to say the least.

As an industry, we saw commodity prices rocket to an all time high and then quickly retrench as a result of the broader financial crisis.

As a result of the weak commodity prices at year end, many E&P companies saw meaningfull negative price revisions to their proved reserves which in many cases resulted in impairments or write-down of assets.

St.

Mary was not immune to these industry developments and our reported financial results reflect that for last year.

Proved reserves for year end 2008 decreased to 865.5 BCF equivalent from 186.5 billion BCFE excuse me, that would be 1.086.5 trillion BCFE in 2007.

The decrease was largely the result of negative price and performance revisions that Jay will cover in more detail in his review.

From a production standpoint, St.

Mary had a strong year.

We had record production of in 2008 of 114.6 BCF equivalent which is a 7% increase from last year.

When adjusted for divestitures of noncore properties we grew 13% year-over-year.

We also had record quarterly production in the fourth of 2008 of 30 BCF equivalent or 326 million cubic feet equivalent per day.

St.

Mary is a stronger Company today than it was a year ago.

First we continued to execute on our strategy of transforming St.

Mary into a resource play leveraged Company through the 2008.

Results of St.

Mary's development of Woodford Shale and Wolfberry title assets improved nicely during 2008.

We also now have exposure to several emerging resource plays.

The Haynesville Shale, the Eagle Ford Shale and the Marcellus Shale that we did not have exposure to at the beginning of 2008.

While we were fortunate to own acreage with Haynesville rights, our entry into the Eagle Ford and Marcellus are a result of delivery efforts to enter emerging resource plays at an earlier stage of their lifecycle.

Importantly, we have put in place the strategies and the mindset that led to our exposure in these plays and will provide exposure to emerging plays in the future.

Next we continue to optimize our portfolio of assets.

You'll recall that we sold a large divestiture package in January of 2008, the largest in Company's history.

Throughout 2008 we rationalized our portfolio further as we sold out of assets in the Greater Green River Basin and the Judge Digby Field in Louisiana.

Lastly the capital market environment is clearly much different today than it was a year ago.

The ability to access this market has become harder and the cost of accessing it has increased significantly.

Our prudent use of leverage in a solid reserve base have helped St.

Mary maintain a very strong balance sheet which has become paramount in the current environment.

With that, I'll turn the call over to Wade for our financial review.

Thanks, Tony.

Good morning.

Yesterday we released our quarterly earnings press release and financial highlights which present our fourth quarter and full-year results.

I know it's a busy time for many of you on the call, so I'm going to focus my comments on key aspects on the fourth quarter.

We reported a net loss for the quarter of $126 million or negative $2.01 per diluted share.

Consistent with others in the industry, we had significant non-cash impairments in the fourth quarter that were triggered by the lower oil and gas prices in effect at the end of the year..

Adjusted net income for the quarter was $27.1 million or $0.43 per diluted share.

In last night's release we provided a reconciliation of the adjusting items.

Non-cash impairments were the largest non-reconciling items this year.

Discretionary cash flow for the quarter was $163.3 million was $2.61 per diluted share.

Production for the fourth quarter was 30 BCF equivalent which was above our guidance of 28 BCF to 29 BCF equivalent .

And was a quarter record for the Company.

Stong performance in the mid-continent was the principal cause for the out performance.

Consistent with what you were hearing from other E&P's, wide differentials had an impact for our revenues.

Since the beginning of 2007, our average pre-hedge realization for oil has been 94% of NYMEX, In the fourth quarter of 2008, it was only 85%.

And it's a similar story for gas.

Since we reported our gas, wet gas convention and we have a reasonably rich gas stream, we have historically realized a price very close to NYMEX gas.

From the beginning of 2007 our average pre-hedge realization for natural gas has been 99% of NYMEX.

Clearly higher prices for NGL's of much of that period helped our gas realizations but in the fourth quarter we realized 78% of NYMEX for our non-hedged gas.

As a result of the wider differ differentials and much lower pricing for NGL's.

With respect to cost that we provide guidance on, I'm not going to spend much time reviewing those.

We came in slightly below guidance for LOE and transportation and there's nothing really significant to comment on there.

Production taxes came in below guidance as a result of lower commodity prices.

G&A was well below our guidance and down from our quarterly run rate.

Compensation related items were the major drivers of this.

The amount of crude for NPV payments was reduced as a result of lower forecasted commodity prices and cash flows.

Additionally, some targets in our incentive compensation system that we had been accruing throughout the year were not met in 2008 and, as a result, we had to true up the full year in the fourth quarter.

DD&A came in much higher than we had guided.

This is a function in the decrease our proved preserve base at the end of 2008.

DD&A is calculated below the cost impairments are calculated.

So this rate should be lower in 2009 as detailed in our guidance.

In the quarter, we recognized a $292 million pretax impairment on proved reserves.

$154 million was related to almost properties in south Texas and Jay will discuss this in further detail in a moment.

We also had impairments related to the Hanging Woman Basin coalbed methane project, $62 million, properties in the Gulf of Mexico, $37 million and properties in the Powder River Basin, $34 million.

And there was also a $34.8 million pretax impairment for abandonment and impairment of improved properties.

Largest portions of this related to prob and poss value for almost properties in south Texas.

And we also impaired acreage value associated with land and [Ford Shale].

Impairment of goodwill before taxes was $9.5 million in the quarter and relates to the Agate acquisition from 2005.

I would note that this goodwill impairment and it's non-deducibility is also why our effective tax rate benefit came in slightly lower than we had guided.

We recognized a pretax benefit of $80.9 million related to the decrease in the NPP liability during the fourth quarter that is a result of lowered forecast commodity prices.

I'll now spend a couple of moments on the balance sheet.

As of December 31st 2008, we had $300 million drawn on a revolving credit facility and $287.5 million at 3.5% senior convertible notes outstanding.

Our reported debt to book cap was 34% and even after adjusting for the unrealized hedge gains in OCI, our debt to book cap is 36%.

We have $321 million drawn on the revolving credit facility as of yesterday.

The borrowing base on the revolving credit facility was last redetermined in October of 2008 in the amount of $1.4 billion.

We currently have a commitment from the bank group of $500 million.

The credit facility expires in April of 2010.

So we've began talking to the banks both in the group and outside the existing bank group about getting a new facility in place.

And we expect to get that done during the first half of 2009.

On the senior convertible notes, as a result of adopting a new accounting pronouncement, beginning in 2009 it will be required to separately account for the liability and equity components of the convertible notes because they can be settled in cash.

We will record a debt discounts and then we'll reduced the amount shown for the convertible notes on the balance sheet which will amortize over time.

As a result, we will recognize an additional $2.1 million of non-cash interest each quarter related to this amortization.

Which may require some of you to adjust how your models treat interest expense at calculating discretionary cash flow.

As of year end we had a net $105.3 million net hedge asset and that net asset is meaningfully higher as of today.

So clearly, our balance sheet is in good shape which we think will be an important and distinguishing characteristic in 2009.

And before I hand it to Jay, I want to point it out to anyone that if you want more details, our 10-K will be filed later today with the SEC.

So with that, I'll turn it to Jay with an operational

Thank you Wade.

I'm going to spend a few minutes discussing our year-end proved reserved report and then I'll provide an update on our operations and plans for 2009.

As reported on our operations press release from yesterday our proved reserves from 2008 came in at 865.5 BCFE which is down 20% from the 1,086.5 BCFE at year end 2007.

The reserves are comprised of 51.4 million barrels of oil and 557.4 BCF of natural gas and are 83% proved developed.

Over 80% of St.

Mary's crude reserves by value were either reviewed or prepared by outside reserved engineering firms.

Prices used to determine the prove reserves decreased significantly from 2007 to 2008.

Base SEC mandated pricing in effect at December 31st, 2008 was $5.71 per million BTU of gas and $44.60 per barrel of oil which were down 16% and 54% respectively from the $6.80 and $95.98 used on December 31st, 2007.

In addition to the drop in base commodity prices used for the calculation of 2008's reserves, the Company was significantly impacted by larger differentials for oil and natural gas liquids on this measurement date.

Proved reserves were adversely impacted by negative pricing and performance provisions at year end.

St.

Mary's negative price revision for the year was 199.7 BCFE, of which 74% related to proved developed reserves.

In other words, a lot of these reserves are still producing and providing cash flow and what is being cut off is the tail of the decline curve.

Two-thirds of the 199.7 BCFE and negative price revisions were from oil weighted properties in the Rockies which bore the brunt of the reserve impact caused by a lower year end oil price and a significantly wider price differential.

Lower year end prices for natural gas liquids also led to a meaningful negative price revision for prove reserves in South Texas.

On the subject of South Texas, we did have a meaningful negative performance revision primarily related to the almost shallow gas properties in South Texas that we acquired in 2007.

The almost reservoir has proved to be more complex than we originally thought and we've seen lower reserve outcomes than we expected in attempting to in-fill the field.

As a result, our expected drilling and completion programs for those properties will be significantly reduced versus our plan at the time of acquisition.

Combined with lower gas and significantly lower NGL pricing at year end the future gas cash flows from this project couldn't support its cost base and resulted in the almost related impairments Wade referred to earlier.

We're obviously disappointed by these results and have learned several things that we will take with us going forwards.

One silver lining coming from the almost program is it has provided an initial position in the Maverick Basin that we've built upon to gain meaningful exposure to the emerging Eagle Ford and [Pureshawl Shale] Place.

In last night's press release, we provided a table what our year-end 2008 proved reserves would have been in a couple different pricing scenarios.

The vast majority of any reserves we recapture will come from improving commodity prices will come from PDP reserves.

In environment where capital is scarce, it is important to note that we don't have to invest any additional capital to rebook these reserves.

The critical take away from the tables is that at year-end 2008 SEC pricing and decrements had been the same as year end 2007 we would have ended the year as the same reserve level as when we entered it.

Even accounting for our divestitures and for performance related provisions.

Given the large impact of pricing on reserves calculations this year, we're seeing a wide variety of methods for presenting finding and development costs and reserve replacement ratios across the industry.

In our press release financial highlight from yesterday, we provide a number of different ways to calculate F&D and reserve placement.

From an operational stand-point, the one I find most important is drilling excluding performance and price revisions.

By this metric our Companywide F&D from drilling was $3.99 per MCFE from last year, which is an improvement from the last two years.

In the Mid-Continent region which operates our horizontal Woodford Shale program, we had a very good year.

And our F&D was $1.76 per MCFE.

The F&D in the Permian Region which focused on the Wolfberry title oil program was slightly below $3.83 per MCFE While that sounds a little high on a MCFE basis, when you consider that is $22.98 per BOE of oil and that the average price of oil last year was $102, you realize why the economics of those projects made sense.

Clearly results from the disappointing almost program I talked about earlier drill of our Company drilling our F&D up.

Our reserve replacement from drilling excluding performance and price revisions for 2008 was 148%.

And again was an improvement from the prior two years of 123% in 2007 and 125% in 2006.

As you've heard us say before we've actively been transitioning the Company over the last couple years to be able to grow more organically and based on these improved numbers we are making progress.

I'll now spend a few minutes on our operating activities.

We're clearly in the mode of laying down rigs.

By the end of February 2009, St.

Mary plans to have seven operated drilling rigs running.

This is a decrease from a peak of 16 rigs reached in mid 2008.

With a severe pullback in price we think that the rational decision now is to defer development drilling until commodity prices improve and/or well costs decrease.

Unless you have leases or rig commitments you should defer.

St.

Mary fortunately doesn't have a large amount of leasehold at risk for expiring in the new term and most of our rig contracts have expired or will expire in 2009.

The press release from yesterday detail where we plan to run our operated rigs this year.

Our focus is to test the potential of our emerging resource plays.

We currently have allocated $80 million for testing in the Haynesville, Eagle Ford and Marcellus Shale programs.

In the Haynesville we're currently waiting on completion of our first operated well which is located in DeSoto, Parish, Louisiana.

We were delayed slightly on the completion when we changed profit and now expect to complete the well, the first week in March.

For the remainder of 2009 we plan to drill three more horizontal wells there.

The next planned well will be in Shelby County, Texas where we have a significant portion of our acreage position.

St.

Mary has 50,000 net acres perspective for the Haynesville.

In the Eagle Ford Shale program in South Texas we plan to continue in Phase II of our joint venture with TXCO and Anadarko.

We expect four horizontal tests will be drilled in 2009 in that JV area.

Additionally we plan to drill four horizontal wells outside of the JV to further test the potentially of our acreage.

We expect to drill the first operated well here in the second quarter.

As many of you are aware, Petrohawk has announced two very good Eagle Ford wells just to the east of us.

So we are excited to test our acreage this year.

We have the potential to earn up to 210,000 net acres, with Eagle Ford potential.

In the Marcellus Shale, we plan to drill two operated horizontal wells in 2009.

Our plan is to drill the first well in the third quarter.

In this play we had the potential to earn up to 43,000 net acres.

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

Thanks, Jay.

Last night, we also announced the pending retirement of our Chairman of the Board of Directors, Mark Hellerstein.

He stepped down as CEO two years ago and continued serving as our Chairman.

Mark has decided not to stand for reelection in our May stockholders meeting and will step off the Board at that time.

The Board thanks Mark for his many years of distinguished leadership, dedication and service to St.

Mary.

During his tenure as CEO and Chairman of the Board, the Company has delivered consistent performance and returns for its stockholders, year after year with a culture and foundation of excellence and values on which the Company can continue to build.

It is a legacy of which Mark can be very proud.

And we wish him all the best in the future.

I mentioned in my opening remarks that St.

Mary is a stronger Company today than was at the end of 2007.

And I have every expectation that it will be a stronger company at the end of 2009.

We have a strong balance sheet that we can use to weather this difficult period along with the ability to capture select opportunities that may present themselves.

Our plan is to invest within cash flow this year, so that we can maintain our financial strength.

With limited long-term commitments for rigs and no meaningful lease expirations on the horizon in the near term, we have the ability to be very flexible.

We can accelerate our activity should industry conditions improve, or we can slow down quickly should circumstances warrant.

While we certain think that 2009 will be a challenging year, our exposure to several emerging resource plays has the potential to provide meaningful growth and value for our stockholders and to significantly expand our drilling inventory to position us for long term success.

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

(Operator Instructions)Your first question comes from the line of Steven Beck with Jefferies & Company.

Good morning.

Good morning, Steven.

First thing, I want to touch on the Marcellus.

Have you identified where you're going to drill those wells?

Yes, the first two wells will be in McKean County.

Okay.

Are they -- I assume they're probably going to be verticles or have you decided that?

We'll probably drill pilot holes and go horizontal, both of them.

In the Haynesville, you mentioned that you are going to drill three horizontals, first one in Shelby County.

to drill three horizontals, first one in Shelby county.

Have you decided whether you're going to focus on East Texas with the remaining two or is that going to back over on the Louisiana side?

Yes, the rest of the wells we'll drill this year will be in East Texas.

We have to test our acreage there and we have some expiring acreage.

Steven, that's where our largest acreage is as well.

We've got 10,000 on the Louisiana side.

Right, I remember that.

Okay.

Well, that's it for me for now.

Thank you.

Thanks.

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

Good morning, guys.

Good morning.

I have a question on South Texas.

You talked about the Petro Hawk wells.

You guys also have some non-operated wells in there.

Can you say anything about those at this point?

Well, they're apartmented by TXCO in a partnership with Anadarko.

At this point we haven't released a lot of data about them.

TXCO is the operator and we'll let them talk about them at the point where the partnership can agree to release data.

All I can really say at this point is that the results are fairly encouraging.

Okay, good.

Then then on the seven wells that you plan to retain I guess by the end of February, can you give us any kind of breakout on where those are going to be.

Seven rigs.

Seven rigs, I'm sorry.

Seven rigs, yes.

We'll pretty much have a full year rig in East Texas drilling Haynesville wells.

We'll have a rig probably half a rig a year, one in South Texas drilling Eagle Ford and the Marcellus, so that's another rig.

We've got a rig up in the Rockies up in the Bauken that's under contract until the end of the year.

We have a couple rigs in Oklahoma, one in the Woodford that's under contract for most of the year and another one in Central Oklahoma drilling deep springer wells.

And then we have a rig, part year in the Permian .

So that pretty much adds up I think to the seven.

And we have some partial years in various places that make that add

Got it.

Okay, and then you said you're going to have a rig in the Bachen.

Is that going to be drilled in three forks?

And where is that going to be?

Is that going to be on the Bear Den acreage or whereabouts?.

We just finished a well in Bear Den and drilling another one and we have other wells plan.

We'll see how the year goes up there.

I think if we had -- depending on how things go, we may try to take it to some other -- do some other things or kind of cut our exposure some.

Okay.

I'll get back in the queue, thanks.

Thanks, Mike.

(Operator Instructions) Your next question comes from the line of John Healey from Forest Investment Management.

Hi, good morning.

Good morning, John.

You said you were negotiating with banks about a new revolver.

Have you thought about what kind of borrowing base?

I know it's kind of hard to project but your current is $1.4 billion and you were using a line of $500.

Can you disclose what you're looking to structure there?

Yes, I probably can't say to much.

I will say that yes, you said the borrowing base was $1.4 billion.

Clearly with the reserves and the prices being lowered, we're pretty comfortable it's going to be above the $500 million commitment that's there now.

So we're getting into the early days of starting that process.

We may try to increase the commitment.

We'll see how the bank appetite is and what the terms look like.

Got you..

And then -- thank you.

And then just another credit question.

On your statement of cash flows, you had a cash use of $47 million attributed to accounts payable and accrued expenses.

Couple tell how that was related -- I mean, why would that larger than normal cash use in the quarter?

Yes, that working capital tends to swing around quarter-to-quarter and we had -- I think -- I can't remember exactly what it was but we -- we had a big -- I don't know.

We just tended to pay a lot of our bills closer to the end of the quarter and they've built up closer to 9-30 is the --

Right.

I just have one more and I'll get back in the queue.

Has your hedging changed much from your -- what was it your presentation last month?

No.

I will tell you, the answer is no.

The positions that you saw on the last slide are the ones that we still have in place.

And if you look at our PDP profile looking forward on an equivalent basis we have about 56% hedged in 2009 and then 45% hedged in 2010 and we actually have 36% of our PDP's right now hedged in 2011.

Got you., thank you very much.

Thank you.

Thank you, John.

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

I got back in the queue quicker than I thought.

Can you elaborate a little bit on the Haynesville.

You said you been waiting on profit.

And I guess you're going to go with resin coated sand rather that ceramics.

And some people seem to be sold on one or the other.

Can you give us your thoughts on that?

Well, yes Originally our plan going forward and we had allocated and had some store with some 2040 bauxite.

And after talking to all the other guys in the neighborhood and talking to all the other coners and looking with other people were doing, the information we have is there were a number of people pumping the larger bauxite that were screening out some of their fraks.

So we talked at length to our coners and other people in service companies.

And we went to a smaller prop and it's a 4070 premium resin coated sand.

Still has a fairly high, an intermediate strength [inaudible], it has a thousand pounds crush I think.

Aand that's what most everybody out there is using now because apparently there's been some screen outs on the larger material.

We changed prop and when we did that we missed our frak date which was supposed to be early February and ended up taking a month delay.

I guess our view of that was better to be right than quick especially in this environment.

So we'll be pumping, we're actually setting up.

I have some pictures actually of our setup.

We'll be pumping here should be March 9th.

We have first frak day.

OK.

And then on the Wolfberry, any update on 40-acre spacing there.

It looks like you may have booked some 40-acre wells; is that correct, in that play?

Yes, the 40 acres particularly in the southern part have done very very well.

Look a lot like the parent wells.

The economics are pretty good.

As this point in our approach in Wolfberry ,is that we think the costs are coming down in Permian.

And where again, it's our view that it's the right thing to do right now is to defer and wait for lower costs.

And so we're planning to -- we have one rig right there right now, and we'll probably lay that rig down here after its commitment is up and come back to that when we think costs are kind of bottomed.

But in terms of reserves I think we had a very good year and the forties looked good to us.

The Marcellus, you mentioned the two wells you planned there.

What kind of commitments do you have and what do you need to do to satisfy the terms to earn the 43,000 net acre?

In fact, we don't have to do anything till next year.

We could defer all our spending into 2010 if we want to or need to.

We'd like to get a couple drilled this year in order to be able to understand our position better and be able to make good decisions about potentially expanding our position.

But I think our total commitment is about $15 million and none of it has to be spent.

It has to be done by the end of 2010 so we have some time.

Has there been much activity in either McKean or Potter county?

There's a number a number of wells that have been drilled out there.

It's a little off the beaten path from the Susquehanna area, or the Southwestern area of Pennsylvania.

There number of reasons for that.

We did quite a bit work before we entered there.

We feel petty comfortable that it's perspective.

It is an exploration play and there isn't a ton of production in that area.

There's not a lot of deepen interrogation in Pennsylvania in general but we feel pretty good about it.

And then I want to go back to one more on the Bach.

Have you seen any improvement in the price differentials in North Dakota.?

You bet and in fact I think from year end I think we are already down $5.

I think year end in Bauken was about $17, now we're down to about $12.

I think if you look forward Henbridge is talking about their expansions next year which should add a 40,000 or 50,000 barrels of capacity.

So I think over time our view is that the differentials are going to get better.

I think right now what's driving activity up there is low oil prices.

When you take $40 oil and stick $12 on it's just not a good economic situation.

And you're starting to see rig count really falling in North Dakota.

If oil prices do say,don't get much better than say, $45, what kind of cost reduction would you need to see or would there be enough cost reduction to entice you to want to drill more up there?

I think eventually there will be enough cost reduction to drill up there if oil sticks at these prices.

I haven't done a calculation of how low it's got to get.

To start drilling again at these differentials, we'd probably need to see $60 oil.

Okay.

And the Woodford, I think on the last call you talked about some down spacing there and you were going to do some simil fracks,.

Well we haven't pumped our simil fracks yet.

We're just getting all the wells drilled in one section to be able to do that.

So we don't have any results to talk about there yet.

And the well costs there still four to $4 million to $5.5 million but are you seeing any improvement there.

They're tending down below the fives now and the deeper part of the play.

We see fees from other people that are still high-fives but most of our staff is in the five range now.

We've been able to obtain additional discounts from several service providers in the Mid-Continent, Mike.

So we continue to see, , the costs trending down and certainly that trend will

Okay.

One last one.

I may have missed it in your release, but do you have a pretext PB 10 number?

Yes, Mike, it's 1.3 billion.

1.3 billion is the one that's based on--

Yes, PBT based on year end pricing.

And year end differentials.

You're don't happen to have any sensitivity on say a higher oil price?

We don't have that.

Appreciate your time, thanks very much.

Thanks, Mike.

Our next question comes from the line of Joe Magner from Tri Stone.

Good morning, Joe.

Good morning.

The production outlook for the year is down from the preliminary estimate you put out a couple months ago.

CapEx is down slightly from where it was at that point in time.

Can you just kind of address some of the changes?

I know you've talked about deferring development activity until costs come back in line.

I guess discuss the changes over the last couple months.

And then also some of the trade-offs that you're wearing as the 2009 quarterly progression, could be down by the order of 18%, 20% by the time we get to the fourth quarter.

Some of the trade-offs we know near term development activity, products, costs and your desire for your need to test some of these emerging plays.

Yes, We can address the difference in rate from the numbers in December was largely driven by the fact we sold or traded the Judge Digby asset at the end of the year which a couple BCF for the year.

There is a little less Woodford development in our current plan.

We shifted some of that money around toward exploration.

Just based on how we see the economics and the potential for lower costs in the Woodford toward the end of the year.

So that really explains the differences.

The CapEx is a little bit lower.

But it's really Digby, sell CapEx and a little bit of reallocation that gets us to the new production number.

What we're showing is the production -- we haven't guided production every quarter.

We've shown you a full year number.

Clearly we do expect production to decrease sequentially each quarter as a result of the fact that we're just not spending near as much money as we did last year.

But -- so you can expect to see the numbers go down every quarter.

Joe, having said that, obviously we are going to be doing exploration work in our key emerging plays and with success in those plays and depending on the financial markets at the time, certainly we have the opportunity to ramp-up, if the situation warrants it.

Okay, along it's lines of development costs or needing to see development costs coming back down in order to pick activity back up again.

You talked a little bit about the Bachen.

But what have you seen so far or what do you need to see in terms of cost or cost inflation to get more comfortable with the economic outlook of some of the various plays.

I don't know that we're looking at absolute costs that we're looking for.

It's really more of a function of what's the trajectory of costs and our view trajectory is sharply downward, sharply deflationary.

As long as you can continue to believe that the costs are going to go down by another 20% in six months then the answer is to defer.

And we've seen significant reductions in rig rates already.

We think we'll see significant reductions in other areas of service costs that is also important.

Rig rate is 20% but that's the first thing that happens, is rig rates start to fall.

It's not absolute levels of cost as to when do we think the costs have stopped dropping so fast because that is what really drives a deferral decision.

It sounds like some service companies or most service companies are willing to work with operators on some of the various aspects of their programs.

Is there -- have there been opportunities, have you seen opportunities or had opportunities to sit down with these guys and negotiate some of that stuff.

Or you're just waiting for costs to keep falling and then you'll revisit and have discussions later in the year and once that starts to stabilize?

Well, typically when you get into these cycles there's a game that's played we know the service companies and the oil companies.

The service companies want you to sign up long-term deals, and they'll cut the price a little and then ask you to sign up for a long term deal.

On the other side of the table, when prices are going up, they want you to sign short-term deals and pay more and more.

So you say negotiate, yeah, we negotiate all the time with these guys on every job or on longer term deals.

But everybody's waiting to see what happens with price.

If it starts to come back up, obviously more leverage shifts to the service companies.

We have been told repeatedly by the major service companies that they all want to hold on to their people, that they're all going to be aggressive in trying to earn work.

I think those are things we're counting on.

But until you let this thing shake out, you're not going to see the best pricing that you can get.

One of the things that we've done over the last year we created a position of a supply chain manager and that individual has been very successful in terms of aggregating the spend for St.

Mary and using that to leverage better pricing with our various service providers.

And he does that on a day in, day out basis whether it's pipe, pumping service, frak sands.

He's done an excellent job in terms of working that to our benefit.

Tony, you've indicated a desire since you've been there to expands the inventory of the Company kind of the two to three year length to out five years plus.

Realizing there are some shifts in 08, where do you think you are now and where do you think you could be coming out of 09 if some of these new emerging plays get off the ground and you start to see some success.

Yes This is the best I've felt, most confident I've felt since I've been here.

We really see the inventory beginning to grow dramatically and with success.

Could grow even more significantly for the Company.

You've seen us continued to optimize our portfolio with the sales and divestiture of some of our nonstrategic properties.

But as I take a look at the progress we made in 2008, especially with the Woodford, dramatic turnaround with that program, the EUR's have more than doubled.

The cost continues to be very competitive in that area.

Then we had very good success as Jay talked about earlier with our 40-acre testing in the Wolfberry.

Right there alone, those are two resource plays that have developed very well for us.

And as the market recovers, certainly we'd like to ramp those up.

But then what I really am excited about are the emerging resource plays that we've mentioned.

And that's why even in a difficult market, we are going to invest over $80 million in those three emerging plays in the Marcellus, the Haynesville and the Eagle Ford and we've got great running room in all three.

And a year ago, those three were not even on our radar screen.

And now with success in those plays, it has tremendous opportunity to strengthen and grow our inventory.

Okay, that's all I have.

Thank you.

Thanks, Joe.

Thanks, Joe.

At this time there are no further questions.

I'd like to turn the call back over to management for closing remarks.

Thanks again for joining us this morning and for your continued interest in St.

Mary.

We're excited to see what 2009 holds in store not only for our Company for but for the industry.

We certainly live in interesting times and I think St.

Mary is very well-positioned with a strong balance sheet and exposure to some exciting resource plays in front of us.

Thank you for joining us this morning.

And good-bye.

Ladies and gentlemen, this concludes today's conference call.

You may now disconnect.