SM Energy Co (SM) 2003 Q4 法說會逐字稿

Good morning.

My name is April and I will be your conference facilitator today.

At this time, I would like to welcome everyone to the St. Mary Land & Exploration year-end earnings conference call.

After the speakers' remarks, there will be a question-and-answer period.

Thank you.

Mr. Hanley, you may begin your conference.

Thank you, April, and good morning to all of you joining us by phone and online for St. Mary's year-end 2003 earnings conference call.

Except for historical information, statements made during this conference call including information regarding the business of the Company may be forward-looking statements.

These statements involve known and unknown risks which may cause the company's actual results to differ materially from forecasted results.

These risks include such factors as uncertainties in cash flow and reserves, oil and gas operating risks, volatility of oil and natural gas prices, the need to replace reserves depleted by production, competition and the potential impact of government regulations, litigation and environmental matters.

The company officers on the call this morning are Mark Hellerstein, Chairman, President and Chief Executive Officer;

Doug York, Executive Vice-President and Chief Operating Officer;

Dave Honeyfield, Vice President of Finance, and myself, Bob Hanley, Vice President of Investor Relations.

I'll now like to turn over to Mark.

Thank you. 2003 was almost the best of all worlds.

Our record earnings, high oil and gas prices, a 40% increase in the company's production, a 21% increase in improved reserves obtained at a low reserve replacement cost, moderate increases in operating cost, profitable sales of non-strategic assets, and the advancement of the Hanging Woman Basin coalbed methane project to the development stage.

Highlights include excellent drilling results at Huxley and East Texas, Northeast Mayfield in Oklahoma, and participating in the new [inaudible] might play in the Williston Basin.

Better than expected production performance at the Parkway water project in the Permian Basin and at Judge Digby in South Louisiana, as well as increased production from the acquisition of properties in the Rockies from Flying J in January of 2003 and Burlington Resources in December of 2002.

We opened a Houston office which will now be directing our Gulf Coast and Permian Basin regions.

Oil and gas reserves grew by 21% to 594 BCFE.

Included in the reserve calculation is a positive revision of 21 BCFE of which 14 related to positive well performance.

The company replaced 293% of its 2003 production at an all-inclusive finding cost of $1.05 per MCF equivalent.

Organic drill bit activity including visions replaced 146% of our production.

We sold 46 QCF equivalent at a pretax gain of $7.3 million.

Over the past two years and five years, we have replaced 298% and 268% respectively, of production, both periods at $1.09 per MCF equivalent.

We're pleased with these results.

Ryder Scott has been preparing the company's reserves for at least 80% of our property value since we went public in 1992.

You should know that reserve preparation is more rigorous than in automatic audited reserves.

We continue to report a very low PET percentage 11% at year-end.

St. Mary reacquired 3.38 million shares from Flying J $91 million on February 9, 2004.

In making our acquisition, we did not consider what what the original economics of our Flying J transaction were, but rather what would we be willing to pay for St. Mary stock from a net asset per share viewpoint similar to how we would view an acquisition of properties.

On all these counts, we view the transaction as being favorable.

I will discuss later how our stockholder value per share has grown over the past year.

You should note that because the transaction closed on February 9th, you must include this repurchase in the average weighted outstanding shares for the quarter in calculating first quarter earning per share.

Some of you have tried to link the decision to buy back shares with the valuing of the original Flying J transaction.

This is actually not appropriate in determining whether we repurchase shares.

However, some might find it insightful in performing a look-back at the acquisition based on repurchase price.

Although comparing the buy back of shares today based on our view of St. Mary's stock today is a bit apples and oranges.

Many things changed since we originally acquired the properties, including the fact that St. Mary's net asset value, reserves and oil and gas prices have grown substantially.

Based on year-end engineering, at the time we made the acquisition, we had booked 92 BCF equivalent of proved reserves for Flying J assets as of the acquisition date.

Since the acquisition in January, the properties have generated $14.6 million, net of hedges and proceeds associated with the sell of several Powder River basin fields.

The $91 million paid for the stock less the cash generated and dividend links a net amount of $76.8 million.

At year-end, we still have 75 of BCF equivalent with a value of $129 million.

In addition, we added 455,000 net undeveloped acres associated with the acquisition.

Obviously, this was a very favorable transaction.

Net income for the year 2003 was a record $95.6 million or $2.80 per share compared for $27.6 million or 97 cents per share for the prior year.

Discretionary cash flow increased 95% to $232.1 million, production increased 40% to 76.9 BCF equivalent.

Average realized price increased 41% to $4.75 per MCFE.

Unit cost increase costs increased for year to $1.15 $1.15 per MCFE.

DD&A increased 9 cents to $1.07 and G&A increased to 36 cents.

The increase in LOE outside of taxes is primarily due to change in our asset nicks in which we became oilier.

G&A increased due primarily to increase in our incentive programs as our cash bonus in the net profits pool reflect the excellent results we had as a company.

For the quarter, we earned $24.7 million or 72 cents per share compared to $7 million for the fourth quarter of 2002.

Average daily oil and gas production during the fourth quarter of 2003 totaled 208 million cubic feet equivalent per day, up 32% from the comparable period in 2002.

Net realized price increased 23% to $4.55 per MCFE in 2003.

In the fourth quarter, oil and gas production costs, including taxes, increased 17 cents to $1.06 as compared to same quarter a year ago.

G&A increased 13 cents to 39 cents per MCFE reflecting higher than normal cash bonus and net profits pool payments as a result of an outstanding year.

DD&A was $1.08 per MCFE compared to $1.06 in the fourth quarter of 2002.

A gain of $7.5 million was recognized in the fourth quarter of 2003 associated with the sale of certain Permian Basin and Rocky Mountain region properties.

Fourth quarter 2002 results reflect a pretax loss on the sale of Flower Bluff field of $2.6 million.

Our 2004 first quarter and annual forecasts are shown in the press release and remain consistent with our previous guidance.

You should note that average daily production associated with the fields we sold was approximately 4.5 million cubic feet a day causing the forecast to be a bit flat.

Also, we lost some production in the first quarter of 2004 due to the electric grid at the HCHA field going down when several transformers blew as well as precepts until the Williston Basin causing us to lose approximately 150 million cubic feet equivalent.

With that, I'll turn it over to Doug York who will discuss some of our current activities and our budgets for the year.

Good morning.

I'd like to provide a little more detail on the 2004 budget and update on you specific projects.

Our 2004 budget includes $173 million for drilling, leasehold and seismic and an additional $100 million is budgeted for property acquisitions.

The drilling budget is allocated as follows.

Mid continent $59 million, Rockies including the Hanging Woman Basin $64 million, ArkLaTex $22 million , Gulf Coast $18 million and Permian at $10 million.

I'll run through each one of these in a little bit of detail.

The Mid-Continent budget is dominated by activities at Northeast Mayfield. 11 rigs at Northeast Mayfield in which St. Mary's has an interest.

We currently have four rigs running.

In addition, we have than an interest in eight wells that are either competing or testing.

Field rate averaged approximately $26 million a day net to St. Mary in 2003, that compares to $10.8 million a day in 2002.

In December of last year, our 2004 budget for Northeast Mayfield included 23 wells.

Our more recent update is a total of 32 wells this year.

ST Mary has an average working interest of 31% in the planned 2004 drilling at Mayfield.

In the Rockies, our 2004 capital budget is $64 million which includes $12 million earmark for Hanging Woman Basin's CBM which we will cover later.

The non-CBM Rockies budget is focused at Red River program where we have a historical success rate of 92% and in the horizontal Bakken Play.

In the Bakken Play the initial wells continue to perform extremely well with a single lateral strand well currently producing 235 barrels of oil per day on pump, and a dual lateral wire well flowing 670 per day of the commingled laterals.

We have a total of eight conventional lands for 2004 as well as 11 Bakken wells or Bakken reentries.

In the Hanging Woman Basin CBM play, activity is progressing.

Highly competitive proposals to build and on operate the transition line and are currently negotiating final.

The terms necessary to complete the pipeline and for the drilling locations have been initiated.

Approximately half of the locations in our 100 well 2004 drilling program follow free acreage and will therefore not require federal permits.

We expect to be drilling the free locations in May.

We anticipate that the remaining federal locations will be permanent by August which will allow to drilling program to be finalized by the end of the year.

With the pipeline terms finalized, our timeline anticipates gas sales in early 2005.

In ArkLaTex, the majority of our 2004 budget will target continuing success in the James Lime horizontal play.

Our first well at our Spider prospect in Louisiana is testing 3 MCFE a day.

We have a total of eight wells budgeted and 7700 net acres at Spider where our average working interest is 96%.

In 2004, we continue to hope this continued success at Spider in Huxley where we took the gross build rate from 1 million a day to 16 million cubic feet a day while cutting oil costs by 36%.

Huxley is expected to increase to 19 million cubic feet per day in the next two weeks.

The Terryville fields in North Louisiana where we had five wells budgeted for 2004 continues to underperform.

Our two more recent completions have had initial rates less than 1 million cubic feet per day and have produced large a little of water.

We have completed a detailed analysis.

Drilling is expected to continue at Terryville, but at a reduced pace.

The Gulf Coast Permian transition is nearly complete.

Our Houston office will open on March 1st, with the goal of growing our Gulf Coast presence and continue the momentum in the Permian basin.

We also we expect seismic data in the company's free land position.

Approximately 10,000 acres of free lands are held by existing production while the remaining 15,000 acres are optioned, but unleased.

If the options are exercised the terms of lease provide for 25% royalty on any future participating wells, the right to participate for an additional 25% working interest.

This is an exciting project for St. Mary, the first time we will have a survey over the entirety of its free lands which have already produced in excess of 3.5 TCF gas and 200 million barrels of oil.

We have $100 million budgeted for acquisition opportunities in 2004.

The acquisition market remains challenging.

The premiums being paid for long life gas reserves appear ton increasing.

We are fortunate to have five operating areas from which to direct our efforts.

We have demonstrated the ability to make quality acquisitions in all of these areas. the company's most recent transactions, Burlington and Flying J, continue to outperform.

We bring a great deal of momentum in 2004 after having had a great 2003.

We have made key additions to our technical staff and we look forward to the coming year.

Thank you, Doug. 2003 was an outstanding year.

The complexity of the Flying J structure and the detail of the moment sometimes mask the excellent year that we actually had; however, with the share buy back behind us, the numbers become crystal clear.

When comparing the 2002 year-end balance sheet with a pro forma balance sheet us adjusted for the 3.3 million buy back from Flying J at December of 2003, they are remarkably similar.

Our net liability position, when you exclude approved oil and gas properties, asset retirement obligations, and deferred taxes, improved modest did modestly by about $2 million or 2%, and our shares outstanding creased by only $269,000 or about 1%.

Essentially, there is no meaningful change in our balance sheet and shares outstanding since December of 2002; however, our proved reserves ins creased by 21% to 594 BCF equivalent.

Our pretax SEC for our proved reserves increased 55% to $1.278 billion reflecting the 21% increase in our reserves as well as the 5% and 37% increase in oil and gas prices respectively.

In addition, we added new probable reserves at Hanging woman of approximately 147 BCF equivalent and increase owed undeveloped acreage position by 41% to 8 825,000 net acres.

On a per share basis, that adds up to tremendous growth.

We enter 2004 on a positive note.

Our financial condition is excellent.

We have more prospects than ever before and a capital expenditure budget of $273 million.

Production is forecast to grow modestly up from 77 BCF equivalent in 2003 well reflect than both a 40% increase in 2003 as well as the impact of selling some production at the end of last year.

Based on a NYMEX strip price of $30.19 per barrel and $5.44 per MCF, we would realize approximately $4.68 per MCF eye equivalent after hedges.

Including taxes we are forecasted $1.18 to $1.25 and G&A and forecast between 32 cents and 37 cents per MCFE.

Not only do we have significant continued drilling activity plans at Northeast Mayfield and the Bakken play in 2004, but we believe these plays have significant running room into 2005 and possibly beyond.

We will begin development of the Hanging Woman CMB project in which we have identified probable reserves equal to one quarter of our reserve base and we have [inaudible] why it a portion of potential.

We expect production to begin in 2005.

Our free acreage in St. Mary Parish was the legacy for decades from doing 200 million barrels of oil and 3.5 TCF of gas.

The middle portion of property has been underexplored, and for the first time we will be receiving 3D seismic over the entire acreage position.

Our interest is large and this has the potential for being very significant.

With that, we'll open it up for questions.

Your first question comes from the line of Joe Allman with RBC Capital.

Good morning, everybody.

Mark, you realized gas price in fourth quarter was better than what we had model.

Was there something different in the fourth quarter than previous quarters?

I'm not aware of nothing, Joe.

Because it seemed to be at a premium for the bid week average, whereas in past quarters it was at a discount.

There was nothing unusual in the price side.

Okay.

So going forward, what's the guide an for the differential versus, say, NYMEX?

See, based on the strip at the end of the year, we show -- this is on an MCFE basis, but we show a prehedge realized price of 494 and a net realized price of 468, and do you have the detail on the oil and gas?

We'll get the detail, breaking out the different products in just a moment for you.

Great.

And do you sell most of your gas during bid week?

We do.

Was it like 70%, 80%?

Probably higher than that, 90.

You mentioned the research revisions.

What was that number again?

We had 21 BCF in total of which 14 related to performance, and the performance was primarily at the parkway Delaware water flood project and as well as Judge Digby wells.

And then the reserve, what was that number?

It was 46 BCF equivalent.

Gotcha.

Okay.

And then I think your organic production growth in the fourth quarter, if I kind of calculated correctly, is about 15% versus fourth quarter of '02.

Is that about right?

I don't have that in front of me, so I can't really respond.

I guess your 6% guidance for '04 I mean, is there any reason why that might be lower than what your organic production growth was in '04?

In 03?

Sorry.

Is there just some conservatism in there?

I think having come off a 40% increase, a large portion of which was organic, and a lot of the organic wells do have a little higher decline rate than on acquisition-related reserves, and so when you have that sort of large ramp-up, there is some production coming off, and you do fight that a little bit.

We did sell a little bit of production, so sort of that combination is the reason we ended up with the number we did.

Obviously, we don't know what the exact results are going to be and from our drilling activities and acquisitions in 2004, so, it is just a forecast with what we know right now.

I know you have in haven't filed your 10-K yet cut but can you give us what the future development costs and the future production costs are for your PV tank calculation at year-end?

Sure, and by the way, we are filing our 10-K today.

We have speeded up our process so you'll have that information.

Let's see.

Our future production development cost is 1,000,065.

What was the price you used?

For your PV 10 for oil and gas?

We used, gas was 5.75 and oil was 30.90.

30.90.

Gotcha.

I'll give someone else a chance.

Thank you.

Your next question comes from the line of John Stables with Morgan Keegan.

Good morning, guys.

Couple of quick easy questions.

The cash position at the end of the year?

Let me get that for you.

I think I saw the working capital and everything else related to cash.

We had cash and cash equivalents of $14.8 million, and then we also had, in a restricted cash account, $10.4 million, and we set aside some/ cash for 1031 exchange and whether we'll use all that or not we're not sure, but we did set that aside, so that's not included in our working capital.

Okay.

For the production number for the quarter, I believe it was 207.6 per day, how much of that was gas?

For the fourth quarter 130 million a day was gas.

And then finally for the cap ex in the fourth quarter, what did that shake out at in the end?

$48.6 million.

48.6.

And that's just the development and exploration.

That includes everything.

That includes everything.

Okay.

The last two questions.

Oh, wait one more for the reserve breakdown I'm curious if you ballpark at the end of the year reserves, what percentage came from each of the different regions, the Mid-Con, ArkLaTex, the Rockies.

The actual final reserves?

Yes, please.

Let me get that for you.

Okay.

On a volume basis, the Mid-Continent was 26%.

The Rockies were 49%, and ArkLaTex was 11%, Gulf coast 5%, and Permian 9%.

All right.

One more and I'll let anybody else somebody else get in here.

I'm hogging the line.

I'm curious to get a little bit more, we're we've heard a lot about the Hanging Woman Basin, I'd like a little color about the Bakken dolomite play.

You mentioned there is a lot more running room there and conceptually I'd like to matter hear a little bit more about that.

Sure.

The play really kicked off in Richland County, Montana, and was being led by a couple of independents.

We got into the play about six months ago and have a sizable acreage position.

We have about 40,000 acres in Richland County.

Most of that could to be in what we think is the dolomite play.

We're not sure how large the play really is, but we have a noise position that's almost all HBP.

There are currently 45 wells producing in the Bach and dole might play and there are eight wells drilling in the balk and dole oh might play in rich land coin.

I also mentioned the strand well which is 100% working, 100% net, I also mentioned [inaudible] that's flowing at 670 wells per day so they're big wells.

The concern always in this type of play what the decline is going to look like.

We're starting to get enough production history that we can build a model that's credible and that gives us confidence to go ahead and deploy capital, and because of our lease position and because we don't have explorations to fight we can really move into this play over the next couple of years.

And the big question then is does it cross the state line into North Dakota where we have major acreage positions or exactly where it's going to go.

So hopefully that helps as far as the play.

Yeah, and what do the early decline rates look like at this point?

We have enough history that we know they're hyperbolic and only obviously the big concern is they would come on off on a screening decline, and they have high initial decline rates, but they definitely turn.

There's no question these are going to be hyperbolic, and we're refining our model as we go forward and get more data but they're going to be hyperbolic wells, the minimum decline I don't think we're quite sure of at this point, but we're definitely building.

You might talk about strand; how it came on originally?

I mentioned the strand at 235 on pump, it was initially flowing at 350 barrels per day, and that well has been on for three months so they don't have the kind of decline they go that 350-barrel a day to 100 barrels a day in a month.

That's not the nature of the profile.

Excellent.

Thanks, guys.

Your next question comes from the line of David Tameron with Stifel Nicolaus.

Good morning, everyone, congratulations on a great quarter.

A couple quick questions.

You talked a little bit about this, but in the St. Mary Parish you're shooting the 3D seismic.

When are you going to have that or has it already been shot and what type of opportunities could this provide going forward?

Sure.

It has been shot.

It was underwritten by several major oil companies and a couple larger independences and has shot in three phases.

The second phase covers the lion's share of our property.

The data is in, and we should have the dates a literally any day.

We're hoping we have it Monday or Tuesday processed.

The process data.

We are looking at this as kind of a unique opportunity as Mark said, the core of our free lines have never been shot and they've been very, very prolific producers.

Predominantly from the shallow mining section the reserves to date are 3.5 TCF and 200 million barrels of oil.

What's been lightly explored is the deeper section, and I think people have always seen a deep structure down the MA and rob series bullet it's deep, it's expensive and no one wanted to drill it without additional definition that you get from seismic.

So we're hopeful that that will get drilled.

Clearly, we have at a minimum we ever we have our 25% royalty position.

We have a 25% working interest election.

We are also hopeful we'll see additional shallow potential that's never been defined before.

So the timing, it will be worked diligently by not only us but the underwriters of the shoot over the next, I would guess, four, five, six months with some activity probably starting in the fourth quarter or the first quarter 2005 as far as actually drilling wells.

Okay.

And I think Mark mentioned it before, but can you guys mention the who the other underwriters are there for that?

Sure.

We have Exxon, El Paso, Penn, Virginia, Cabot, Burlington and BP.

Okay.

The second question, talk a little more about Hanging Woman Basin.

Remind me again what type of price threshold did you use out there to run these economics?

Were you using a $3, $4 number as opposed to the strip or how much downside did we have there before?

We had a positive downside.

We ran it with sort of the strip at the time that we were doing it, and we did that probably about November-ish, and if I recall right, it had about a 75 cents, $1.00 sort of cushion in there economically.

Clearly gets real skinny at 350 NYMEX.

Because then you're looking at anything until the Rockies.

And you did not book anything from that; is that correct?

Correct.

Okay.

Two more quick questions.

Northeast Mayfield, I know you mentioned production averaged 26 a day in '03.

What's that current number running at?

It's been real volatile with the big well to come on.

I mean, some of these wells are riping at 15, 20 million a day; some of the Atoko wells in the dolomite section declined rapidly.

Some of the other wells in the Morrow and Sandstone section of Atoka don't.

But it's been running between probably 22 to 28 or 29 for the last several months; and it's been up and down, frankly.

Okay.

And that's up from 4, 5, three or four years ago?

In '99, we averaged from 6 or 7 million a day.

Good.

The Williston Basin, you mentioned the number of wells I think you're going to drill this year.

Can you hit that again for me?

Sure.

It was in the Red River, we had 8 conventional and two horizontal wells in Red River.

So ten total Red River wells and eleven Bakken wells.

And that's '04 numbers?

That's correct.

I think that's all.

Thanks a lot.

Your next question comes principle line of Larry Busnardo with Petrie Parkman.

Good morning.

Mark, can you talk a little bit about your acquisition program, where you would be focusing your attention on, where we may see you look to potentially at a position?

Are you focused more in areas that you're currently situated in or are would you look to expand out into other areas?

I think as a general statement we focused on the areas we're in and we tend to have the best expertise, which generally, to be successful in a tougher acquisition market, usually you have to have an idea that someone else isn't seeing or some sort of operational synergy that makes it worth more to you than it does to someone else, and that's, quite frankly, is going to happen in areas that we're already in.

At the same time, we do have an interest in the [Piance] and so we would be looking at opportunities there as well.

And I would say those are probably maybe south Texas as an expansion of sort of our Gulf Coast area.

Those would be the areas that might be a little bit different than what we've been in historically.

Great.

And then just going back to the Bakken play, you've got eleven wells planned.

Where do you think that will go if everything continues to work well and continues to meet your expectations, do you see that maybe doubling or getting evening larger going forward or just in term of the number of wells that are going to be drilled on an annual basis?

It looks like it's going to be around for a while, it's not going to go away in 12 months.

I think one big question is does it cross the state line, and how important is the thickness of the dolomite itself.

There's a lot of speculation with the fracture system, where the storage is for the oil, and I think that's going to be define over the next several months.

If it extends across the state line, obviously we have a major position and we have a lot of high interest leases, but it's a little early right now.

The activity was initially focused in the spring lake area and has moved to the south and the east.

But it's a little early to probably predict exactly how far it's going to run.

So do you have a pretty good idea at the end of this year?

We'll have a lot better idea.

I think we'll be able to speak to that -- I think seeing not only the wells we drill, but the wells that other people are drilling and some of the ideas they're testing will get us a better idea and help us define what truly is the fair way.

And it does cross the state line, we actually have over 50 well bores where we have 100% NRI where we could reenter a fairly inexpensive basis.

So that would be a nice upside if it does, in fact, cross the line.

Great.

Thanks for the update.

Your next question comes from the line of Ellen Hannan with Bear Sterns.

Thank you.

Just a few follow-up questions.

Mark, the properties that you sold this year, where were they?

Were they scattered?

Basically, it was at Fort Chadbourne and we had several Powder River Basin fields that we had acquired with Flying J that does didn't fit us and we knew when we first bought that it those weren't something we wanted to hold longer term.

And following with the Hanging Woman, could you talk about the cost of the pipeline, the infrastructure and what kind of rights of way issues you may or may not be facing and also your production, what are your expectations for initial production rates in '05?

It's probably a little premature to address some of those issues.

We're in negotiations right now on the pipeline side.

We did get a variety of proposals all of which we thought were pretty darn competitive, quite frankly, and we compared that to building our own pipeline, and we have elected at this point in time to not build our own pipeline, but we are going to have an alternative that allows us to have access to both of the major markets and we think it is quite favorable, quite frankly.

As far as initial rates and that type of thing, it's probably a little premature to try to predict for 2005.

I mean, we'd like to see how thing go on the timing.

We hate to get locked into a number so far in advance.

Are you expecting any kinds of rights of way or permitting issues to get --

We definitely started that, and we definitely started surveying some of the well locations, and we know that obviously that's going to be required in a route and a path is going to have to be nailed down for the pipeline.

Just given the nature of the culture in the area, I don't expect it's going to be a problem.

You never know when you do a survey if you're going

to find something unexpected, but at this point, it certainly doesn't feel like it's going to be a big English and as far as the wells on the federal side, as Doug mentioned, we're going to begin drilling the fee acre wells first, and so we won't have the permitting issues, and then later in the year proceed with the federal leases.

We have given ourselves, based on what we're seeing is actually happening in terms of their backlog and the time it's taking them to issue permits, we have figured that in with the some cushion, and it looks like everything makes pretty good sense.

Okay.

Just a couple of housekeeping matters for Bob, I think think.

SG&A in the fourth quarter was up substantially from the third quarter.

Is there anything of a one-time nature in that?

Basically it related to both our cash bonus as well as our net profits pool.

Our cash bonus, quite frankly, what we do is it's based on an EBA, we call at it score card but it's basically a net asset value type calculation, and, quite frankly, we did better than we did -- we try to update it every quarter and estimate where we're going, but it was very, very good, and so we bumped up our cash bonus and that's kind of a cumulative adjustment for the year, all coming in the fourth quarter.

Our net profits pool continue to be very good because wells performed well and prices were very, very good.

So we have to do a mark-to-market adjustment on our net profits pool, and that mark-to-market adjustment for the year is a $5 million, that's a non-cash amount, and in the fourth quarter was $2 million.

Thanks.

One last small question.

What's in the other revenue category?

Give you a breakdown of that.

I just have to make sure what number you're looking at.

What's the amount of number you're looking at?

1,000,589.

1,000,589 and it's $8 million to date and there are a bunch of things throughout the other three quarters, but ...

Yeah, we had some gas imbalance income that came in.

Okay.

That's it for me.

Thank you.

Your next question comes from the line of Michael Scialla with AG Edwards.

Hi, guys.

Another question for you on the horizontal Bakken Dolomite.

Have you seen that Dolomite on the North Dakota side?

Is that the risk there or is it just whether or not it's fractured enough to produce economic rates over there?

I think clearly the mapping we've done to date has been focused in Richland County but it appears that it doesn't stop at the state line, but to answer your question, Mike, I don't think we really know exactly is it the Dolomite that's driving the play, is it the thickness or the it is fact techniques that have been used in the past 18 months that have never been used before?

Basically we're drilling open hole laterals and fracking them.

We are not really controlling where the examiner frack is going, and that stimulation alone may be driving this renewed play.

But the answer to your question is no, it does an peer from our mapping to actually stop at the state line.

I don't know how prolific it is on the North Dakota side.

Have any of the 11 wells that you're planning on drilling in the Bach in this year, any of those plan to be over on the north Coast side?

They're not, they're in Richland County, Montana.

And then on the order of production costs, looks like sequentially they whether down on a permanent basis.

Can you give us some idea what was going on there?

In Oklahoma, they approved some severance tax holidays.

Basically, they do a kind of once -- I think it's once a year, but they go back and look at what prices are and determine whether to give those severance tax holidays or not, and they approved that, and so we were able to book that benefit, and that was about $2 million.

Okay.

And then one final one on the properties that you sold.

I'm sorry if I missed it, but I think you said that it was 46 BCF.

Could you give Tuesday production number there in.

It was 4.5 million dollars a day.

Okay.

Thank you.

The next question comes from the line of [Pavil Mochano] with Raymond James.

Hi, good morning.

More of a modeling question than anything.

Given that your long-term debt was increased by about 20 million following the share repurchase, how will that affect two things, one, your diluted share count, sort of Q1 going forward; and secondly, your interest expense?

As far as the share count, essentially you can take out the 3.8 million shares.

Except for through February 9th, so for the first quarter you have to do the weighted outstanding shares will count the number of days that we have more shares outstanding and the number of days after, and I think it is in our press release, to give you that, but essentially all of that comes back.

Then on our debt, the debt that we've incurred suggest a fairly low interest rate, essentially we're at live bore plus 1.25% so it's fair I inexpensive from an interest standpoint.

Okay.

Your next question comes from the line of Phillip Dodge with Stanford Group.

Yes, good morning, everybody.

Another question on hanging woman.

Could you tell us of the develop million budget for 2004 how much of that is for actually drilling wells?

Yeah, we'll get that for you.

And then while you're looking, what's you're assuming now in terms of the timing of actually gas production after completion of a well.

I can answer the second question.

We will test the wells.

We will have a, probably a limited flow period before the pipeline's installed.

There is a state or federal mandated rate limit at which you can vent.

I believe that number is about 60 MCF a day, so we will probably -- it's a little tricky to begin your dewatering without being able to sell gas.

We will have to time that initial production to coincide with having a pipeline installed before we hit some of those maximum vent rate limits.

As far as the budget, in the $12 million we have a little bit of budget on some other CBM projects that we haven't really talked about that are in the early stage so it's about 1,000,002 of that is for that, and about a half million for other exploration overhead.

As far as the drilling of the wells, we have about 8.5 million dollars for the wells, about a half million for power, and then for additional lease acquisition, about 1.5 million.

Thanks.

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

Hi again.

On the Hanging Woman Basin, can you give us the total acreage can what fee?

I know you said this earlier, I'm sorry.

What's free?

What's state?

What's federal?

Well, the total acreage is 139,000.

We'll pull the breakout.

While we're pulling you the out, let me answer another question that we had earlier, I think it was from Ellen, just as far as the differentials for our gas that we have in our budget.

Based on a NYMEX gas price of 544 we show a realized price without hedges, a differential of about 51 cents, and then that would get it down to 493, and then with hedges to about 479, and then on the oil side on a NYMEX $30.19.

Without hedges, we would show $25.64 and then with hedges about $25.29.

And then on the acreage, on our net acreage, federal is 83,000 acres, fee is 43,000 acres, state is 12,000 acres.

Great.

And then separate question.

Mark, on Flying J, you were mentioning some reserve numbers higher than what I thought you actually bought.

I thought you bought like 69 BCFE.

That's correct, and what we did was the number I quoted was our year-end reserves and then added back the production and what we sold to get back to a sort of pro forma at the beginning of the year.

The differential has way outperformed what we originally thought.

Part of it is the Bakken play we had a water flood project that work well, and then just in general it's performed very, very well.

How about your Burlington assets?

The performance there?

They, too, have been better than expected.

They've held up real well.

And then Doug mentioned on the Bakken play, their acreage has actually come as a result of three acquisitions, Choctaw that we did several years ago, Burlington as well as Flying J, and the strand well that that had the 100% working interest as well as net revenue interest, that was a Burlington well, and the [Viara], which he also mentioned, that one came through Flying J.

Gotcha.

Great.

Northeast Mayfield, I know you spoke about it being kind of production moving up and down, about you just overall do you think you can grow that or do you think you're just going to be able to keep it flat or in fact is it jugs going to decline?

Just our proved forecast has us growing the production, and we have a lot of probable and possible locations that aren't in our approved forecast, but it might be helpful, I know the big question probably everyone is wondering and where is this going and how does our activity look going forward.

The 32 wells we're projecting for 2004 compares to 16 wells in 2003; so activity-wise we're about doubling our efforts.

And 18 of the 32 wells we're forecasting to be drilled are on term acreage which essentially means they're typically the first well in the section, so the play is really expanding to the north, mainly to the west, and our activity level is increasing substantially, so we hope the production will follow.

What kind of running room do you have after 2004?

What kind of location?

How many locations do you would you have based on your acreage?

We have 50 sections in northeast Mayfield.

A lot of those -- and the heart of the play, where the play really initiated around the crook sand, many of those sections have four, five, circumstances seven wells in them that are in the crook sand under upper Morrow, the Atoka.

As the play expands, of course the big question will be if all of those zones continue to be productive to the west and to the north, and if they are, what spacing is required to effectively drain them.

And we're dealing with really multi-thousand foot thick interval.

So it's probably difficult, it may be inappropriate to, at this point to try to guess on the number of locations, but the fact that we're drilling 18 new sections next year and all of those could be down spaced in multiple intervals.

That alone suggests a lot of future activity if it continues to work.

And one interval that we haven't actually tried to produce here yet, but we do have on log is granite wash, and so that's another possible vertical expansion of this play.

And then how about Judge Digby?

What's your production there now net and where do you foresee that going, say, a year from now?

We're at about 10 million a day net roughly, and I would guess we're going to stay in the 7 to 10 million a day net range, just via recompletions.

The thing that could impact that positively is a well that VP is drilling to the south, and they've logged about 60 feet of pay in the B-1 which has been a real prolific zone.

We'll have 11.5% of that of which feels like a relatively low working interest, but those are very, very big wells as you know.

Some of those come up to 60, 70 million a day, so that could have a real positive swing for us.

They're currently in the C series.

The well probably won't be down until maybe the end of March at the earliest with production probably not established for maybe a month after that, but we are excited that the B 1 has been extended to the south, quite a way down and that could have a positive impact.

But as we've talked in past, also just a multitude behind pipe region opportunities; so that production is going to be around for a long time.

I think it will be a saw tooth with a little bit of a down trend over the next five or six years, but we'll see that saw tooth be recompletions and hope that this well to the south will be a nice contributor.

Do you guys see the majors getting anymore active today than previously?

In your own experience, like with BP and others you might be dealing with?

I don't think so.

And that's funny.

I mean, just the general North American rig count would suggest that we're relatively flat activity-wise, and the new proposals we're seeing are typically coming from independents.

Gotcha.

All righty.

Thank you.

Your next question comes from the line of Chris Clark is Southwest Securities.

Good morning, guys.

Question for you on the Permian Basin.

I see you guys were bowing to do fracture stimulation.

I was wondering if results came out on those and what you see going forward as a result of that?

We put together a position out there.

We had a nice HBP situation.

We put together another position to the south, and felt like the section had a lot of the same qualities that the section has in the Fort Worth basin.

We did a sizable frac on our first well and we're making gas, about you it's not at an economic rate, so we're in the process of frying to figure out our next step on the well and our next step on the acreage position, and weigh really need to let the well continue to clean up.

We had a lot of our frac load back, but not all of it back so we're kind of in a wait and see mode right now.

Thank you very much.

Your next question comes from the line of David Tameron with Stifel Nicolaus.

Good morning.

Quick follow-up question.

If you choose to pass on acquisitions because you don't see something you like this year, obviously you're going to have some excess cash, and well remind me again on the balance sheet you have to that convert of about 100 million.

Right.

Are any thoughts of taking that out or ...

Basically, our choice is once the convert has been outstanding for five years, we have a couple of years left on it, we have the right to basically call it or say we want to pay it off, and then they would immediately convert it at $26 and currently those converts are trading at about 135% of face value, and so it's not having that we would, you know, want to go out to the marketplace, and there is no liquidity, either, to try to buy them back.

Okay.

And one more quick question, I guess this is for you, Mark.

Can you just give us some insight into what your board and what conversations go on when you do your reserve booking?

Obviously you maintain a historically low PUD and you've kind of kept that on --

One of the things that we do that some firms do, but the vast majority do not do, is our audit committee actually meets with Ryder Scott, the engineer who did the work, and we've been doing that for two years now.

We actually asked him how many companies do that.

He said he has been asked in his entire career to do that four times, and we were two of those times.

Okay.

And is it just a function of St. Mary mentality to be more conservative on those?

Yeah, and it's kind of interesting, I think one of the sort of flaws of Sarbanes Oxley and sort of a checklist approach to life is that it's written for the whole world and it doesn't have visit with your reserve auditor on that reserve checklist.

We basically in the audit committee said the most important number for an oil and gas number is reserves and why isn't the audit committee talking to our auditors, not auditors, but Ryder Scott who prepares the reserve, and so we implemented that a couple years ago.

And all that being said, I'm going another way with the question, but at Hanging Woman Basin let's say you drill these wells this year, are you going to have to wait for any type of data before you can book these things?

Would you anticipate getting some production data by the end of the year and production data and be able to book some small reserves there?

One of the key things was just making the pipeline commitment and actually having the pipeline in place so at year-end that issue will be resolved.

We'll have additional wells down.

We'll have test rates at a minimum.

Clearly, we'll go to book reserves on the hundred wells that we're going to drill if they drill as anticipated, which they certainly should, and then we should be able to book some offsets and another ring of offsets around that for probables.

There is some discussion about if you can determine pressure communication, multiple sections away, you can book PUDs in between, and I'm not sure we're going to go down that path.

I know some reserve auditors have pulled their horns in a little bit about what they called PUDs in the coalbed methane, but I think we'll have some probably, what would be classified as PDN, if they're not producing at year end, but they're drilled and the pipeline is in place then we'll have PUDs around that as well.

Thank you very much.

At this time, there are no further questions.

Well, thank you very much for attending.

If you have any questions, we are filing our 10-K today, and hopefully that will answer a lot of them for you.

Thanks again.

This concludes today's conference call.

You may now disconnect.