SM Energy Co (SM) 2004 Q4 法說會逐字稿

Good morning.

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

At this time I would like to welcome everyone to St. Mary Land and Exploration 2004 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 period.

If you would like to ask a question during this time, simple press "star" then the number "one" on your keypad.

If you would like to withdraw your question, press the "pound."

Thank you.

Mr. Hanley, you may begin your conference.

Think you, Latisha.

And good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's fourth quarter 2004 and full- year 2004 earnings conference call.

Before we start, I need to read the following statement.

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 turn the call over to Mark.

Good morning.

St. Mary, again, has shown good sequential production growth in the fourth quarter.

Fourth quarter production is 5% higher than the September quarter and 9% higher than the June quarter.

This growth has been achieved primarily through the drill bit.

Our reserves grew by 11% to 659 Bcfe. 52% oil, 85% developed with the PV-10 of $1.5 billion.

Net income for the quarter ended December 31, '04, was $26.6 million or 83 cents per diluted share compared to $24.7 million or 72 cents per share last year.

Results reflect a 7% decline in diluted weighted shares outstanding now from 35.845 million shares to 33.335 million shares.

As a result of the acquisition of the 3.38 million shares acquired from Flying J in early February, partially offset by shares issued on option exercises.

We also repurchased 489,300 shares at an average cost of $33.39 during this September quarter.

Discretionary cash flow increased by 32% to $82.9 million.

Production increased 4% to 19.9 Bcfe.

Production increased 0.59 Bcfe for 1.273 million, 0.55 Bcfe at the Constitution field due to the Paggi-Broussard well. 0.32 Bcfe at the Bakken play. 0.22 Bcfe due to the Goldmark acquisition and 0.27 Bcfe at the Spider field.

Judge Digby declined 0.28 Bcf to 0.84 Bcf but has outperformed engineering estimates.

Northeast Mayfield declined 0.65 Bcfe to 1.71 Bcfe due to the flush production last year.

The average realized price increased 35% to $6.13 per Mcfe, while our cash margin increased 42% to $4.53 per Mcfe.

Unit costs increased modestly, as production expense, excluding taxes increased 6 cents to 90 cents per Mcfe.

Taxes increased 20 cents due to special credits received in the fourth quarter of 2003.

DD&A increased significantly $1.48 per Mcfe and G&A expense declined 1 cent to 28 cents per Mcfe.

The DD&A rate will continue to increase as we replaced low cost reserves with new reserves found or acquired in a higher cost environment.

Two previously announced acquisitions, Goldmark and Nemours, closed as planned in the fourth quarter and the Agate acquisition closed as planned in January of '05.

Goldmark closed on November 1st with 29.4 million allocated approved reserve and undeveloped acreage and reserves of 31.9 Bcfe.

Nemours, the Border Company closed on December 15 for $37.8 million and 14.5 Bcfe approved and 9.4 Bcfe of probable reserves.

With that, I will turn it over to Doug York, who is going to talk about our budget as well as progress on some of our more important fields.

Good morning.

I would like to begin by updating you on our 2005 capital budget.

Our 2005 drilling budget of $293 million represents a 24% increase over 2004.

The majority of the increase occurs in the Rockies with increases also occurring in the ArkLaTex and the Gulf Coast regions.

The increase for Rockies budget reflects success we are experiencing in the Bakken Red River formations of the Williston Basin as well as the Green River basin of Wyoming.

We also have capital allocated in 2005 for the development of the Fourbear filed in the Big Horn Basin, which was purchased in 2004 acquisition of Goldmark.

The ArkLaTex budget increase is driven primarily by development drilling in the Elm Grove field, which came to us via the Nemours acquisition.

To date, well performance has exceeded the forecast at Elm Grove.

Increases in the 2005 Gulf Coast budget result primarily from prospects generated in our 50/50 joint venture with Huma Exploration covering approximately 900 square miles of 3D seismic in the inland waters of South Louisiana and the Galveston Bay area of Texas.

St. Mary will act as operator on these prospects.

In addition, we've entered into agreements with Huma covering two to four prospects in lot Shanger San Block 55.

We plan to start an amplitude driven exploratory test in West Cameron Block 542 in 60 to 90 days, where we will have a 30% working interest working and will act as operator.

Our 2005 budget for the Hanging Woman Basin coalbed natural gas play is $26 million.

Expectations call for drilling approximately 150 wells in the play depending on permitting and regulatory approval.

The key areas being developed in Wyoming in 2005 will be the Randapom (ph) and Box Elder areas, which are adjacent to our 2004 development drilling.

In addition, the river area will be developed to protect our acreage from drainage resulting from offset operator activity.

In Montana, the plan of development is being prepared for Trout creek and on the border areas with expectations for permanent approval in late 2005 or early 2006.

Non-operated coalbed focus in the Atlantic Rim area of Wyoming where St. Mary holds working interest ranging from 5 to 10% in several units operated by Anadarko Petroleum.

In the Sun Dog unit, approximately 10 wells have been drilled to date with average per well producing rates of 350 to 400 Mcf a day.

If St. Mary's activities increased, so has that of many of our peers.

The result has been a continued stretching of the service and supply sector.

Rig day rates have continued to increase.

Thus far, we have been willing and able to absorb the increases in areas where we have active programs exhibiting strong economics.

In areas where we have short-term drilling programs, we have, at times, had difficulty securing rigs to drill individual wells.

The rising costs of casing made headlines in 2004 with steel cost for tubular goods rising almost 100% during the year.

The increasing casing costs appeared to have slowed but small percentage increases are still being noted.

Cost for services such as cementing, tracking and logging are trending up and we are expecting overall cost increases of approximately 20% for 2005.

Current commodity prices have more than offset the increase in service and supply costs, but the relationship between prices and costs must be monitored carefully as we proceed through 2005.

At this point, I will go into a little more detail in two of our key projects, beginning with Northeast Mayfield in Beckham County Oklahoma. 2004 was a transitional year at Northeast Mayfield.

St. Mary began operating in the field in 1996 and by following methodical delineation program through 2003, excellent results were achieved.

Beginning in 2004, the level of activity at Northeast Mayfield increased dramatically.

The increased activity included a number of deep step-out wells that were more exploratory in nature.

As a result, 2004 numbers, as you might expect, were not on par with historic results.

However, the majority of the leasehold is now held by production and it appears that with the knowledge gained in 2004, profitable development of the field should proceed in 2005.

St. Mary has three operated rigs running at Northeast Mayfield and is participating in one non-operated drilling well.

In addition, nine wells are being tested or completing.

Net field rate for 2004 averaged 20 million cubic feet per day as compared to an average of 25.6 million cubic feet per day for 2003.

St. Mary's budgeted $33.6 million for drilling and completion of the Northeast Mayfield in 2005.

The 2005 capital program should maintain current production levels with the possibility of modest growth.

In the Williston Basin, the horizontal Bakken program continues to perform very well.

Gross operated Bakken oil volumes in Richland County, Montana, increased from 600 barrels of oil per day in January 2004 to 1,600 barrels of oil per day in December 2004 and have further increased to 3000 barrels of oil per day in February 2005.

Our two most recent completions, the State 416-H and the France 215-H were brought online in early February, flowing between 500 and 600 barrels of oil per day per well.

In North Dakota, the flat top deep federal is 2114-HR is flowing back at a rate of 175 barrels of oil per day after being fraced and cleaned out.

The Mondac federal 328-HR has not been fraced but is bumping approximately 250 barrels of oil per day.

Both wells are single lateral reentries of existing well bores.

We are currently drilling our fifth horizontal Bakken reentry in North Dakota.

The company has two drilling rigs and to reentry rigs working in the Bakken play.

A third drilling rig is scheduled for arrival in late May. 30 wells are budgeted in the Bakken for 2005, which includes 20 operated and 10 non-operated wells.

Of the 20 operated wells, 14 are grassroots wells and six are reentries of existing well bores.

With those comments, I will turn the call over back over to Mark.

The year 2004 was highlighted by high oil and gas prices and record earnings per share, return on capital employed of 23%, a very competitive acquisitions market, growing recount and escalating costs, reasonable drilling results led by outstanding performance in the Rockies, driven by the new Bakken play as well as the Red River results, good results in the Gulf Coast and ArkLaTex, offset to some extent by disappointing results at Northeast Mayfield and 66 fields in Oklahoma, a modest drop in production after increasing 47% the prior year, commencement of development and first production at the Hanging Woman basin coalbed methane project.

The company completed $77 million of acquisitions in 2004 and grew its reserve base by 17%.

The company repurchased 3.9 million shares at an average price of 27.40 while we saw our stock price increase 46% for the year to 41.75.

Reserves per share grew 23% to 23.13 Mcfe per share.

Highlights include excellent drilling results in the Bakken horizontal dolomite play in the Williston basin.

We participated in the drilling and completion of 15 wells with 100% success rate.

Grassroots completed dual lateral wells drilled Richland County, Montana cost approximately $2.7 million with initial production rates of 350 to 600 barrels per day and reserves of approximately 350,000 to 500,000 barrels of oil which results in outstanding economics.

At year-end, we had 45 PUD in probable locations identified.

We have begun to test the plain North Dakota via reentry of existing well bores with single lateral completions, which cost approximately 40% of grassroots dual lateral well.

The middle Bakken dolomite thins as it move southeast into North Dakota, where our initial results have been encouraging with un-stimulated flow rates of 150 to 300 barrels per day.

We have approximately 80,000 net acres in the middle of the Bakken play.

We have several outstanding individual well completions in 2004.

The Paggi-Broussard # 1 where we have 40% working interest, is currently producing 31.2 million cubic feet a day and 1575 barrels of condensate per day.

The Vermillion 273 where we have 50% working interest was initially produced at approximately 15 million cubic feet a day and is currently producing 10 to 11 million cubic feet a day.

The (inaudible) MC at Judge Digby has initial rate from the season of only about 20 feet of pay, where we have 7.84 working interest, up 15.4 million cubic feet a day with 154 feet of net pay yet to be completed in the B zones where we have 11.5% working interest.

We've also had continued success in our Red River play in the Williston as well as tight horizontal plays in the ArkLaTex including Huxley, Spider, Dirscoll, Walkers, Chapel and growing activity in the greater Green River basin.

Northeast Mayfield has been one of the company's most successful projects beginning with the initial quicksand play in 1996, which grew to include 18 morrow sands, 5 Atoka zones and then initial (inaudible).

The play moved quickly to the north, south, and west in a more exploratory manner in 2004 due to increased industry activity and expiring leasehold.

As we moved away from the nine core sections, we drilled deeper and tested more zones initially to obtain a better understanding of the geology.

Although we gained more knowledge of the play, our results were disappointing.

Our knowledge, however, will allow us to reduce our drilling and completion costs and high grade our future prospects locations.

We began development of our Hanging Woman coalbed methane project by drilling 57 wells in 2004.

The pipeline in compression facilities were completed in December, and we began selling our first gas.

Netherland Sewell completed a comprehensive geologic and engineering study of the project with an estimate of 3P reserves of 723 BCF.

Our 24% increase in drilling CapEx budget represents our growing inventory prospects with multi-year development plays in the Bakken, Red River and Northeast Mayfield together with long-term project at Hanging Woman.

Our future is bright indeed.

And with that, we'll open it up for questions.

At this time I would like to remind everyone, if you would like to ask a question, please press "star" "one" on your telephone keypad.

We'll pause for just a moment to compile the Q&A roster.

Your first question comes from Joe Allman with RBC Capital Markets.

Hello?

Good morning Joe.

Hey, good morning.

Can you remind us what you're working interest in that revenue interest is in the Bakken?

Just looking at our budget, I calculated those numbers just a few days back.

On the operated wells, we have 20 operated wells budgeted, our working interest average is about 72%.

And on our nonop program its more in the high teens, I want to say 17 or 18%.

A safe bet for NRIs would be low 80s.

I don't have an exact number for nets but I'd say it's going to range kind of in 80% to 85% net revenue interest range.

Of the working interest, right?

Correct.

Okay.

And then going forward with, kind of the remaining acreage you got in the remaining locations, is it about the same as what you've done so far in terms of working interest and net revenue interest?

Yes, the numbers I just gave you were, of course for our '05 plan, that would be our going forward numbers.

Okay.

And I would assume, if you look out further into '06 and '07, you come up with a similar set of numbers, but I haven't calculated that Joe.

Okay.

Got you.

Although the acreage that we've quoted those are net acreage numbers.

Okay.

Got you.

And then, what was the production contribution in the fourth quarter from the acquisitions that you made?

Very relatively small.

As I mentioned we had a 0.22 BCF with Goldmark, and we had 0.06 BCF due to Nemours.

Okay.

The Goldmark acquisition, didn't that close in November?

Correct.

Okay.

November 1st.

November 1.

And I thought that was producing about 23 million a day net.

No.

No?

I think it was 2,300 barrels a day.

As I thought in your release it was like 590 barrels a day and then 20 million a day.

The 590 is right, Joe, but I think that was an equivalent number.

The number I was going to quote was 600 equivalent barrels per day.

But it's almost all oil.

It had very, very small gas component to it.

Okay.

My fault there.

Okay.

I appreciate that.

And then two more quick things.

One, in your 2005 production guidance, are you baking in some acquisitions in there?

Yes, outside of the Agate, which has closed.

Okay.

We have just over 2 BCF in there.

Okay.

And then, lastly on the Northeast Mayfield field, based on what you've learned in 2004, are you not going to drill as deep as you did in 2004?

What's the plan going forward there?

There's several things going on.

I think we updated throughout the year that we were stepping out 4 or 5 miles from production in some cases, which had not been our previous mode of operation.

But we also were drilling deep.

And many of the leases, you hold only to the deepest depth drilled.

So some of our peers and competitors in the area were proposing wells to 19,000, 20,000, 21,000 feet in order to hold all of those depths.

When you go back and relook at the results, in many cases, in Atoka test to 16,000 feet may be sufficient to develop the uphole reserves.

So, I think it will be a combination of being more selective about the depths drilled, probably having to test less zones, to determine which zones are productive, since we had a lot of that data gathered.

So, I think it'll be -- it will really be a combination of those two things.

All right.

Thank you.]

Your next question comes from Larry Busnardo with Petrie Parkman.

Hey, good morning.

On the Bakken play, can you give me a breakdown on the number of wells?

Of the 30 wells that you're going to drill, how many will be in Richland County and how many are in other areas.

Actually most of the budget is in Richland.

It is.

Okay.

Because at the time we prepared our budget, we were just beginning to test some wells on the North Dakota side.

That could grow, although rig availability certainly could limit it.

So, it might be a shift from one to the other.

But most of our budget was based on Montana.

Okay.

So you're going to continue to focus there in Richland County?

It will certainly be a focus area.

Richland County continues to be a focus area, but as North Dakota continues to be proved up and if we continue to like the results we're seeing, the potential exists to become more active.

I think the actual number for our budget was four.

We had four reentries in North Dakota of those 30 block tests.

Okay.

And then in -- shifting over to the Atlantic Rim base, can you just give us little bit more details on that, how many wells you plan to participate in this year?

And then also, flow rates things like that.

I think you already gave us the flow rates.

I did.

And that's, again this is a non-operative project where we have a relatively low working interest.

I think it has gotten a lot of attention because it's one of the few, if not the only, economic coalbed methane play in Wyoming.

But we're going to participate in 28 wells.

The rates I quoted were in the Sundog (ph) unit.

I think the wells are planned in two other units called Doty Mountain and Blue Sky where we also have, kind of same range of working interest.

But so net, net a 5 to 10% working in 28 wells, obviously it's not a large number.

Net wells, two to three net wells to St. Mary.

But I think the reason we talk about because it's certainly an area that can grow overtime with future development.

Would you look to -- would it be possible for you to expand that on our own there?

Or are you going to continue to be part of this joint venture?

We picked up this acreage Larry when we bought Flying J, and excuse me-- and it's acreage that came in that transaction that we closed in early 2003.

Our appreciation is that the play was heating up at the time and certainly heating up a lot since then.

And our appreciation and understanding is that it's effectively all leased up.

So, we'll probably stay with the position we have.

Okay.

Is there any watering process to this?

Do they produce water?

I'm not sure I can answer that.

What I understand is they tend to come on with initial gas rates and they reach peak production more quickly than people anticipated.

But I feel like there probably is some water production.

Some dewatering is occurring, but I don't know the specifics.

Okay.

And then, can I get the working interest again on the Valladolid West Camp 542?

30%.

30%.

Great.

Thanks.

Your next question comes from Philip Dodge with Stanford Group.

Yes, Good morning everybody.

Could you give us a little more detail on the Bakken dolomite, what determines whether you drill dual lateral rather than single lateral and what the relative costs and reserve potentials are for each of those?

The dual laterals are drilled when we have a grass roots location.

Typically what we've done over time is we try to use, utilize existing well bores that were either temporarily abandoned or producing at very, very low rates to go in, reenter those, drill a horizontal leg into the Bakken dolomite, and tested and see if, you know, as a means of extending the play at a lower cost.

And those wells are coming in, in the kind of, 1 million to $1.4 million range.

I think we've been talking about 1.1 million as an average.

Once an area is proved to be productive either by us reentering wells or by our competitors drilling wells, we'll typically go to a grass-roots type program where we drill two laterals on a 640 acres basing unit.

Each lateral is 4 to 5,000 feet long and we track each of the laterals individually.

And those wells cost about $2.7 million.

Yes, you said before re-entry is 40% of dual lateral.

And what's roughly the difference in reserve potential between those two?

Yes, I think Mark quoted it, kind of 350 to 500 MBOE reserve range for our grass-roots wells.

We don't have as much data, as much history on the reentries.

But I think a safe bet would be somewhere in the 150 MBOE range.

It could be a little better than that.

And it's going to depend on the area of course.

Yes, so it's sort of proportionate to the cost.

Right.

Okay.

Thanks very much.

Your next question comes from Michael Scialla with AG Edwards.

Good morning, guys.

Good morning.

I think I'm a little bit confused on the number of Bakken wells you're talking about.

If I heard you right, you'd said that you were planning four of five reentries this year but I thought you had also said you'd already done three or four and you still had two reentry rigs burning.

Is that right?

Yes, we're on our fifth reentry on the North Dakota side.

We've already completed four reentries.

We also are doing some reentries on the Richland County side.

And we're also using those reentry rigs to go in and clean out the laterals in the grass roots wells after we frac them.

Sometimes they get sand deposited in the laterals.

So the reentry rigs are count of utility rigs that are doing both, cleaning out the laterals and the new wells after we frac them or actually doing reentries of existing well bores.

We have six reentries in our '05 budget.

Out of the 20 -- excuse me; out of the 30 total stocking wells in our budget, six of those are reentries.

So, mainly confusion might, maybe, if we kept few reentry rigs running all year, you'll maybe think we'd do more than that.

But, they're bouncing back and forth.

They're kind of utility rigs we're using them for different purposes.

Also, I think there was a bit of contingency on the North Dakota side.

At the time we did the budget, we had very little information on the North Dakota side as well.

So that could -- that's the place where we could potentially grow.

Safe to say you're encouraged by what you've seen so far on the North Dakota side?

We are encouraged, absolutely.

It's still a bit early.

We only have after frac rates on one well.

And then, of course, our Mondac well performed so well, we didn't really even need to frac it, which was encouraging.

And then, we frac a third reentry on the North Dakota side, we're cleaning it out.

We don't have any rates.

We're scheduled to frac the fourth reentry on March 2nd, and we're drilling the fifth reentry.

So, its still a little early, but what we've seen has been encouraging.

And then, in the Hanging Woman Basin, given some of the disappointment that others have seen in the wide act play, how much production history do you need to see out of your wells before you step up the effort there, and how fast could you ramp up if you are encouraged?

When we looked at the Hanging Woman Basin, when we ran our internal economics for management approval and Board approval, we looked at the offset plays to the West, CX Ranch and the Prairie Dog, where hundreds or perhaps thousands of wells were drilled and producing.

And we use that as our analog.

So, as far as the shallow coals, the Anderson, Canyon, Cook, we have a pretty high level of confidence, and we're not -- we, also, subsequently, of course, did are two pilot programs, which bolstered our confidence further.

So as far as the shallow coals go, we're not really holding back or we're not tentative in terms of waiting for results.

We think we have those pretty well understood.

I think in the press release we talked about, you know, the deeper colas are a little riskier just to the extent that we don't have those really strong analogs like we do in the shallow coals.

I think the deeper don't have quite as good permeability.

So we view that as being a little riskier.

And out of the three key reserves, that's about half and half between the shallow and the deep.

Okay.

I saw that Enterra purchased US Energy Corp's properties up there this morning.

Is that something you all looked at or were interested in?

We didn't look at that.

Okay.

And then, just one last one, any update on the fee lands oil?

Yes.

We actually have two ASC's in-house on the fee land.

One is for 17,200-foot test approximately, and another one is for 19,000-foot test.

Burlington Resources will act as operators.

It's my understanding they have and will keep about 50% working interest.

Mcmoran and others are in the well as partners.

As I said we have two ex-wells, actually ASC's.

There is discussion of a third prospect that's being reviewed.

I don't have the exact spot dates for those wells, but, clearly, they're '05 wells and likely first half '05 wells.

And we, of course, as we've discussed in the past, we will have 25% cost re in a royalty interest, and the option to participate for 25% working interest, which we're reviewing right now.

Very good.

Thanks.

Again, I would like to remind everyone, if you would like to ask a question, please press "star" "one" on your telephone keypads.

Your next question comes from Dave Tameron with First Albany Capital.

Good morning.

Good morning.

Question for you up -- believe it or not, I'm going back to the Bakken, up in the Williston Basin in general, what kind of per acre prices are you guys seeing paid these days, maybe in recent lease sales, etcetera?

And secondly, is there any consolidation opportunities out there as far as additional acreage?

Yes.

Acreage costs have skyrocketed.

Well, depending on how far you go back, it was $100 an acre domain; that's moved to a $1,000 an acre world over the last year or two.

And if you look at some of the implied costs per acreage in some of the acquisitions, it's even higher than that.

We're constantly looking for consolidation opportunities.

We've had discussions with several companies, typically privately held companies, and we'll continue to look for those opportunities.

Clearly, the valuation is going to have to make sense.

We have a wonderful position that we're very proud of, and it's going to give us a multiple number of years of future development.

So, we don't -- we're not desperate.

We're in the play in a really nice way, and we don't want to do something that dilutes that.

But, clearly, we'd like to grow if the valuation makes sense.

Okay.

And then, I guess, second to you Mark, obviously, you guys have never done anything -- I guess, stupid would be the right word on the acquisition front, never really chase and overpay per se.

Given your outlook for your production, it looks like your inventory is deep, you've only got 10% kind of production growth targeted for '05.

Are you -- I mean are you guys still going to be active?

I mean how do you view the acquisition market and what you need right now to complement what you've got?

We continue to think acquisitions are part of our game plan.

In terms of our budget it's about 30% of our total budget this year.

That's probably down from 35 to 40% historically.

We've already closed one of those in the $40 million range.

So we've done about a third of our acquisitions, sort of, budgeted this year.

Our view is that you stay in the market, and you stay disciplined in the way you look at it.

We don't change the way we do our technical evaluations.

We mentioned previously that we did bring down our rate of return requirements a little bit driven by interest rates being lower, and the fact that we really have very little outstanding bank debt, and the fact that the market is a little bit lower.

But, we can do well at the rates that we're kind of putting it in that, and we leave ourselves some upside.

We'll continue to bid with that framework, and we've been able to get a number of acquisitions done.

And because we hedge, we're not really afraid of being in a higher price environment so much.

But we lose a lot.

And usually, we're in the pack, there's usually just one party that kind of use the world a lot differently than everyone else.

But a lot of times that doesn't happen, and we're right there.

And a lot of times it's the result of maybe having special circumstances or a reason why the assets are worth more to us than they were to someone else.

The acquisition we just closed in January, Agate, was a little unusual, and that it has a combination of Williston as well as Arkoma assets.

And, quite frankly, there aren't a lot of players out there that have that mix of asset base.

And so, other people just -- they are being getting very aggressively, and we're able to get that.

It gives us a bit of competitive edge.

The Goldmark acquisition that we closed last year was really a negotiated deal, where we saw -- we had an engineer, who basically sell value on the property that others, really, hadn't identified.

And we proactively went after that and were able to make that happen.

So, the more you can come through an idea that we have, or something so unique about ourselves or the circumstances, the more chance we have of actually getting something.

Okay.

And then, real quick, remind me again, how much growth you have built into 81 to 85 Bcf number for '05?

How much have you included for acquisitions?

There's just over a 2 Bcf for acquisition that we haven't done yet.

That you haven't done yet.

Okay.

All right.

Thanks.

Again I'd like to remind everyone, if you would like to ask a question, please press "star" "one" now.

All right.

Well, thank you very much for calling in.

And we look forward to 2005.

Thank you.

This concludes today's conference call.

You may now disconnect.