SM Energy Co (SM) 2003 Q3 法說會逐字稿

Good morning.

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

At this time I would like to welcome everyone to the St. Mary Land and Exploration third-quarter earnings release conference call.

All lines have been placed on mute to prevent any background noise.

After the speaker's remarks there will be a question and answer period. (OPERATOR INSTRUCTIONS).

Mr. Hanley you may begin your conference.

Good morning to all of you joining us by phone and online for St. Mary Land and Exploration Company's third-quarter 2003 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 will now turn the call over to Mark.

Good morning.

By most standards the third-quarter results were very good.

A net income increased 81 percent from the same period one year earlier to 13.8 million or 41 cents per share compared to 7.7 million or 27 cents per share.

Production increased by 46 percent.

Unfortunately our results are a bit below expectations primarily because we ended up at the low end of our production forecast range and saw production decline sequentially from the prior quarter.

At our Northeast Mayfield field in Oklahoma we saw production ramp up quickly in the first half of the year due to many significant well completions.

These wells have a fairly rapid initial decline rates with few new wells contributing significantly new production in the third-quarter we saw production at Northeast Mayfield decline by 6.6 million cubic feet a day net to St. Mary.

Fortunately the Dean 1-19 which we own 53 percent of was completed on September 15 and is currently producing 21 million cubic feet a day into the sales line.

And we are currently completing the Kathy 1-1 where we have a 54 percent working interest and the Molly C #1 where we have a 46 percent working interest which together should increase production again.

We have also seen net production at Judge Digby decline from 25 million cubic feet equivalent a day net to St. Mary, in the second quarter about 2003 to 14 million cubic a day.

Net to St. Mary in the third-quarter reflecting normal production declines and the loss of the Wertele-1 which sanded up.

We are currently testing the Majors 3 (ph) in the B-8 (ph) zone after an unsuccessful completion attempt in the C-1.

Doug will discuss other new wells in a few minutes.

Oil and gas equivalent production increased 46 percent for the third-quarter to 19.3 BCF equivalent of which 64 percent was gas production.

Higher production reflects the Burlington resources acquisition, the Flying J. acquisition, and the ramping up of production at Northeast Mayfield where we have had tremendous success through the drill bit as well as other drilling activities.

Production net to St. Mary at Northeast Mayfield has increased from 7.9 million a year ago to almost 15 million a day today.

Overall acquisitions represented approximately 60 percent of the increase in production.

We are particularly pleased that we have had significant growth in production organically through the drill bit.

The average price realized for the quarter increased 31 percent to 449 per Mcf equivalent.

Cost increases generally remained moderate.

Oil and gas production costs excluding taxes increased 20 cents to 94 cents per Mcfe reflecting an increase in relative oil production from 31 percent to 36 percent as a result of the Burlington Resources and Flying J. acquisitions, as well as some general cost inflation.

Taxes increased 11 cents per Mcfe due to 31 cents, due to an increase in higher prices.

Our G&A expense decreased four cents per Mcfe to 29 cents.

The absolute amount of our G&A expense has grown from 4.4 million to 5.5 as a result of higher gross salaries to do growth in activity levels, a higher incentive compensation and higher charitable contributions, which increased higher earnings.

G&A has not grown this quickly as our growth in production and accounts for the drop in G&A per Mcf equivalent.

DD&A increased 11 cents per Mcfe while our exploration expense increased 5.7 million due to the write-off of our Duchesne project of $6.4 million.

We earned a record $70.9 million or $2.08 a share for the first nine months of 2003 compared to 20.6 million or 72 cents per share in 2002.

The nine month's earnings are higher than any fiscal year earnings in our history.

The results were driven by a 42 percent increase in volumes, a 48 percent increase in average price realized, offset by an 18 percent increase in cost per Mcfe.

Discretionary cash flow increased 105 percent to $169 million.

We closed approximately 76 million of our $92 million acquisition budget.

Our balance sheet remains very strong.

At a 9:30, we had 13 million outstanding on our bank credit facility and currently have $5 million outstanding.

Our current calculated borrowing base is $275 million.

We have elected a current commitment of $150 million.

Acquisitions remain opportunity-dependent and because of our strong balance sheet we are non limited to the target $92 million budget.

We have hedged 45 percent of our gas production for the remainder of 2003 at a NYMEX equivalent price of $4.52.

We have hedge 48 percent of our oil for the remainder of 2003 at a NYMEX equivalent price of 26.05.

Our forecast is shown in the press release.

With that I will turn it over to Doug who will go over our drilling activities.

We're very pleased with our activity levels and drilling success in the third-quarter.

Currently we have 11 St. Mary operated drilling rigs running along with an interest in 9 operated drilling rigs.

A total of 57 wells in which St. Mary has an interest are either drilling or completing at the current time.

I will refer listeners to our October 6, press release outlining specific completions in the quarter.

In the third quarter, St. Mary participated in a total of 43 wells of which 36 were completed as producers.

Northeast Mayfield continues to be very active.

Noteworthy completions in the third-quarter include the John Patrick 1-27 in which St. Mary holds a 55 percent working interest at 5.7 million cubic feet a day.

The John B 130, 15 percent working interest at 9.1 million cubic feet a day and the Dean 1-19 in which St. Mary owns 53 percent working interest is producing 21 million cubic feet a day.

St. Mary has four operated rigs running at Northeast Mayfield and an interest in two outside operated wells that are currently drilling.

In addition, five wells are currently being completed including the Kathy 1-1 where St. Mary has a 54 percent working interest and the Molly C135 where St. Mary's working interest is 46 percent.

Activities continued outside of Northeast Mayfield as well.

In total the Mid-Continent region has an interest in 11 current drilling operation, seven of which are operated.

At our Huxley field in Shelby County, Texas we are currently drilling the USA 6H on our 2200 acre USA lease, where we have an 80 percent working interest.

The USA 3H and 4H are producing in the sales line at a combined rate of 7 million cubic feet a day.

The 5H has been drilled and will be put on line when the drilling rig moves off location.

The USA 7H and 8H should start before year-end.

The Weeks No. 1 (ph) located adjacent to our USA lease, tested at a rate of 1.5 million cubic feet a day and is currently awaiting a pipeline connection.

St. Mary has a 100 percent working interest in this well.

St. Mary has been able to substantially reduce completed well costs in this play from the original AFE cost of $1.4 million to actual completed cost of $900,000 on our most recent wells.

The Terryvillle field located in Lincoln Parish, Louisiana, the Tatum #1 where St. Mary has a 67 percent working interest tested at 1.2 million cubic feet a day and 35 barrels of (indiscernible) per day.

We are approaching total depth on the Lamar Dowling 28-1 with a 26 percent working interest and the Dowling No.1 where we have a 30 percent working interest has just been completed and is preparing to flutter the sales line.

The Williston base and several successful horizontal wells were completed in the third-quarter and the horizontal Bach and Play (ph) the Vyer 235.H (ph) where we own an 84 percent working interest flowed 400 barrels of oil per day from a single lateral after fracture stimulation.

A plug has been set and the second lateral is being drilled.

The Strand 22-27H in which we control both a 100 percent working interest and a 100 percent net revenue interest flowed 325 barrels of oil per day from a fractured lateral of the Bach and section.

The Doll 114H, a horizontal gut well in the Brushlake field (ph) averaged 416,000 barrels of oil per day in its first ten days online, where the company holds a 100 percent working interest.

The Company's first Red River well in Ridgelawn 3D shoot the Steinbiser (ph) 7-2 where we own an 83 percent working interest is testing 360 barrels of oil per day after a Naptha treatment.

On our Hanging Woman Basin CBM play, we have continued to evaluate our properties by drilling additional core holes and attempting (indiscernible) completions in Robert's coal.

A favorable EIS decision was issued in April of this year and although several groups have filed lawsuits to block development both Wyoming and Montana are issuing drilling permits.

Generally we continue to be encouraged by the additional data that we have gathered.

We are finalizing our economic analysis and expect to present the project for review at our November Board meeting.

At Judge Digby field the fill rate declined from an average of 108 million cubic feet a day in September to an October average of 93 million cubic feet per day.

Our net (indiscernible) from the field declined from 14.8 million cubic feet per day to 12.7 million cubic feet per day during the same period.

A substantial portion of this decline is attributed to the (indiscernible) number one, in which St. Mary owns a 15.6 percent working interest and which had been making 12 million cubic feet a day prior to sending up in October.

The majors number three, St. Mary 11.5 percent is currently testing the B8 (ph) at a rate of 1.7 million cubic feet per day.

The (indiscernible) number one where we hold a 10 percent working interest is testing to C1 at 3.9 million cubic feet per day.

With that operational review I will turn it back over to Mark.

2003 continues to be an excellent year.

Rarely is it possible to increase production dramatically during a period of high process and moderate costs.

We have done that.

More importantly we have had very good drilling results together with sound acquisitions which are the building blocks for the future.

In addition, we are cautiously optimistic about the Hanging Woman CBM project and expect to make a go, no go decision before the end of the year.

With that we will open it up to questions.

(OPERATOR INSTRUCTIONS) Joe Allman with RBC Capital Markets.

What is your expectation for production growth for '04?

We actually have not put anything out yet, we normally complete that process in December and then usually will do a press release in January on that, so we haven't done that.

Normally just from an objective standpoint as you know our goal is to replace 200 percent of our production during the year and we usually do that through a combination of organic growth and as well as acquisitions.

We are generally hopeful that our drilling will replace about 135 present and then we get to add additional growth through acquisition.

We have been able to grow over the 200 percent level for the last five years on average.

And if you're able to do that over time you will grow your production at about 15 percent rate.

That is our objective but we have not done anything in terms of specifics for next year yet.

What I'm trying to get at is based on what you know now about Northeast Mayfield and Judge Digby and the other areas do you think just organically -- do you think production will grow?

Or are the declines so great that having some trouble?

I think it is probably fair to say that we are getting close to having Judge Digby fully developed.

BP is drilling a well to the south on a lease basis that could open up additional opportunities.

We will participate in that well if it is successful in the C zones or the B zones.

But clearly we have a very active effort at Digby for the last three years and we have reaped the benefits of that.

Northeast Mayfield I think it is a very different story; while we have had tremendous activity we still do not know the extent of that field.

We still haven't defined the field limits, we know that the Morrow and the Atoka have the potential to move considerably to the west.

We have Morrow and Atoka penetrations as far as three miles west of our current production of oil and leasehold in between.

We also see the Atoka potentially extending to the North and that is very ill-defined at this point, so I think those two fields are in different phases of their life.

I think while we have a lot more opportunity at Mayfield we also have some new upstart opportunities that we spoke of at Terryville for example, that could turn out to provide a lot of potential drilling for the company.

Do you think Northeast Mayfield will grow?

That region by itself, do you think you're going to grow production there?

I think as Mark said while we have not gone through the budget process and rolled the numbers up, it is not fair to talk about quantitatively but qualitatively my instinct is that we have a lot of running room at Mayfield as well as in the Mid-Continent in general.

What are the best formations at Northeast Mayfield?

Is it springer (ph) or --?

The play started in the lower Morrow moved up to the upper Morrow and has now moved up to the Atoka, so we are playing a section that really from about 15,000 feet to 20,000 feet with numerous pay zones.

Have you found anything below 20,000 feet?

We haven't explored much below 20,000 feet and the lower Morrow.

To the south of us where we have acreage, one of our competitors has drilled some very meaningful wells and we are actually plan to participate in a deeper test to the south of Northeast Mayfield, probably in the next quarter.

On the acquisition front, I know Mark you said it is opportunistic but is it, and it is hard for me to phrase this question but is it critical for you folks to make an acquisition in your mind, jut to keep production growing?

I think it has always been a component of what we do.

We do not put that pressure on ourselves to have to make a deal.

I think we have been able to -- if you look at this year's growth we were able to grow our production 40 percent, including offsetting production declines just through our organic activities.

That happened to be an outstanding year we probably cannot do that every year, but our goal is if we are able to replace more than 100 percent of our production organically and in a good year if we can do 135 percent we will be able to modestly grow our production through the drill bit only.

But historically we have done about 40 percent of our budget or CAPEX in acquisitions.

They tend to come in chunks and at different points in time but it has been a component of what we do and what we are very good at.

As you know the last two larger acquisitions we did were the two largest we have done in our history and those were in the Rockies and primarily the (indiscernible) where we have been a consolidator and we are actually now the second-largest player in Montana and we feel like we have a competitive advantage.

So where a lot of the overcompetition has been in the Mid-Continent we have really not done much lately, but we have been able to go and maybe areas that other people aren't as competitive in.

I will give someone else a chance.

Thank you.

David Tameron with Stifel Nicolaus.

A quick question for you.

I apologize, I got cut off and I missed, maybe you have already answered this but your organic growth, what did that look like third-quarter to third-quarter year ago?

Do you have that breakdown?

Yes, we did do that.

We had 60 percent was acquisition, 40 percent of our growth third quarter this year to last year, so it is 40 percent.

That includes the covering of our production decline as well.

Okay.

And getting back to Northeast Mayfield you said -- did you say Mark the current rates are 15 million a day?

Right.

And that is down from you guys were at --?

Yes, we were as high as in that 26, 27 million a day, and the wells tend to be hyperbolic and decline fairly rapidly and then we will make a turn.

We really didn't have much kind of contributing in the third-quarter, but we do have at least the Dean well came on at 21 million a day where we have a good size interest and we have a number of number of wells we are completing.

We really expect to have that rate to come back up fairly soon.

How quick are those wells -- I mean what does the decline profile look like?

How quick are they coming off?

I think it varies a bit from zone to zone, but it is probably safe to say that initial declines in the 60 to 70 percent range, maybe in the Atoka as high as 80 percent.

We expect them to go hyperbolic and flatten out now probably around 10 to 12 percent.

Okay.

Thanks, Doug.

We are talking in terms of reserves, our typical sort of reserve profile has been a kind of four to eight Bcf range.

That is very, very economic and in some ways having that initial flush production is very, very good from an economic standpoint.

Okay.

Is it fair to say that you have -- in the 2002 year you didn't book a lot from this field as far as a reserve basis?

We did not have a lot booked at Northeast Mayfield last year.

Hanging Woman Basin, the focus now seems to be now the Robert’s Coal (ph), does the (indiscernible) pilot at Andersen Coal, and is that still viable?

I know at one point you said you had seen some small gas shows from that.

Actually the Andersen performed wonderfully on our pilot and it actually outperformed our expectations.

It isn't enough to develop all the infrastructure for that one coal scene.

We have also had a pleasant surprise in the Brewster Arnold (ph), that it looks like it is going to contribute.

And then the Robert's has been one that has real good gas content but it has performed kind of more on the in-between side but we think when you put them all together we also have some other contributing coal scenes.

We have only evaluated a small portion on the Wyoming side.

We are actually fairly enthused right at the moment.

Is the Robert's coal -- I think you said before you are 15 miles or so from pipe.

Is the Robert's coal the key to getting all three of these--?

Originally we thought it might be but with the Brewster Arnold performing better that isn't as critical as it once was.

That is good.

Total number of wells you are drilling this year, you had said earlier 160 and I know you have already surpassed last year's total.

Is that still the right number, 160 and another 75 recompletions?

Fortunately that is not a number --.

We have to date, 115.

115 to date and we just annualize that it would be reasonable.

That is 115 through three quarters?

Correct?

Correct.

Okay.

Mark, I will try to pin you down here.

On production growth for 2004, and Joe asked this question, this is about where I got cut off, but you had said your goal is 200 percent of reserve replacement which would lead to kind of 15 percent production growth.

Are you -- I know you don't want to say 15 percent, but are you comfortable with double-digit type production growth numbers?

Yes.

I think it is just premature.

I think it is a combination of organic drilling as well as acquisitions.

If we do no acquisitions, it probably wouldn't be double-digit growth.

But if we have a good year, it possibly could be.

And with acquisition we would expect that and even though they are hard to predict we have been able to do it over and over again.

And as I mentioned before, I think our five-year replacement percentage, and this isn't exact but it is in the ballpark -- I think about 225 percent or so.

And last year was a little over 300 percent.

So we have been able over a long period of time to meet that 200 percent and do it economically.

That is what we shoot for and we have been growing our organic capability year after year.

We grow our technical staff in each of our offices and kind of indoctrinate them into our culture and basically they generate prospects day after day after day.

That has been how we have been able to keep our organic growth going.

Unfortunately we don't have one of those legacy assets that we can tell you we're going to drill 200 wells a year on for the next ten years, but we do have the talent base that generates prospects year after year and it has grown the number of prospects in our inventory year after year.

So our generative capability we think is very, very good.

You lead me to the acquisition front.

Are you guys seeing anything out there, I mean is it kind of still -- oil comes a little bit cheaper than gas right now?

What is your current view on the acquisition market?

I think it has been -- gas reserves as everyone knows have been very competitive for the last several years.

That is not to say that we haven't been in the hunt on several opportunities.

We have found more favorable returns in the Rockies, particularly in the Williston but we have active acquisition efforts going on in the ArkLaTex, the Mid-Continent, the Gulf Coast and we will continue to be very active in those markets.

Our history has been that if we continue to participate, continue to determine where we are relative to the market that we have been able to get those types of deals done and closed.

So we actually view the market going forward pretty favorably.

Okay, thank you very much.

I appreciate it.

Phillip Dodge with Stanford Group.

Let me just ask a question for my understanding on Hanging Woman in terms of the permitting process.

Assuming you decide to go ahead, when do your applications for drilling permits and water discharge permits are applied for?

At what point in the timeline?

To be honest with you I am not sure I can answer your question directly.

I can tell you if we get approval to proceed shortly we will file those permits.

I don't know what exactly the turnaround time on those would be.

I do know that permits are being issued both in Wyoming and Montana.

But I honestly can't tell you what the exact turnaround time would be.

In regard to lawsuits, there was some concern that somebody would ask for an injunction against the issuance of a drilling permit or the actual drilling.

Have there been any indication of that or what is the status of the lawsuits that might apply to Hanging Woman?

Are there any specific dates out there to think of?

We are not aware of any, Phil.

Right now they are issuing permits and have not been stopped from doing that.

With these lawsuits sometimes you never know, but right now it seems like the environment is okay.

Kind of in a philosophical sort of way I mean I think as a country we need that gas very desperately.

That is the one area that is growing and quite honestly if they stopped issuing permits for coalbed methane in some ways that would be favorable to St. Mary because we don't have any coalbed methane production today and prices would tend to shoot up.

But I don't think that is going to happen quite honestly.

I do think we need the gas too badly.

Fair enough.

My other question is on the Feelands (ph).

Any activity there that we should be aware of?

There is activity.

I think this may have come up in the last conference call but I probably should give an update.

The 3-D that is being shot over the Feelands is completed.

It is in processing and that data should be available for review in the first-quarter.

This is a meaningful deal to St. Mary to the extent that our entire position has never been shot.

We have HBP portions that are approximately 10,000 acres that have been shot.

But there is a core area in the center of our position that has never been shot.

That is about 15,000 acres.

It has been optioned and we know that there are some deeper targets and deeper potentials so that is something that is going to be occurring early next year.

We will have a better feel for what we are going to see deep.

We will have a 25 percent royalty on all of that acreage that has been optioned.

We will also have the right to participate for a 25 percent working interest if there is a prospect that we want to join in.

Okay, sounds good.

Thanks.

Ellen Hannan with Bear Stearns.

I think most of my questions have been answered but one.

This may be kind of a gnarly one, but Mark could you give us an idea of what you think your base decline rate is?

Company-wide?

I think it is probably about 20 percent.

I would think we are probably fairly average in total relative to other companies, so we have very long life reserves in the Rockies and that as you know represents about 48 percent of our reserve base.

Also the very rapidly declining Gulf Coast represents a fairly small percentage of our reserve base now.

I think it is 9 percent if I remember right.

The Mid-Continent although it has initially high decline rates on new wells, they are hyperbolic and then level out and so that is sort of a moderate decline rate.

So in total, I think as a company, we are probably pretty much in the middle.

One other question about '04 and again this may be premature.

Any thoughts on capital spending excluding acquisitions, just kind of for maintenance CAPEX if you would?

Again we haven't done that.

We have been growing that sort of ratably each year.

Without seeing numbers yet I would expect it to be plus or minus 15 percent, something in the range.

Thank you very much.

Dan Morrison with Aperion Group.

I think you have covered everything pretty thoroughly but back to Northeast Mayfield, was the kind of the lull in activity just purely a byproduct of the drilling calendar or are you starting to run into any bottlenecks on the service side up there?

I don't really see any bottlenecks on the service side.

We did have some issues.

Moving gas with our gathering system, we had it fairly packed for a limited time.

That has been resolved.

But it really was just the way the timing worked out in the drilling schedule and the completions and -- but whether related to availability of services or availability of rigs, it was just more of a timing issue.

You have got four rigs there now if I --?

We have four operated rigs, that is correct.

We are also participating in two nonoperated drilling wells.

That is an increase in your operated rig count isn't it?

It is and we had over the years we increased it from one to two to three and now at 4.

We are at the high -- we will probably keep three of those rigs running, one is a little shallow of a rig that is drilling in the Atoka and I am not sure if we will keep that on the payroll but we will absolutely keep three rigs running.

Great, thanks.

(OPERATOR INSTRUCTIONS) Rehan Rashid with Friedman, Billings, Ramsey.

Could you take a second and talk about the Burlington acquisition up in the Williston, what has been done so far (indiscernible) and shooting some seismic there as well.

What is the outlook for that portion?

We really always liked the Burlington properties mainly because they were such a wonderful geographical fit for us.

Through the process we were able to end up with 59 sections where we had 100 percent working interest and 100 percent net revenue interest and the Strand well that I mentioned in my opening comments that is flowing about 325 barrels of oil per day is one of those wells where we have 100 percent net revenue interest.

We have several seismic shoots planned and in process.

What we found is from the time we close the acquisition, get the shoot designed, implement the shoot, process the data and drill our first well, that is usually about a 24 month period.

What I can say to date the acquisition is performing at forecast on both the cost side and the volume side.

We have already had a pleasant surprise with the Strand well.

Longer term I think it is going to be a function of how some of the 3-D shoots work out for us.

I think the Flying J has also been performing right on the button.

Just as an example of sort of the timing to get the shoots, the Ridgelaw well that Doug had mentioned, that was a result of the Choctaw acquisition that we did a couple of years ago.

And we had a real nice 3-D shoot out of that and with the success there we have identified a number of other prospects in that same shoot area.

So we are pretty optimistic about that, but there is sort of a lead time that tends to come with these.

Okay, thanks.

Joe Allman with RBC Capital Markets.

Could you take us -- I know Northeast Mayfield -- it sounds like you've got a lot of running room there, so it sounds like you're somewhat optimistic about growing production there in reserves.

Any other areas stick out as ones that we should pay particular attention to for the potential for pretty good growth in production reserves?

We have an area in Oklahoma we call 66 where we have drilled multiple Grant (ph) Washitoka (ph) wells with very good results.

We will continue to develop that.

Another area that I mentioned briefly actually in the ArkLaTex is Terryville.

We first saw this I guess it has been over two years ago and what really appealed to us, is it is Cotton Valley production.

It is based on 6-40 and as many of you know that is highly unusual.

It is nonexistent.

Most Cotton Valley fields have been drilled down to 160s, 80s some of them are in 40s.

We have drilled our first three wells, completed our first three wells actually we have just completed our fourth and are drilling our fifth and we have nine sections that were earning.

So depending on what assumption you want to use about density, you can do the arithmetic and figure out there there is quite a few locations left to drill at Terryville.

We are also looking at outside of Huxley in the James Lime play where I mentioned we have two more wells to drill this year and another well to drill in the first quarter.

We also have an acreage position in a prospect we call SPIDER (ph).

We have drilled two wells and have multiple wells planned for 2004.

So quite a few areas around the company.

If you just jump from region to region that we have active drilling programs that have some running room left in them.

What is your interest there at Terryville?

It varies from a low of about 25 percent up to 100 percent.

This is an area we tried to acquire for about two years unsuccessfully.

Ultimately did a drilled to earn deal with the owner of the properties.

We can earn up to 100 percent of their working interest subject to back-in and their working interest varies from about 25 to 100 percent.

That is Northern Louisiana, is that correct?

Right, it is.

What are you seeing in Northern Louisiana in general?

Am I right that that is getting increasingly competitive there?

I think it has been a place really in my opinion from the late '90s maybe 97, 98 there have been a lot of interesting plays have moved through.

It has been competitive from an acquisitioning standpoint.

We have had a (indiscernible) in Shreveport since 1992 and I think that gives us a definite competitive advantage to know what is going on and see those emerging plays.

It absolutely is competitive but we are one of the competitors.

Okay, thank you.

David Tameron.

I was just going to ask about hedging for '04, but I saw you filed the 10Q this morning so I pulled it off of that.

Thanks.

At this time there are no further questions.

Are there any closing remarks?

No, just appreciate your listening and look forward to our next conference call.

Thank you.

Thank you for joining today's conference call.

You may now disconnect.