西南能源 (SWN) 2004 Q1 法說會逐字稿

Good day and welcome to the Southwestern Energy Company first quarter 2004 earnings teleconference. This call is being recorded. At this time, I would like to turn the conference over to the President, Chairman and CEO, Mr. Harold Korell. Please go ahead, sir.

Good morning and thank you for joining us. Greg Kerley and I will be doing the teleconference today since Richard Lane is out of the office due to a death in his family. If you have not received a copy of the press release we announced yesterday regarding our first quarter results, you can call Pam at 281-618-4809 and she will fax a copy to you.

Also, I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would like to warn you that these forward-looking statements of subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results or developments may differ materially.

Well, we have begun 2004 on a very positive note. Our financial results were the best in the Company's history with net income of 24.5 million and cash flow of 56.5 million, an increase of 79 percent and 54 percent, respectively, over our results in the first quarter of 2003. Production for the first quarter was 11.4 Bcfe, up 29 percent from the 8.9 Bcfe we produced in the first quarter 2003 and up from the 11.2 Bcf we produced in the fourth quarter of last year. Due to our early drilling success, we're forecasting that our second quarter production will be near the higher end of our previous second quarter guidance of 11.6 to 12.1 Bcfe. This puts as well on-track to achieve 15-20 percent organic growth in our production for the year.

During the first quarter, we participated in drilling 43 wells. Of these, 28 were successful, 13 were in progress at the end of the quarter. I will talk just briefly about each of the strategy areas. The Arkoma Basin, we spudded 16 wells in the first quarter and of the 16, nine were successful, two were dry and five were still in progress at the end of the quarter.

The Ranger Anticline continues to be a very active value-adding project for us. In the first quarter, we drilled a total of four wells, of which two were successful, one was dry and one was still in progress at the end of the quarter. One of our first quarter successes was the Albright 1-7. This well is located about three miles west of our existing range of production and three miles east of the successful Smith 1-10 discovery we announced late last year. The Albright well tested at a little over 7 million cubic feet a day from the upper borom (ph) and is currently awaiting pipeline construction. We have an 83 percent working interest in the Albright well.

In our last teleconference, we reported that we had encountered 350 feet of a parent pay in the Doggle 2-15 well, just south of the Smith discovery. After testing, it appears that this well is only capable of producing at low rates due to low permeability rock and the lack of natural fracturing.

Finally, at Ranger Anticline, we drilled a trial dry whole on Amua (ph) well, which is located north of the Smith as the lower borom thrust sheet was faulted out. Based on our drilling to date on the Western end of the anticline, it appears that we have a complex geological setting very similar to what we are developing in the main body of the field. Production from the Smith, Albright and Doggle wells will be brought online late in the second quarter after completion of a six-mile pipeline currently under construction. We presently have two rigs running on the Ranger Anticline line and plan to drill approximately 20 wells there this year as we continue to develop the main body of the field and drill delineation wells on the Western side of the structure. To date, we've completed 28 out of 34 wells drilled here, adding over 33 billion cubic feet of net reserves at a finding cost of 85 cents per Mcf.

Now I would like to move to the Overton field. Our development program there continues to be very active and is yielding very good results. In the first quarter, we spudded a total of 22 wells, of which 17 have been completed and five are in progress. We have maintained 100 percent drilling success at Overton that began in 2001. Gross production in the Overton field at the end of the first quarter was over 70 million cubic feet per day, up from 60 million a day at the end of 2003. We currently have seven rigs running at Overton and we expect to drill a total of 70 wells in 2004 with some of the locations being 40 acre spaced.

Based on current well performance, we also anticipate a significant drilling program in 2005. In 2003 and in the first quarter of '04, our average drilling time at Overton has been 23 days per well. This is an improvement over the 27 day average we achieved in 2002 and helps offset increasing costs for materials and services that we are experiencing. In the first quarter of '04, the Texas Railroad Commission approved our request to change Overton's field rules to allow for optional 40-acre spaced drilling. Our drilling results indicate that a significant portion of the field will likely require 40-acre spaced wells to adequately develop the field while other areas of the field will not.

I would now like to move to a brief discussion of the Stockman area. At our last teleconference, we reported that drilling of a successful Cotton Valley sand well at what we call our Stockman, prospect about 50 miles southeast of Overton in Shelby County, Texas. The Beckham well, the Beckham number one well, initially tested at 1.8 million cubic feet a day from the Cotton Valley sands at a little deeper than 10,000 feet. In the first quarter, we've drilled and completed two additional -- or two offset wells and the Stockman 1-4, which we operate with a 95 percent working interest in countered pay in the Beckham's productive interval. Additionally, it encountered pay in a deeper stand at approximately 10,400 feet, which were not present in the first Beckham well. This well is currently testing at a rate of 1.4 million a day.

The second development well, the Beckham number 2, is currently testing at a rate of $2.1 million a day from the Cotton Valley. We expect to drill additional wells in the Stockman area in the remainder of '04 and we hold roughly 3700 gross acres in the Stockman project area.

I would like to move to the Permian Basin. In the Permian, we're continuing development of our River Ridge discovery that we made in 2003. As reported last time, we had just reached a total depth on our Rio Blanco 33 number one well, which is a direct offset to the Rio Blanco Federal Com (ph) number 1 discovery well. We hold a 50 percent working interest in the 33 number 1 well and a 12.5 percent working interest in the 4 number 1 well. In the first quarter, we completed the Rio Blanco 33 number 1, and this well is currently producing at over 9 million cubic feet per day. Additionally, production from the discovery well is holding flat at over 7 million a day. But we believe the overall gross potential size of this Devonian reservoir to be approximately 50 Bcfe. Current plans here call for drilling an additional 2 to 3 wells during 2004.

In south Louisiana, we expect to spud L'Orange prospect and our Duck Lake 3-D shoot in the second quarter. We will operate this prospect, which targets the Marg A sands at about 15,000 or 15,000-plus feet and we will have a 50 percent working interest. As we have discussed previously, we still plan to drill probably two exploration tests in south Louisiana this year and expect to decrease our activity as we go forward.

We are continuing our effort to identify and acquire undeveloped leasehold positions in new venture project to provide exploration and development opportunities for the future. One new opportunity that we discussed in our last teleconference was our Reed Point Coalbed Methane project, located in the Crazy Mountain Basin of Montana. In the first quarter, we drilled a test well on this 95,000 acre project area and we are currently analyzing cores taken from the well to determine its produceability and we will report our progress on this project as the data becomes available.

So in closing, we have had a very good start to 2004, a year which we believe will be an important one for our company. I would now like to turn the teleconference over to Greg Kerley to discuss our financial results and then we will take your questions.

Thank you, Harold and good morning. As Harold indicated, we are off to a great start in 2004. Our strong production growth, combined with higher realized commodity prices resulted in record earnings for the first quarter of 24.5 million, or 67 cents a share, up 79 percent from 13.6 million, or 47 cents a share in the first quarter of 2003. Cash flow provided by operating activities before changes in operating assets and liabilities also set a new record for the first quarter at 56.5 million, up 54 percent from the same period in 2003. Operating income for our E&P segment was 33.4 million for the first quarter of 2004, compared to 18.9 million for the same period in 2003. The improved results were primarily due to a 29 percent increase in our production volumes, combined with a 19 percent increase in our average gas price. We realized an average price of $4.92 in Mcf for the first quarter of 2004, up from $4.15 a year ago. Our average realized oil price was $28.43 a barrel for the quarter, up from $27.69 a barrel last year.

Going forward, approximately 65 percent to 70 percent of our targeted gas production in 2004 is hedged at attractive prices. Our current hedge position is detailed in our form 10-Q that we filed yesterday.

Our E&P segment continues to benefit from some of the lowest operating costs in the industry. Leased operating expenses per unit of production were 38 cents in Mcf in the first quarter of 2004, down from 42 cents in Mcf a year ago. The decline in our per-unit operating expenses were primarily due to the increase in production from our Overton field in east Texas. General and administrative expenses per Mcf were 39 cents Mcf were 39 cents in the first quarter of 2004, down from 44 cents per Mcf in the same period of 2003. The decrease was primarily due to the growth in our production volumes.

Operating income for our utilities segment was 8.8 million in the first quarter, up from 8 million in the same period of 2003. The increase in operating income resulted primarily from the effects of a 4.1 million annual rate increase we implemented in October of last year. The positive impact of the utilities rate increase more than offset the effects of warmer weather in the utility service territory during the first quarter, which was 4 percent warmer than normal and 10 percent warmer than the prior year.

Operating income from our gas marketing activities was $900,000 during the quarter, compared to 700,000 in the first quarter of 2003. Our capital investments for the first two months of 2004 totaled 58.6 million, including 56.6 million for our E&P operations, up from 30.4 million during the first quarter of 2003. Our strong cash flow from operations in the first quarter of 2004 not only funded our increased capital investments, but also enabled us to pay down approximately 24 million of debt during the period. As a result, our total debt to capitalization ratio improved to 41 percent at March 31, 2004, down from 45 percent at December 31, 2003.

Our outlook for the balance of 2004 remains very positive and we continue to believe that we'll generate 15-20 percent growth in both our production and reserves in 2004. That concludes my comments. I will now turn back to the operator, who will explain the procedure for asking questions.

(Operator Instructions). Jeff Mobley, Raymond James.

Hi, good morning, gentlemen. First off, I was curious if you could provide a breakout of your production by region?

Sure, Jeff. Our production volumes in the first quarter in the Arkoma Basin were 4.8 Bcf equivalent; in East Texas, they were 4.3 Bcf and then 1.2 Bcf in the Permian and 1.1 in the Gulf Coast to total 11.4.

Great. And I think Harold mentioned it in his opening remarks what was your second quarter guidance, again, if you wouldn't mind repeating that?

The second quarter guidance that we previously provided was 11.6 Bcf to 12.1 and we currently believe that we will be towards the higher end of that guidance.

Okay, great. Just in terms of the acquisition market, I know there has been some transactions out in East Texas lately. Do you expect to continue to be active in that market as well, or what is your view on acquisitions going forward?

Jeff, we have not been very active in the acquisition market primarily. As you know, our formula calls for us to try to achieve at least a PVI of $1.30 of value created for each dollar we invest. And when we look at trying to compete buying reserves, we don't see those as very -- opportunities that look very good to us. Our program is -- (indiscernible) that's on it has been in excess of $1.30 value creation for each dollar we invest, and that is through putting together things that we drill. So it is not likely for us to be out there competing in the buying market.

I think a positive for us is -- I don't know what numbers you all have -- but the Dale operating transaction that just took place over on the east side of Overton looks like it probably went somewhere in the $2 per Mcf at least value. And that is kind of interesting when you look at valuing our Overton field on a comparable basis.

Okay, great. I noticed that across the board, you really had a lot of improvement this quarter on your operating costs, both in LOEs, G&A, as well as in your utility segment. Could you comment on some of the steps that ya'll took to improve that? And is there any indication that you'll be able to make further progress on that as it progresses is through the year?

Jeff, as you know, operating costs per unit are largely affected by the volumes of production that one produces. And so, as our production is growing, the unit costs are going to go down. That is something we've talked about many times in the past that will occur. We work every day to keep the costs down in each of the areas that we operate. And one basic thing is as our production continues to grow, we're going to see -- we should see those costs per unit come down. And if Richard were here, he might be able to talk to you about specifics of cost savings in the given areas, but I'm not really prepared to do that.

Great, thanks. Nice job on the quarter.

David Heikkinen, Hibernia.

Good morning, guys. I am just curious -- any additional exploratory activity in the Permian plan for this year, and that is the first question?

We certainly have exploration activity taking place out there. Our team of idea generators are working to come up with additional things that we can pursue and so, yes, our idea generation machine is working. We're doing some drilling there in the Cowden (ph) Ranch. We would like to find some more of these Devonian things to do. But they don't pop up every day. So we will be drilling a few more exploration wells out there.

And they are similar to the River Ridge Devonian, or are they just exploratory wells?

We don't have another one of that setting right in front of us now. We have the development to do there, which if we drill another two or three wells there, that is going to add nicely to be production rates also. Depending on -- this is carbonate, so you always have the question of -- do you have the porosity developed at the locations we will be drilling? But the two we have drilled there so far on this structure, which is pretty good size and it offsets a structure to be west that has produced 30 billion cubic feet, and we have very good rates coming out of here. A good-looking section in the two that we have presently drilled.

The working interest in the remaining wells to be drilled -- are they a similar split of one offset at the lower interest, one at the higher?

I think the next well to be drilled, we will have 50 percent in. And there are some other land issues to iron out before we know what interest the others will be. But they would probably be in the 30-50 percent range. But we don't have that completed right now.

Onto Greg, the utility in second quarter typically sees a little downturn. Do you have any feel for what type of operating profit you'll have in the utility for the second quarter?

Well, David, you're right that the utility in the second and third quarter typically incurs some -- is down from the first quarter and the fourth quarter, just for seasonality. We do expect that the rate increase we put in effect at the end of last fall will probably give us at about $1 million a quarter, kind of where our results were last year.

And then onto Crazy Mountain. The coring was completed. You're going to drill another well, Harold, just to core as well, or what are your thoughts there?

I intentionally did not describe that in my comments because we're not sure what we're going to do yet. We are going to wait and get the results out of this core analysis. As you know, when you get coals (ph) and shales and put them in canisters, you start that desorption of it, and it takes a few months to where you have the data. And so we are puzzling about -- do we go in there and complete this well and see what we get, or do we go drill another well? And right now, we just have not decided.

, Okay. And it sounds good as far as on the production side with your guidance being at the high-end. So good job there.

Thank you.

Joe Allman, RBC Capital Markets.

Good morning, guys. Just in terms of service cost, what are seeing in your different operating areas in terms of service cost? And can you remind us what you have done to protect yourselves against increases?

I wish Richard was here to talk intelligently about service cost. I know that, in regard to the drilling areas, we're seeing increases -- I don't think you need to ask me about the increases in steel costs. They are there. We have some protection I know through the first half of the year in regard to our tubulars for Overton. I can't address here because I just don't know specifically the extent of it. The fracture stimulation costs are going up, as I know you would be aware that the service companies are raising those costs. So we're trying to assess completely what the extent of that is right now as we sort of re-project our capital plan for the year. But we are seeing increases and I can't tell you the percentages of them.

Okay, I appreciate that. Thank you.

John Olson, Sanders Morris Harris.

Gentleman, good morning. Harold, is it -- given the fact that you have gotten the down spacing to 40 acres up in Overton and the production momentum is good to excellent, is it too early to come out with a number with your production might look like in 2005 now?

Well, I think it is. We have not projected that, other than just in some simple models. But we think -- the one thing I would say is our production, we would anticipate our production growing in 2005 over the volumes we'll have in '04 because we see another -- as we have talked at every occasion -- probably to drill at Overton 70 wells this year. Next year, there's at least an equal number or more and then some left over into '06. As we think about the rest of our business, the Arkoma Basin continues to generate a base level of drilling in our main fairway area. We're doing some drilling in a shallower sand in the fairway area in the Arkoma as a portion of what we're doing this year. Hopefully, that will develop into something. And then the Ranger Anticline, we have extended, as I mentioned, over to the west there about six miles away, the furthest well had we've had some success and some failure. But it is not unlike what we had in the main producing area. So we think we have a number of wells to drill down in the Ranger Anticline as we go through this year and into next year.

And plus, the things that we're doing that are a combination of development and exploration in the Permian and to some extent in the Gulf Coast, which includes some development drilling in South Texas. Hopefully we will have a success in south Louisiana. We tend to get our dauber (ph) down like we did a couple of years ago in the Permian Basin. And then keeping a little effort there and people generating ideas, we found his River Ridge Prospect. And so you hope for some upside to work in some of these exploration project areas.

I have not given you an exact answer, because I think it's always risky in this business to be given too many exact answers too far out in the future. And since we rely upon our drilling results to generate our production volumes and we don't have a tendency to go do an acquisition to fill layers in there, I would just be cautious about what I am saying. But I am optimistic about '05.

Thank you very much.

(Operator Instructions). Ron Mills, Johnson Wright.

Good morning, guys. A couple of questions as it relates to east Texas. On Overton, with the TRC approved in the 40 acres spacing, you mentioned it would be potential over a significant portion. Do you have any more guidance, in terms of -- do you think that half of your acreage is prospective on 40 acres, 20 percent, or just trying get a sense as to how many more locations you think that could add.

Well, Ron, probably the best thing for you to gauge in the near term is my comment that we plan to drill 70 years there this year maybe 80 or so next year. So in a good -- some portion of that will be 40 acres versus 60. This year of the 70, we'll probably drill, well, in rough numbers, 25 of those, maybe 40 acre spaced wells, and the remaining would be 80 acres spaced wells as we go into '05 at maybe more a higher percentage would be 40 acre. But maybe half to two-thirds of the field area looks like we may be going to 40. And then the open comment still is, for those of who have looked at the Overton map, is at the end of that time, we'll be really pretty sparsely drilled in that south Overton farming area, which we tend to -- we're not drilling a lot down there, just because the economics are a little better drilling north of where there. But all of that area is still pretty wide open. We just recently drilled another well down there that looked pretty darned good to us. So I am hopeful that we have more down there. Maybe we should be touting all of this more optimistically than we are, but we tend to have a wait-and-see attitude at it internally before we get too carried away with talking to the street about it.

Okay. So to the south, you're still drilling, but it's more sporadic and your focus remains really on the north -- is that fair?

I would not use the term sporadic. We have a drilling obligation in order to keep earning that. We have to drill a certain number of wells and so we're doing that. And that is why -- we have a little lower net revenue interest down there than we do up in the main body of the field. So, logically, you put your money where the highest net revenue interest is. That's what we're doing.

Okay. And as it relates to Stockman, then another Cotton Valley play, is the initial thought then that if the wells remain successful that way they have started out, that at first, you would start that field on 80 acres development as well?

Yes, that is probably right. And so far, that looks pretty good to us. We have pretty good acreage spread down there that we're going to continue drilling on.

Okay. In terms of your new venture project areas, we know about the acreage you have in Montana. And I know you have not mentioned any other names, but do you have any other acreage either leased or under option in other areas, in terms of giving us a comfort level that there is more than one new venture position you're working on?

Ron, I presume you're aware that our 10-K, we reported that we had put $11 million into leasing on some I guess 345,000 acres of land last year in 2003. So that definitely fits into the category I think of answering your question.

Okay, thank you guys.

Bob Christensen, Buckingham Research. Mr. Christensen, your line is open. (Operator Instructions) Kyle Henderson, Emperium (ph) Capital.

Good morning and congratulations. Following your announcements on the Doggle Smith and Albright wells, can you give us an idea as to what further activity we can expect in the Arkoma Basin west of the lake in the remainder of '04?

We have two drilling rigs running on the Ranger Anticline in total and we will be moving those back and forth from the main body of the field over to locations on the west side as we get those sections prepared to drill on. We are -- the way the Arkansas rules work now, as we drill on a new section of land over there, we have to go through an integration hearing. So we can't just go out there and do it until we file each one of those. But we will probably drill another six or seven wells over there on the west side, but that could vary, depending upon how some things flow out there. But that would be our current plan.

Okay. Following up on your earlier Crazy Mountain response, the way I read your press release and interpret your earlier answer, should we believe that you will likely be making an assessment as to the future of the prospect from the core samples that you currently have? Or will there be more activity?

That's a good question. I don't know the answer right now. I'll tell you that when -- the well that we did drill and core, we had some disappointments in that we, for example we ran a core barrel (ph) and we ran the state of the art stuff in there to core with, but we'd week drill a core 15 feet and come out of the hole. And we're trying to core through this coal section and we come out of the hole and have 18 inches of core recovery. So we have some unknowns here. We did not get full recovery on our cores, we're trying do understand that means. And we just have not decided what we're going to do there yet. I don't think it would be entirely -- the decision would entirely be made based upon what we desorb out of these coals, because we were missing some of the section. We cored it and we did not recover it. So we have a second sort of tier of analysis to do here about what we have. Do you see what I'm saying?

I do. Well, certainly best of luck and I look forward to chatting with the guys next week in Naples.

Ron Mills, Johnson Rice.

One quick follow-up on the Ranger Anticline. With the variability amongst the geology in the Ranger Anticline, are you getting after drilling I guess four wells or five wells now, a better sense as to what the geology is doing where you have anywhere from 50 or 75 feet of pay to 350 feet of pay in various wells, in terms of directing your future drilling?

Ron, actually, I think we have drilled 34 wells on the Ranger Anticline, and I think 28 of those have been completed, are successful type wells. So the experience -- I tried to make this point when I was talking earlier -- that what we've seen over there on the western side is pretty similar to what we have seen in the main body in the field. So it is variable both stratographically and structurally. We are on a thrust fault, an anticlinal feature that has multiple thrust sheets. It's not just one thrust fault. You have multiple thrust sheets, one upon the other. So you have both complexities to it that the thrust faulting there is -- makes it complex from understanding the structural elements of it. We have probably one of the best structural geologists in the country that works this project for us, or we probably would not even be here doing this.

But that faulting also enhances the permeability of a sand that otherwise is relatively tight. So the thrust faulting gives us the chance of the fracturing that has made this so productive. We do have the variability of the stratiga (ph) free (ph), meaning in some places, we may be in an area where we have higher quality sand and thicker sand. We may be in an area at times like in the Doggle where we had a thick sand but apparently a lot of clay content in it that gave it -- it won't produce as well. Even though it was thick, it's a rattier sand. So when we started this drilling back about four years ago, we were concerned that based on our modeling of it, we had to be at least 50 percent -- we would have to have at least a 50 percent batting average to make it economic. Well, we're 28 for 34 and our finding and development costs are under $1. They're probably -- they're in the 80 cent per Mcfe range. And so what we found over to the west, we are actually quite encouraged.

Okay, thank you very much.

Michael Bodino, Stearn, Agee and Leach.

Good morning guys. Congratulations on a great quarter. I had a probably few really simple questions here, but I wanted to ask you anyway. What is the timing on additional wells in the River Ridge area? Are they second quarter, third quarter?

One will spud in the second quarter. It may be any day now. I'm not exactly sure. I've kind of been -- probably within a week. And the next one world likely be in the third quarter.

Relative to south Louisiana, I see you're going to spud L'Orange. I know you had a few prospects that you were trying to sell. Are all the prospects sold now, and has the appetite been what you expected?

Well, L'Orange we have a 50 percent interest in. Clayton Williams is joining us in that. We have not found partners for the others and we probably are kind of fine with wanting to drill a couple of wildcats down there this year. So I don't think we're shopping that hard on some of these right now.

Okay. I have been hearing some stories about gas storage. Some of the LDCs are trying to get some gas into storage into inventory in anticipation of a hot summer or a cold winter and worried about the volatility in the gas markets. Are you seeing anything in the gas storage facility where people are being a little bit more aggressive right now in trying put some gas in storage?

Well, we're nothing anything that I can speak directly to, Mike. I do know from our utility, we are starting our fill season right now for it. So I assume that the utilities across the country are doing the same thing. And our utility guys when we talk to them are very concerned about the high prices that they're seeing right now from their side of the business.

But you're not seeing any abnormal or concerned activity right now?

Not that I can speak to.

I would say, we don't have really any reconnaissance of that nature, Mike, maybe a good way to answer that, other than our own -- we know within our company the attitude of the utility guys. And these gas prices last winter kind of hurt again. So I can tell you that they are thinking of ways to try to mitigate run-ups in gas prices and will do that both through hedging and through assuring that AWG's gas storage reservoir has as much gas in there as can be put in there, trying to put it in there at the lowest possible prices that they can as we go through the fill season.

Last question. You mentioned Dale (ph) operating and I know that package was out on the street for awhile. One of the things that we've talked about relative to proved (ph) value is the reservoir is a little bit different as you move to east. I know that they don't have the exposure to all of the Taylor sands. What would you characterize -- I figure ya'll had probably looked at this in a little bit more work. Do they have maybe two or three sands there or one or two sands there? Because obviously having all four sands makes a big difference in terms of reserves and returns?

I personally didn't look at it in detail. I know that our guys did study it. And again, I don't have Richard here to fall back on. But what I know of it is one would anticipate probably lower reserves per well then what we have in our area. And therefore on a relative value basis, it should have a lower value. But that again is in the eyes of the beholder and that is just how I would say in a rough way how we see it.

I just didn't know if you knew anything about the reservoir there relative to your acreage. Well, very good guys. Great quarter and I look forward to the next one.

Thank you.

Bob Christensen, Buckingham Research.

On the six-mile pipeline to the west on the Ranger Anticline, what kind of diameter is this? What kind of capacity are you installing to get gas from the western side of the Anticline?

Well, we hope it's enough to produce anything through that we drill up there. But it could probably handle 40 or 50 million a day. It does not cost a whole lot more to out larger pipe in to be sure you have capacity.

Sure. And how many wells do you think you will drill out to the west this year left to spud? If you have some guidance on that?

We have two rigs drilling -- I mentioned this earlier -- we have two rigs drilling out in the Ranger Anticline right now and we will be moving them back and forth as we get locations ready. But probably six or seven out to the west.

Harold, is it impossible to drill beneath the lake at some point in time in the future? I mean you see that on your map. I've been meaning to ask that question. It seems to go directly -- 6000 feet down to get directional might be a little hard. I don't know.

You know, you have the limitations of the extended reach on whatever those are. We have a setback off of the lake that we can't set up and drill right at the edge of the lake, and I don't even know what that is here. But if it becomes something we want to do, we'll just have to look at the economics of it. You know, you can drill horizontal wells today for miles. So it's just a question of the cost and the economics of it. But we are not to a point of answering that question yet, because we have plenty of space to drill there right now.

Thanks a lot, Harold.

You bet.

Joe Allman, RBC Capital Markets.

Hi again. Harold, how many pud locations are you drilling this year at Overton out of those 70 total wells?

I couldn't tell you specifically. I can tell you that we have roughly 20 pud locations booked at Overton, which is a very conservative number relative to what one could book, given that we could book a pud location offsetting generally any well that currently exists in the field. So that -- in general, that answers that question. If we drill 20 that are on the books as puds this year, you know, one could choose to book another 20 at the end of the year offsetting these. So reserve-wise, we are a darn conservative position at Overton.

Alright, thank you.

Ron Mills, Johnson Rice.

This is the last time, guys. Greg, this is actually for you. On your E&P revenues, there was an extra $3 million in the quarter from selling gas out of storage. Out of curiosity, do have any information, in terms of what volumes you sold out of storage and what the average cost of that gas was?

We sold -- and we had a similar activity in the first quarter of 2003 also, Ron. But we sold about 2.5 Bcf of gas. And it's probably in the ground at a little over for 450 is what -- we have two different things. We have what we call working gas, which is in the ground at that kind a little higher, that kind of average price. And we have cushion gas of about 6 Bcf that is in the ground historically at a less than $3 price that we have in the ground that used to help meet the pressure needs of the reservoir to deliver the peaking needs of the contracts that we have.

And how much of working gas do you have?

Working gas, we started the year with about -- a little over 3 Bcf, so we're down to about 1 Bcf left of what we had injected in working gas last year. So you will probably see us inject some working gas this summer.

Okay, thank you very much.

We are standing by with no further questions at this time. Mr. Korell, I'd like to turn the conference back over to you for additional or closing comments.

Just to wrap this up, overall, we believe this year of 2004 is going to be a very exciting year for our company and our shareholders. And with the pace of drilling that we have budgeted for this year, we look forward to production and reserve gross over 2003 and those ought to be in the double digits. So we also look forward to successfully testing some of our new ideas areas later this year. And I want to thank you for joining us and this concludes our teleconference.

Thank you. Once again ladies and gentlemen, that concludes today's conference. Thank you for your participation.