西南能源 (SWN) 2003 Q2 法說會逐字稿

Good day, everyone, and welcome to the Southwestern Energy Company's second quarter 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 today. With me today are Richard Lane, our Executive VP of exploration and production and Greg Kerley, our chief financial officer. If you've not received a copy of the press release announcing our second quarter results, you can call Sharon at 281-618-4784, and she'll 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 the Securities and Exchange Commission filings. We also would warn you that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To start off with, I am very pleased with our progress so far in 2003. The plan that we described back in February is delivering the results we had hoped for. High commodity prices helped drive our earnings to a record $9.5m in the second quarter. Our cash flow was also strong at $28.5m, which was over 60% higher than in the second quarter of 2002. While the current commodity price environment has helped our entire industry, we also are seeing a steady rise in our production volumes, which were up 14% over our production level in the first quarter, primarily due to the accelerated drilling at our Overton Field in East Texas.

Our Overton project is going very well. As of today, June 30th, we had 29 wells either drilled or in some stage of being drilled and completed. Gross production from the field today was approximately 54 million cubic feet of gas per day, which is roughly double the 2002 year-end rate of 27 million a day. So things continue to go according to our plan with our infill drilling program there at Overton, and our economics are very good at these high gas prices.

The Arkoma Basin drilling program continues to deliver as well, and we expect our Ranger Anticline area to yield meaningful results with the down spacing opportunities we have there. We announced in our press release that we are increasing our exploration and production capital expenditures by $15m, for a total of $165m for 2003. Most of the increase will be directed toward our activities in the Arkoma, particularly in the Ranger Anticline area, and an additional amount at Overton. Richard will speak more about our E&P program in just a moment.

On the utility side, we announced a settlement agreement on July 17th with the staff of the Arkansas Public Service Commission and various consumer groups regarding our rate increase request, and Greg will give you an update on this in just a minute.

To close, our drilling program is going very well, and I am pleased with the results to date. We are looking forward to the remainder of 2003, and we're excited about 2004. This is a very exciting time for our company. That concludes my comments, and I'll now turn the conference over to Richard for an update on our E&P operations and then to Greg to discuss our financial results and then we will be available to answer questions.

Thank you, Harold, and good morning. In the second quarter of 2003, we benefited from the increased drilling activity at Overton and the Arkoma Basin with higher well-head production volumes. Production in the second quarter was 10.1 Bcfe, up 14% from the 8.9 Bcfe in the first quarter. Results of our drilling program are creating production growth, and we expect our third quarter production to increase as well in the range of 10.5 Bcf to 11.5 Bcf in line with our previous guidance. In the first half of 2003, we have participated in 68 wells in our core operating areas of the Arkoma Basin, Gulf Coast, East Texas, and Permian Basins. Of these, 49 were successful and 11 were in progress at the end of the quarter.

This well count is greater than the 65 wells we drilled in all of 2002. On a year-to-date basis, we have invested $75.2m in our E&P efforts as compared to $37.8m in the first half of 2002. In the Arkoma Basin, we participated in 18 wells in the second quarter in contrast with 10 wells in the first quarter of this year, and 11 wells we drilled in the second quarter of 2002. Of the 18 wells, 10 were successful, four were dry, and four are still in progress.

We continue to find strong producing wells in the fairway area of the basin. Two wells of note in the second quarter are the Page [ph] 128 and the Parker 129 wells. We operate both of these wells in Franklin County, Arkansas. We hold a 100% working interest in the Page Well, which was completed in the L [ph] sand and put in a production rate of about 6.5 million cubic feet per day. The Parker 129, also an L [ph] sand completion, and we operate this well, and it was put on product at a rate of 4.7 million cubic feet per day with an 87.5% working interest. So these are more examples of high-productivity operated wells with high ownership levels being found in our mature fairway play.

At our last teleconference, we discussed a recent change in the Arkansas state law concerning drilling units. Act 964 provides operators in the state the ability to pursue multi-well development of original 640-acre units when applied for on a field-by-field basis and supported by technical data. Earlier this year, we were able to successfully obtain regulatory approval to reduce well spacing from 640 acres per well to 80 acres per well in our Ranger Anticline area. In 2003, to date, we have drilled six wells in the area. Of these six wells, three of them put on production at an average rate of 2.5 million cubic feet per day per well, and the other three are currently being completed. Southwestern operates five of these six wells, with a working interest ranging from 73% to 100%. We currently hold 4,480 gross developed acres and over 35,000 gross exploratory acres in this area, which is in Yell County, and our plan is to drill approximately six to eight more wells here in the remainder of 2003.

In the Permian Basin, we continue to focus our drilling activity in our Cherry Canyon and Devonian plays. In the first half of the year, we drilled and completed three horizontal wells on our Birds of Prey prospect in Eddy County, New Mexico. Typically, our wells in that field have a horizontal section of about 1,900 feet and are drilled to a Cherry Canyon depth of about 4,850 feet. By refining our drilling and completion practices, we've been able to materially increase the economic returns of these horizontal wells over that of a normal vertical producer. Total production from the area is approximately 260 barrels of oil per day and 128 Mcf per day. We operate these wells with a 100% working interest and are currently planning an additional well for this year.

In addition to our Cherry Canyon play, we are currently drilling a test of a deeper Devonian gas prospect, our Rio Blanco prospect in Lee County, New Mexico, will test the Devonian formation at approximately 15,000 feet. Southwestern holds a 12.5% working interest in this initial well and will hold a 50% working interest in the subsequent test. Overall, the prospect has approximately 30 Bcfe of gross unrisk [ph] potential, which is typical of some of the adjacent areas.

At the time of our last teleconference, we were drilling a sidetrack of our Shiloh prospect in South Louisiana. Due to mechanical problems, we were unable to evaluate the sidetrack hole and have temporarily suspended operations on this well. We are currently evaluating our alternatives, which may involve bringing in another working interest owner to jointly participate.

In the second quarter we also drilled a third well on our North Grosbec discovery in Assumption Parish. We hold a 33% working interest in the Brown-Sonnier (ph) #1, which targeted the field producing P-10 pay [ph] sand at a depth of approximately 17,000 feet. This well was a disappointment and was plugged and abandoned after log analysis indicated that the sand was wet.

Current gross production from North Grosbec field, however, remains strong at a rate of approximately 14.6 million cubic feet per day and approximately 500 barrels of condensate per day.

Our next South Louisiana exploration well will be our Coleburn (ph) prospect located in Jefferson Parish. This well targets the Tex W sand at 12,700 feet and will spud during the third quarter. We will operate this well with approximately 50% working interest.

We continue to interpret and formulate exploratory drilling plans at our 135-square-million Duck Lake 3D seismic project. In the second quarter, we continued leasing state and fee lands under many of our IDFs. We expect to spud two or three wells on this shoot this year and have identified several additional leads that we expect will yield opportunities for 2004. We expect to operate all these wells with approximately a 50% working interest. The first well to be drilled is our Canvasback prospect, and this ADB cfe potential prospect will be spud late in the third quarter and will test the Lee Bacella [ph] sands at approximately 18,000 feet. The second well is a 110 Bcf reserve potential Daffy prospect. This well, which is expected to spud in the fourth quarter will test the five D [ph] and Finulotta [ph] sands at a total depth of approximately 14,500 feet. Finally, we may spud a test well on our Redhead prospect late in the fourth quarter.

We have continued our significantly increased activity at Overton Field. In the second quarter we drilled 16 wells of which 11 are currently producing and the other five are in progress. On a year-to-date basis, as Harold mentioned, we have drilled 29 wells while maintaining our 100% success rate. The completed well costs have averaged approximately $1.5m per well, and our production rates and our estimated recoveries for these first-half wells are on track with our expectations for this program.

As discussed last time, we are continuing to set production record highs for the field as a result of our drilling program. At year-end 2002, gross production from the field was approximately 27 million cubic feet per day. Currently that has doubled to approximately 54 million cubic feet per day at the end of the quarter.

In the third quarter, we expect to have additional market capacity of approximately 60 million cubic feet per day for production from our Overton activities. We are also continuing to lower our drilling time at Overton in the second quarter with one of the H&P flex rigs. We set a new record by taking only 17 days from spud to total depth on our right 1-2 well. So far in 2003, our average drilling time has been 24 days per well, which compares favorably to last year's average of 27 days per well.

In 2003 we plan on drilling approximately 55 wells. The Overton Field is located in Smith County, Texas, and produces from the Taylor series of the Cotton Valley formation at approximately 12,000 feet. Southwestern holds an average of 97% working interest in this area.

Our lease operating costs in the second quarter were $3.6m, or 36 cents per Mcfe, and this compares favorably to our first quarter '03 costs of $3.7m, or 42 cents per Mcfe and second quarter 2002 costs of $4.4m, which was 42 cents per Mcfe. We expect our operating costs per unit of production to continue to drop through the remainder of 2003, primarily due to our increasing production.

As Harold mentioned, since our last teleconference we have increased our 2003 E&P budget from $150m to $165m. The majority of the increase will be directed to additional development drilling on our Arkoma-Ranger Anticline project, increased non-operated activity in the Arkoma Basin, and further drilling at Overton. All of these investments from our inventory of projects have fairly low risk and yield high PVIs.

In summary, our second quarter results were in line with our expectations and our 2003 plan, and we are pleased with our year-to-date drilling program. Because of this program, continued strong commodity prices and our efforts to control operating and drilling costs, we have captured more value through our E&P program. We are well positioned to take advantage of higher cash flow to invest by having a strong inventory of projects, and we continue to focus on adding value with every dollar that we invest.

I will now turn the teleconference over to Greg Kerley, who will discuss our financial results.

Thank you, Richard, and good morning. As Harold indicated, we have very strong financial results for the quarter driven, in large part, by higher commodity prices. We reported net income of $9.5m, or 26 cents a share for the second quarter of 2003, up from $1.8m, or 7 cents a share, for the same period in 2002. Discretionary cash flow was $28.5m during the second quarter, up from $17.4m in 2002. Net income for the six months ended June 30, 2003, was $23.2m, or 71 cents a share, up from $8.5m, or 33 cents a share for the same period in 2002. Our discretionary cash flow was $65.2m for the first six months of 2003, up over 50% from $43.3m for the same period in 2002. Operating income for the exploration and production segment was $21.5m for the second quarter, up from $10.1m for the same period in 2002. Our gas prices realized what our production averaged, $4.28 per Mcf for the quarter and $4.22 in Mcf for the first half of 2003, up 45% and 48%, respectively, from the same periods in 2002. We realized an average price of $27.54 a barrel for our oil production during the first half of the year compared to $20.10 per barrel for the same period in 2002.

Our commodity hedging activities lowered our average gas price by 86 cents at Mcf during the second quarter and by 37 cents an Mcf in the prior-year period. Our hedging activities also lowered our average oil price by $1.40 per barrel during the second quarter of 2003. Our hedge position for the remainder of 2003 is unchanged from the detail provided in our Form 10-K. However, during the second quarter, we placed price collars on an additional 4 Bcf of our expected natural gas production in 2004 with an average floor price of $4 per Mcf and an average ceiling price of $8.50. Our detailed hedge position is included in our Form 10Q filed yesterday.

Our E&P segment continues to benefit from very low lease operating costs. Operating expenses decreased during the second quarter of 2003 to 36 cents an Mcf, down from 42 cents an Mcf in the first quarter. The decrease was primarily due to increased production from our Overton Field. Our production taxes were up from the prior year as a result of higher commodity prices and general and administrative expenses were 40 cents an Mcf for the second quarter of 2003, down from 44 cents in the first quarter but up from 28 cents in Mcf in the second quarter of 2002.

As we discussed in the first quarter, the comparative increase from the prior year is primarily due to increased pension and other general expenses and the accrual of incentive compensation costs.

Our utility systems realized a seasonal operating loss of $2.1m in the second quarter of 2003 compared to a loss of $1.7m for the same period in 2002. Operating income for utility systems was $5.9m during the first six months of 2003, down from $6.9m in the prior year. The comparative decreases in operating income were primarily due to higher operating and general and administrative expenses.

In November of 2002, our utility subsidiary, Arkansas Western Gas Company, filed an $11m rate increase request with the Arkansas Public Service Commission. On July 17th of this year, AWG executed a joint stipulation and settlement agreement with the staff of the Arkansas Public Service Commission and various other consumer groups that would resolve all outstanding issues related to its rate-increase request. Under the terms of the settlement, Arkansas Western Gas would receive a rate increase of $4.2m annually and would also be entitled to recover certain additional costs totaling $2.9m over a two-year period. The difference between the $11m rate increase requested by Arkansas Western Gas and the rate adjustment contained in the settlement, primarily results from a reduction in AWG's requested return on equity and its rate-increase request, AWG assumed an allowed return on equity of 12.9%. The settlement provides for an allowed return on equity of 9.9%, which is in line with the equity return approved in recent settlements that have been approved by the other two Arkansas local gas distribution companies.

The settlement agreement is subject to the approval of the Arkansas Public Service Commission. A scheduled hearing was held at the Arkansas Commission on July 22nd and 23rd to hear testimony of AWG, the staff of the Commission, and the various other intervening parties that support the settlement agreement, as well as to hear testimony of the office of the Attorney General, who opposes the settlement. The Commission has requested the various parties file post-hearing briefs addressing the proposed stipulation settlement agreement by August 7th, and the effective date of any rate increase has been extended until the 1st of October. If the Arkansas Public Service Commission approves the settlement, we would expect to see a return to a more normalized profitability for our utility business.

Our energy marketing efforts also provided approximately $500,000 of operating income during the second quarters of both 2003 and 2002. Our capital investments in the first half of the year totaled $80.5m including $75.2m for expiration of production segment. We currently expect our total capital investments for 2003 to be approximately $173.6m, up from $92.1m in 2002. Our total debt outstanding was $247.8m at June 30th, including $22.8m outstanding under our revolving credit facility. As a result of our successful equity offering in March, we've reduced our debt-to-total-capitalization ratio to 45% at the end of the second quarter, down from 66% at the end of 2002. We currently expect our debt-to-capitalization ratio to remain at approximately the same level for the remainder of the year.

That concludes my comments, so now we'll turn to the operator, who will explain the procedure for asking questions.

Thank you, the question-and-answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touchtone phone. If you are using a speakerphone, please make sure your mute function is on in order to reach our equipment. We will proceed in the order that you signal us and take as many questions as time permits. Once again, please press star, 1 on your touchtone phone to ask a question. We'll take our first question from Jeff Mobley (ph) with Raymond James.

Good morning, gentlemen, congratulations on the good quarter, particularly good results around the LOE front. A question for you -- you say you have five rigs -- or five wells -- in progress in the Overton Field. Does that imply that you have five rigs in the field now?

Jeff, this is Richard. We do actually have five rigs out there right now. We've picked up a fifth rig here just recently for a well or two that we wanted to fit into our schedule but, for the most part, we'll be staying at the four-rig count for the year.

Okay, so you'll stay around four?

Right.

So the fifth -- the $15m increase in capex, is that directed more towards the Arkoma or how would you characterize that between your different regions?

About two-thirds of it would be associated with the Arkoma and East Texas, and the remainder would be in our other operating areas and in places where we're getting more outside submittals of projects that look pretty good to us that we want to participate in and covering some of that as well.

Okay, good. In terms of the production by region, could you give us a breakdown of what the production looks like in each region?

Sure.

And give an average for the second quarter exit rates, either one?

Sure. Of the 10.1 Bcfe that we reported, 4.7 of that is in the Arkoma; 3.2 of it in East Texas; 1 Bcfe out of the Permian; and 1.2 out of the Gulf Coast.

Okay, great. As far as your exploration program goes, previously you guys had kind of indicated that gross reserve potential on your first three wells at Duck Lake were around 95 Bcfe, but your first two wells look like it's closer to 200. As you guys have gone through the seismic data, does it appear like that play looks more prospective than you previously thought?

Well, in terms of the number of ideas and the things that are gelling from it, I think that prospectivity is kind of what we thought. We're starting to -- you know, as we work these things in more detail, and we're really quantifying the potentials and engineering the wells, I think our net and gross potential has gone up there as we detail out those prospects, yes.

Great, great. And finally, as far as the rate increase opposition that you're facing from the Attorney General's office, how big a risk do you think that the rate settlement that you all reached will wind up being materially different than what you had previously thought?

Jeff, this is Greg Kerley. That's awfully hard to tell right now. I think the Commission has asked for briefs to be filed by the parties, and we are filing a joint brief with the staff, the Commission, and the other interveners who all support the settlement agreement. The Attorney General is the only intervener that opposes it, but the Commission will -- those briefs are due to be filed the 7th, and then there's also a public comment period that takes place for a week or so after that. So we'll just be waiting for the Commission's order after they've digested all the material.

Great, okay, congratulations again. Nice quarter.

Thank you.

We'll take our next question from Joe Allman (ph) with RBC Capital Markets.

Good morning, everybody.

Good morning.

Could you -- Harold or Richard -- could you talk about the Ranger Anticline in terms of how many locations you've identified for additional drilling beyond the six to eight you're going to drill this year and what the reserves per well look like and the costs per well and how much you've booked already there for -- how much you've booked just in terms of reserves?

Sure, Joe, this is Richard. I'll try to cover that for you. I think probably the first thing to say about that play is that it's different than our Overton play in the complexity and in the geology. I don't think you can think about it as these blanket Cotton Valley sands like we're pursuing in East Texas, although we have had a very high success rate. But the geology is more complex, and I think as we develop it, it will -- we'll be, in general, wanting to evaluate the wells that we've recently drilled prior to pushing forward. So a little bit different -- I think I would just kind of categorize it that way.

I think, for next year, we're looking at being able -- though we haven't formulated all our plans there, but it looks like we could drill the amount of wells that we are forecasting for 2003, we could do that again in 2004 as long as the performance is still there as we watch this. So I would kind of look for something in about the 15-well range for next year, and we'll just have to watch the performance of these wells as we go forward.

The typical cost out there depends on the conditions where we're drilling. Again, it varies more than some of our other areas, but they're about $1m wells that could go up to $1.2m, depending on how deep we're going. The depth ranges there from 5,000 to 8,000 feet. And we're looking at reserves that are, you know, a low of 1 Bcf to as high as 2 Bcf per well. And, again, that's variable, but all those ranges of reserves and costs, pretty much in any combination, gives you a very economic project.

And then for the additional wells you're drilling this year, do you have PUDs [ph] booked already, or everything you're doing this year is incremental in terms of reserves?

Yeah, it's all incremental -- we'll be doing incremental reserves. We don't have any undeveloped locations on the books out there.

Okay. You mean, because of this legislation in Arkansas, I mean, are there other similar-type plays that you're looking at or that you've applied for to do down spacing?

Not that we have in a producing, developed state. We have some other exploratory ideas that are similar in their geologic nature that could evolve to that kind of thing, but, no, not in a producing field right now, are we really pursuing another big area like that.

This is Harold -- just another comment on it. I think Richard's comments about this kind of are focused in the area where we've been drilling; specifically where we had, I guess, 13 wells, more or less, producing at the end of last year, and we'll probably drill another 14 this year and, as Richard said, if things go well, we'd have at least that many to drill in 2004 and possibly more. That's on the developed acreage, and then we have the -- kind of an interesting thing for us is the acreage that we hold to the both east and west of this developed area on which we are planning to drill a wildcat -- well, we call it a wildcat, we're stepping out probably three or four or five miles on trend, on the same structure. The question is -- what's out there? As Richard mentioned, we've got some 35,000 acres of exploration that could be, you know, very good out there. So this has -- I don't think we want to be in a position of trying to get ahead of ourselves on what it could be, but, you know, it could develop into a pretty darn significant project for us. It's one of the things for us to keep an eye on and for you guys, certainly, to be interested in.

Okay, and then just shifting over to East Texas, have you been successful in purchasing more acreage since the last conference call?

We don't have any really large blocks to report, Joe. We have -- we continue to add small pieces of ownership and new leases on the flanks and internal to the field and working on some other areas to try to bring into the fold but no real big blocks to report to you.

And then any update on the down spacing of 40 or 50 acres?

Well, we're working on that as a technical issue. We continue to study that. The performance of the recent wells we've drilled and we'll be doing that analysis through this year to try to get a better handle on whether that 40-acre development is likely to come about. I mean, we have said, in the past, and still believe that when you calculate drainage areas out there, that you get a number significantly lower than 80 acres. So we'll be working on that this year and trying to understand it as we go forward.

Okay, and then lastly, and I'll give somebody else a chance, in South Louisiana, that third well at North Grosbec (ph)-- if I remember correctly, that was developmental in nature, which, to me, implies you had some reserves booked on that. Is that right? And if that is the case, what kind of negative reserve revision would we be looking at?

Yeah, it was an undeveloped location, you're correct about that -- disappointing, because we really did think it was a proven location. You know, our nets in the field were started out lower than a lot of our other ones. That's, you know, good and bad. We were pretty much at a 25% working interest. So the net effect of that well will assess and we'll take at year-end, but I think we're going to be somewhere in the 5 Bcf to 6 Bcf range of a revision. So it's pretty insignificant in the overall scope, if you look at where we're going to be at year-end as a reserve price for the company.

Okay, thank you.

We'll take our next question from Van Levy [ph] with CIBC World Markets.

Good morning, gentlemen, how are you?

All right.

To me, the impressive thing in the quarter is the sequential comparison. It looks like, as you mentioned, production is up 14%. Cash costs look like they're down 19%, and I just want to get a sense of trends. Can we extrapolate forward the second quarter unit LOE, which was somewhere around 36 cents, going forward?

Van [ph], this is Richard. I think we had given some guidance previously that we would -- could attain 35 cents per Mcfe of production for the whole year, and I think, you know, as the production grows -- we're pretty confident it's going to grow -- I think that we'll attain that number. We had a range of 30 to 35. I think we'll get inside that range, and that will come primarily from holding our absolute cost dollars constant in the production coming up.

Okay. Second question in Overton -- how many penetrations do you have in that southern block that was large undrilled and how confident -- what kind of risk -- do you see -- what kind of reserves per well, et cetera, characteristics, relative to the main area? Can you give us a comparison there?

Sure. I believe when we started out there that we had nine units. There were a couple of those units that had extra wells in them already when we acquired it -- or -- when we farmed it in. So I think we started out with probably 12 there. We have done, I think, four wells ourselves down there. So that would bring the total to about 16 wells on that block. And we're pleased with the results of the new wells that we've done down there.

I think we've got one more, two more in here.

We may have five to six that we've drilled there, because we had four at the end of '02. I know we drilled at least one additional this year, and we have to drill one every 120 days there, and, Van [ph], you might remember that, and in order to continue to earn the acreage. So our effort is mostly in the northern part, because our net revenue interests are higher up there, and so that's still an open area, pretty much, down there.

So with this new data, at this point, would you feel comfortable recasting -- I guess you'd mentioned 100 wells over the next couple of years -- maybe recasting that number? And can you see possibly more locations?

You know, in general, I think we'll more or less stick with our plan of the 100 -- that's probably 100 plus a little bit at this point in '03 and '04, and then the upside for this project is, you know, what about the acreage to the south? We, quite frankly, haven't worked real hard on it, because the terms of our deal down there aren't as good as the north, but we are drilling and, so far, the results to the south have been fine in the areas we've drilled in. The question is -- and you raise a good question -- maybe we should be stepping out away from it instead of kind of drilling right along where we have -- we've been drilling locations pretty close to ones that already exist. Maybe we ought to step out a little bit in there and test one.

But that upside is there, but we don't have to get in a hurry over it, and the other part is that I think someone asked the question earlier about can we eventually drill this entire area down to 40-acre spacing, and that question -- you know, production data helps you answer that question, and we're going to be getting data on 80-acre spacing, since we're now producing there, and likely we'll drill some 40-acre-spaced wells this year sometime and then study the information from that. So I still think this field has a ways to go, once we've drilled our current round, but time will tell that.

Okay. Duck Lake -- how many prospects and leads has this 3D shoot generated and how many are leased? And then maybe you can give us, Richard, the Canvasback -- kind of the geologic concept; go through the analogs; give us the risk; and reserve potential -- can you talk to that?

Sure. The ones that we would call prospects that we're ready to talk about are the ones I mentioned -- Canvasback, Daffy, and Redhead. There are three or four other leads that we're working and trying to pull those together. Canvasback is, to me, is a very attractive opportunity. It is high risk. It's an 18,000-foot well, and so it's nothing you should count on, certainly, but it's an attractive exploratory test in that the little sub-region that it's in, there have been some very nice accumulations found in the section that we're exploring for. To the northwest, in the Miet [ph] Point area, there has been some very nice fields found in that section, and then our Grosbec Field, to the east and northeast of where Canvasback is, sets up pretty similar in terms of the section and the type of trap. So we like those analogies and certainly the reserve potential but, again, it's down in the low [inaudible] category.

Okay, and what would you say is the principal risk here?

Oh, I would say, you know, that we're at 18,000 feet, and we're trying to image a trap and hope that the trap is there like we have depicted, and it got charged with hydrocarbons, and I think that's probably the main thing. Some sand risk, but the sand picture looks pretty good.

Okay, last question -- and this is for Harold -- conceptually, it looks like what's emerging with the company is a couple of manufacturing plays -- lower risk, steady sort of performance with Overton and Arkoma and this Ranger play. How do you balance that, Harold, with the South Louisiana, which, by nature, is lumpier and, in large part, it's a game of larger numbers? And how is your thinking evolving, given the success in the other areas?

Well, that's a good question. You know, we would all like to be able to have predictable, high PVI projects and have no risk in them. In our business, you know, we look long and hard for the kinds of things that Overton has turned into and the things that we continue to be able to generate each year in the Arkoma basin and that, so far, a development on the Ranger Anticline represents. So if we could -- if one could have all those kinds of things laying in front of them, I guess no one would have to take any risk. But in terms of balance, I think that the fact that we do have such a large percentage of our capital going into those kinds of projects, it's kind of interesting to have sort of a shot at something that produces at a lot higher rates, if and when you do find it.

So South Louisiana does represent that part of a portfolio, and that's kind of why we like what we -- the types of things we've been doing there -- the risk/reward in South Louisiana is pretty good. I will tell you, when you sum everything up right now, our finding and development costs there have gotten higher than we'd like, and so, as I've said in prior conference calls here, we need to have some success there to keep the size of commitment there that we have going currently, because we are driven by economics. There was a time when we had six successes out of eight, and tremendously low costs and very high PVIs. So we like this Duck Lake area. It seems that when we look at our overall success in South Louisiana, we have been successful where we have conceived of a 3D seismic shoot, based upon regional geological work and lead ideas and then shot the 3D. Then the first eye is to see data, particularly in this deeper section, apply our brain power to ferret out where opportunities exist and then drill those. And Booray [ph] area, with the Malone, Glory, and North Grosbec discoveries, and then up in the Noticeria [ph] shoot, have been our two really more successful areas, and where we seem to have stumbled a little bit is where we bought shelf data and tried to ferret out ideas where somebody else might have already looked at the 3D.

So in terms of strategy, what we'll be doing the rest of this year will be driven around Duck Lake, which -- where we just have, you know, last year shot the 3D and hopefully we'll get back to the higher success kind of rate that we were experiencing in Booray [ph] and Noticeria [ph]. Now, you know, if we don't have that, we'll have to look pretty long and hard at how much capex we want to put into these types of projects in the future, but we do like the idea that we've got some pretty substantial targets here, and that when they work, they can really add substantial production rate to the company. On the other hand, if they don't work, everything is fine, because -- well, everything is fine -- you could have said, "Well, you shouldn't have spent that money," but I think the risk/reward is a good relationship there.

So I don't know if that answers the question, Van [ph], but that's my shot at it.

No, that's good, and, I guess, in the sense of Duck Lake, you originated, and so you're laying off the risk by promoting other parties. Okay, thank you very much.

Once again, you may press star, 1 if you'd like to ask a question. Next we'll hear from Barry Sahgal (ph) with Brean Murray and Company.

Gentlemen, I'd like some more color on the Ranger Anticline. Perhaps you could give me some guidance as to what your net interest position is in the 35,000 acres that you talked about?

Okay, this is Richard.

Hey, Richard.

We're still doing some leasing out there, so it's kind of a changing number all the time, but, for the most part, you can kind of think of it as we have pieces of several of these sections, these 640-acre sections, but I think we're probably, on a net basis, we're somewhere north of 60% of that gross number.

Okay, and is this a seismically controlled play? This is a very old play, so I can't imagine there being any new seismic that's being shot on it.

We have some 2D seismic data across the area that we have license to, and that we're working to try to understand the area and help guide us in what we're doing, but it's mostly understanding the well control and the structural configuration of the area.

Richard, I might try to -- I'm not sure when Barry's question -- he probably is thinking about this being the Arkoma Basin, and therefore it's an old, well-known area, but this area that we're drilling in is in the southern part of the basin as you move sort of down in the depositional environment, down the slope and into the more distal fascia, and so we're not up in the old, mature area of the basin, and most of the drilling that's been done here began in -- I guess, for us -- began in 1997. There weren't many wells down here, and we participated in the first of those wells back in 1997. So this is not up in the old, sort of, what you would think of normal play in the Arkoma Basin, which you may have as your backdrop. So it is in a different area. It's not in the channelized part of the depositional environment, but rather it's out in the fan area where the sands tend to be more continuous. But we're in a structurally complex area, because we're in the thrust belted area. So that adds some complexity but, you know, I guess we're 18 of 21 wells there at this point. It may be a better statistic than that right now, but the last number I remember is we had drilled 21; 18 were successful. So statistically it's been good in spite of the complexity. The complexity may actually make it more homogeneous because of the thrust vaulting and the repeated sections of sediments that we get into.

Harold, what's holding you back from accelerating your program over there? It seems like '04 is going to be -- you know, 15 wells is about the same as '03. Is it just a geological density?

Well, we are accelerating the program there, and that is part of the $15m that we're doing incrementally that we've increased our capex this year. What we were doing is we're going very carefully. In fact, we were, in the past, could only drill one well per 640, and we would go in and try to get an exception location to drill an additional well, and we'd have to go through a hearing, and all that would take time, and then we finally got approval in the Waveland [ph] Field, as it's defined, which is on the Ranger Anticline, to down space it to one well per 80. That allows us to accelerate in itself, and then there are little land complexities, because there are bits and pieces of land that may still be open that we have to get leased and get the drilling unit formed and move forward. So we are accelerating it.

Could we accelerate it even more? Well, maybe. You know, there's a lot of work that -- you know, you have to put each little -- each drilling location together in terms of the land. But then we're sort of in -- I'd say we're kind of in the first round of acceleration, if you will, here. You know, we're drilling with one rig continuously now; whereas, we were getting a location ready, getting a rig and drilling it. Well, we know, from everything we've done, when we have a continuous operation, we're able to cut our costs down. So we just made the decision to keep one rig running the rest of this year. Do we go to two rigs sometime? We don't want to accelerate beyond our learning curve. So that's kind of the main thing, and we'll try to do the right thing.

At Overton, what's the pipeline capacity situation over there?

This is Richard. Probably the biggest development there is that we're about to finalize a new take point for us with a 10-inch line that Gulf South is installing that will be in service here probably within less than 30 days, and that's going to add an additional 60 to 70 million cubic feet of capacity to our already existing capacity. That will be kind of a third option for us for any kind of takeaway that we need for the field, and it will bring our total out there well in excess of where we forecast we're going to be here over the next couple of years. So we're in good shape there.

One last question -- I may have missed this -- initial first cut on capex for 2004?

We haven't talked about '04 yet. We're just in the throes of putting together our '04 plan, but it would appear, you know, based on all of our early work in terms of our cash available to reinvest that we ought to have at least this size program that we're having this year, next year, if not larger.

Terrific, thanks, gentlemen.

Next we'll take a question from Ken Beer with Johnson Rice and Company.

Hey, guys. Actually, all of my questions have been checked off. Thank you so much.

We'll now move on to Evan Smith with Sanders Morris Harris.

Hey, guys, good morning. Richard, a question on Ranger -- what do the decline curves look like there, and what's your guess at lives?

What was the second part, Evan?

Well lives -- what's your guess at how long those lives -- those wells -- will produce?

Well, they're tight gas sands, low porosity and permeability, and we think we have some fractures coming into play there that affect the productivity in a positive way. I think probably the best way to think about them is they're definitely hyperbolic decline-type reservoirs, so they'll start out and decline very steeply the first few months. But then, like some of our other production in the Basin, it will flatten out to a much shallower decline rate and be around for a long time. The wells will probably have, you know, 20-plus year reserve lives to them.

Is this where we'd probably see maybe half the production out of the well in the first two or three years?

I don't have that sitting here in front of me, but I think you get -- certainly, you'd get a high percent of the value of the project on a discounted basis.

Okay, another question for Greg -- I know you guys have been dealing with the credit rating agencies for some time, but given the strong cash flow in the first half of the year and, really, the nice prospects for the next couple of years, do you think you'll see an upgrade from Moody's to investment grade rating?

That's real hard for us to say. I know it's something we really work towards. We think it is justified for us. A lot of it depends on what they predict gas prices to do in the future, and they've had a pretty conservative stance. So I think a lot will be -- we'll learn a lot as we go through this winter period and see where prices really are. We typically will see them, either towards the end of the year or during the first quarter on an annual basis, we would expect to go in and see both of them about that time, and hopeful that they will look at where we are and think that S&P has got us at a rating that I think we deserve, and we do believe that Moody's, we deserve a higher rating than Moody's has got us at.

Okay, thanks a lot.

We'll now take a follow-up question from Joe Allman with RBC Capital Markets.

Hi, good morning again. Harold, a question -- are you looking at any acquisitions or -- I mean -- of corporate or asset or leasehold -- that would take you beyond the four core areas that you have right now?

Well, Joe, if we -- I say this facetiously, but if we were, we couldn't talk about it.

Conceptually, I guess.

In terms of other operating areas, not at this point in time.

Okay, I guess, Overton may have a couple more years or may have several more years, and then South Louisiana, I guess, you're waiting to see what the success will be there; and the Permian, you're not putting a whole lot of capital into that; and Arkoma, it looks like you've got some increasing running room there. I mean, it just -- kind of looking out beyond the next couple of years, I mean, would you -- do you think you might look to -- just kind of beef up what you've got now? Or do you think at some point you will kind of diligently look at some other opportunities?

Well, you know, we've pointed out before that, in terms of our split of capital this year, that a little over half of it is going into East Texas; about 20% into the Arkoma; the Gulf Coast, about 13%; Permian, 4%; the utility, 5%; and we have a wedge of other projects which, for us, probably means kind of new projects, about 7% of our capital. So we have some -- you know, we continue to look for other areas that -- I mean, areas similar to what we have done here so successfully that we can grow the company around, and I just would fall back on -- you know, one of the things that sometimes frustrates me, which is that I don't think we get credit as a company for the -- necessarily the brain power or the engine that's under this hood to generate new ideas and opportunities, and, you know, Overton wasn't here when we came. Ranger Anticline wasn't here when we came. South Louisiana was kind of a mess, we hadn't done the success we had in the Permian all that Morrow [ph] play, that we did there that we had quite nice finding development costs on - those things are -- come from internal idea generation, and, you know, the machine isn't shut down, the engine isn't off, and so we're working on other things, and some of those have competitive nature to them, other would be too early to talk about whether they even would work. So we aren't shutting down, just expecting that we're going to ride the horse out with Overton and the Arkoma Basin -- I guess that's what I would say to you. And so we're working on other things, certainly.

Okay, understand. And then in terms of reserve replacement, to date, any estimate of what reserve replacement would be at midyear?

This is Richard. Joe, we do our reserve assessment at year-end, and so probably won't get into where we are right year year-to-date. But you see the capital that we've deployed, and we're liking the results and the finding costs that's given us. So we're in good shape, and we're going to end the year with a real nice multiple of our reserve replacement.

Okay, great, and then, lastly, just back to the Arkoma Basin -- you know, I think in the first quarter you indicated that you have seen some more non-operating activity than you had last year. Is that still the case?

Yes, it is. We saw it in the first quarter, and then we saw it probably even more in the second quarter. The activity that had kind of dried up from the other independents up there that we'd done projects with in 2001 and 2002 seems to be coming back in some measure. So I think it's a good thing for us. We're seeing more opportunities to evaluate on joint acreage areas, and some of those look good, and we're participating in them when they look good, and the ones that don't, we'll decline. It gives us more projects.

Great, thank you.

There are no further questions at this time. Mr. Korell, I'd like to turn the conference back over to you for any additional or closing remarks.

Well, thank you. I think that pretty much wraps up our teleconference. I would just close by saying that we're, again, very happy with the results, to date, in 2003. I think we have a good inventory of things to drill, and we are active in the drilling arena. We should expect to see some growth in production as we continue to move through the year and look forward to the rest of this year and what '04 brings for us.

I'd just like to thank you for joining us today, and if you have any further questions, feel free to all Brad Sylvester, who is our manager of Investor Relations, or Greg Kerley with any questions that you might have. So thank you.

Thank you, that does conclude today's conference. Thank you for your participation and have a great day.