2002 Third Quarter Results Conference Call
Monday, October 28, 2002

Chaired by
Harold Korell
President, Chief Executive Officer and Chairman of the Board

Korell:     Good morning. Thank you for joining us today. If you've not received the copy of the press release announcing our third quarter results, you can call Sharon at 281-618-4784 and she'll fax a copy to you. Also, our attorneys have asked that I point out that some of the comments during this teleconference may be regarded as forward-looking statements that involve risks and uncertainties that are detailed in the Company's Securities and Exchange Commission filings. While we believe they are reasonable representations of the Company's expected performance, actual results could differ materially. With me today are Richard Lane, our Executive Vice President of Exploration and Production, and Greg Kerley our Chief Financial Officer. Before getting into their presentations, I'd like to make a few comments about the quarter.

Although we had a decline in production from the second to the third quarter, we estimate that our production volumes for the year will still result in positive production growth for 2002. In addition, we believe we're on track to be within the target range we discussed for earnings and cash flow for this year.

So where do we stand in the overall program? Number one, drilling activity in the Arkoma Basin has been less than anticipated due to fewer non-operated well proposals this year. Secondly, we've had restricted producing rates at some of our high-rate South Louisiana wells. And finally, we've not had a significant discovery in South Louisiana this year. The combination of these things has caused us to feel the effect of the natural decline in our production base. On a positive note, we have several key wells and workovers in the Arkoma Basin and two recent discoveries in South Louisiana that will come online in the fourth quarter. In addition, we have two rigs drilling at Overton, which continue to yield significant results.

As we look forward, we have exciting drilling opportunities both in this quarter, like our Piedmont prospect, and over the next six months that have the potential to add significant value for our shareholders. I'd like to now turn this over to Richard Lane for an update on our E&P operations and then to Greg Kerley for comments on our financial results for the quarter.

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Lane:      Thank you, Harold, and good morning. Our third quarter exploration and production activities continue to focus on our core areas in the Arkoma and Permian Basins, East Texas and South Louisiana. In total, we've participated in 15 wells in the third quarter, of which nine were successful, one was unsuccessful, and five were still in progress. Through three quarters we have participated in 47 wells, of which 33 were productive and nine were unsuccessful.

Production for the third quarter was 10.0 Bcfe, down from 10.3 Bcfe in the second quarter. On a year-to-date basis we have produced 30.6 Bcfe, 4% above our 2001 production for the comparable time period. As we announced in our recent press release, this quarter's production decline has been due to several factors including production curtailments and declines in the company's South Louisiana properties, less than expected production from exploratory drilling, and lower non-operated activity in the Arkoma Basin. Now, I'd like to talk a little bit about each of these areas.

In South Louisiana, water production from a portion of our high-rate gas wells has caused us to curtail some of the producing rates there. This is a prudent action to take in order to maximize the ultimate recoveries from those wells. At our North Grosbec field, the Raymond Egle #1 well has experienced significant decline for another reason. Based on our analysis, we believe a previously side-tracked hole near the current producing well bore is allowing cross-flow of water from a deeper sand into our producing well bore. As a result, the production from the Egle well declined from a net 400 million cubic feet equivalent (MMcfe) in the second quarter to approximately 150 MMcfe in the third quarter, or approximately 1/4 of a Bcfe decline for the quarter. We're currently evaluating courses of action to correct this problem, which may involve drilling an additional well on the field. Southwestern holds a 26% working interest and a 17.5% net revenue interest in this outside-operated well.

Overall, in South Louisiana we appear to have experienced our greatest decline rates in the last two quarters, and our current net daily production volumes of approximately 9 MMcfe per day in this region are only slightly down from the average daily rate for the third quarter.

Our production declines in our Arkoma Basin and exploration areas are primarily a function of timing. In the Arkoma Basin, we have not drilled as many wells year-to-date as we had planned due to a lack of non-operated well proposals. Additionally, each year our plan includes a risked amount of production from our Gulf Coast exploratory tests, spread out over an annual program. As you know, it is difficult to predict which of these higher risk projects will be the successful ones. So, to the extent test wells in the first half of the year are not successful, that planned production increment is not realized. We do, however, have a strong inventory of exploration prospects for the future and, as Harold mentioned, we will be drilling some of these significant tests in the next two quarters.

As announced previously, we have revised our full year 2002 oil and gas production target to 40 to 41 Bcfe. And even at this reduced level, we will have an increase over 2001 and achieve our fourth consecutive year of production growth through the drill bit.

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I would now like to discuss some specific activities in our core areas. Starting with the Arkoma Basin, we have participated in four wells that were spud in the third quarter. Of these, two were successful, one was a dry hole, and one was still in progress. One successful well note is our Brasher #1-11 well located in Yell County. That's in our Ranger Anticline project area. This well, put on production in August, is currently producing 2 million cubic feet (MMcf) per day from the Upper and Lower Borum sands at 5,500 feet and 6,750 feet, respectively. Southwestern operates this well with a 100% working interest.

Additionally, we continue to be very active with our Arkoma Basin workover program. We have completed 32 workovers to date in 2002, resulting in good economic production increases there. One example of a third quarter workover is the stimulation of our Swarm #1 well in Franklin County. Gross production from this well, which we operate with a 98% working interest, increased from 25 Mcf per day to 600 Mcf per day. Although individually these projects are small, combined they have a very positive impact on our results. And we expect our workover activity in the Arkoma Basin to remain at high levels throughout the end of the year and into 2003.

We plan to spud the first well on our Midway prospect located in Logan County, Arkansas, during the fourth quarter. This wildcat is targeting the Spiro horizon at approximately 10,200 feet. Southwestern will be operating this internally-generated prospect and will pay 20% of the cost to drill this well but own a 60% working interest if it is successful. This project could open a multi-well area for us where we have a large lease position.

In the Permian Basin, we drilled and completed two successful wells in Eddy County, New Mexico. The Freddie Federal #1, which is completed in the Morrow at 11,840 feet, tested at a rate of 1 MMcf per day and the Grizzly Adams 13 #1 well tested at a rate of 2 MMcf per day from the Atoka at 10,240 feet. Southwestern holds a 43% working interest in the Freddie Federal well and a 25% working interest in the Grizzly Adams well.

At our Overton Field in Smith County, Texas, we continue to have a 100% success rate in our infill drilling program. So far in 2002, we have drilled 14 wells, of which 12 were successful and 2 were still in progress. In order to sustain a full year two-rig program, we have increased our 2002 capital plan for Overton by $10 million. We expect to drill a total of 18 wells during the year.

Current gross production from the Overton field is 23 MMcf per day and accounts for approximately 13% of our total company year-to-date net production as compared to 5% for that same period in 2001. Southwestern operates the Overton wells, which are targeting the Cotton Valley sands at approximately 12,000 feet with an average working interest of 98%.

As an update to our last teleconference, in the third quarter we did close on the acquisition of 3,300 net acres of land offsetting some recent Travis Peak and Cotton Valley development in Anderson County, Texas. While this is undeveloped leasehold at this time, we see good potential to try technologies we have refined in our Overton area to this acreage block and it is located about 55 miles to the southwest of Overton.

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In South Louisiana, we reached total depth at approximately 15,000 feet on our Bushmills prospect in Iberia Parish during the third quarter. The targeted Planulina sands were well developed and in a structurally advantageous position but were wet. Southwestern operated this prospect with a 70% working interest.

Also in the third quarter, we spudded our Piedmont prospect located in Vermilion Parish. This well is targeting the Alliance sand at approximately 12,700 feet and should reach total depth during the fourth quarter. Southwestern operates this well with a 62.5% working interest.

During our last teleconference, I discussed our planned participation in a five-well exploration program located in Cameron Parish. To date, four of these prospects have been spud, two are discoveries, one was unsuccessful, and one was still drilling at quarter end. We expect the remaining prospect to be spud late in the fourth quarter. The two discoveries are currently waiting on pipeline and we expect first sales by the end of the year. Southwestern holds a 25.7% working interest in each of these wells.

Also in the third quarter, we completed a data acquisition on our 140-square mile Duck Lake 3-D project located in St. Mary and St. Martin Parishes. This project is adjacent to previous successful areas for Southwestern. The seismic data will be delivered for interpretation by the end of the year. And our review of the preliminary processed data is encouraging, as we can see high quality imaging of the deep Miocene objective section there. We expect that this shoot, which Southwestern operates with a 50% interest, will lead to a number of exploration prospects that we can begin to test in 2003.

In addition to the Duck Lake shoot, we were able to acquire approximately 1,000 square miles of 3-D seismic data in South Louisiana from a major seismic vendor at very favorable terms, and in an area where we have prior technical experience and plays we can pursue. This project should also lead to future impact exploration projects for us.

Finally, we are continuing to pursue the sale of our Western Oklahoma properties. We believe that this is an opportune time to monetize them and deploy the proceeds into other core areas where we can create more value and to reduce debt. We anticipate closing a transaction on these properties in the fourth quarter.

In summary, while we are disappointed with the decrease in our third quarter production volumes, we should achieve year-on-year production growth over 2001 level. We have continued to maintain low operating costs per unit of production and a strong inventory of Gulf Coast, Arkoma Basin, and East Texas projects.

I will now turn the teleconference over to Greg Kerley who will discuss some of the Company's financial information.

Kerley:      Thank you, Richard, and good morning. Our financial results for the third quarter were down from the prior year but were within our expectations.

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We reported net income of $1.3 million or $.05 per share for the quarter, which compares to $5 million or $.20 per share for the third quarter last year. Cash flow from operating activities before working capital changes was $15.7 million during the quarter compared to $22.7 million last year. The decrease in earnings and cash flow was a result of lower realized natural gas prices and, to a lesser extent, the decline in the company's gas production that Richard discussed. Favorable commodity price hedges in place last year had the effect of increasing our earnings for the third quarter of 2001 by $.13 per share and accounted for over $5 million of additional cash flow realized during the prior period.

We reported income for the first nine months of 2002 of $9.8 million or $.37 per share, compared to $27.9 million or $1.09 per share for the same period in 2001. Cash flow from operating activities before working capital changes was $58.9 million for the first nine months of 2002, as compared to $86.4 million for the same period of 2001. Again, the decrease in earnings and cash flow is primarily a result of a decline in our realized natural gas prices. Our year-to-date production was up 4% from last year's level, which helped to partially offset the effect of lower realized commodity prices.

Operating income for the exploration and production segment was $9.7 million during the quarter, down from $15.9 million for the same period in 2001. We realized an average gas price of $2.96 per Mcf during the quarter, down 12% from $3.37 per Mcf in 2001. Our commodity price hedges had the effect of reducing our average realized gas price by $.03 per Mcf in the third quarter of 2002, while during the same period last year our hedges increased our average realized gas price by $.57 per Mcf. Our detailed hedge position is included in our Form 10-Q that we filed at the end of last week.

Our exploration and production segment continues to benefit from some of the lowest operating costs in the industry. Operating expenses for this segment were $.48 per Mcf equivalent (Mcfe) in the third quarter, compared to $.38 per Mcfe the same period in 2001. Operating costs for the nine-month period averaged $.43 per Mcfe in both 2002 and 2001 The amortization rate for the full cost pool was $1.16 per Mcf equivalent for the third quarter compared to $1.15 last year.

On the utility side of our business, we experienced a slight improvement in our normal seasonal operating loss. The utility's operating loss was $2.2 million in the third quarter of 2002, compared to a loss of $2.4 million for the same period in 2001. For the first nine months, our utility had operating income of $4.7 million, compared to $6.3 million for the same period in 2001. And as we previously stated, we're planning to file a general rate increase for our utility during the fourth quarter to improve our returns.

The company's marketing operations added $500,000 of operating income during the third quarter of 2002, compared with $600,000 for the same period last year.

Capital expenditures for the first nine months of 2002 totaled $67.8 million, including $63.4 million invested in our exploration and production operations. With the recent improvement in

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gas prices, we have been able to increase our 2002 planned capital investments by $10 million, which brings our total budgeted expenditures to approximately $88 million.

Our debt level is up from the end of the second quarter due to normal seasonal operating cash flow differences primarily related to our utility. As we've indicated, we're in the process of marketing our non-strategic Mid-Continent properties, and proceeds from the sale will be used to reduce debt.

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

Questions and Answers

1.         What would be the impetus for adding a third rig at Overton? Is that under consideration right now?

Lane:     Just to kind of set the stage, we have two rigs running out there this year and currently running right now. We're beginning our capital plan and budget for 2003. And, that will be when we're looking at that kind of thing. That's when we'll determine what kind of activity levels we'll have there next year.

2.         In South Louisiana, do you think that some of the recent problems with the water production will affect your reserve estimates at year-end? Any potential for revisions?

Lane:      Yes, certainly there's some potential for that. We'll assess that on a well-by-well basis. At year-end we do a reconciliation and analysis of the whole year's reserves and we'll be assessing that. We could have some of that related to water production. But in general I would say that we're going to have a healthy amount of reserve adds for the year. To the extent price is up we could have some positive effects on our reserves related to that. And overall, the impact of those things we're seeing I think will be not very significant in our total year-end reserves.

3.         Richard, can you talk a little bit more about the issues in South Louisiana? You mentioned North Grosbec, but it seems like issues are affecting more than North Grosbec. Is that right?

Lane:      We have several high rate wells there and, in general, it's an area where you have high producing rates and high decline rates. Some of the wells we have out there are producing water and should be producing water at what stage they're in in their reservoir life. And we have some recompletion opportunities moving up the hole when they water out. The bigger impact has been some of the ones I discussed, and the declines there seem to have flattened out and we're running closer to what our average third quarter production was right now currently.

4.         And then I guess where might the biggest reserve issues be? Would that also be North Grosbec?

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Lane:      Well, North Grosbec is a big field and I've talked about what our interests are there. It's a big field but our net revenue interests are 17 to 18%. So, ironically there at North Grosbec where we're seeing some of the bigger production impact, potentially it's the kind of decline that wouldn't affect reserves. So, we'll just have to look at that at our year-end assessment, and if it truly is a mechanical issue which we think it is then those reserves for the field are notionally still there, and they may need to be developed in a different manner.

5.         So that one may not impact reserves, but maybe I didn't hear it, but I didn't hear any other descriptions of other issues at other specific areas. Where are there some other issues and what are those issues, and what might you see in terms of a reserve impact?

Lane:     Yes, again, we really won't know the extent of that till year-end when we go through each of those and we assess our production for the full year and estimate that. In our Malone field, I think we could have some impact there. To be a little bit more specific about some of our properties, we see some water production there associated with zones that are producing water sooner than we thought they would have based on our models. And that maybe we'll have some undeveloped areas that we need to get with a different well bore or sidetrack or something like that. But the early assessment of that whole regional reserve base is that there will not be a real great downward revision.

6.         And then on your LOE, on a unit basis LOE was up this quarter versus the past. Is that a good number going forward? And what's the cause for that to go up on a unit basis?

Kerley:      For the quarter it was up a little bit higher than normal because depending on the level of workovers we have at any one period, it does fluctuate as you can tell the last couple of years. We're still averaging about $.43 per Mcfe both for 2001 and 2002. And in the third quarter of this year we had a small amount, a few hundred thousand dollars, related to a non-recurring catch-up on some accrual of LOE that affected it a little bit, but the year-to-date number still stayed at $.43. You could see that it may be a little bit higher in the fourth quarter, but I would not think that it would, on a year-to-date basis, be any higher. The fact that our production is down may have a slight impact, but I think that what we're talking about you'd be able to use them in any kind of modeling forecast for us.

7.         Greg, when you say fourth quarter is a little higher, you mean a little higher than your yearly average or a little higher than third quarter?

Kerley:     A little higher than the yearly average.

8.         While I've got you Greg, G&A however was down pretty nicely. You had $2.4 million for the third quarter. Is that a good number to use going forward?

Kerley:      Yes, I think that the G&A numbers that you're seeing right there for this year are good numbers to use going forward. We have enjoyed some positive variances between the year and so we feel good about it. I think you should feel good about using that going forward.

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9.         Richard, what about operated activity in the Arkoma? Could you give us a sense of what this year's operated activity is versus say a year ago? Because you talk about non-operated activity but is operated activity up or the same or is it down?

Lane:     The short answer is that the operated well count is down from last year as well. And some of the effects that we are seeing - the lack of proposals from other operators in the basin affecting the non-operated activity, and their willingness not to be doing a lot of investing there right now. It also has an effect on our operated projects as well, because to the extent we have to propose those wells and get their consent to participate. If they're in a non-investing mode, then it affects those operated wells as well. And I don't have the exact data for each year for non-operated and operated in front of me here, but we can provide that for you.

Korell:     I think to follow-up on that we've got to remember where gas prices were in February this year. When gas prices were $1.80 we found people who believed they may be that low for a longer period of time, not approving AFE's to drill wells. And when you lose activity level, which we talked to you about in the second quarter, at the end of the first quarter in regard to the Arkoma Basin, we're feeling the effects of you can't just replace that by drilling later in the year because you're still missing volumes that you would have had from activity in the first part of the year.

10.         Lastly, reserve replacement for this year. Would you say that most of it's coming from Overton?

Lane:      There's a significant part of it there, certainly, because our success rate has been great and we're putting a lot of our capital there. So it's an important part of it, yes.

11.         And then I guess when you say - you mentioned a healthy number - do you think you might get close to 200% reserve replacement?

Lane:     I don't want to speculate on that right now. We'll see how the rest of the year shapes up and we'll be looking at that.

12.         Just following up on the South Louisiana questions. I know it's too early for you guys to indicate how many reserves might be at risk or how it ends up in the year. I know only 10% of your reserves roughly are booked in Louisiana but of the wells where you are seeing premature water breakthrough or water coning, how many reserves have been booked in those wells? Just so we can get an idea of how much reserves could be impacted. So of the 10% that's booked out there I'm assuming it's about 5% would be affected by premature water coning.

Korell:       I think the first thing is when you asked your question about premature water coning, that's a pretty technical description of what's really going on there. I would say that I'm not sure that our definition would be premature water coning even. But not to battle about that it's just

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that I mean this could be natural water encroachment in various other ways. But I don't think we have the information right here to answer that question.

Kerley:     One thing to remember is for example in Grosbec our net revenue interest I think is about 17%. So while it was a good discovery for us for sure, as a percentage of total reserves for us, you can see that the activity we have going on in other areas has substantially more net impact to us, not on an individual well basis, but just the overall activity.

13.         Since you've talked about releasing your production in the South Louisiana region as a result - from the water encroachment, does that affect 2003 outlook by any - to a certain extent for production?

Lane:     The way that it affects 2003 is it affects our cash flow and we'll be stewing that into our plan here and we're doing that right now. And it'll be a part of our available cash flow, certainly.

14.         But in terms of how much production you are cutting back in the region, can you quantify that in terms of how much of that can continue in 2003, or is it small operational issues that are going to be fixed up by 2003?

Lane:     The region is a high decline rate region and it will always decline. It's not going to go up. So I think the rate of decline that we've experienced in the second and third quarters would be the highest we'll see. It seems to have tapered off but the properties are going to decline, that's a natural part of their life and the region as a whole to increase production needs to come from new drilling and from recompletions and projects we see in 2003.

Korell:      Let me take kind of a shot at that. With the exception of Grosbec; I don't think there's a magic bullet to increase production. For example, Richard talked a little bit about Malone, it's likely that the production there will probably be restricted until we're out of the current zone and go to the next recompletion, then you may see the rate go up again because we've got various zones to complete up the hole. But to efficiently produce that set of wells right now they've cut it back. And you mentioned water coning, to get in that discussion, it may slowdown water coning if that's the problem there.

Grosbec, on the other hand, is a mechanical problem. We think it's a mechanical problem as Richard mentioned earlier of water coming up from a deeper zone through one of the old - one of the sidetracked wells. That was a difficulty encountered when they were originally drilling it. I doubt we're going to be able to fix that well bore but he did mention that may involve drilling another well. Of course on a finding and development cost that would hurt because we would be drilling a well to get the same reserves. But nonetheless if it's the right economic thing to do, that's under consideration. So if we were to drill another well there and we're not the operator of this thing, and there are three other partners in it, so if we're stammering around a little bit about what's going to really happen there, we're not the only one involved in that decision. And if we were to drill another well there, then we'd expect to see producing rates come back up at Grosbec. But those things are beyond our control to talk about in this teleconference.

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15.         Have you guys set your 2003 capital budget yet? Or when can we expect that?

Korell:     We haven't pulled that together yet. We're in the throws of our operating and capital budget process right now. And it'll be later in the year before we finalize it. And, in fact, it may not actually be finalized until quite early in the year, as far as our Board is concerned. But we're going through that process now and we'll have some pretty good idea by the end of the year, of course.

16.          Regarding the Anderson County property in Texas, can you give us some more information about that? Is the field producing right now or is it completely undeveloped acreage that you plan on developing?

Lane:     The project you're talking about is what we call Cayuga, and it's essentially undeveloped leasehold. The good thing about it is that adjacent to it there is some Travis Peak and Cotton Valley production that we've been keeping our eye on and we were able to put that lease block together based somewhat on the analysis of that production and extending that production. So, it's undeveloped and we will try to test that leasehold next year. And we see the chance to apply some of the same technology that we used in Smith County there.

17.         Any idea how many wells you might be drilling there next year?

Lane:      No, we haven't finalized that yet. That'll be part of that capital plan.

18.         What's your working interest in this undeveloped acreage?

Lane:     I think it's approximately 70%. Different amounts for different tracks but on a whole the average is somewhere in that 70% to 75% working interest range.

19.         Greg, could you give me the clean gas numbers year-over-year, you know, without the hedges?

Kerley:     Without the hedges I would have to add $.03 and back off $.57 from last year, so that would look like $2.80 for the third quarter in 2001 and just about $3 even for us for the third quarter this year. It's probably about $.15 off of NYMEX for the period. We're probably, on average, about $.10 off NYMEX for the year, but we feel more of the differential in the second and third quarter than we do in the first and fourth because some of the contracts we have have some premiums that really only kick in during the winter periods, which gets our differential down to about the $.10 for the year.

20.         It looks like you have about 75% of your gas production hedged in 2003 with a floor of about $3.30 per Mcf. Has that changed any?

Kerley:     No, that's still accurate.

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21.         Everyone's grappling with this South Louisiana. Your company has about 400 Bcfe in total reserves, South Louisiana's about 40 Bcfe. So even if there was a material impairment, let's call it half of it, 20 Bcfe, I'm looking at net asset value numbers without it and I'm getting about a $22 net asset value. Maybe that takes a couple of bucks off of your asset value. But, clearly, unless there's something really awry with some of the other areas, whichever way this comes out it still shouldn't be a material degradation in firm value. Am I reading that correctly?

Kerley:     Yes, you are. I mean, that's the point I think I was trying to make, but you made it a lot more artfully. While there is some potential for some impacts in some of the South Louisiana wells, when you look at this on a overall basis, it is really immaterial any impact that they would have.

22.         What is your year-to-date EBITDA from the utility?

Kerley:     Year-to-date EBITDA for the utility, I don't have that right in front of me. We can try to get that to you.

23.         Do you have a rough sense? Is it running at the annualized $20 million number?

Kerley:      No, it's not, and that's why we're in for a rate case. We expect to file between now and the end of the year for a rate increase and to get our EBITDA back up to that historical level of $18 to $20 million. And we're down probably, if we have a normal fourth quarter, we'd probably be down in between the $16 and $17 million range right now without the rate increase. But the rate increase, again, wouldn't be effective until in the fall of 2003 just because of the normal regulatory time lag.

24.         Your property sales. If you do sell these properties what impact would it have on your LOE?

Kerley:      It would help our LOE for sure. These properties are kind of "long in the tooth" properties. It's about 27 Bcf of PDP and the average LOE there is the highest area that we have in the Company, and it is the lowest average realized gas price area we have in the company too. So it'll help all of our stats. I know that the LOE is close to $1.40. And the average realized gas price there is quite a bit off from our average. It's probably $.40 to $.50 lower because of some old-line contracts that exist there for some of those properties. So all of our metrics will improve.

Korell:     Except for production.

Kerley:      Except for production, that's right.

Korell:       And reserves.

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Kerley:      There's about 2 Bcf on an annual basis of production that comes from those properties. It's historically what we would have expected this year from it. So, we lose a little production there and those properties were probably expected to produce about that kind of level next year.

25.         And roughly what's the total reserve amount?

Kerley:      PDP is about 27 Bcf. There's some PDNP I think, so there's a little over 30 Bcf of reserves there.

26.         For 2003 it looks like you've locked prices, because unless the gas price has changed dramatically, you'll get at least the $3.30. If we apply this to your full cost structure, it looks like you'll net back somewhere around $2.10. And I'm looking at your DD&A. It's been solid at $1.19, so while you could have some downward revisions, which would be temporal, it looks like $1.20 is probably a good number to use historically. You know, I want to revert this back to your PVI concept. It looks like on this basis, $2.10 divided by $1.20 gives you about a 70% cash-on-cash return, which is a pretty good number in terms of accretion to value. Is there something funny about my math, or is that kind of the way that you guys read this.

Kerley:     No, your math's good. I mean it's the same way we really look at it. With the floor price of about the $3.30 that we have, about 2/3 to a little bit more than that, between 65% to 70%, of our production next year with that floor underneath us it gives us a lot of protection.

27.         South Overton, your farm-in acreage? That was what, 5,800 acres? Could you give us a sense of how many wells were drilled there and relative prospectivity of that at this juncture? In addition to that, you have a graph showing downspacing to 80 acres, which gives you roughly 125 additional locations. I guess if you're drilling 20 wells a year or so, or 30 wells a year, that's quite an inventory. Is there something funny about these down spaces? Is there a price sensitivity where they maybe - you need $3.00, $3.50 price or do they make sense at $2.75 or so?

Lane:      The sensitivity is price and, of course, cost as well. And they tend to move together. But in the South Overton area to just talk about that specifically, I think you had a question of the activity levels there. We've drilled three wells down there on those properties and we're trying to manage our activity between the two areas. The three wells have been good wells and pretty much what we expected down there. So we see further development in that South Overton area. We have a continuous drilling clause, so we have to perform a certain amount of wells each year there and we're trying to manage that, plus the Overton program. But, so far so good down there. And, with further down spacing in that area we should be able to attain that.

28.         And when do you get to the point, Richard, that you feel that this big block of acreage is very similar to your northern block?

Lane:     I think we're pretty close to that now, the core area of it. These things always have the outer fringes where the well control drops off and you're certainty is lower. But the core area of that, the middle part, I think we're there now.

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Kerley:      One of the issues there is that in the northern part we have a 98% working interest and high net revenue interest. The southern part we don't have quite as high an interest. It is still good, in our eyes, but given the two options, as long as you have wells to drill in the north you'll always drill those wells first and then drill the wells in the south. One other point I'd make, in the different presentations that we have where we talk about Overton, in the table there where you were talking about the 125 wells, that's only the well count for the northern part of that map. And for the southern farm-in acreage, we don't have those wells added into that table. So that would be additional drilling opportunities there. And we expect to do is to continue on meeting the obligations so we'll drill - Richard, is it every 90 days we drill a well or 120 days? So that's the kind of activity I think you could expect to see in the next year from that area until we've drilled up really all of Overton where we still have the primary field we acquired, which would still take a few years.

29.         And your presentation says an $.85 finding cost at Overton, let's call it $1.00. Do you still feel comfortable with that?

Lane:      Yes. We watch every well that we drill very closely, obviously, and our latest wells have been very good. Our cost structure there is real good, and we're achieving a better than $1.00 finding cost there.

30.         You mentioned that you thought that you would have healthy reserve adds that would offset any decrease from South Louisiana. Part of that was price related adds. The non-price related adds, what are you thinking about? What are the areas where you have been adding reserves?

Lane:      We've been adding reserves in all of our core areas. We haven't had a big discovery in South Louisiana, some smaller stuff there. But we've been adding it in all of our core areas. And, net of any kind of a price revision, we're still going to have solid reserve adds. I didn't mean for the price revision to be a real important part of that. We're going to have real reserve adds that we're adding with the drill bit through our Arkoma Basin activity, our Overton activity, and also in our Permian activity.

31.         Just curious. Production guidance. Does that include the properties from Western Oklahoma that you're selling?

Lane:      Yes it does.

32.         Do you have any specific date of when your closing might be?

Lane:       No.

33.         Regarding the Anadarko Basin properties, I'm assuming that you must have an agreement signed or you're pretty close to that. Is that correct?

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Kerley:     We're in the process of marketing those properties, so we are working towards selling the properties. We're hopeful we'll have something in place in between now and the end of the year.

34.         Isn't your increased capex budget coming from the proceeds of the asset sale?

Kerley:      No. As you might recall, our original capital budget has moved around a couple of times. Early in the year when prices were so low we started at $71 million for E&P. We ratcheted it back down to $61 million when prices in February were about $1.80. It was dependent on our expected cash flow. Then we increased it back up to $71 million, and since we've had some very healthy prices here in the last several months we've been able to move it on up to the $81 million for the E&P area. In total, we'll be about $88 million when you include the utility activity. So, while we believe it's a prudent thing for us to do to monetize those assets at this time, if you look at our expected cash flow numbers that were also provided in the guidance, we still feel good about those at the different price levels and that cash flow will fund our program.

35.         Yes, I just saw your press release last week said it was - that increased capex budget was coming from the proceeds of the asset sale. But I'll just go back and reread that. Quick question on the Anderson County property that you just acquired or you just accumulated. You said at Travis Peak and Cotton Valley, is that Cotton Valley sands or Cotton Valley lime or?

Lane:      Cotton Valley sands.

36.         Going back to the Piedmont prospect I was wondering if you can give us a feel for what the estimated reserve target is at as well as what the cost of drilling the well might be?

Lane:     Yes, the Piedmont prospect is currently drilling. We see it as a 25 to 30 Bcf gross reserve potential prospect. And we have about 30 days to get that finalized and evaluated. The dry hole cost for the well I think is somewhere in the $2 to $2.5 million range.

37.         What is your bank line drawn and availability?

Kerley:     We have availability on our line of $140 million right now. If we sell the properties in the Oklahoma there's a mechanism that the capacity could ratchet down to a little bit lower level because we won't need as much borrowing. We had about $128 million borrowed on the facility at the end of the quarter. During the summertime, the utility has negative cash flow from operations, and our CapEx is quite a bit higher. So you see us getting behind in this period just looking at an absolute period. And then in the first and fourth quarters, when we're getting in heating revenues from the utility, is when our real cash flow comes in for the entire period and allows us to kind of move our facility back down. So, the facility is used really for working capital needs as much as anything besides the base borrowings we have underneath it.

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38.         Your new $88 million budget, how much is the utility and what is the spread between exploration and development?

Kerley:     The utility and corporate, which would include information technology is about $7 million in total. The E&P budget is a little over $81 million, $81.3. The actual breakdown between development drilling and exploratory drilling would be $40 to $50 million that would be allocated to development drilling, and then about the same level that we'd originally budgeted for exploration which would be about $12 to $15 million. Then you've got capitalized interest and expense that gets allocated between the parts, so that probably brings it up to about $20 million and the development drilling to about $50 million.

39.         And of the exploration, what component is seismic?

Lane:     We have our Duck Lake project in there this year, so we got to have a big chunk there this year. That project itself is a little over $3 million. And then some other small projects seismically as well.

40.        And while I have you Richard, a lot of us tromped around in the swamps with you guys looking at the Duck Lake shoot, which was pretty impressive. Could you give us a sense of what you're seeing, what the new telemetry that you used, the longer offsets, et cetera, what it's allowed you to articulate. Maybe just kind of review the project with us.

Lane:     I would first say that it's a very difficult area to acquire seismic data, and it went extremely well. It's an area where weather and other things can affect you and delay things and cause the cost to go up and that all went extremely well. We did employ the highest technology out there with some real large spreads that gave us big offsets. We did utilize telemetry data which is a nice tool to speed the process up. The short answer is we're getting really nice deep imaging of the section there that we wanted to. The quality of the data, at least in the preliminary state, looks very good.

Kerley:     Thank you for joining us today. And feel free to call me or Brad Sylvester with any other questions you may have or information that you need.

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