西南能源 (SWN) 2003 Q3 法說會逐字稿

Good day everyone and welcome to the Southwestern Energy Company third quarter earnings conference call. Today's conference 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. With me today are Richard Lane, our Executive VP of the Exploration and Production Company; and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release announcing our third quarter results, you can call Sharon at 281-618-4784 and she will fax a copy to you.

Also I would like to point out that many of the comments during the comments during the 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 begin with, I would like to tell you that I am very pleased with our progress for the first three quarters of this year. Our earnings were a record 10.9 million. Our cash flow was also a record 29.8 million in the third quarter, due primarily to high commodity prices and higher production volumes.

We're continuing to see a steady climb in our production volumes, which were up 10 percent over our production level in the second quarter, and 11 percent over last year, primarily due to the drilling program at the Overton Field in East Texas. Overton continues to deliver strong results for us. We have completed 41 wells through the first nine months of the year, and gross production is now around 58 million cubic feet of gas per day. As we announced yesterday some of our drilling in Overton in 2004 will likely be 40 acres space wells. And we continue to believe that our drilling in Overton will extend into 2005.

The Arkoma Basin program continues to deliver solid results. And we're looking forward to drilling a couple of exploration wells on our Ranger Anticline in the fourth quarter. And in South Louisiana we did have a discovery at our Coleburn prospect, and are currently drilling on our Duck Lake prospect. And Richard will speak more about the details of the E&P program in just a moment.

On the utility side, we announced in September that we received regulatory approval for a rate increase, which we put in place starting in October, and Greg will update you on that as well. So in closing we're looking forward to the remainder of 2003 and '04 as this continues to be a very rewarding and exciting time for our Company.

I will now turn the teleconference over to Richard for an update on our E&P operations, and then to Greg Kerley to discuss our financial results, and then we will take questions.

Thank you, Harold, and good morning. I would like to begin by giving you an update of our operational activity. In the first nine months of 2003 we participated in a total of 99 wells. Of these, 77 were successful and 8 were in progress at the end of the quarter. In the third quarter we participated in 31 wells, of which 20 were successful and 3 were dry.

Our capital investments through the end of the third quarter were $121 million, with approximately 83 percent invested in drilling new wells. This high percentage of total investment to the drill bit comes from working hard at directing our cash flow to investments that maximize our returns and potential for growth.

So now let's talk about where those dollars have been put to work. In the Arkoma Basin, we participated in 40 wells through the first nine months of 2003. Of these, 28 were successful, 11 were dry, and 1 was in progress at the end of the third quarter. In the Ranger Anticline area of Yell County, Arkansas, we have drilled 10 wells so far this year. Of these, 8 were successful and 2 were dry. We operated 9 out of 10 of these wells with an average working interest of 75 percent. We expect to spud up to 4 more development wells in the area by the end of the year.

Gross production from the field in December of '02 was 4.3 million cubic feet per day, and in September of this year we produced an average of 9.3 million cubic feet per day. As Harold said, we also expect to spud two exploratory tests in the fourth quarter of this year. The first of which is approximately six miles west of the current Ranger Anticline development area. This well will target an extension of the same borum (ph) sand reservoirs producing in the field, and will begin the evaluation of our 35,000 gross undeveloped acres in the Prospect area.

We continue to be active in the traditional Fairway area and on the Oklahoma side of the basin. One well of particular note is the Collins 2-13 in Pittsburgh County, Oklahoma. It encountered 43 feet of pay in the Dirty Creek Sands (ph), and is currently producing at a rate of 11.6 million cubic feet per day. At a gross cost to drill and complete of about $1 million, this well represents the kind of low-cost impact projects we continue to generate in this basin. Southwestern holds a 46 percent working interest in this well, and it is an extension of our Haleyville Field production that we discovered in 2001.

In the Permian Basin, we made a potentially significant discovery on our River Ridge prospect in the third quarter. This discovery was made by deepening the Rio Blanco for one well to the Devonian formation at about 14,590 feet. The Devonian open hole completion tested at a rate of 5.2 million cubic feet per day, with 3,320 pounds of flowing tubine (ph) pressure. We hold a 12.5 percent working interest in this discovery located in Eddy County, New Mexico. However, we are currently drilling a direct offset in which we hold a 50 percent working interest. And as we discussed in our last teleconference, we believe the overall prospect has approximately 30 BCFE of gross unrisk potential typical of adjacent producing features.

We also successfully completed an additional well in our Cowden (ph) Ranch area of Frane (ph) County, Texas. The Cowden 49 2 is producing 100 barrels of oil per day from Devonian perforations at 6,100 feet. Southwestern operates this well with a 52 percent working interest, and plans are to spud two additional wells in the area this year.

I'm happy to report that in South Louisiana we have a discovery well on our Coleburn prospect, which is in Jefferson Parish. The well reached a total depth of 13,000 feet in early October and encountered 33 feet of pay in the Tex W formation, and recently tested at 2.4 million cubic feet per day and 24 barrels of condensate. We hold a 50 percent working interest in this well, and expect it to be on production in early December.

We recently commenced drilling operations on our first exploration tests in our Duck Lake seismic project. Our Canvasback project, located in St. Martin Parish, La. is targeting the Liebusella Sands at approximately 18,200 feet. Southwestern Energy operates this 80 BCFE potential past with a 50 percent working interest. We expect this test to be at total depth in approximately 60 to 75 days. And there have been very significant previous discoveries regionally in this part of the lower Miocene (ph) section that we're targeting, and that makes this an attractive high potential test for us.

In addition to Canvasback at Duck Lake, we expect to spud a test well on our Daffy prospect by the end of the year in our Redhead prospect early in 2004. We have also identified additional leads at Duck Lake that we expect will yield prospect later in 2004. We anticipate operating all these Duck Lake area wells with approximately a 50 percent working interest.

In East Texas the Overton Field continues to be a focus for us. In the third quarter we drilled 16 wells, of which 11 are currently producing, and the other 5 are in progress. On a year-to-date basis we have completed 41 wells, while maintaining our 100 percent success rate. A large part of our production increase this year is attributable to our Overton drilling program.

Overton production in the third quarter was 4 Bcf, up from our first and second quarter production rates of 2.1 and 3.2 Bcf respectively. By comparison, our production from Overton in the third quarter of 2002 was 1.5 Bcf. Gross production in the field is currently 58 million cubic feet per day equivalent. And initial production rates of new wells drilled in the field this year have averaged 3.3 million cubic feet per day. And we estimate that the average expected recovery of the new wells drilled will be approximately 2.2 gross Bcf per well.

We are continuing to decrease the days it takes to drill a well at Overton. In the third quarter with one of the H&P flex rigs we set a new record by taking only 16 days from spud to total depth on the right 15 well. So far in 2003, our average drilling time has been 24 days per well. And this compares favorably to the average drilling time of 27 days per well in '02, and 35 days per well in 2001.

In the third quarter we successfully increased the market capacity for our Overton Field by about 60 million cubic feet per day by working with the pipeline company to install additional tenant line. This increase in capacity will meet the needs of our future development plans there.

Our 2004 plan for Overton will be to drill another 50 to 60 wells, with some locations likely being forty acre spaced wells. Based on current well performance in the field, we also anticipate a significant drilling program in 2005. Although current field rules allow for development at optional 80 acre spacing, regulatory approval has allowed the Company to drill four wells during 2003 at locations that are effectively forty acres based wells.

Results from the four wells drilled at 40 acre spacing have been encouraging. Of the four test wells drilled, three wells indicated pressures near original reservoir pressures, and one showed partial depletion. The data from these four wells indicates that some of the field will likely require forty acre space locations to adequately develop the field, while other areas of the field will not.

Moving on to our lease operating costs, in the third quarter they were $4.7 million, or 43 cents per Mcfe, as compared to 36 cents per Mcfe in the second quarter. Operating costs in the third quarter were higher predominantly due to increases in work over expenditures compared to the second quarter. Most of these work overs were associated with our ongoing program in the Arkoma Basin.

Overall, we anticipate our LOE per unit of production to be in the 35 to 40 cent range, which is higher than our previous guidance of 31 to 35 cents per Mcfe, but lower than 45 cents for the full year of 2002.

In summary, we're pleased with our year-to-date program. And our strategy of organic growth is working as evidenced by our production growth. We continue to be well positioned to take advantage of our high cash flow by drilling a strong inventory of fairly low-risk, high PVI projects.

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 had very strong financial results for the quarter driven by high commodity prices and higher production volumes. We reported record net income of 10.9 million, or 30 cents a share for the third quarter, up from 1.3 million, or 5 cents a share for the same period in 2002.

Included in our results for the quarter were pre-tax gains of $3 million, or 5 cents a share, from the sale of real estate and certain fixed assets. Our discretionary cash flow was 29.8 point million during the third quarter, which also set a new record and was almost double the 15.7 million reported last year.

Net income for the nine months ending September 30th, 2003 was 34 million, or $1.01 a share, up from 9.8 million, or 37 cents a share, for the same period in 2002. Discretionary cash flow was 95 million for the first nine months of the year, up from 58.9 million for the same period in 2002.

Operating income for the exploration and production segment was 22.3 million for the third quarter, up from 9.7 million for the same period in 2002. Our gas production realized an average price of $4.23 an Mcf for the quarter, and $4.22 for the first nine months of 2003, up 43 percent and 46 percent respectively from the same as periods in 2002. We realized an average price of $27.17 a barrel for our oil production during the first nine months of the year, compared to $20.87 a barrel for the same period in 2002.

Our commodity hedging activities lowered our average price by 61 cents an Mcf during the quarter, and by 3 cents an Mcf in the prior year period. Our hedging activities also lowered our average oil price by $2.31 per barrel during the quarter. Our hedge position for the remainder of 2003 through 2005 is provided in our Form 10-Q, and is also detailed in our press release filed yesterday.

Operating expenses in our E&P segment were 43 cents an Mcf in the third quarter, down from 48 cents per Mcf in the prior year. The decrease in the 2003 unit rate reflected a larger portion of the Company's production being provided from the Overton Field, which has lower operating costs.

General and administrative expenses for the quarter were 37 cents per Mcf, slightly lower than the guidance that we provided earlier, but still up from the prior year. As we discussed earlier in the year, the increase in our G&A is primarily due to increased pension and insurance costs and the quarterly accrual of annual incentive compensation costs.

Our utility systems realized a seasonal operating loss of 3.4 million in the third quarter of 2003, compared to a loss of 2.2 million for the same period in 2002. Operating income for our utility systems was 2.5 million during the first nine months of 2003, down from 4.7 million in the prior year. The comparative decrease in operating income was primarily due to higher operating costs and general and administrative expenses.

In September, 2003, our utility subsidiary, Arkansas Western Gas Company, received regulatory approval of a rate increase totaling 4.1 million annually, exclusive of cost to be recovered through its purchased gas adjustment clause. Arkansas Western is also entitled to recover additional costs totaling 2.3 million through its purchased gas adjustment clause over a two-year period. With this rate increase, we expect to see a return to a more normalized profitability for our utility business.

Our energy marketing efforts provided approximately 2 million of operating income during the first nine months of 2003, compared to 1.7 million in the same period in 2002. During the third quarter we also sold some commercial real estate located in Fayetteville, Arkansas, and certain other fixed assets for a pre-tax gain of 3 million. This gain is reflected in other revenues in our income statement.

Our capital investments in the first half of the year totaled 128.3 million, including 121.1 million for exploration and production segment, and 6.7 million for our utility. We currently expect our total capital investments for 2003 to be approximately $174 million, up from 92 million in 2002.

Our balance sheet and liquidity has improved significantly during the year. Our total debt outstanding was 262 million at September 30th, including 37 million outstanding under our revolving credit facility. As a result of our equity offering in March and our strong earnings, our debt to total capitalization ratio was 45 percent at September 30th, down from 66 percent at the end of 2002. We expect our debt to capitalization ratio to remain at approximately the same level for the remainder of the year.

That concludes my comments, and I will turn back over to the operator, who will explain the procedure for asking questions.

(OPERATOR INSTRUCTIONS) Jeff Mobley, with Raymond James & Associates.

First off, could you provided a production breakout by region?

Sure. For the quarter ending the September 30th, the Arkoma Basin was 4.8 BCFE, East Texas 4.0, Permian Basin 1.2 BCFE, and the Gulf Coast 1.1, for a total of 11.1.

Thank you. In terms of your drilling costs for next year, have you all taken any steps to lock in any of the rate for next year yet?

Jeff, we're in the process of negotiating that now. We have not signed any contracts as we sit here today, but we're working on that. And, of course, our East Texas activity is a real focus of that, but we're in the middle of that now.

Okay. Are you anticipating any material difference from the current rates that you're paying?

I would say no, not material. So far, we like what we're seeing in negotiations, and we will just have to see how they come out.

As far as the Canvasback Prospect, what would you characterize as the key risk behind that Prospect? Is it permeability? Is it gas in place, the seal? What would you say is the key risk?

Well, you know, we're below 18,000 feet and certainly a high-risk environment. The key, I think, would be -- we're kind of a step out in terms of our sand control, so there is some risk that those deep Liebusella sands are present on the structures. But I would say that, coupled with the timing of the prospect, that it receives gas charge and have a resultant accumulation.

A question for Greg. With the big run up in the stock market this year, is there any chance that the pension costs that shot up last year as a result of the stock market decline, that might reverse for next year? Have you all taken a look at that?

Jeff, this is Greg, we have taken some preliminary looks at that. I think what we will see the impact is more up from a long-term standpoint. In the near-term, I don't think we anticipate very much a material variance from how the FAS 87 expenses calculated and the funding over the next year or two.

But if the market continues to -- we have to remember, we've had a couple of bad years of the market, and if we get more than just the current period and push that together with some additional quarters that have the same return, we will see a lowering of the pension expense in the future. But we don't expect a material difference in 2004 as we look at things today.

So just kind of assume some of the same cost structure going forward at least for '04?

That is the indication we have so far from our actuaries.

Regarding the gas distribution segment, with the rate increase, and obviously it is going to depend upon the weather, what kind of operating income would you expect over the next couple of quarters in light of the new rate increase assuming, say, normal weather.

Well, assuming normal weather, I think last year the utility made about $3 million of operating income in the fourth quarter. Most of their earnings, as you know, are in the fourth quarter and the first quarter. We would expect that the rate increase will definitely push the utility operating income up higher than it was last year, and we hope to see an 1 million incremental increase there. And it could be a little bit better if we have some normal weather there in this fourth quarter. First quarter, we expect about 1.5 million or so of the rate increase to show up again in the first quarter of 2004 over the prior year level.

A question for Harold. Any new plans to do any more hedging?

We're pretty well hedged I would say for 2004. Although, if we were to see prices that flew up and we had an opportunity to do more of those collars that have $4 floors and 7 to $8 ceilings on it, we might be interested in doing some of that.

We do plan, assuming we have the opportunity to do it, to lay our hedges in for 2005. The information we put out would show you that we just have 3 billion cubic feet hedged in 2005. And those are hedges, those are swaps in the second and third and fourth quarters.

So as we move in to this winter, we would anticipate doing some hedging for 2005. And probably our plan would be that by the time we get to midyear '04 we would like to have maybe half, 50 percent, of our gas production hedged for '05, with a combination probably early on of swaps, because that is the only thing that make sense when your hedging early on. And then most of it as collars when we got get an opportunity to do that.

And last question for me. And it may be difficult, or too early to tell, but if you are successful on these two exploration wells in the Ranger Anticline area, what do you think the upside potential is in terms of extending your drilling inventory and your potential reserves in that play?

If those are both similar to what we're getting over in the main field area, it is pretty substantial. The proven area, where we are currently drilling, down spacing, 80 acre spacing, basically we have about 4,500 acres of that. And we've got another 35,000 acres of undeveloped that runs easterly and westerly there. So sizewise it could be a lot of wells.

Some of the areas under that lake would be hard to reach. But I think it is too early to really to talk about how many wells might be there. Reservewise in the main body of the field, the wells we drilled this year are probably averaging 1.8 Bcf per well. So those are pretty exciting opportunities for us, low finding costs.

But I think it is important -- the first one we will drill is certainly important, and the second one is important. If we don't find something on either of those two, we always take the information from those. We need to be in the right structural position. We can't be too far north. If we are too far north we can be not productive at all. But hopefully, we will be in the center on it, and it is full of gas like it is over where we have been drilling. But it is an exciting project for us.

Ranger Anticline Great. Okay. Well, thanks for your time and a nice job on the quarter.

Joe Allman, RBC Capital Markets.

A quick question on the 40 acre spacing. I know you have only drilled four wells down the '40s in the Overton Field, but what is it that gives you a sense that a large portion of your acreage could be developed with 40 acre wells?

The main answer to that is that we have drilled some 41 wells there this year, and 33 wells over the prior year. So we are now getting well performance, both pressures and production rates, and sand thicknesses. As you know, or as we have talked before, these Cotton Valley sands, there tend to be four of them present in the field, and they're not present -- all four sands are not present across the whole thing.

So as we're getting more control and performance information, we are able to look at the areas of the field and say, well, one area at least from the data we have, appears that 80s will drain it, and other areas it appears that it won't. So it is the summation of all the data that we have, and the reservoir engineering that we're doing to put that together. That we will be gathering a lot more data as we continue to drill.

I guess for Richard, you know you are looking at 2.2 Bcf per well. Could remind us what you are finding when you started drilling there at Overton on a reserve per well basis? And also what is it that you think has enabled you to get to 2.2 Bs per well?

The 2.2 is the average that we have for the wells we have done this year. It is about what we have been able to achieve in our prior program, so pretty much the same kind of wells that we drilled earlier this year and last year. And, of course, we're trying to maximize our returns there. And we are always striving to drill the best wells that we can first. That is how we're picking them, trying to pick the best wells, because that makes the most sense. And we will work our way down through the inventory.

I think just to add to that, Joe, as we do drill on down into the inventory, we could anticipate some areas of the field, just as now Richard says we have a 2.2 Bcf average, but that doesn't mean every well produces -- will EUR that. There is a range. I don't know, Richard, if you could address that range, but as we drill in parts of the field that aren't quite as good, we will expect some lower EURs in those areas. Do you want to -- ?

Harold is exactly right. It comes from -- we have a large body of wells there now, and we can see different parts of the field respond differently. And wells as low as 1.5 Bcf, and wells in excess of 3 Bcf. We're making a success on all of them, but they are all not the same. So that that 2.2 comes from an average of all that activity.

I know that you can't talk about too many things or say too many things at one time, but in your Arkoma Basin, I know the Ranger has quite a bit of upside, especially if you are successful with this exploration acreage. Any other things that might be coming up in the Arkoma that we should be looking for?

We have to constantly generate new inventory there. We've got good inventory in front of us, but we always want to be looking out in out years. And we have efforts going on to put together new plays there, both in the fairway and in some of the other areas. Nothing we would want to talk about right now.

Cost pressure, have you seen any cost pressure there on that drilling or service side?

In the Arkoma?

Just overall, sorry?

I think if you just look at the onshore, it is a different world than offshore than onshore. If you look at the onshore costs, we saw a big pretty big ramp up. If you few just look at drilling, we saw a pretty big ramp up in the regularization in the middle part of the year. And then that has kind of flattened off. We are seeing, depending on what basin and state you are looking at, we are seeing a little bit of softening of that.

And in different basins, different things are happening. But if you had to just kind of paint it with one brush, I see it as a year where we ought to be fairly flat to the kind of costs we saw this year with, maybe, a little bit of creep at 3 or 4 percent in some of the ancillary services and goods.

So given that, do you have an incentive to lock in rig rates in, say, East Texas for '04, or just an incentive to not lock them in?

I think the question is, can you float on the market and do better than what you can lock in, and that is what we are assessing now. We think there is some value in locking in for the continuity that it provides a program, even if you have given up a little bit over the current market. But that is just what we will have to assess your. And we will have a plan for '04 soon.

Well, one thing Richard touched on there, I think it is real clear to us that continuity of the same rigs and same crews is something we don't want to give up in the East Texas area, because loss of days eats up -- if you found yourself with a different drilling rig out there than you currently have, where you have had the learning curve developed with those people, that is our preference for sure, if we can do that and still do it at reasonable prices.

And last one. Budget for '04, any guidance on that there?

Joe, we haven't released any guidance for '04 other than what we put out earlier in the year with a little bit of a production guidance. And it will probably be just as we have historically -- end of January, first-half of February time frame, we will probably be talking in more detail about 2004 as we look forward with that.

Evan Smith, Sanders Morris Harris.

I guess a couple of questions regarding costs. We had seen a nice trend in the LOEs on an Mcf basis really since last year. And some of those ticked up in the quarter. It sounds like some of that is attributed to work over expense in Arkoma. Can you quantify that? And as well, it seems like we would have seen a little better production given some expenditures there on work overs.

Sure. Evan, this is Richard. I will try to address that for you. On a year-to-date basis, we are at about 40 cents per Mcfe. Last year, of course, we were at 45 cents, so overall we are making some good improvements there. The contrast that you're talking about in the second quarter, we were at about 36 cents per Mcfe. And in the third quarter this year, 43 cents.

And it is hard to look to look at it on a quarterly basis when you have some of the activities that we've had. On the work overs side, we had a big quarter there where we have a lot of expenses related to work overs, about $700,000 worth, which is about $500,000 over what a typical quarter might be for us.

So they don't spread themselves out equally within four quarters. The wells to behave that way. I would expect that they will -- so that is good for about 5 cents of that variance there. I would expect those work cover costs would fall back to more normal levels in the fourth quarter.

The other thing that you would think about, Evan, is that if you do work over during the quarter, the well doesn't have much time to deliver production during that quarter.

So we should see an improvement there in Arkoma in the fourth quarter?

Well, that means some of them are just pure expenses related to the maintenance, and sometimes you are returning a well to production that was off production. So they are not all big production boosts, some of them are maintenance in nature.

Understood. Also at AWG, it looks like there might have been some incremental expenses, a little heavier in the third quarter than normal. Can you address those? And what can you do to help lower those costs going forward?

Evan, this is Greg Kerley. The utility for the second quarter to third quarter has normal recurring seasonal operating loss in those two quarters both. And you can see that same comparison with the prior year. The difference really between 2003 third quarter and the third quarter of 2002 driven by a lot of the same things we've seen and we talked about earlier in the year with primarily in our G&A area where pension expense is up considerably, insurance. And then which, again, are drivers that had been affecting us all year long.

And the utility has obviously a large number of our employees and the pension expense, it definitely affects it. The good news about that, I think, with our lake increase, I think that will be starting to be recovered -- that portion of the increase -- beginning October 1 with our rates. So we will see an improvement there.

The seasonal comparison -- excuse me, again -- we're kind of all suffering a little bit here from allergies and under the weather. We will see some improvement as we go forward in the quarters. And for us a comparative decrease was not unanticipated, and is why we were in for a rate increase.

Fair enough. I guess on AWG on an annual basis then a range of operating income, assuming the 4 million or so of incremental rate increase would be, what, 11 to 13 or 14 million?

Yes, I think it would be probably 10 to about that range, 10 to 14, with our EBITDA ranging from the 17 to $20 million range.

Michael Bodino (ph), Stern, Agee and Lee (ph).

It was Stern (indiscernible) at one point in time. Good quarter guys. I wanted to follow up with a couple of questions. I know a lot of them have been asked, but I will see if I can come up with a couple of things that we haven't talked about.

Number one, how much real estate in your portfolio has been sold, and do we anticipate more sales in the future, Greg?

Well, from time to time, as you know, we have sold bits and pieces of real estate in the area that is adjacent to our offices in Arkansas. During the quarter we sold 18 acres of that land, and we've got about 60 acres remaining there. So it is something that -- those sales are periodic, and there's always a continuing effort there to sell that property, but it is unimproved real estate located near a very active area in northwest Arkansas close to one of the regional malls. So it is property that we think goes up in value each year as that area continues to get developed.

And I would say it is not a decision that we make, we're going to sell this amount this month or this quarter. It is as the market comes to us and as we -- you know, we have offers on it from time to time. Sometimes we say no, and sometimes we're having a good enough offer to sell it. And we will continue that program.

But beyond the 60 acres, you still have quite a bit of acreage up there anyway?

The undeveloped land around the office is the 60 acres.

That Haleyville offset where you had a really nice production, is there any room up there for offsets? And is that going to be impactful to fourth quarter production?

Certainly the existing producing well will be impacting the fourth quarter. There are some locations near that well. I think we will probably spud a second well there some time in December to the West of where this well was. And then, of course, we're remapping everything with a new understanding and see some other potential. But at least I think we have a good chance of getting one more spud there in December.

Richard, you had said that on the balance of the year we had four development wells in the Ranger Anticline area, then we talked about two exploration wells. Is the two part of the four, or are we 16 wells? Because I know on the presentation we had talked 13, 14?

We have talked about development wells alone and exploration wells. I'm talking about four being development wells. It is hard to pin these down, Mike, in detail, because sometimes they get drilled on air, and they go down very quickly. And other times we have to mud them up early and they are twice as long. Those would be the development wells we would hope to at least get spud during the calendar year. And then the second exploratory well will be also right at the end of year.

Two more questions, and one was a Coleburn discovery. I know that in the presentation you talked about 10 Bcf growth and 3.9 Bcf net estimates. Are those still good numbers, or now that it is down and you have got a little bit a log there, higher or lower?

We started out with 10 as an unrisk potential number. Which is you're not starting with a very big prospect. And our most likely range was 3 ro 4 Bcf, and it is closer to that. So so it is not a real good big accumulation, but it made sense going in because we derisked it some amplitude work, and so we're happy with it. We will get a good return on it.

It is still highly economic?

Right.

The last question, I don't want to read much into the operational update, but I know for the first time I've seen it says 50 to 60 wells in the Overton Field for '04. I know we talked about 53 in the slide presentation, Rig days are down. Is it possible that we're actually going to get more wells in the year because of that?

Yes, we have to put our capital plan together. I think that is the real driver on it. And we're not finished with that yet, so we're trying to give a range ahead of where we really pin that down and put that together. Certainly if it takes you less days to accomplish a well, and you've got a rig contractor from the year that will add to it. And we have seen some of that this year as we've gotten quicker at it. It caused each rig to creep up a little. I think that range is probably about where we will be. We will just have to see where our capital plan comes out.

Very good. Well, guys, great quarter, and I look forward to the next quarter.

Carl Henderson, Imperium Capital.

Good morning and congratulations on your continued success. You touched on it briefly in a previous answer, but I wanted to gauge your comfort level regarding production guidance. This morning you guided to 40 B in 2003. And previously you have guided 2004's production level to the 50 to 55 B range. Are you still comfortable with the 50 to 55 B range for 2004?

This Harold. Let me try to answer that. I think that the first answer to it is, we haven't changed that number as we have expressed it. But as you know, this is the time of year when we're doing our operating and capital plan for the future. And as we sum all of that up, which we have to take that in front of our Board obviously, late in the year and early in the year. We will be talking any adjustments to what we have said in '05. But at this point in time, we have not changed what is out there.

Thank you. And previously you had given us some detailed EPS sensitivities for 2003 at various levels of natural gas and carried forward prices. Given your updated forward price assumptions and your hedging activities, will you be providing us with that information for 2004 here shortly?

We will not be be -- when we get our plan together, we get to our Board, we will be putting out guidance for '04. And I think that will not happen until at least in January.

Robert Christianson (ph), Buckingham Research Group.

Hello guys. I missed when you would start your first Arkoma exploratory well. And you said something about a second one that would be started?

Yes, Bob, this is Richard. The first one, which is the western most of the two should start in the next week. And then it will go do some more development wells, and then hopefully spud the second one right at the end of year.

And then you said you would drill them with air, but then I guess if you hit a better formation I thought it was all tight rock, you would back to back and you mud up. Is that right? Did I hear that right? What happens in the actual drilling process to cause you to do that?

A large part of the basin is drilled with air handling packages, compression packages on the rigs, which basically you have a large part of the basin that is kind of underpressured, and so you clean the hole, if you will, with air rather than fluid circulating. That doesn't always work.

In this area, the Ranger Anticline area, sometimes we run into problems with not so much being overpressured that we can't do it with air, but more of problems related to having fall in from the hole previously drilled, and having deviation problems in the hole. And sometimes it just makes sense to go with drilling fluids to finish the hole. So when you go to the drilling fluid, it drills considerably slower than when you're on air.

Then do you hydraulically fracture stimulate these wells? And how long does that process take?

They have to be stimulated, fracture stimulated until we can get at economic rates. And do actually do that is a two or three day process.

Changing over to the Overton, what kind of railroad commission permitting to go to 40's? It sounds like you had permits to do four wells a year ago. What is the mechanics there with the railroad commission? And how many permits do you have in hand for some 40's this year?

What we have fieldwide is approval in hand for optional 80 acre spacing. And it is effective 40 acre wells in our comments -- until you have drilled the 16th well in a 640, if you will, you're not really drilling 40. So it allows us to drill a well that is effectively spaced at 40 acres relative to other wells before we filled out the entire 80 acre unit.

That is how we have done the four we have been able to do. We have to just look at the offsets to the other wells, and follow those rules, which of course we have. But going in a more widespread development at 40, we would move to filing with the commission to have 40 acre optional spacing in the field. And we have looked at that and begun discussions with folks on that. And we think that will be something we can do.

Van Levy, CIBC World Markets.

Duck Lake, can you give us an update and review -- I guess, you have worked the 3D seismic for some time now. Give us a sense of the quality of prospects that you're seeing, and what benefit you have received from the survey? And also give us a sense of maybe some sort of success rate that you would hope to achieve there with this new seismic? And maybe take a shot at finding costs?

Yes, we will try to cover that, Van. We got the data in the third quarter of last year, and then entered into the intensive investigating of it and mapping of it -- very pleased with the quality of the data. And we can see the deep section that we want to see, and so from that standpoint it is good. We also got a disproportionate cost reduction in the project because we had put it together and managed it and conceived of it, so we received a promote on it, so it was helpful that way.

We see Canvasback, Daffy and Redhead on the inventory as drillable. They're good solid prospects, but they are exploratory, and they are less than 30 percent chance of success mode, and probably more like 15 to 20. But they're good solid prospects, and we have a significant working interest in them.

And it is hard to try to pick a finding cost for just that body of wells. But if you look at our risk economics, say, just on Canvasback, which we take into account all the risk factors and what the most likely the outcome will be, we're a little bit over a $1, $1.09 for that prospect. And the other ones would be similar. So if we reach our risk economics, then we would be $1 to $1.20 something in that range, which with the kind of deliverabilities that those wells have and the cash flow they have, that would be tremendous.

And I think, Richard, you would be putting, in that type of F&D costs for Canvasback, you would be taking in terms of a 15 to 20 percent probability of success when you generate that economics at that you have got.

So the real question in these things is, what do you find, Van? You don't know until it's over. And the only thing that makes these were drilling is that they're so large. The large size of them makes it worth the risk dollars.

And your 3D should have enhanced that. My understanding it is an area that was difficult to shoot seismic. And we were all out there in the swamps with you where we saw it firsthand. So this was bypassed, yet you have a much better science. So maybe a data sample that was overlooked because of structural issues, so that should help you quite a bit.

Right.

Okay, Harold, on the other end of the spectrum, clearly East Texas low-risk manufacturing has been very good to Southwestern. What are you doing to either add more property in East Texas, or trying to find another play that would have a similar sort of characteristic.

Well, we continue to work the area, and are working towards trying to acquire additional positions there, either through buying or farming in. We don't have one of that nature to announce right now, but the effort continues.

David Heikkinen, Hibernia Southcoast.

A lot of good question so far. Just one quick one. You had mentioned adding a fifth rig in the Overton Field to drill a petit formation. Any update on the results there?

Yes, this is Richard, David. We have got an update, but they're not good. We did drill a horizontal well in the petit there to try to test the new concept. We drilled about 4,000 feet of lateral trying to steer it in thin petit oil zone. We thought we thought that. We have a lot of good shows, but the well -- in testing right now, the well has not done a whole lot for us. So we are scratching our head on it. We're going to put a pump in the well and try and unload it and see if we can get some better results. But right now, it doesn't look very good.

Ron Mills, Johnson Rice.

A lot of questions have been answered. It looks like the cookie cutter is working. A follow-up on Duck Lake. I know Canvasback is drilling right now, kind of a nice prospect. Is that one where if you get it down late this year, early next year, is that something that could actually come into book reserves this year, or is this really an '04 prospects, if it is indeed successful?

We are at about 12,000 feet approaching our intermediate point. And we are trying -- it is difficult to pin down the exact timing on it. The guidance we have given is 60 to 70 days. So that puts you just right there at the end of the year. More than likely it would be something that rolls into the next year. But it is hard to say.

Remind me, what is your net cost for that well?

It would it would be about $2.9 million on the dry hole costs, to drill it and test it and evaluate it.

Gentlemen, there are no further questions at this time.

I appreciate all of you being on the conference call today, and the questions that you asked. From this end of things, we've got a good quarter looking at us here in front of us with the inventory that we have to drill. And as we begin to build the plan for '04, we're excited about what we see out there and beyond. So thank you for being with us today.

This does conclude today's conference call. You may disconnect at this time.