西南能源 (SWN) 2004 Q3 法說會逐字稿

Good day and welcome to the Southwestern Energy Company Third Quarter 2004 Earnings Teleconference. Today's teleconference 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 our E&P operation, and Greg Kerley, our Chief Financial Officer.

If you've not received a copy of the press release we announced yesterday regarding our third quarter results, you can call Annie at 281-618-4784, and she'll fax a copy to you.

Also, I'd like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that and involve risk factors and uncertainties that are detailed in our 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, there are no guarantees of future performance, and actual results or developments may differ materially.

Well, to begin, our results for the third quarter and first 9 months of 2004 have been exceptional. Our financial results continued to set new quarterly records, with net income of 25.4m and cash flow of 58.5m, up 133 percent and 97 percent, respectively, over our results in the third quarter of 2003. Our production continues to grow significantly, increasing by 36 percent from the third quarter of last year and by 19 percent sequentially from the second quarter of 2004.

Overall, our full-year production volumes for '04 are on track to grow at approximately 30 percent over our 2003 results, driven primarily by our drilling program.

Our development drilling programs in East Texas and the Arkoma Basin are very active, and they're working well, and we have a significant inventory of drilling to do in these two areas in the future.

Also, earlier this week, we released an update on our activity in our Fayetteville Shale shale play in Arkansas. The results to date in this new gas play continue to be encouraging, and we look forward to reporting on this activity as it unfolds.

I'd like to now turn the conference over to Richard Lane for an update on our E&P operations and then to Greg Kerley to discuss our financial results, and then we'll answer questions.

Thank you, and good morning.

As Harold said, production for the third quarter of 2004 was 15 Bcfe, up 36 percent from the 11.1 Bcfe we produced in the third quarter of 2003 and up 19 percent from the 12.6 Bcfe we produced in the second quarter of this year. Of the 15 Bcfe of the third quarter production, 6.2 was from East Texas, 5.3 from the Arkoma Basin, 2.4 from the Permian Basin, and 1.1 from the Gulf Coast region.

In the first 9 months of 2003, we invested $210.7m in our Exploration and Production program and participated in drilling 149 wells. Of these, 117 were successful, and 20 were still in progress at the end of the quarter.

On a year-to-date basis, we have invested approximately 81 percent of our total capital expenditures in drilling new wells and have maintained an overall success rate of 91 percent.

In the Arkoma Basin, we participated in 56 wells through the first 9 months, excluding our DeSoto project. Of these, 42 were successful, 6 were dry, and 8 were still in progress at the end of the quarter. We continue to be very active at our Ranger Anticline area in Yell County, Arkansas.

In the first 9 months of 2004, we spud a total of 16 wells, of which 13 were successful, 2 were dry, and 1 was in progress.

Current net production from the Ranger Anticline is approximately 16 million cubic feet per day, up from 5 million cubic feet per day at the beginning of the year.

Two wells of note -- the [Albright][ph] 17 and the [(Cory Heights])[(ph]) 17 are currently producing at a combined gross rate of 10.1m cubic feet per day.

Southwestern operates these two wells with an 83-percent working interest. In addition to completing high-rate wells in the wWestern portion of the Ranger Range Anticline, we continue to bring on successful wells in the original productive area.

An example of this is our [(Brasher 311])[(ph]) well that was brought online at the end of the quarter at a gross rate of 5.1 million cubic feet per day.

Ranger continues to be a very successful development project for the Company. We plan to drill approximately 23 wells there this year. Since we began drilling at Ranger in 1997, we have drilled 39 successful wells out of 46 attempts, and we have added 47 Bcfe of reserves at an average finding and development cost of about 80 cents per MCF.

At our DeSoto Fayetteville Shale shale project in Arkansas, we announced earlier this week that the Arkansas Oil [Arkans-oil][ph] and Gas Commission has approved field rules for our new Griffin Mountain Field in Conway County, Arkansas.

In Arkansas, an application to establish field rules for a newly discovered field must be submitted no later than 6 months after the initial completion of the discovery well or after the completion of 3 wells, whichever occurs first.

Our application included modeling data for 2 of its test wells, indicating an expected drainage area of 30 acres or less per well, estimated gas in place of 58 to 65 Bcf per square mile, and estimated ultimate recovery of 580 to 600 million cubic feet per well. The application sought and received approval for wells completed within the Fayetteville Shale shale formation to be spaced at a minimum distance of 560 feet apart. The estimates contained in our application are based on models utilizing limited preliminary data, and those models will be refined as more data becomes available.

The Griffin Mountain Field rules will cover an initial 9-square-mile area and represents a the small initial area of testing relative to our acreage position in the Fayetteville Shale shale play. The Company expects variability throughout the play. Therefore, the drainage area per well and gas in place and ultimate recoveries included in our filing are not necessarily indicative of the other pilot areas or the entire play area in general.

To date, Southwestern has drilled 13 wells in its Fayetteville Shale shale play and is currently drilling 1 well. These wells are located in Franklin, Conway, Van Buren, and Faulkner Counties in Arkansas. Four (4) wells have been placed on production; 2 of the producing wells are located in the traditional Fairway fairway area of the Basin and are completed within a thinner section of the Shale shale and are selling gas at rates ranging from 125 to 160 Mcf per day. The other 2 producing wells are located in the Griffin Mountain Field and are selling gas at rates ranging from 250 to 450 Mcf per day after 70 and 35 days of combined testing and production, respectively.

Of the remaining wells drilled to date, 6 are in various stages of testing or completion, and 3 are shut in pending the pipeline connections.

Southwestern has completed 10 wells using the nitrogen foam fracture stimulation treatments of various sizes and has completed 1 one well with the larger slick-water fracture treatment. The wells are in various stages of flow-back now, and the Company has seen significant variability in the well performance and, therefore, it's difficult to conclude what the most effective stimulation treatment will be at this time. We're encouraged by our results to date and plan to drill approximately 10 more wells in the play by year-end 2004.

At this time, Southwestern has acquired leases on approximately 500,000 net undeveloped acres and controls approximately 125,000 net developed acres in the Fairway fairway area of the Basin that is held by our conventional production.

Our Overton Field development program continues on course and is yielding very good results. In the first 9 months of 2004, we [spudded] a total of 67 wells, of which 60 are producers and 7 were still in progress.

Our year-to-date 2004 wells have had an average initial potential of 2.8 million cubic feet equivalent per day and an estimated ultimate recovery of 1.8 Bcf per well.

Gross production at Overton Field at the end of the third quarter was approximately 85 million cubic feet per day, up from 60 million cubic feet per day at the end of 2003.

We recently announced that we were increasing the number of wells to be drilled in the field in 2004 from 74 to 84 wells. The increase is due to achieving additional drilling efficiencies that are driving down the time to drill these wells. In the third quarter, the average drilling time to reach 12,000 feet was reduced to approximately 15 days versus the prior-year average of 23 days.

In the Permian Basin, we were active at our River Ridge discovery in the third quarter. Since our last teleconference, we have completed 2 additional wells, the Rio Blanco 3032 and the Rio Blanco 43, which are currently producing 10m cubic feet per day and 8m cubic feet per day, respectively. And we are currently completing a third well, the [Rio Blanco 9-1]. Each of these wells is a Devonian formation completion at approximately 15,000 feet.

Combined gross production from the discovery's 4 wells is currently 32.6 million cubic feet equivalent per day, or 13.2 million cubic feet equivalent per day net to Southwestern.

Moving on to the Gulf Coast, at our last teleconference, we had 3 wells being drilled in our Gulf Coast region. Our L'Orange prospect test well, located in our Duck Lake 3D program, was targeting Marg A sands [large A][ph] stands at about 15,600 feet. The well in [(Cander Desands])[(ph]), structurally high to offsets and had hydrocarbons present. However, the accumulation was not in economic quantities, and we plugged the well.

In our Lake [(Ducay])[(ph]) Field in Terrebone [Tarabone][ph] Parish, our Apache Fee 15-1 well was targeted to Tex-W sands [Texwsans][ph] was also a dry hole. The objective sands in this well were shaled out, and the well was plugged and abandoned.

Our working interest in L'Orange and the Lake [(Ducay])[(ph]) wells was 50 percent and 45 percent, respectively.

The third well, a development well in our Seven Sisters Field in Duval County, Texas is currently being completed. We hold a 33-percent working interest in the [(Humboldt Umbole Fee])[(ph]) Number 9, which targeted the [(Reagan Regan])[(ph]) and [House Wilcox Sands][ph] between 11,500 feet and 14,000 feet.

And, finally, in the Gulf Coast, in the third quarter, we reached total depth on our Rosebank prospect in Lafourche Parish, Louisiana. This prospect, in which we held a 50-percent working interest, is 2 miles west of our [(Holburn])[(ph]) discovery, which is currently producing 3.6m cubic feet per day after being put on production in December of 2003.

The Rosebank prospect recently tested at 3.2 million cubic feet per day plus 150 barrels of condensate per day, and we anticipate this well will be placed on production late this year.

To summarize, our program is performing well, delivering significant growth in production and reserves, while achieving our investment return target of 1.3 PVI or greater. Our drilling inventory is strong and provides for significant future value-adding opportunities, and we are pursuing new projects, like DeSoto, that have the potential to provide long-term opportunities for the Company.

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

Thank you, Richard, and good morning.

As Harold indicated, our Exploration and Production segment had an excellent quarter, -- strong commodity prices and a 36-percent increase in our production volumes, combined to result in record third quarter earnings of 25.4m, or 68 cents a share, more than double our earnings of 10.9m, or 30 cents a share, for the third quarter of 2003.

Included in our results for the third quarter was a pretax gain of 4.3m, or 7 cents a share, on the sale of undeveloped real estate. And in the third quarter of 2003, we recorded a pretax gain of 3m, or 5 cents a share, for the sale of real estate and certain fixed assets.

Our net cash flow provided by our operating activities before changes in operating assets and liabilities also set a new record for the quarter at 58.5m, almost double our cash flow for the same period in 2003.

Net income for the 9 months ended September 30, 2004 was 70.7m, or $1.92 per share, up 108 percent from 34m, or $1.01 per share for the same period in 2003.

Our net cash flow provided by our operating activities before changes in operating assets and liabilities was 165.3m for the first 9 months of 2004, up 74 percent from the same period in 2003.

Operating income for our Exploration and Production segment was 43.1m for the third quarter of 2004, up from 22.3m for the same period in 2003.

Our improved operating results were primarily due to higher production volumes and higher realized oil and gas prices, which were partially offset by an increase in our operating costs and expenses. Including the effective hedges, we realized an average gas price of $5.04 per mcf for the third quarter of 2004, up from $4.23 for mcf a year ago. And our average realized oil price was $31.21 a barrel for the quarter, up from $26.46 a barrel last year.

Going forward, approximately 70 percent of our targeted gas production in the fourth quarter of 2004 is hedged. We also have approximately 45 bcf for expected gas production in 2005, and 27 bcf of our expected gas production in 2006 hedged at attractive prices. Our current hedge position is detailed in our Form 10-Q that was filed yesterday.

Our Eexploration and Pproduction segment continues to benefit from one of the lowest operating costs in the industry. Our leased operating expenses per unit of production were 38 cents in mcf in the third quarter of 2004, down from 43 cents in mcf a year ago.

Our general and administration expense per mcf were 33 cents in the third quarter of 2004, down from 37 cents in mcf in the same period 2003. The decreases in both our permanent (indiscernible) lease operating expense and G&A expense were primarily due to our higher production volumes.

Our utility systems realized a seasonal operating loss of 2.7m million in the third quarter of 2004, compared to a loss of 3.4m million for the same period in 2003. The comparative improvement in operating income was primarily due to the effects of a 4.1m million annual rate increase implemented in late 2003. While our utility segment’s results have improved since last year, we don't believe that we are currently earning our authorized rate of return and as a result, our utility has filed a Nnotice of Iintent to file for a rate increase request with the Arkansas Public Service Commission before the end of the year. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

Operating income for our gas marketing activities was approximately $700,000 for the quarter, compared to approximately 800,000 in the third quarter of 2003. Our capital investments for the first 9 nine-months of 2004 totaled 217.7m million, including 210.7m million for E&P operations. Our capital investments are up approximately 70 percent from the 128.3m million that was invested during the first 9 nine-months of 2003.

We currently expect that our total capital investments for 2004 will be approximately 285m million, which includes about 275 million from our E&P operations. Our strong cash flow from operations combined with our record earnings over the first 9 nine-months of the year have enabled us to fund our increased capital program and still reduce our total debt to capitalization ratio to 43 percent at September 30th, 2004, down from 45 percent at December 31, 2003. Our financial position continues to improve and we currently have approximately 240m million of available capacity under our revolving credit facilities.

Our outlook for the remainder of the year remains very positive. We currently expect our production in the fourth quarter to range between 15 and 15.3 bcf equivalent, which would result in total production for 2004 of 54 to 54.3 bcf equivalent, which is up over 30 percent from our 2003 production of 41.2 bcf.

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

(OPERATOR INSTRUCTIONS.) Van Levy, CIBC World Markets.

I missed part of the call, so excuse me if I’m asking a question quarter that you covered. Can you spend a little more time on the Fayette Sshale play? In your release, you talked about I think it was 50 to 60 bs bcf per section. Is that recoverable or in place because? Because that seems to be quite a bit higher than the Barnett shale play.

Harold Korell Unidentified Company Representative: What was filed, Van --, of course, that’s just for this initial area and it’s based on the modeling and just a couple of wells. But what we filed there relative to the gas in place, was 58 to 65 bcfe per square mile.

In place. And recoverable, what are you guesstimating estimating?

Unidentified Company Representative: Well, we had an EUR ranging from 580 to 600 million cubic feet per well.

And how many wells per section?

Unidentified Company Representative: Well, what we filed is that we expected drainage area would be 30 acres or less, based on this early modeling in those couple of wells.

So it’s 21 wells, call it 600. So , so that’s about 12 bs bcfe per section potentially ?

Harold Korell Unidentified Company Representative: Yes.

I’m doing the math right?

Um-hum.

Okay. And can you take us down the timeline as far as gaining confidence and gaining confidence in terms of booking reserves and those sorts of things? What do you have to do physically? What types of tests do you run? Is it just monitoring the production or are there any sorts of other tests that you can do to assess reserve estimates?

Harold Korell Unidentified Company Representative: Well, we have some wells on production as we talked about and hopefully, we’ll have some more here as the year goes on. And so at year-end, we’ll have PDP pdp reserves that we’ll have to address and . And then look at what may or may not be appropriate for immediate offsets to those wells.

So is it just monitoring production relative to IP rates and then looking at some sort of type well analysis? There’s no not pressure buildup build up and stuff like that you can do, right?

Harold Korell Unidentified Company Representative: Right. Well, early Early on, I think it’s kind of difficult typical to try to make an estimate of these wells using some analogies. And of course, we’ll be working with our reserve auditors on that. But it would probably be more based on analogies early on and then just updated as we get production history.

Second question, Overton, you’re doing a bang- up job there. How many more locations do you think you still have to drill?

Harold Korell Unidentified Company Representative: We We've talked about here either this year that as things have gone along well, that we see a couple more years after this year of drilling to be done out there.

And this is down spacing to what level?

Harold Korell Unidentified Company Representative: Well, some of what we’re doing is 40-acre spaced wells. But if we had like a $5 gas price, we’d we see about another 120 locations that would bring us down nominally to 70 acres if you average the field. If we’re looking at $6, which we’re looking at a high PVI threshold here that we want to achieve. So at $6, that brings you up to almost 180 locations.

And what would be the IRR or the PVI at 5 and 6, roughly?

Those are locations that we determined using a PVI of 1.3 to meet that perimeter.

Harold Korell Unidentified Company Representative: And the 180 locations would get you kind of mostly down to about 50 acres average for the field.

Okay. Last question, as you build a terracid (ph) terraced base, your balance sheet’s in great shape, . Are are there any other areas emerging, potentially a new area, a new Overton or a new Ranger?

Harold Korell Unidentified Company Representative: Van, our idea generation machine is working every day and we have people specifically assigned to finding new opportunities for us to be involved in. We have not identified any of those that we’ve talked about publicly. But that's probably the best way to answer that question.

Well, congratulations. You guys have done a great job. The quarter looked fantastic and keep it up.

Operating: Joe Allman, RBC Capital Markets.

Can you comment on the variability in the well performance that you’ve seen among the 11 wells that you’ve fractured, – the 10 with the (indiscernible) frac and the 1 one with the slick water frac?

We’ve given a range of test rates there and maybe just to put a little bit more color on it for you, the ranges we’ve given, there’s a significant amount of variability there obviously. But the other kinds of things we’re seeing is that -- – and that we have commented previously on some of the variability we would see. Some of the wells have produced a little bit more water than others. We see some variability in the rock properties. And as we’ve said in previous teleconferences, we’re trying to understand structurally, when you’re drilling in faulted areas, how is that going to impact the production? So all those different things are coming into account. And what we’re really trying to do is find out what really does cause variability and to be able to drill the best wells first.

In terms of the slick water frac, has that -- – I know we’re probably still fairly early, but has that been positive or disappointing or can you comment on that?

Of course, we’ve only tried one of those, so it’s kind of premature to really draw a whole lot off of one attempt at that. But generally, it’s in the range of the rates that we have reported, so it’s not outstanding in any significant way from those ranges. And of course, you have a lot more water to produce back from that type of a completion. We put a lot more water into the formation. And it’s just too early to really say. It doesn’t stand out really either way and certainly one attempt at that is not going to give us our answer.

Joe, we’ve had other -- we’ve had variability within -- – we’ve basically drilled in 3 three areas here now. I think everybody’s pretty much familiar with that, but . But 1 one area back in the fairway fairway and then 2 two kind of pilot areas over to the East in the other counties. And those wells have been spaced, more or less, generally a mile apart. And we have seen, in some cases within those two areas to the East, in those eastern counties, we have seen some differences in geology between those.

We had one well that came in high, meaning it had to be fault separated from wells that were near it. It has one kind of performance, doesn’t look particularly good. That slick water frac happens to be in that same area where we’ve had quite a bit of variability in how the wells have produced. So we don’t know right now whether the fact that the slick water frac was not one of the best producing rates. It's sort of in the middle. Given the whole scenario, – the field of results that we’ve had so far, so . So it’s sort of in the middle.

But what What that tells you is it’s not a silver bullet at least in that well. Now is that due to the slick water frac or is due to something in the geology particularly there or where the frac job went. We’ve not done any micro-seismograms seismigrams (ph) here. We’re going to be doing that. We needed to get enough wells close together to where we can put the geophones in a well and then frac a well and try to see what’s the fracture pattern look like? Where is it going? There is a whole lot that we have to learn here.

Some people have said we seem to be conservative in what we’re saying. We’re trying to report the facts, but not so many facts that you can’t figure out what’s going on here either, because. Because we are having different well results in different areas and we’re having different well results in a given area, which . Which tells us that it has something to do either with our frac job or is has something to do with the shale itself, or it has something to do with possibly fault or fracture patterns that might be in the area that are affecting that.

So when we make general statements that there’s a lot to be learned here and that quantifying and qualifying the reservoir rock itself, the fault and fracture patterns and how they affect the producing rates, and . And then really to Van’s question earlier, reserves, – we’ve done modeling work, which we were required to do to present at the AOGC in order to do a spacing hearing, which we were required to do in order to produce the well. So we did that with the minimum amount of data that we currently have and then obviously, reserves are going to be determined by being able to look at the production histories of the wells, over time, so that we can project producing rates over time, and therefore, expected ultimate recoveries in order to sum it up and then report more. And guys, we don't have a whole lot more than that.

Have you gotten to the point in this development -- – I know it’s very early and I know you still need to learn a whole lot, but have you gotten to the point where you feel like this is a go? And and – for example, in 2005, I know you haven’t actually reported what your budget is, your plans are, but have you decided, hey, yes, we’re going spend a bunch more money in ’05 than the 28 million in ’04 and we’re going to drill a whole bunch more wells? Have you gotten to the point where you’ve made that kind of decision in the Fayetteville shale?

Harold Korell Unidentified Company Representative: Well, first of all, we haven’t made our decision for 2005 yet. But what we have made a decision on and we’ve said is we’re going to continue to drill out here through the remaining part of this year. I could speculate about next year, but next year depends on the summation of the results of what we have going on here.

We’ve also drilled really just in a couple of small areas relative to the acreage position that we have. And so we’ll be doing some testing. One of these wells we’re presently drilling is in another county. It's in a new county, in Faulkner County. So we’re going to be testing a new area. We have a lot to learn within each one of these 3 three areas we’ve currently drilled in. We’re drilling in another new area now. What we have said, and I think it’s safe to say, we’re encouraged by what we’ve seen here. We know there’s gas in place in this rock. We’ve in fact been producing gas out of this rock. We’re now selling gas out of this rock through 4 four wells that are on production and soon another one to be on line and some more coming.

And what we’ll do next year will we’ll be driven by the results as we go along. It would be hard for me to imagine we aren’t going to be continuing to drill in this next year, though. I’m not trying to be coy about that. It’s just that I don’t know how much capital we’ll put into this next year. But I can say safely that we are going to have a -- – it looks to me like we’re far enough along here, we’re going to have an active drilling program here next year.

And then just a quick question on Ranger anticlineAnticline. It looks the like most recent wells have had less reserves per well than the first group of wells. Is that just -- do Do you expect that going forward or is there just variability in kind of the wells there as well?

In the Ranger anticlineAnticline? Are you talking about Overton or Ranger?

I’m talking about the Ranger anticlineAnticline. In the Ranger anticlineAnticline, if you look at the most recent successes that you reported yesterday, it looks like on a per well basis, the net reserves are less than what they were on a per well basis previously.

You know, if you look at a quarter’s worth of wells or 1 one group of wells, we have a lot of variability in working interests out there. So you really would have to assess them on a well by well basis. But the year- to date, we’ve had 13 successful wells and we’ve added over 17 bcf there. So I think if you look at the project on a whole, we’ve added about 47 bcf with 39 successful wells, some real good economics and low finding costs. And if you want to try to characterize the most recant activity, we’ve had some of our better wells drilled here recently.

I just wanted to see if there’s any kind of trend there or if your expectations on a per well parallel basis changed at all. But it sounds like that’s not the case.

No.

Amir Arif, Friedman, Billings, Ramsey.

Good morning, guys. Congratulations on a great quarter. Just a follow-up question on Joe’s questions there in terms of what you’re doing in the shale play. Just over the next quarter, can you give us a better sense of what you’ll be focusing on, whether it’s just developing a pilot project or focusing on the completion techniques or testing the other acreage? Or I guess it’s a little bit of all of those?

Richard Lane Unidentified Company Representative: Yes, that’s really what we’ll be doing, Amir. You hit it right on the head. Harold mentioned that the most recent well is in a new county, so there’s some of that going on. We’re going to be drilling close to some of the wells we already had, so we can get some more wells on production and learn some more. And then the spacing of those wells would allow us to do the micro-seismic work. That will give us some good data, we hope, on the orientation and magnitude of these fracs. And like you said, the completion work, trying to work towards understanding what the best way to do it is.

We’re also -- – one of the things I think some of us are anxious to test is a horizontal well here. But before we can do that, we need to have enough well control on the area to make sure we’re guiding that within the confines of the targeted reservoir in the shale. So, that’s something too that needs to be tested here at a point in time.

Okay, and just a final follow-up question here. In terms of acquiring more acreage, are you seeing any more competitive pressure there in terms of other companies trying to move into the area or are you still being able to acquire stuff at a very good price?

Harold Korell Unidentified Company Representative: I don’t think that we’re going to talk about competition for obvious reasons.

Okay, but in terms of your acquisition costs for land, is it trending -- – Strokelin (ph) was what, about $40 an acre. Is it roughly in the same range? You don’t want to talk about that?

I don’t want to talk about it. I think I might be on grounds that I don’t actually know the total answer to that if I did.

Jeff Mobley, Raymond James.

Good morning, gentlemen. Great quarter again. Not to spend an overly amount of time on just the Fayetteville shale. (indiscernible) There’s there’s a lot of other good things going on. Of the wells that you’ve completed and drilled so far, could you just comment on the shale thickness in these areas versus what you expect for average thickness in the play?

Harold Korell Unidentified Company Representative: Well, back over in the fairway fairway, the 2 two wells that are on production there are thinner, – 50 to 70 feet-, something thick like that. And over -- go ahead.

We can’t say what the full range of the thickness will be in the play, because we sampled only parts of it. But kind of as we have tried to project it and map it in the basin, we think we’ve tried some that will be more in the lower end of the range, the stuff in the fairway fairway. And then some of the wells that are drilled further East are in the higher thickness, 250 to 300 feet. But certainly, that may not be the limit of that thickness as well.

Okay, great. In terms of your reserve additions this year, obviously, you had a great success rate again this year and with a lot of predictable programs. Are you at a point now where you kind of feel comfortable with the range of where you think your funding and development costs may come in this year and where reserve growth may be?

You know, I don’t think we -- probably Probably at the year-end, we will really roll all that up and look at the adds and do those calculations. So we’d we probably, you know, probably not try to comment on exact exactly numbers this year. I think what the Company and Harold has talked in the past that this year is going to be the year to finding costs to have a little bit more upward pressure because of some of the, you know, where some of the capital is going, but . But still, you know, pretty desirable looking, I think.

The land acquisition cost in the --shale play with minimal amount of reserves added relative to the overall acreage we've acquired, because we haven't tested much of it, will certainly have an upward pressure on it, plus some of the service costs you're going to have.

Okay. Yeah, just quickly on the service costs. Some of the wells well that you'll be drilling in Overton on increased density that you've added to inventory, if you have a higher gas price environment, how would a -- say, a 30 percent increase in service costs affect those wells? Are your PDI PVIs still high enough that they could absorb that and you would still probably be looking to drill those, or is there, you know, a $5.50, $6.00 gas price and a $30 service price an area where you'd have some pause there?

Well, I think, you know -- like the first thing I would probably -- I mean, you can do the calculation. We've been averaging about $1.5m million per well, so 30 percent would be a significant add to it. But I guess probably the first thing I would say is that we have been able to mitigate what has been a pretty strong price increasing environment already this year by continuing to get efficiencies on what we're doing out there and offsetting the pure cost increases with efficiency and holding our costs there. And then we'll be looking at -- and are looking right now with several of the vendors on,--you know, by offering up a large amount of work here. We think we've got a good chance of holding costs at a decent level. We're getting some indications of that. So -- and then, you know, the gas prices are more than offsetting some of the data that we've published in the past showing a range of really solid economics for a range of reserves out there.

Okay, great. Yeah. No,, I wouldn't expect service costs to go up quite that much, but just trying to get a sense for sensitivity. And as As far as South Louisiana goes, how many additional wells do you anticipate drilling there? I know you've dialed down your expenditures there. Will you -- do you plan to still test a few wells or are you about wrapped your plans [indiscernible] there?

No, we're going through the planning process right now. We have some existing inventory out there still, and we really need to kind of wrap that up and see how it compares to our other investment opportunities. You know, I would--I would look for it to be not a real big year. It will be probably less than what we did this year.

And Then lastly, out in the [Permian], obviously, River Ridge has worked great for you. Are there any additional acreage positions that you've been able to work into recently?

Are you there?

Unidentified Company Representative: Yeah, I'm sorry.

Okay. Any analogies [indiscernible ] to River Ridge?

Yeah. Have you been able to add to your acreage for this scenario and increase your inventory of opportunities in the Permian?

Well, in general in the Permian, we're, you know, we are doing that. In terms of do we have another big Devonian [indiscernible] prospect like River Ridge that we've leased up, no. We have some ideas that we're looking at, though.

All right. Great. Thank you very much. Great quarter again.

We'll hear next from Bob Christensen (ph) with Buckingham Research.

Yeah, guys. Can you explain a little bit more your hedging policy and thinking towards hedging? You know, with a balance sheet as good as yours, cost structure as good as yours, I’m not, I guess on the same page I mean, you've been a little bit--your balance sheet is good. Is your cost structure good? Is your--I'm not, I guess on the same page as you all with your hedging philosophy. It seems a little--a little higher than I would have imagined. Is there something on your minds that leads you to this?

Bob, this is Greg Kerley Curly. I mean, our hedging philosophy has stayed stay fairly consistent, although as we--as we've moved forward in the last couple of years, as our balance sheet has improved, I think what you've seen us move to is more optimistic hedging. And most of our hedging, the largest portion of it, is the cost that's callers [indiscernible] to where we set a floor price that relates to a our project economics to hit our 1.3 PVI target and still give us the upside. In fact, some of the --, you know, the upside on average in our [callers] that we have out for '05 and '06 are over $8.00 an mcf. in MCS.

So we think we've captured the minimum that we have to for our economics to guarantee a very solid program for us. And we know we're never going to get the right perfect time for gas prices to hedge. To get all of the upside, I think, if you look at our numbers through the 10Q 10K, for the 9 nine months this year, the hedges that we've had in place, have resulted in about a 40 to 45-cent negative effect on our average realized price. But again, while those hedges were put in some time ago, and, I mean, from our program going forward, we like to be about 50 percent hedged for the future year about -- as we get about halfway through the preceding year. And we think that that's a prudent thing for us. From our standpoint, we're an organic growth Ccompany. Our project inventory is very deep right now, and if we can guarantee those kind of minimum prices to hit those project economics, we are adding a significant amount of net asset value to our Ccompany as we go forward.

Let's come back to this shale price, if I may. This third quarter frac, was it in the Griffin Mountain pilot area or was it one of the -- another area, the slick-water ? The third quarter frac well.

Yeah, I--I mean, I don't know that we want to kind of pinpoint right now that for competitive reasons. But, it's not in an obscure location and it's where we've been doing some of the other drilling.

Is it 1 of the 2 one of the two wells that's on production?

No, it is not on production.

So is it still in the classification of testing, or is it in the classification of waiting pipeline hookup?

Well, both Both ,I would say. We’ve been experimenting with that well, including how to maybe pump it off and things like that. So it’s really more waiting on the pipeline.

Bob Christensen(ph) So you have a down-hole electric, some ESP in there?

No.

Bob Christensen(ph) No? But you might consider putting an ESP in the hole?

Well, is it -- I guess we could -- I don’t know how important it is to for you to know which kind of pump we’re going to put in it, but we will be putting a pump in the hole. It’s called a -- what What it is called? - Progressive Cavity or something like that. It’s not a beam unit, but it’s not an ESP either. We’ve tried to put plunger lift on it to keep the water unloaded. And so we’re going to pump it for some period of time here and see what happens with that. But that well is not in the Griffin Mountain. It’s , it’s in the other pilot area in the east. There’s nothing secretive about it, except --–- it’s not a silver bullet, at least in that well, we know that.

Bob Christensen(ph) Right. It sounds like you suspect you might have caught something local like a fault. That’s a possibility?

Well, who Who knows what it is exactly. But the frac job was a fairly sizeable slick water frac. The question is where did the frac go? We’re not producing huge daily volumes of water. So it’s not like it’s an ocean. But it can be a combination of –- -- the possibility of just put a lot of water into the formation, lacking the energy of the nitrogen to get it back out, and that water may still reside in the frac and you are going to produce more of it back before you get much gas. That’s one possibility.

I guess there’s a possibility we fractured into a fracture system that had some water in it. But it doesn’t look like its high deliverability water if that’s true. It could be that if we fractured into a fracture system, we lost our energy and didn’t fracture the shale up very much. And so we don’t have a lot of gas coming to help unload the water. So we do have gas producing -- gas coming out of it. We’re just trying to get more of the water unloaded on it and see what happens there.

The other thing I think I would say in general about that, Bob, is that it’s not just a given in any kind of reservoir or target that if . If we you have a productive well and you move to a slick water, that it might help that it’s the silver bullet it built a (mullet) (ph) or that it’s automatically going to be -- create better productivity for you. There’s a lot of places that’s not the case. There’s a lot places that has been touted (indiscernible) that the performance is as good, but not really measurably better than other types of completions. But there’s been some cost effectiveness to it. Each one of these is its own thing and that may or may not be it. Each one of the plays is its own thing. And then as we can see here, these wells have variability. Even when we’re doing these foam fracs, they have different performances. So we need to understand that.

Will you be doing other slick water fracs in the remaining wells in the year? Are you deterred at the moment? You’ve only done 1 out of, what, 13 wells. I would think you would probably try some others.

Yes, we’re going to experiment with -- –- we’ll do some wells like what we’ve been doing where we’ve had decent results until we get decent duplication of that and we’ll be experimenting with changing up some of the parameters in the nitrogen jobs and changing up some of the parameters in the slick water jobs towards trying . Trying to understand what tickles this thing the best and -- –- so, yes, we’ll be experimenting with all that the rest of the year.

The cost of nitrogen versus the cost of water, I mean, for instance, how much did this what did this, I guess, slick water frac cost versus the nitrogen frac? I know one involved a lot more quantity of pumping, but --

Yes.

–- I mean, could conceivably we continue on a path of doing nitrogen and wouldn’t even notice it in our finding of development normal costs? Is that -- ?

Again, I think that was going to depend on where you really end up on your preferred design because. Because even within the nitrogen completions, we have -- –- right now, if you looked at our expenditures, we have a range of, you know, as low as almost $100,000 to up to $200,000 in the nitrogen job.

So a $400,000 well has as a range of $100,000 to $200,000 and –- I think you threw out $400,000 a well, which was some time ago in the first revelation on the play. So is $100,000 to $200,000 on top of that related nitrogen, or is it in the $400,000 well?

Well, you know, the $400,000 number was the number that was out there early. We’re spending -- investing more than that in each one of these wells now, as we’ve been testing more extensively and learning about the completion of things. So really, the kind of numbers you need to be thinking about right now, we’re spending somewhere between $500,000 and $700,000 per well. Now we think we can drive that down. We have a history of doing that kind of thing when we have a high well count play.

But on the completion part itself, what I was saying is, even in the nitrogen jobs, we have a pretty good range, and why is there a range? . A wider range? Well, it depends on how we’re doing it. Sometimes we’ve done a single stage; sometimes we’ve done 2 stages. Which one is going to be the best? We don’t know. So there exists a range there.

On the slick water completions, you know, we may be able to do that now more like -- –- I think we were in the $100,000 to $125,000 range. So, yes, I mean, there is the potential for some savings there, but it depends where we end up. It depends on where we end up.

Harold Korell Unidentified Company Representative: Bob, your question about whether we could do nitrogen jobs and you wouldn’t notice it in the finding and development costs, it’s purely related not just to the cost of the fracture. frac job; It’s it’s related to the results of the frac treatment and what the reserves are. So the answer to that is if the slick water fracs are less expensive, but don’t give as good results, the F&D costs could be higher than they would be with a higher cost nitrogen job.

The real question is what works the best and we’re out there doing various treatments in various areas and we’re trying to do it in a way that we have things that we can compare one to the other so that we can sort that out. But that’s not uncommon. That’s the way you have to do this business.

And one final, Harold help. I mean, let’s go down the road maybe into ’05 or something and say your encouragement level stays high, and could we ever get real modern drilling equipment in? I mean like drilling with coil tubing or --. I don’t know. I guess you’re using the standard drilling rig right now and maybe if you really wanted to punch lots of holes very effectively with -- –- is there a piece of drilling equipment that could come into the area and do it different than a rotary rig? You know, let’s get out here a ways and speculate on -- well, -- speculate is the wrong word --, imagine what the drilling efficiencies might be?.

Harold Korell Unidentified Company Representative: We’re using the most modern equipment available at this time in the Bbasin. We have had conversations with drilling companies about trying to imagine different ways of doing this. As you know, any time you imagine a new way to do something, there is an investment required and an amortization and a return expected. So, yes, we’re having conversations with people about that type of thing. It’s all got to be factored into the cost effectiveness of it ultimately.

Will we see another pilot area like Griffin Mountain filed before too long?

You mean the field rules?

Yes.

You called it pilot area.

Yes, I feel -- yes, that’s sort of -- –-

We call pilot areas where we’re drilling.

Right.

You know, the field rule of filing is a requirement when we get to a certain number of wells in that given area. At some point, we’ll have that happen again in the second area that we’ve been drilling in and then hopefull --.

And a 3-well Twelve minimum versus 6 months minimum, whatever comes first? I would think you have 2 wells in 1 area. If if you’ve had another 1, punched that would get you there. Is that -- –- ?

That’s right.

We’ll be applying before too long, probably on some more of that, Bob.

And then as we drill in other areas, the same thing will occur.

Are you real happy with this Ranger Anticline? The wells that I’m seeing come in are just pretty darn good.

We couldn’t be more than happy with what we’re doing there. Yes, it’s going very well. We have a lot of wells to drill going forward. Got a lot of offsets to currently producing wells. We’ve been encouraged by drilling off to the west side and then the (Glory Heights) (ph) there back to the middle. We’ve gotten into a real good fractured area there. In fact, 2 wells there that are some of the best we’ve seen on the a Ranger Anticline. No, Ranger Anticline is going very well.

Those very great big wells that you mentioned at the front end, I think it was 10m million a day coming out of 2 wells. How fast do they decline? I’ve seen 4 and 5m million a day wells and more on test and then they –---- can Can you give us a sense now of --, I don’t know what one of your good ones out there, the Smith or the Albright, what it came on at because ? Because these wells are now flowing for, God, god now, what, a year? I mean, what do they look like now after a bunch of months of production? Are they -- ?

Yes, well, the The 2 you referred to that are combined at 10m million a day, their decline has been quite flat actually.

Wow.

So I think 1 of them has cum’ed somewhere around 600m million already and it’s going on its way towards its first bcf PCF already. It’s been pretty darn flat in the main producing area. You know, our good solid bread-and-butter wells there where we’re kind of 1 to of the 2 bcf BCF-type wells, you know, they’ll start off -- –- some of those will start off as high as that, but more typical, a couple million a day to 3m million. And they’ll drop off very quickly, but hold at decent rates and give good economics. So these are not doing that. We have some of both. I think it’s got to do with whether you’re primarily draining matrix ferocity or if you have some big nice open fractures that are really contributing.

Well, thank you very much for your openness on the shale play and helping us understand. I really appreciate it. Good luck over the course of the year.

Thanks, Bob.

Mark Bonafacik (ph), Future Frederick (ph) Capital.

Good morning, gentlemen. Just one more quick question on the shale, Fayetteville sShale pPlay. When you talk about the thickness of the 2 lower-producing wells, what is the thickness for the shale on the a wells producing the 250 to and 450 and the Griffin Mountain pPlay?

They’re in about the 250-foot thick range.

All right. And is there any -- –- still plan to drill the horizontal wells by year-end?

I think we’ll -- –- we’re not certain about that. I don’t know that we’ll get it done by year-end. More likely, it’s going to creep into early next year. We’re trying to get some design and actually some well wall control to help us steer that, though. spear that. So I would probably look more towards early next year.

All right. Well, thank you very much. (indiscernible).

Travis Anderson, Gilbert, Gagnon & Howell (ph).

My question was pretty much the same. I was wondering when horizontal was going to happen and what criteria you’re looking at to make that decision. If you could do some seismic work on this to really determine -- ?

I think -- excuse me.

Go ahead.

I think we’ve decided that we want to try horizontal. Certainly it needs to be part of the evaluation of this kind of a play. So really, the timing on it is more related to preparing 1 one and looking at the design and having the well control. We will try some.

And what are the estimates, if any, of what those wells would cost?

We really haven’t put that together yet. So it would be kind of premature to estimate that.

Okay. Thank you.

Frank Bracken (ph) (Indiscernible), Jeffries & Company

I’ve kind of got two. First, it looks a lot of the geology you all have done to date is kind of pipeline geology and that you’re trying to drill wells in areas that you’ve got infrastructure, which makes loads of sense. Can you detail your plans for maybe -- and as a consequence, it looks like you’ve drilled some of the shallower shale in the area. Can you tell us your plans for maybe trying to get some depth and extra pressure in evaluating the shale in some deeper parts of where it’s available?

Harold Korell Unidentified Company Representative: The first thing is we are still leasing land in this play. You are correct in assessing that we’ve drilled a lot of along a pipeline in 2 of the pilot areas to the east. Of course, back in the fairway, we’ve got pipelines all over there and gathering system there. I mentioned earlier here that we are drilling in Faulkner County. So you can follow that well as it goes down. So that’s a new area for us. As far as where we’re going to go next, we’re not going to put dots on the map for you.

But does it make sense generally that with depth might come extra pressure and extra reserves?

Harold Korell Unidentified Company Representative: Well, we’ve seen it generally normally pressured here. In the eastern part, there’s some little subnormal pressuring over in the fairway area, which is probably relative to some of this gas moving up into shallower zones that have been produced over the years. It makes some sense, but I -- you know, we kind of anticipate normally pressured reservoir here, so if you get deeper, then you would have more pressure. That’s correct.

And then secondly, to what extent does the notion that this shale isn’t, you know, a completely clean, continuous shale, influence your thinking on what might be causing the variability in your well results?

Harold Korell Unidentified Company Representative: Well, we log each well and of course, we get the full suite of logs and in some cases, the FMI logs and we see some variability on log responses. It’s hard for us to tell whether that’s what’s the -- what’s causing the variability in the production. It could be relative to that and of course, if it is relative to that, the response on the logs, then what causes that response on the logs?. And then is that predictable in advance or is it, rather than being a mineralogy and a rock type or change, is it -- is the variability in response that we’re seeing due to the fact that we’re near some faulting or fracturing, and we’re losing some of our frac energy by it going into some fracture system that exists there. It may -- you know, we just don’t know the answers to that yet. So those are the type of things -- we have to get enough sampling and continue to work this thing to figure out.

Got you. And then lastly, what is it that you're using to -- in the Griffin Mountain area, to call the top of your -- you’ve got a pretty thick section there. The bottom looked pretty obvious. It looked like you had a sand there that demarcated the bottom of your shale. The top, though, looked a little curious to me.

Right. It depends where you are in the play, Frank. Actually, the base of the interval is more described by some limestones. We had the Boone formation down there and then the top of it is a little bit more variable. We have a Pitkin formation; that’s a limey formation and then depending on where you are in the play, you have some plastics that come and go in the top of if the interval as well.

Is it your assessment that those are generally sufficiently impermeable, but you don’t have -- that you’ve got reasonably good frac areas?

Well, you know, we've done some limited modeling on that that suggests that given limited perforating and the types of jobs that we've been treating with, that we’re containing the height and that those limestones are held to be effective, but we really need to kind of get out in the field. That’s on paper and we really need to get out in the field and do the micro-seismic work and look for the real geometries of that if we can, and try to understand that relative to some of the well performance.

Got you.

Marshall Carver, Hybernia Southcoast Capital

This is David Heikkinen, actually. I just had a question. I wanted to make sure I got the numbers down right. The cost per well, the completed well cost for the Fayetteville, did I hear $500,000 to $700,000?

Correct.

And then what are your thoughts, Harold, as far as when you're going to be able to provide some sort of ‘05 guidance and overall capital plans and allocation?

Well, pretty much as we've done historically. We go through building our plan from the base up, projecting all of our properties and we’re doing that at this time of the year, and then we go through an (interative) (ph) process with layering in the inventory of capital drilling projects, development and exploration that each of our business units would want to do.

And then as management, we review and sort that with a focus on present value added for dollar invested, and so we ultimately wind up presenting all of that to our Board for approval in our first Board meeting of 2005, which ought to happen in February. And then we would generally at that point give our expectations, set our guidance, if you will, for 2005. I know it’s -- you know, some other people do it a lot earlier. Our plan is a bottom-up-driven plan, rather than a top-down-driven plan, and so we wait until we get all the pieces together. So you may have to kind of wait on us longer than some others. I don't know, but that’s the way we do it.

And as you’ve gone through the year, you’ve increased guidance and had talked earlier about some double-digit growth still in ‘05. Feel good about that still from the -- even though you continued to exceed expectations throughout this year?

Well, we feel good that we’ll have double-digit growth next year in production, yes. We’ve had some good things build our base layer of production to this point, which we've talked about earlier.

It isn’t anything where the west Texas or any of the little success in south Louisiana that would decline off that would give you any concern about that double-digit target still for next year?

No, no.

Okay, good.

The real question is, what’s the number going to be out there and we don’t know until we pull everything together. And for example, things like this discovery in south Louisiana that Richard talked about earlier, you know, that’s a pretty substantial little rate that we’re adding there, and the fact that that will come on late in the year, now we’ll have it modeled into our performance, rather than to try to give numbers earlier.

Ken Beere (ph), Johnson Rice

Two questions, one is up in the Fayetteville area, in terms of infrastructure, obviously, there’s some in the fairway and less around -- or outside of the fairway, but do you feel like if this play is very successful and you really ramp up, is there -- what kind of capacity is available to you, or are you going to have to really think ahead of time to lay lines and add capacity? And could that ultimately be -- obviously, a high-grade problem, but could that be a lag factor in the development of this play?

Well, Ken, there are two major pipelines, or significant pipelines, that go through here. One of them is the Ozark pipeline that happens to pass through the area that we’ve been drilling these 2 pilot areas in. As most of you probably know, we still own a 25 percent interest in that, and then there is a Reliant pipeline that goes across the state a little further south, running east-west, from -- it goes through there also. Our interest in the NOARK north pipeline, or the Ozark pipeline, as I mentioned earlier, probably has what, Greg, 100 and --

50 to --

-- 150 to 200 million cubic feet a day capacity. You know, it would be nice if we could fill it all up.

Okay. You just answered it with that question -- I mean, with that -- okay. So that really isn’t an issue and if it is an issue, it’s such a high-grade issue, that --

And then the Reliant pipe to the south has some capacity. We have visited with them just in terms of -- yes, we do planning out in advance and they're interested in what’s happening here, and they would have to do some expansions, I guess, some crossing the Mississippi River to put a lot more through there, but you know, I don’t think we’re going to have a big constraint on takeaway here for the immediate future.

Got you. And second question on -- maybe this is more for Greg, but when you're doing your PDI PVI analysis to kind of rank all your projects and get them lined up for next year, what kind of gas and oil price are you using just to go through that exercise?

Ken, this is Greg, and we haven't decided that yet. I mean, it’s something that we’re looking at as we go forward as we -- last year, we used a $4 price to -- at the time to do our planning. And so, I mean, that’s a process that Harold indicated. As we pull everything up together, we’ll make a call on what price we’re comfortable using to base our base budget off of.

Okay, fair enough. I’m not sure of the price for ‘05 either, so appreciate a good quarter, a long conference call. Thank you.

Thank you.

Joe Allman.

I’m contributing to the length of the conference call, sorry. The powder, Richard, are there any in the Fayetteville shale? Are there any issues with the development, any environment issues that you may be encountering or any local opposition or anything like that?

Well, hopefully not. We've always operated in an environmentally very best way we know how, and I think within all the regulations of the state. A play like this, depending upon the density of drilling that would take place in it, you know, could -- certainly, we could have and would have an impact on whoever the landowners are there. And so, it really depends on how this goes. When you're drilling wells like we are right now, more or less a mile apart or a half-mile apart or whatever they get to, I think the drilling density ultimately can be a question in any area. And we’re committed, within our operations, to work as a good citizen in each of the areas that we drill in and I don’t see -- think that we’re going to have a particular problem with that here.

Great. And then I know in your September 21 press release, you gave a range -- you had 7 wells drilled at that point that you announced a range of test rates 150 to 700. Are we still within that range for the 13 wells that we've seen so far?

Yes. Now, and we need to be -- we need to maybe clear something up there, because you're sort of verging on maybe not -- it not being clear, and that is that when we were reporting test rates earlier, we had -- we did not have those wells on production. So those were rates that we were flowing them back at and so they -- you know, those would be the initial early days of it and so the rates we've reported now are rates that wells are producing at that are actually selling gas into the pipeline. So they had some decline off of an initial rate, and all of you need to keep that firmly in mind because you want to know production rates, which we reported testing rates because it’s all that we had early on. Now we’re reporting producing rates on the wells because I think that’s the more important thing is what are the wells producing at and selling gas at?

Well, I guess my question is for the ones that aren’t producing right now, the ones that you’ve tested. You're still within that range, you know, 150 to 700?

Yes.

Um-hum.

Yes.

And then in terms of your model for this play -- I know it’s early days, but do you have a model that basically says, “Okay, we've got 500,000 undeveloped acres.” What percentage of that, do you think, will work at this point? Again, I know you only put on a slice of it.

I’m sorry, we don’t know the answer to that.

All right. Thank you.

We have no further questions in the queue. I’ll turn the conference back over to our speakers for additional or closing remarks.

Okay. Well, as a few people have said, it’s been a long conference call, but I think it’s -- we appreciate the questions. They’re good questions. I know everyone out there listening is trying to understand this as best they can, and we’re doing everything we can to try to evaluate and assess it, so we know what we have here. We are -- and we’re talking about the Fayetteville shale.

So thank you for being with us today. When we look at this year overall, 2004 is shaping up to be an extremely good year, setting aside the Fayetteville shale. You know, the Company has never been in better shape. Its production is growing; the reserves are growing and we’re adding significant value in our investment program. And as we think about 2005, although we've not put out numbers out there, you know, we see another very successful year in front of us.

So again, thanks, and have a good day.

That does conclude today’s conference. We thank you for your participation. You may now disconnect.