西南能源 (SWN) 2005 Q1 法說會逐字稿

Good day everyone and welcome to the Southwestern Energy Company first quarter 2005 earnings. Just as a reminder, today's call is being recorded. At this time I would like to turn the conference over to the President, Chairman and CEO, Mr. Harold Korell. Please go ahead, sir.

Good morning and thank you for joining us. With me today are Richard Lane, our Executive VP of Exploration and Production, and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced on Friday regarding our first quarter financial results, you can call Annie 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 this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would 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're not guarantees of future performance and actual results or developments may differ materially.

While we are off to a great start in 2005, our first quarter financial results were the best in the Company's history as we set new records for earnings and cash flow due to our production growth and higher commodity prices. We continue to have excellent results in our drilling programs at the Overton Field in East Texas and the Ranger Anticline in the Arkoma Basin. In addition, we continue to make progress in our Fayetteville Shale play. By the end of the quarter we had drilled 39 wells in six pilot areas in four separate counties in the play. We have begun testing horizontal wells with encouraging results which Richard will dicuss in a moment. On the land front, we are continuing to lease new acreage and to date we have leased approximately 630,000 net acres in the undeveloped play area and we control an additional 125,000 net developed acres in the traditional Fairway area of the basin.

We have also seen increasing competition for leases over the last few months. Overall, we continue to be excited about the potential of the Fayetteville Shale play. Our drilling program will remain flexible throughout the year and we will continue to be impacted by a number of factors including the results of our drilling efforts, our progress in determining the most effective fracture stimulation treatment, the performance of wells we drill in new pilot areas, prevailing costs for services and materials and the gas commodity price environment. We have had in excellent start to what I believe will be a very exciting year for the Company. I will now turn the teleconference over to Richard Lane who will tell you more about our E&P results, and then to Greg Kerley to discuss our financial results, and then we will answer your questions.

Good morning. During 2005 we continued with an active drilling program in East Texas and the Ranger Anticline field in the Arkoma Basin. In addition, we have been evaluating fracture stimulation techniques and testing horizontal technology in our Fayetteville Shale play. We currently have six rigs running in East Texas, three at Ranger and three in our Fayetteville Shale play. In the first quarter we spudded a total of 64 wells including 21 in East Texas, 13 at Ranger, and 18 in the Fayetteville Shale. Our production volumes for the first quarter were 14.0 Bcfe, up 22% from the first quarter of 2004 despite the curtailment of a portion of our production at our Overton Field in East Texas. Due to continued curtailment at Overton into the second quarter, we are revising our second quarter production guidance down slightly from a range of 15 to 15.4 Bcfe to a new range of 14.8 to 15.2. We are continuing to hold our full year guidance at 61 to 63 Bcfe.

At this time, we expect all curtailment issues at Overton to be resolved by the end of the second quarter. Of the 14.0 Bcfe of first quarter 2005 production, 5.9 was from East Texas, 4.9 from our conventional Arkoma Basin properties, 1.8 from the Permian Basin, 1.2 from the Gulf Coast, and 0.2 from our Fayetteville Shale play. Going onto the Fayetteville Shale play, in the first quarter of 2005 we invested approximately $20.1 million in the play including 11.9 million to drill 18 wells, 6.9 million for leasehold acquisitions. As of March 31st, we held approximately 630,000 net acres in the undeveloped play area. And in addition, as Harold mentioned we control approximately 125,000 net developed acres in the traditional Fairway area of the Arkoma Basin which is held by production. Since beginning our drilling program in the Fayetteville Shale play in 2004, we have drilled a total of 38 wells and anticipated in one outside operated well. Of the 39 wells, 27 are producing, eight are in some stage of completion or waiting on pipeline hookup, and four are shut-in due to marginal performance. To date we have drilled three horizontal wells in three separate pilot areas. Of the three horizontal wells, two have been completed and tested and one is waiting on completion.

The first horizontal well was drilled in the Company's Griffin Mountain field area with approximately 1,800 feet of lateral and required 32 days to reach total depth. We initially planned to perforate and stimulate four different intervals along the length of the horizontal section. However, problems with well bore isolation limited the potential stimulation of the well to effectively only one stage at the tail of the horizontal section. This well had a final test rate of approximately 580 Mcf per day. The second horizontal well completed the Company's Rainbow pilot area had 2,264 feet of lateral and required 11 days to drill. This well was successfully fracture stimulated in four separate stages, tested at a rate of approximately 3.7 million cubic feet per day, and will be on production later this week. The third horizontal well located our Brookie pilot area took 19 days to drill and had 2,175 feet of lateral section. We expect to be completing this well over the next few weeks. And we are currently drilling our fourth horizontal well which is located in our Rainbow pilot area.

The average drill and complete cost for the first three horizontal wells was approximately 2.1 million per well. Excluding extraordinary and nonrecurring costs, we estimate that our horizontal well costs during the second quarter will range between 1.5 to 2.0 million per well. We also recently placed a new vertical well in production at a rate of approximately 1.3 million cubic feet per day, with the flowing tubing pressure of approximately 1,100 PSI in our Brookie pilot area, and tested another vertical well at a rate of 1.28 million cubic feet per day, with a flowing casing pressure of 490 PSI in our Rainbow pilot area. The cost to drill and complete our vertical wells range from 440,000 to 650,000 per well, with the higher cost wells predominately in our Griffin Mountain field area.

We are continuing to get more history on our producing wells. As was expected we have begun seeing more variance in the Fayetteville Shale's productivity between the different pilot areas. Initial potentials of the vertical wells have ranged from 300 Mcf per day to 1,500 Mcf per day. The first 30-day average producing rate from the 13 wells which have been on production that long, is 375 Mcf per day. The second 30-day average rate from the eight wells producing that long is approximately 215 Mcf per day. Assuming a first-year average exponential decline rate of 75%, second year rate of 45%, (technical difficulty) completed horizontal wells. Our activity for the remaining part of the year will include continued efforts in improving the fracture stimulations on vertical wells, drilling additional horizontal wells, some seismic acquisition, and testing of additional new areas of our acreage.

A key word here is flexibility so that we can pursue the best path forward for value creation. Moving to the Ranger Anticline. As I mentioned previously, we spudded 13 wells in the first quarter of 2005. All of these wells are either on production now or currently being tested. The Ranger Anticline is located in Yell and Logan Counties, Arkansas and produces from the borum stands between 5,500 feet and 8,500 feet. Of the 13 wells, ten are located in the core producing area of the field, two are located in the Western expansion area we began developing last year, and one -- the Standridge #1-10 well was drilled as a nine mile eastern step-out of the core producing area. As mentioned last time, the Borum sands were tight in the Standridge well, however, we did penetrate about 150 feet of gas pay in the Basham and Turner sands at approximately 3,500 feet.

This well is currently waiting on pipeline connection. We plan to drill offsetting wells in 2005 to determine the extent of these shallow pay sands, as well as to continue testing the deeper section. The success of our Ranger Anticline drilling program is reflected in the field's increasing production. We are currently producing 25 million cubic feet per day gross, up from 8 million cubic feet per day at year-end 2003. In East Texas, we continue to be very pleased with the results of our development drilling program at our Overton Field, which is in Smith County, Texas. In the first quarter, we spud 18 wells at Overton and have maintained a 100% success rate. We have now drilled 191 wells since we acquired the field in 2000. The average estimated ultimate recovery for our first quarter of 2005 well is approximately 1.6 gross Bcfe per well. The combination of our cost controls and continuing goodwill performance is allowing us to continue to exceed our economic hurdle rates at Overton.

As mentioned earlier, our production at Overton is still being curtailed due to the failure of a transmission line into which a large part of the field's production goes. The operator line is continuing to seek regulatory approval to return the line to its normal operating pressure. To partially offset the curtailment caused by the line failure, additional compression was recently added to a second transmission line and plans also call for looping this line to further increase our take away capacity. We expect all the curtailment issues at Overton to be resolved by the end of the second quarter. In addition to our Overton Field, we continue to be active in other areas in East Texas. The Reavley #1 well located in our Black Bayou Prospect located in Nacogdoches County, is probably producing 1.3 million cubic feet per day from the Travis Peak at about 11,000 feet.

We are currently staking two offsets to this well which we operate with a 40% working interest. At our Doyle Creek prospect in Cherokee County, we are currently completing our Session Naires (ph) well. This well encountered about 95 feet of pay in the Travis Peak formation at 10,900 feet. We expect this well to be on production in late May. Also in East Texas we plan to spud two of our exploration tests in the second quarter, the Watch No. 1 in our Pines Prospect in Marion County, we will test the Lower Cotton Valley in Bossier Sands at about 11 300 feet, and this well is currently drilling. We also plan to drill a test of our Ginger Quill (ph) Prospect located in southeast of our Black Bayou discovery in Nacogdoches County, late in the second quarter. Moving on briefly to the Permian Basin.

At our Low (ph) Bluff project in Eddy County, New Mexico we are developing a shallow oil play in the Glorietta Yeso (ph) formations at about 3,700 feet. And to date in 2005 we have drilled two wells producing 144 barrels of oil per day and 93 barrels of oil per day, respectively. Although fairly small at these shallower depths and strong oil pricing, this project yields an excellent PVI for us and we plan to drill additional two to five wells here by the end of the year. In summary, we continue to be encouraged by our results at Overton, at the Ranger Anticline and particularly at our Fayetteville Shale play. We are looking forward to strong results for the remainder of the year. I will now turn it over to Greg Kerley who will discuss the Company's financial results.

Thank you, Richard, and good morning. As Harold indicated our results for the first quarter were excellent, primilarly fueled by our strong production growth and higher realized commodity prices. Earnings for the first quarter were a record 32.6 million or $0.87 per diluted share, up 33% from the first quarter of 2004. Cash flow provided by operating activities before changes in our operating assets and liabilities, also set a new record for the first quarter at 37 -- 73.6 million or up 30% from the same period in 2004. Operating income for our E&P segment was 47.7 million for the first quarter of 2005 compared to 33.4 million for the same period last year. The improved results were primarily due to a 22% increase in our production volumes, combined with a 16% increase in our average gas price.

We realized an average gas price of $5.71 per Mcf for the first quarter of 2005, up from $4.92 for the same period last year. The Company's hedging activities had minimal impact on the average gas price realized during the the first three months of the year compared to ur hedges in place during the first quarter of 2004, which lowered our average price by about $0.42 per Mcf. Locational differences in market prices for natural gas have continued to be wider than historically experienced. Disregarding the impact of hedges, our average realized gas price during the first quarter of 2005 was approximately $0.55 per Mcf lower than average NYMEX spot prices. This was in line with our previous guidance and about $0.20 wider than our average for the prior year period. We currently estimate that our average realized market differentials for the second quarter will range between $0.40 to $0.50 per Mcf lower than average NYMEX spot market prices, excluding any impact from our commodity hedges.

We have approximately 70 to 80% of our targeted gas production hedged in 2005, and our current hedge position is detailed in our Form 10-Q that was filed Friday. We continue to be one of the lowest cost producers in the industry. Leased operating expenses for per unit of production were $0.45 per Mcf in the first quarter of 2005, compared to $0.38 for the same period in 2004. The increase in our unit operating expenses was primarily due to increased compression costs and higher oilfield service costs. General and administrative expenses per our Mcf equivalent were $0.39 during both the first quarters of 2005 and 2004. Our full cost pool amortization rate rose to $1.29 per Mcf equivalent compared to $1.18 a year ago, primarily due to increased finding and development costs. Operating income for our utility segment was 7.4 million in the first quarter, down from 8.8 million in the same period in 2004.

The decrease in operating income resulted primarily from decreased deliveries due to warmer weather in the utility service territory during the first quarter and higher general and administrative expenses. On December 29, 2004, our utility filed a rate increase request of 9.7 million annually with the Arkansas Public Service Commission. The scheduled hearing date for the rate increase request is in September and any increase allowed would likely be implemented in the fourth quarter of 2005. Operating income for our gas marketing activities was 1 million during the quarter, up slightly from the first quarter of 2004. Our capital investments for the first three months of 2005 totaled 80.9 million, including 78.5 million for our E&P operations, up from 58.6 million during the first quarter of 2004.

Our strong cash flow enabled us to fund our increased capital expenditures and also pay down 27 million of debt during the quarter. As a result, our total debt to capitalization ratio improved to 40% at March 31, 2005, down from the 42% at year-end. Our outlook for the balance of 2005 is very positive. As Richard indicated, we are targeting total oil and gas production of 61 to 63 Bcf equivalent for the year. If you assume NYMEX commodity prices of $7.00 per Mcf of gas and $50 per barrel of oil, we are targeting net income of 120 to 130 million, and net cash provided by our operating activities before changes in our operating assets and liabilities, of 290 to 300 million. Our current planned capital investments for 2005 of 352.7 million are expected to be funded by our cash flow from operations and borrowings under our revolving credit agreement. We currently have 427 million of available capacity under our credit facility. That concludes my comments and now we'll turn to the operator to explain the procedure for asking questions.

(OPERATOR INSTRUCTIONS) Joe Allman with RBC Capital Markets.

Good morning everybody. Herald, in the Fayetteville Shale, what might be constraints in developing that as fast as you would want to -- people, equipment, anything?

I guess, Joe, we really having gotten to the as-fast-to question. At this point in time, we are progressing at the pace we would like to. It is a pretty -- it's kind of a hypothetical question, I suppose there could be various answers to that. Richard, maybe you want would what to take a shot at that?

I think we have people in place to execute the kind of plan that we have talked about. We have equipment and reasonable anticipation for equipment and resources to do it. I think, as we have talked about it as a group, if you want to call it a constraint, we want to move quickly and realize value of it but we don't want to outpace our understanding of it and have waste. So I think right now, we are not really constrained by resources or people and we want to move down the path of understanding it the best way and not have waste along the way by doing operation that aren't the most optimal.

Okay. I know it is still fairly early on in the play, but can you just talk about any surprises that you have had, either positive or negative, with what you have seen so far?

There are some things in my comments and in the press release and in the past we have talked about, that we are seeing variability in the play. I wouldn't know if I would call that surprise. We have kind of said that all along. And the variability can be in the individual pilot areas even. So we are still working to try to understand what drives that, yet we're seeing some pretty good things happen also.

All right, I will get back in the queue. Thanks.

Amir Arif with Friedman, Billings, Ramsey.

Good morning guys. Congratulations on a great quarter. My question, just a follow-up question on variability here. Richard, can you tell us a bit more in terms of what variability you are seeing, whether it is just thickness or if it's the fracs that you're seeing in the formation? Can you just go into a little more detail if possible?

Sure Amir, sure. The thickness that we're seeing in the shale, I think we are getting fairly good at predicting that before we drill. There is variability in it and as we have understood it from the beginning and from the well controll. Everywhere we have drilled we are seeing gas from the shale and a good gas resource. I would say probably the main variability is how they are reacting to the stimulations and where the stimulations are going, the best way that we can understand them and try to visualize them, and then how the wells are flowing back and performing.

Great, second question. In terms of your horizontal development program going forward, can you just summarize what you have in the queue right now in terms of, you're stimulating one and then you have two more drilling. Do you have anything else lined up after that?

As we have talked about in the past, this idea of wanting to be flexible in the plan is just for this kind of thing. And Harold has talked about it a good bit also, that as we see good things happen with horizontal wells, obviously we will want to do more of those. We do, for just the facts right now, we do have one waiting on completion, we have another one drilling, and then as we look into the second quarter, we would -- probably the best guess there would be that we would have a higher ratio of horizontals to verticals than in the first quarter.

Thanks guys.

David Heikkinen with Hibernia Southcoast.

Good morning guys. Just, again, congratulations on a good quarter. The rates from the horizontal and the Fayetteville are pretty encouraging. Can you talk about the finding and development costs from the Griffin Mountain field and your PVI for that? It looks like if you're coming in at the low-end of reserves and high-end of costs, that you above $2.16 kind of average F&D cost. How does that qualify? And then what are your thoughts as far as, are you going to keep that development up or go to other areas, more likely?

This is Richard, David. I think we started at Griffin Mountain in this vast acreage block. We had to pick a place to start and we had some thesis (ph) on where to start. I think kind of a little bit ironically, it doesn't look like it is the best of the areas that we have started to develop. It is also where the higher costs have been on the vertical. So that, in conjunction with a slightly (indiscernible) makes it not as promising as the other areas. But when we're talking about the reserves or the production -- ultimate production there, we're looking at what we think these ultimately might produce. When you talk about finding costs and you're talking about proved reserves and we are not to the point there where we know what those are or what they would be at the end of the year. So the pressures are there that the performance is slightly lower and the costs are more, so the finding costs will be a little bit higher. But it really represents just one small area in the acreage.

Kind of thinking about each one of the areas, the Rainbow product, project, but Brookie project, what are your average net revenue interests in each one of the projects?

Let's see, we are probably around 87.5 NOI to the 100%, and for the most part we have right at or near 100% working interest.

Okay. In each one? So it's pretty contiguous across the acreage?

Right.

Okay, I guess I will get back into queue.

Ryan Zorn with Simmons & Company.

Good morning guys. Let me ask this first. The variability in your drilling days on the horizontals, what did you see in your Brookie well in terms of number of days to drill?

The Brookie well, I believe was 19 days. You have to kind of equalize these up for depth. The first well took 32 days to TD, the second well 11. If you kind of normalize those to depth, it's more likely a comparison of about 26 or 27 days to 11 days. And then the last one, 19, with a little bit more measured section there. I think the key though that we saw on number one and number two was in some of the design changes in the drilling part of it, where we kicked off how we built our angle and all of that, was more efficient.

So your plan for the upcoming horizontals would be towards the better end of that range?

You know, we have only done a few of them here, but we are learning pretty quickly on them. I think we have talked about looking forward, that would be in 1.5 to 2 million per well. That is a kind of completed basis, during the second quarter.

Okay. The recent land that you have taken, can you give it roughly the same terms that you had before? It sounds like your net revenue interests have been holding up. I wondered what the last segment of land acquired, what the terms were there?

Specifically, I don't think we're going to tell you what our specific terms are that we're leasing at right now as far as royalties and so on. So maybe we will just leave that at that.

Can you give us a hint on what percentage might be non-operating at this point?

Well, it's kind of a forward-looking thing to try to predict that. We have places that we're still adding leaseholds and --. Harold Korell:Is the question what percentage of wells that we might drill, would be non-operating?

What percentage of your land position right now might be non-operating?

I don't think it's possible to answer that question. It won't be operated until a well would be planned to be drilled there. And since we don't know when that would be it, it would be hard to answer that question.

Okay, all right. I will jump back. Thank you.

Ken Beer with Johnson Rice.

Good morning guys. I'm sticking with Fayetteville. A couple of other questions, and I may have missed this. How many rigs do you have running in the Fayetteville?

We have three, kind of been our average and current. And we have moved one in and out a few times, but kind of our nominal rate there is three rigs.

And your thought is, let's go ahead and stay with three. Let's call it through the end of this year. Is that a good thought or would you look to slowly but surely ramp that to 4, 5 or 10? I guess I'm trying to get a sense as to when and how the ramp might occur?

I think our best look at it now is still kind of a capital number that we have put out there, the up to 100 million. I think we can see our way to that, investing that amount at a prudent pace. And that would require us to start to ramp up our rig count in this next quarter, last in the quarter. And depending on the mix of wells -- I hate to keep beating on that -- but depending on the mix of horizontal and verticals, we could build up to five to ten rigs late in the year.

And the other factor in it, is depending upon getting acreage concluded and integration hearings and so on, that will allow us to drill that new pilot area.

Fair enough. Just one more, Harold or Richard. In terms of variability or tinkering with the frac technique, are you happy with that? Is that something where for the last five or six or seven wells, you have been happy with your technique and you're not tinkering so much with that going forward? Or is there still work to be done in that area?

I think -- Ken, this is Richard. I think we are not set on a procedure.

That is what I'm getting at.

There will be plenty more tinkering I think, and some of them will be very subtle things, but we're starting to see some reaction to fairly subtle changes and we just need a bigger dataset to make that conclusion. But I think you will see us working on that procedure in both verticals and horizontals throughout the year.

Okay. Fair enough. Thank you guys. I will step back as well.

Michael Bodino of Sterne, Agee.

Good morning gentlemen. Just a couple quick questions, I will make it real simple. First of all, given the limited amount of data we have out of the Fayetteville, could you venture to guess whether there has been any changes to the spacing on vertical and horizontal wells, and what you would anticipate going forward?

I think -- this is Richard. Just to kind of go back to where we started from there, our initial filings where we had to get field rules at Griffin Mountain, the data there concluded about 30 acre spacing or less for the verticals. From what we have seen, I think that would be kind of the top of the range. It could be lower than that. On the horizontals, it would logically be a multiple of that. But until we get to where we can start projecting some reserves off of those, it would be hard to say. Certainly the well bore is out there over a bigger area and they're stimulating all along that horizontal. There will be some geometry that defines that, that will go into that drainage calculation. But it is really to early to say on the horizontals.

Okay. The second question I have is on the Standridge well, the step out, and the Ranger Anticline. Was this a situation where the borum was tied because you were too close to the overthrust, or was it properly placed for the borum and it was just tight?

It's hard to say it was properly placed because it doesn't look too good, but the variability that we saw in that well relative to say offset wells, out on the Eastern end of the field is not very different than what we see throughout the structure. Even in our core producing area, we can have a poor well in the borum right next to a really good well. So we're not too flabbergasted by the fact that that one was tight in the borum, and thin. I think we will see variability as we continue to drill out there in the hopes that we will find some more good borum. But the shallow section looks very promising and we will be offsetting that to try to prove it up. I don't think there was a big structural component to what happened with the borum, Mike.

Okay, thank you. Great quarter. I will get back into queue.

Robert Christensen with Buckingham Research.

Good morning. Could you conceivably do dual laterals, or is not worth it because the veritcal portion is so small because dual laterals would allow for a lot fewer wells, and I could make the case of getting to a lot of this acreage pretty quick. That is question one. Question two, on the Vonn (ph) well where you had the mechanical difficulty completing it, could you give us a little more insight as to what you think went wrong there, and put it in laymen's terms? Thank you.

Question one, as to dual laterals, is it feasible? I think certainly it is feasible. It is done in other areas and the engineering technology is there to do it. We're just starting to scratch on that and try to think about it. It is certainly something that will be evaluated as part of the overall pursuit of this play. I think it is really a question of economics to me whether you do those, Bob. If you have some savings and the performance, cost savings and the performance outweighs doing two separate laterals, then we would look real hard at that. The other thing is, the help you get there on the surface, part of the cost savings is mostly one surface instead of two, and then also the impact to the surface if we end up doing lots and lots of wells, it's a good thing. It is really economics.

If you drill down and you go 2,000 feet on way and 2,000 feet another way, there is almost a square mile. And if you stepped out within that square mile to the East a couple thousand feet and drilled down, did the same thing, you would have that square mile covered in effect by two surface locations. And you have 1,000 square miles -- or 1,200 square miles you've got, then it's 2,400 locations. It would seem to be something, probably way down the road for you.

We will certainly look at the technology and see if it makes better sense and the PVI will drive it. The Von well, maybe to elaborate a little bit more there, we have about 1850 feet of lateral, all of it in the shale, and then looked at segmenting that lateral section into four intervals with the idea we wanted to try one of these nitrogen foam simulations on each interval. We pumped the first job, which isolated the most end of the horizontal section, and then after that we really had a lot of mechanical problems. And I think when I talk about wellbore isolation, I think basically after that we weren't able to get good isolation in the individual intervals that we want them to stimulate, and we saw some things happen that indicated we had -- we were seeing some pressure in places that should not have been, perhaps related to some poor cement bonding. And that is not definitive that that was the cause of it, but certainly we were containing the fractures in the individual intervals. And the result is we spent quite a bit of money on the completion, and really we just have the one interval which is acting like a vertical, and that is kind of what you would think it would do.

So it sounds almost totally mechanical.

Yes, absolutely.

Was the Stoball (ph) well done with nitrogen, where you did get a good cement job off? What kind of frac was done on that lateral lag, on the second one? You're staying with just nitrogen?

Yes, staying with that and tweaking some little things on what we are pumping, and quantity of sand and quantity of nitrogen and those kind of things. I think the difference there is the individual stages of (technical difficulty) went away pretty well, and individually, and accumulating to something a lot better.

Thanks Bob.

I will get into the queue.

Mike Bradley of Millenium.

Everyone seems to be getting excited about the drilling results, which is understandable, but my question is more operational. It seems to me, if I can get some clarity, I am looking at your press release and your guidance for 2005 compared to those of your most recent --.

Is there something -- could you get closer to the phone or something? We're having a hard time hearing you. Mike Bradley: I am just looking at some of your presentations from recent investor conferences, and I just want to get a little bit of clarity here. It looks like you have assumed the same production guidance here, but you're assuming now a $4.00 higher on oil price assumption and you're getting lower EBITDA cash flow and operating results. I was trying to get an idea of why that is? Is it an expense issue, or am I looking at that right?

This is Greg Kerley. We had given, I guess in the $6.00 guidance, we had $5.00 and $6.00 guidance and we put out $7.00 guidance also this quarter. In the $6.00 guidance, our earnings comparison was down somewhat due to really just an increase in primarily in our higher DD&A rates. So the cash flow effect was about -- the range is to 260 to 270. Our range, upper end of our range before was to $2.70 on our cash flow also. The lower end range maybe about 5 million more, just wider range, and that was driven by a combination of a couple of different things. One of which was their utility having a poor first quarter due to warmer weather, which affected us a couple million for the year there. And then there is just a combination of a little bit lower production numbers originally in the quarter, with when we're expecting prices and a little bit higher lease operating expenses. So I think there is about a 5 -- maybe just a range of $5 million effect in our net cash flow range. And the earnings was a little bit more than 5 million, probably about twice that, as far as the range goes, and driven by the combination of those same things that affect cash flow plus the DD&A.

The only reason I ask because, in your presentation you have $6.00 gas here and $40 oil, and in the last presentation you were assuming $6.00 gas and $36 oil, and the ranges were lower based on what you just gave in this presentation. I just want to get an understanding why you would have a higher price tick but lower assumptions?

Well we only changed oil by about $4.00 and we have got less than -- about 8% overproduction is oil. And part of the difference too is just the basis differentials that we've seen as we have talked about, both in the first quarter and second quarter.

Okay, thank you.

Stu Wagner with Petrie Parkman.

Good morning guys. A couple of quick questions. Correct me if I'm wrong but it seems in the past your EUR, you more or less gave an average, and I think it was a little over 400 million per location. Is the reason for the range that you've -- the range, the upper end of the range, but you don't have enough confidence to up the average yet? Is that fair? Am I interpreting that right?

I think we gave an average of about 430 gross. Griffin Mountain is more like about 300, so it could be pulling that down some. Our current -- more of the wells, Stu, are weighted in the Griffin Mountain area. I still think kind of -- and then the wells that look like they are higher EURs, we don't have a lot of production on those. So yes, there is some uncertainty there, but I think the averages still would be somewhere around 400 million cubic feet per well.

I got you. Second question, obviously the reason you look at the horizontal wells is to see if they're more economic and you can drill through wells, etc. But is there also an issue of -- maybe you haven't determined it yet, but is there maybe a vertical thickness -- or the thickness of the shale, is there a cut off point of say 40 feet or 30 feet or something, where the verticals don't work but you're hopeful that a horizontal might go into that section and actually turn it into an economic well because you will come in contact with more of the shale, even if it is a thinner bed. I don't know if you have determined a cut off point of thickness yet, but is that one of the hopes where the horizontals might add some value?

The primary job of the stimulation as we viewed it here and we've talked about this along, is that the name of the game here is going to be to get into contact with the most rock you can per dollar invested. We had a question earlier from, I think, Bob Christensen about derailing (ph) dual laterals which also gets to that point. We think that logic would tell us that we will get into contact with more of the rock if we drill a horizontal well and do multiple stage fracing along that, than we would if we drilled vertically through that same section and then attempt to do just a frac or simulation there.

What is guiding us is to get the most contact with the rock and that is why we are doing the horizontals. An offshoot of that could be, back over in the Fairway where the shale tends to be thinner, horizontal wells might make that more economic. But out here where we're drilling, where we are in 200 feet of so, at of shale, still the main job is to try to get most contact. We are encouraged by what we have seen to this point in the horizontal wells.

Good, thanks guys.

(OPERATOR INSTRUCTIONS). Joe Allman with RBC Capital Markets.

Just in terms of the Fairway section, I noticed that you co-mingled a well with the Weddington sands. Are you going to try some more of those or might you switch over to the horizontals up there in the Fairway section, as well?

This is Richard. We have -- one of the wells over there, I believe the comingled zone is a Hale (ph) sand, which is the typical producing interval in the Fairway. So the kind of connection with the Weddington that we have talked about before, I don't think that is what we have completed there. But in the Fairway, we hold a lot of acreage, followed by production. Those wells, we are kind of encouraged by what we are seeing there. We could do some recompletions there or deepenings. We can have secondary zones like that well indeed is. And then like Harold said, the ability to maybe go in there where it is 50, 60 feet thick and do some horizontal work may be a potential also. So a lot of good things that we can try there and we hold a big piece of it, as you know.

Away from the Fayetteville for a second. In East Texas, at this point how much acreage do you have outside of Overton in East Texas?

I believe the number is about 20,000 acres gross, and our net is way up there, probably 18 and 19,000 of that in the separate four or five project areas that we've talked about.

All right. Lastly in Ranger, if I heard you correctly, Richard, just the fact that you drilled this one well to the borum and it was tight. Did you see some of those same kinds of tight borum sands in the core area or to the West, so that tightness doesn't necessarily discourage you from further development in the borum out there in the East?

Definitely, I think that is a correct statement. I think as I said earlier, we might set up in the core area and offset a good well and find the borum section tight and not very good. But overall if you look at the performance of the field, we have some variability there but our success there is something like 50 out of 57 wells, I think. Yes, there is variability but our average is very good and the economics are excellent. Also in this trend, on the Southern part of the basin, where you have big rollover anticlines and trust faulted anticlines, other fields along trend, it is not uncommon to have these shallow sands present in a significant part of the accumulation of those fields. I think certainly we have good hopes for finding more borum out there and the shallow stuff is promising.

Great, thanks Richard.

David Heikkinen with Hibernia Southcoast.

I just had a few questions outside of the Fayetteville. First on the Permian, what is your net revenue interest and should we expect some oil production growth a little, in your guidance? What is the percent oil for third and fourth quarter?

David, I think we're talking about maybe for the year, we might do six or seven wells total, and they are not huge rate wells. Our net revenue interest is high. I can't tell you an exact number, but certainly I don't see that project alone driving our oil guidance for the year. We've got other areas affecting all of that, but it is a good solid little project that we're trying to pursue.

Harold, go back a couple years. You had a couple of exploratory plays before you really got into the Fayetteville. You are still pursuing some new ventures. Any outlook as far as when you can start talking about some of the new venture plays?

I think Richard might want to comment on one of our new venture plays that we planted a seedling in, that a pine beetle got into in the first quarter. I will let him address that. But aside from that, we do have some other new venture things that we're not ready to talk about. We also have some exploration wells that will probably come about later in the year and we will talk about those a little bit later.

The pine beetle got to us on a thing we call our road crossing project. We had put an acreage block together there with another operator. There is Ft. Union (ph) Coals there in the Green River Basin. We had a nick thick coal, really looked good. Measured good gas content. But we had a very high concentration of CO2 in it when we did the analysis. Looks like that will not work.

The other kind of things we have in the works are, we have talked about our block acreage we have with Encana, in that similar area there. We have a Madison prospect that we're trying to get spud this summer, that is on the order of 50 Bcf gross potential. We have a Jackfork, large Jackfork prospect in Arkansas that we control a big acreage block that we are trying to get spud maybe in June or July. And then our unconventional team is working on some other areas that I really don't want to talk about right now.

Okay. Thanks a lot guys.

Michael Bodino from Sterne, Agee.

My follow-up has been answered. Thank you.

(OPERATOR INSTRUCTIONS). Robert Christensen of Buckingham Research.

If I look at the Fayetteville and take away what is out to the West, I guess, in Franklin County and just drew a line around the wells, the 35 wells that you have, make a perimeter line around it --.

Bob, we're having trouble hearing you.

If I threw away Franklin County and I'm making sort of a preliminary map on this Fayetteville Shale here, and if I just did sort of a perimeter line around the wells that you have drilled I would come up with about 225 square miles having been tested again, exclusive of Franklin County. That would imply about 22% of your acreage, or 20% of your acreage courage has been tested. Is that a reasonable calculation to do right now?

I don't think it is, Bob, because there is going to be vast areas in between those pilots that undrilled. I think we looked at a number here recently that, the actual sections that we have drilled the well in -- whether it is one or more than one -- sections that we have tested relative to the total acreage block is less than 2%, I think something like 1.5%. I think we're starting to get some decent spatial sampling of the play because the pilots are of some significant distance away from each other, and so that is good. But then they'll just wrap them all, corral them and say that whole thing is -- how you described it, it might be kind of early to do that.

Second question. This shale is sedimentary and probably pretty extensive. How much acreage is remaining out there when you kind of look into your maps? I know everything has a different cost associated with it as the play gets levels of interest from others. But I mean, how much acreage could still be leased?

That's a good question that some people would certainly like to know the answer to, and we may not have found the edges of it. What we're doing on our leasing is we're continuing to fill in leases where we have been working all along and we are stretching into some areas additionally. And we are also seeing competition along the edges of where we have been leasing up to this point in time. We're not going to address the total perspective acreage here. We may have our idea of it, but we may also may not be (technical difficulty).

Thank you very much.

Mr. Korell, it appears we have no further questions at this time. I will turn the conference back over to you.

Thank you operator. We're off to a great start this year with the drilling we have done at Overton and Ranger. We are also making progress, as we have discussed here, in understanding and pushing forward with the Fayetteville Shale play. And we think we're looking at a very bright year for the Company, overall. And I want to thank you, each of you, for the interest in being on the call today. That concludes our conference.

That concludes today's conference. We thank you all for joining us.