西南能源 (SWN) 2004 Q4 法說會逐字稿

Good day everyone. And welcome to the Southwestern Energy Company fourth quarter 2004 and year-end earnings teleconference. This call is being recorded. And 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 Vice President of Exploration Production Company and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our 2004 financial results, you can call Annie at 281-618-4784. And she'll fax a copy to you. Also I would like to point out many of the comments during this teleconference may be regarded at forward-looking statements and involve risk factors and uncertainties that are detailed on 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 assumption, they are not guarantees of future performance and actual results or developments may differ materially.

Well, 2004 marked another record year for our company as we set new highs in our financial results, and impressive marks in all the important operational statistics. We set new records again for annual production volumes, reserve replacement, and year-end reserve levels, thanks to our team of creative people and our discipline of adding value for each dollar that we invest. Our financial results were outstanding as well as we delivered new records for earnings and cash flow, due to our increased production and higher commodity prices.

Looking forward to 2005, we plan to invest up to $339 million in our E&P program, an increase of 20% over our E&P capital in 2004. In east Texas we plan to continue our level of drilling activity at Overton by drilling 80 wells are sold there. In our conventional Arkoma basin drilling program we'll increase the number of wells drilled to around 86, up from 71 wells drilled during 2004. Specifically we'll be accelerating our activity at the ranger incline, where we plan to double the number of wells we drilled last year. In our Fayetteville shale plain, we increased our leasehold position to approximately $557,000 net acres in the undeveloped play area by year-end 2004. In addition, we controlled approximately 125,000 net developed acres in the traditional fairway area of the basin, held by conventional production.

As of February 28, we have drilled a total of 31 wells, and participated in one outside operated well. These were all vertical wells located in 6 separate pilot areas in Franklin, Conway, Van Buren and Faulkner counties in Arkansas. Of the 32 wells, 13 wells are in production, 7 are in the process of completion or waiting on pipeline hook-up, 7 are scheduled to be completed and 3 were shut in, due to marginal performance.

Based on the average vertical well results today and using current well costs and our current forecast for the future performance of these wells, we believe that a vertical well drilling program is economically feasible in the pilot areas drilled to date. While the results we're reporting are of a short-term nature and not based on extended production histories, we continue to be excited about the potential of a play. We're learning more with each well we drill and have made improvements in lowering our drilling and completion costs. Additionally we're drilling our first horizontal well into play, it will be assessing its potential to further improve the economic results.

In 2005, we expect allocate up to $100 million in our capital to our Fayetteville shale plain. The company's drilling program, with respect to the shale play is very flexible and it will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic factor stimulation, and the gas commodity price environment. In summary we're proud of our results in 2004, and it looks like 2005 is shaping up to be another record year. I'll now turn the teleconference over to Richard Lane, who will tell you more about our E&P results in 2004 and our plan for 2005 and then to Greg Kerley to discuss our financial results. And then answer your questions.

Thank you and good morning. As Harold said, we set new records for our annual production. Reserve replacement and year-end reserves in 2004. Gas and oil production totaled $51.1 bcfe, 31% up from 32 bcfe in 2003. The increase in 2004 production resulted primarily from the continued development of our Overton field in east Texas, our ranger field in the Arkoma basin and increased production from our river ridge discovery in New Mexico. Production for the fourth quarter of 2004 was 15.1 bcfe, up 35% from the 11.2 bcfe we produced in the fourth quarter of 2003. Of the 15.1 bcfe of the fourth quarter production, 6.3 was from east Texas, 5.4 from the Arkoma basin 2.2 from the Permian basin and 1.2 from the Gulf Coast region.

The 15.1 bcfe produced during the fourth quarter included the effects of curtailment of production at our Overton field in east Texas, which were caused by the failure of transmission line into which we delivered a large portion of our gas production. The current lack of full sales capacity at the Overton field due to continued disruptions during the first quarter of 2005 will likely cause our production to be approximately 1 bcfe less than our previously-estimated first quarter production guidance, of 14.5, to 15 bcfe. Current estimates for the first quarter production are between 13.5 and 14.0 bcfe. While our previously announced full year guidance of 61, to 63 bcfe, remains the same.

We ended 2004 with 645.5 bcfe of total approved oil and gas reserves, which is up 28% from 503 bcfe at year-end 2003. In 2004, we added 204.1 bcfe from extensions and discoveries and 5.8 bcfe from the acquisitions of additional interest in our Permian basin river ridge field. Total downward revisions from the company were 12.7 bcfe. Of the 645.5 bcfe of year-end 2004 reserves, 299 bcfe were in east Texas, 239.5 bcfe in the Arkoma basin, 7.5 bcfe in the Fayetteville shale, 60.8 bcfe in the Permian basin, and 38.6 bcfe in the Gulf Coast region. Including the effect of revisions we replaced 365% of our 2004 production. At a finding development costs of $1.43 per mcfe. Approved developments reserves accounted for 83% of our total. And our reserve life index was 11.9 years.

In 2004, we invested $282 million in our exploration and production program and participated in drilling 204 wells, which compares to 139 wells in 2003.Of the 2004 wells, 166 were successful, 14 were dry. And 24 were still in progress at year-end. Giving us an overall success rate of 92%. Approximately 81% of the $282 million invested in 2004 was in drilling. In 2004, we invested approximately $28 million in our Fayetteville shale play, including $11.6 million for drilling 21 wells, bringing our total investment in the play to $38.9 million.

Total approved gas reserves booked in the play at year-end 2004, were 7.5 bcfe, from a total of 20 wells. 10 of which were classified as approved, undeveloped locations for an average gross estimate ultimate recovery per well of 430 million cubic feet. As Harold mentioned as of the end of February, Southwestern had drilled a total of 31 wells and participated in one outside operated well in the Fayetteville shale play. These vertical wells are in 6 separate pilot areas located in Franklin, Conway, Van Buren and Faulkner counties in Arkansas.

Of the 32 wells 13 are in production, 9 are in the process of completion or waiting on pipeline hook-up. 7 are scheduled to be completed and 3 were shut in due to marginal performance. Excluding 3 shut inn wells the first 30 day production average from the producing wells was 375 Mcf per day. Recent costs to drill and complete wells into play utilizing nitrogen foam fracture stimulation treatments ranged from 400,000 to 550,000 per well.

Based on the average vertical well results to date, current well costs and our current forecast for the future performance of these wells, we believe that a vertical well drilling program is economically feasible in the pilot areas drilled to date. We anticipate drilling approximately 16 total wells during the first quarter of 2005, including 2 horizontal wells, the first of which is currently drilling. This first horizontal well is designed to drill a 2,000-foot lateral section in the Fayetteville shale and utilize multistage nitrogen foam fracture stimulation technology in its completion.

Moving to the conventional side of our Arkoma basin, in 2004, we invested approximately $53 million, in our conventional program. Drilling 70 wells, of which 55 were successful, and 6 were in progress at year-end. We added 47.9 bcfe approved reserves, including revisions and our 2004 production for the Arkoma basin is 6% greater than the 8.9 bcf we produced in 2003. In 2004, we further increased our drilling activity at our ranger incline project in Yell and Logan counties, Arkansas. We successfully completed 20 out of 22 wells at ranger in 2004, and adding 29.8 bcf in new reserves and a finding and developments costs of $0.82 per mcfe, which includes revisions.

Since early 2004 we have extended the productive area of ranger incline area to both the east and west of our core producing area. The Albright number one seven, which we operate with an 83% working interest, is located in the western portion of the ranger incline is currently producing 4.1 million cubic feet per day. Since being put on production, in May of 2004, this well is already produced a total of 1.3 bcfe. In the first quarter of this year, we drilled the number one ten well located to the east of our core producing area. The Borum sands, which are the main producing Verizon at ranger, were thin and tight in this well.

However, the standards well did penetrate approximately 150 feet of gas pay, in the Bashum (ph) and Turner sands at about 3500 feet, which is shallower. This well is currently weighing on pipeline connection. We plan to drill additional offsetting wells in 2005 to determine the extent of this Bashum pay zone, as well as to continue testing the deeper Borum sands. Since drilling our first successful well at ranger in 1997, we have successfully drilled 43 out of 50 wells, adding approximately 63 net bcf reserves and finding cost of $0.72 per Mcf.

At December 31, 2004,gross production from the field was 23.4 million cubic feet per day. Compared to 7.6 million cubic feet per day at year-end 2003. Our average working interest in the 43 wells is 81%, and our average net revenue interest is 66%. As of year-end, we held approximately 7,700 gross developed acres and 43,500 gross undeveloped acres in that play. In 2005, we plan to invest 59.3 million in our conventional Arkoma program to drill approximately 86 wells, 43 of which are planned at ranger, and to perform approximately 30 work over projects.

In the east Texas, in 2004, we invested approximately $156.7 million. Drilling 92 wells, of which 84 were successful. And 8 were in progress at year-end. Of this, 148 million was invested in our Overton field where we drilled and completed 83 wells. We added 125 bcfe approved reserves, including revisions in east Texas. Our 2004 production of 22.2 bcfe from east Texas was 63% greater than the 13.6 we produced in 2003. The development drilling program at our Overton field, which is in Smith County, Texas, continues to be very successful.

We have experienced a 100% success rate at Overton since we began our development program in 2001.The average estimated ultimate recovery of gas and oil reserves from new wells completed in 2004, was approximately 2.0 gross bcfe per well. Compared to 2.2 in 2003. Daily gross production capacity at the Overton field has increased from approximately 2 million cubic feet in March of 2001, to approximately 90 million cubic feet per day at year-end 2004. Resulting in net production of 21.8 bcf during 2004, compared to 13.6 in 2003 and 5.9 in 2002.

As mentioned earlier, our production at Overton is currently being curtailed, due to the failure of our transmission line into which a large part of Overton field's gas sales are made. A leak in this pipeline was discovered on November 24, of 2004.Since this time, the operator of line has been working on repairs, and performing confirmation inspections, and seeking approval of the department of transportation to return it to its normal operating pressure. We currently estimate that this will occur in late March.

In addition to our Overton field activity, we recently completed the test well on our black bayou prospect located in Nacogdoches County. The reefly (ph) number one, which we operate with a 40% working interest is completed in the Travis peak and this well potentialed at 4.4 million cubic feet per day in early February of 2005. We anticipate drilling up to 4 more wells in that area this year.

In 2005, Southwestern plants invested approximately $147.6 million in east Texas, to drill approximately 96 wells. Of which approximately 80 wells are planned at Overton. In the Permian in 2004, we invested $27 million, drilling 14 wells, of which 8 were successful and 3 were in progress at year-end. We added approximately 13 bcfe approved reserves, including revisions. Our 2004 production from the Permian basin was 69% greater than the 4.2 we produced in 2003, mainly due to increased production from our River Ridge discovery.

The River Ridge discovery, in which Southwestern holds a 50% working interest, is located in Lea County, New Mexico. And produces from the Devonian formation at about 14,600 feet. After the River Ridge discovery well, which was in the end of 2003, we drilled 4 additional wells in the field, all of which are producers. Cumulative net production from the field through the end of 2004 was 3.2 bcfe. Total remaining net proved reserves at year-end was approximately 11 bcfe; bring our overall finding and development cost in the field to $1.64, per mcfe, including reserve revisions. Current gross daily production from the River Ridge field is about 23 million cubic feet equivalent per day. In 2005, we plan to invest approximately $4.8 million in our Permian basin program to drill approximately 12 exploration and exploitation wells.

Moving to the gulf coast, in 2004, we invested $15.7 million, drilling 7 wells of which 4 were successful and one was in progress at year-end. We added 3.7 bcfe approved reserves, including revisions, replacing 80% of the 4.6 we produced in 2004. Our 2004 production from the gulf coast, was essentially flat, to the 4.5 bcf we produced in 2003.

In December of 2004, we put our Rose Bank discovery and Bush Parishon (ph) production at a rate of 3.5 million cubic feet per day. And it is currently producing at about 4 million cubic feet per day. We hold a 50% working interest in this discovery, which is 2 miles west of our earlier Coalburn discovery. The Coalburn well is currently producing 3.2 million cubic feet per day after being put on production in December of 2003.

As we have discussed previously, our recent drilling activities in the gulf coast are not meeting our economic criteria. Because of this, we continue to reduce our planned investments there, with only 4.8 million planned for 2005. We plan to drill up to 8 wells in the area; the majority of the wells will be developmental in nature.

On the exploration of new ventures friend, along with our Fayetteville Shale play, and our ongoing east Texas and Arkoma basin drilling programs, we continue to develop new prospects for future development. During 2004, we acquired approximately 47,000 net undeveloped acres outside of our 4 areas, associated with other conventional and unconventional natural gas and oil plays we're pursuing. In 2005, we plan to invest approximately $18 million in exploration projects and $4.2 million in new venture projects, including drilling up to 14 wells in the continental US.

In summary, our program is performing well. Delivering significant growth in production and reserves, while achieving our investment return target of 1.3 PVI or greater. We're continuing to grow and develop our inventory with potentially significant value-adding opportunities. I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Richard and good morning. As Harold indicated, 2004 was an exceptional year for Southwestern. We end of the year with record fourth quarter earnings of $32.9 million, or $0.88 a share compared to $14.9 million, or $0.41 a share for the same period in 2003. Our net cash provided by operating activities before changes in operating assets and liabilities was $72.4 million during the fourth quarter of 2004, up 94% from $37.4 million in the fourth quarter of 2003. A 35% increase in our quarterly production in higher realized commodity prices led to improvements results.

For the full year of 2004, we reported record net income of $103.6 million, or $2.80 a share, up 112%, from $48.9 million or $43 per share in 2003. Net cash provided by operating activities before changes in our operating assets and liabilities also set a new record at $237.7 million, in 2004, up 80% from $132.3 million in 2003.

Operating income for our E&P segment was $164.6 million in 2004, compared to 84.7 million for the same period in 2003. Including the effect of our hedges we realized an average gas price of $5.21 per Mcf in 2004, up $4.20 a year ago. We saw our locational price differentials for our natural gas production widen substantially in our core operating areas during the fourth quarter of 2004, lowering our gas revenues by approximately 5.9 million and negatively affecting our earnings for the fourth quarter by approximately $0.10 per share. Disregarding the impact of hedges, the company's average price received for its gas production during the fourth quarter of 2004, was approximately $0.62 per Mcf lower than average Nimax block prices compared to an historical average of $0.20 per Mcf.

We had about 45% of our basis differentials protected in the fourth quarter of 2004, and have approximately 75, to 80% of our basis differentials protected in the first quarter of 2005. We currently expect our average realized market differentials to be approximately $0.30 to $0.50 per Mcf lower than average Nimax spot market prices for the full year 2005. And we're currently estimating that our market differentials for the first quarter will range between $0.50 and $0.60 in Mcf.

Our average realized oil price in 2004 was$31.47 cents per barrel compared to an average price of $26.72 per barrel in 2003. Disregarding the impact of hedges we would expect the average price received for oil production to be approximately $1.25 a barrel lower than average spot market prices. Going forward approximately 70% to 80% of our targeted gas production, and 60% to 70% of our targeted oil production is hedged in 2005. Our hedge position for our 2005 production is unchanged, from the detail included in our third quarter Form 10-Q.

Our E&P segment continues to benefit from some of the lowest operating costs in the industry. Lease operating expenses per unit of production were $0.38 per Mcf equivalent in 2004 down from $0.39 in 2003. As the effect of the increased in our production volumes more than offset rising oil and service costs.

Taxes other than income taxes per Mcf equivalent were $0.28 in 2004, compared to $0.22 in 2003. The increase in 2004 was due to increased severance and Ad Valorem taxes that primarily resulted from higher commodity prices.

Our general administrative expenses per mcfe were $0.36 in 2004, down from $0.41, an Mcf equivalent in 2003. The unit decrease was primarily due to the effect of the increase in our production volumes, partially offset by increases in our general administrative expenses. Our full cost pool amortization rate averaged $1.20 per Mcf in 2004, compared to $1.17 in 2003.

Operating income for the utility was 8.5 million in 2004, up 26% from 6.8 million last year. The increase resulted primarily from the effects of a 4.1 million, annual rate increase implemented in October of 2003. Partially offset by increased operating costs and expenses, and reduced usage per customer due to customer conservation, brought about by high gas prices and warmer than normal weather.

Weather during 2004 in utility service territory was 10% warmer than normal, and 9% warmer than in 2003. Despite the improvement in the utilities operating income, our analysis indicates that current revenues in our utility segment are not sufficient to cover the costs providing utility service and earn the rate of return authorized by the Arkansas Public Service Commission.

On December 29, 2004, we filed a request with the Arkansas Public Service Commission, for an adjustment in the utilities rates, totaling $9.7 million or 5.2% annually. The Public Service Commission has 10 months to review the filing and reach a decision. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

Operating income from our natural gas marketing activities was 3.2 million in2004, up from 2.6 million in 2003. We also recorded a pre-tax loss related to our investment in the Ozark gas transmission system of $400,000 in 2004, compared to a pretax income of 1.1 million in 2003. The pretax loss in 2004 was due to a negative adjustment from the operator of the pipeline, for prior period allocations of income and expenses.

In 2004, and 2003, our other revenues including gains of 5.8 million, and 3 million, respectively, related to sales of undeveloped real estate and certain property and equipment. Other revenues also included pre-tax gains of 4.5 million in 2004, and 3.1 million in 2003, related to the sale of gas and storage inventory. Our capital expenditures for 2004 totaled $295 million, including $282 million invested in our E&P operations, 7.3 million, for gas distribution system improvements, and 5.7 million for general corporate purposes.

Of the $282 million invested in our exploration production operations, approximately 20.1 million was invested in explore Torre drilling, 208.7 million in development drilling and work overs, 21.1 million for lease hold acquisition and seismic expenditures, 14.2 million for producing property acquisitions and 17.9 million in capitalized interest and expenses and other technology-related expenditures.

Our financial position in liquidity both improved in 2004. Our strong earnings helped us to decrease our total debt to capitalization ratio to 42% at December 31, 2004, compared to 45% at the prior year end. And in January of this year, we amended our 300 million unsecured revolving credit facility that was due to expire in January of 2007. We increased the borrowing capacity under the facility to $500 million and extended the exploration to January of 2010. The interest rate on the new facility is currently 125 basis points over LIBOR. And as of February 28, we had approximately 420 million of available capacity under this revolving credit facility.

Our capital investments for 2005 are planned to be up to $352.7 million consisting of up to $339 million for exploration and production, 10.4 million for gas distribution system improvements and 3.3 million for general purposes. Our capital program is expected to be funded from cash flow from operations and our revolving credit facility. Despite planned borrowing under our credit facility we expect our debt to capitalization ratio to remain at or below its current level during 2005.As Richard indicated, we're targeting 2005 oil and gas production of 61, to 63 Bcf equivalent. Assuming Nymex commodity prices of $6 per Mcf per gas and $36 per barrel of oil in 2005, we're targeting net income between a 112 and 114 million and net cash provided by operating activities, before changes in operating assets and liabilities of 265 to 270 million in 2005.

Yesterday we announced that our board of directors has approved a 2-for-one stock split. Subject to shareholder approval of an increase in our authorized share of common stock at our annual shareholders meeting on May 11, 2005. We'll be proposing an increase from 75 million shares to 250 million shares and we currently have approximately 36.5 million shares of common stock outstanding. The stock split reflects the board's confidence that our strategy is continuing to deliver value for our shareholders. That concludes my comments. I'll now turn it back to the operator who will explain the procedure for asking questions.

Thanks you very much sir.

[Operator Instructions].

And our first question today comes from Ken Beer from Johnson Rice.

Good morning, gentlemen. A question more for Harold and I guess more for Harold and Richard, in terms of the Fayetteville. Of the 31 wells, have any been actually drilled or any of the pilot areas on the, within the fairway, within the original held by production fairway?

Yeah, they're basically of the 5 pilot areas, one of those pilot areas we talk about being over in the fairway area.

Okay.

And we have just -- we've drilled 2 wells there that are on production. In fact I think those 2 wells have been on production longer than any of the other wells.

Okay. And that leads to my second question. And that is, if you look at a, what you're modeling as a typical well, which obviously is too early to get a great sense of confidence. But now you've got 31 data points to at least start to play with. As you model that out, what is the production profile look like? What kind of decline curve do you see in year one, 2, 3, 4? And then where does it start to flatten out? Have you modeled that when you come up with your roughly, you know, 0.4, 0.5 b's per well?

Yes, we have. We have, we have basically we a hyperbolic decline and I'll let Richard describe that.

Yeah, well the data set can you know, the 31 we're talking about are drilled.

Right.

So when we're talking about being able to model production, of course we're talking about a smaller --

Less than half of that. Absolutely.

Yeah, less than half of that. And then when you look at those you know, they have varying amounts of time on production. So you know, the data set is still small and if you look at the decline, and again, with not a lot of production life, it's a little harder to do. But you know, the first year, decline, the best way we can model them right now would be about 70% decline.

Okay.

And then it certainly -- like Harold said, it's hyperbolic. So you really have to understand the full nature of the early time life of that curve. But then you know our best guess is that they get flatter, out in the future years. So if you kind of -- everybody likes to try to compare it to the Barnett, if you compare to the Barnett you know, our best guess right now is that it's a little more decline in the first year. And then maybe flatter -- in the second year.

Okay.

I think just to add to that, it would be unfair to say that you would start from an IP and then do 73% in the first year and that would be there. That the actual declines that we're seeing are very steep. Very steep in the early part of the production data that we have. We have, we have I don't know the full histogram on we have 10 wells that we reported the 375. We have some wells that have been online longer than that. Our longest well has been on probably 180 -- how many days?

Close to 200.

Close to 200 days now. But we see pretty steep real steep declines in the first month or 2 and then it's, it's beginning to flatten. And the hyperbolic, I guess probably to simplify all this. We need to spend some sometime to be able to describe to those people that can do the math on hyperbolic, what the factors are in those and we need to probably do that over some period of time here.

What about the well that was coming off, that had an IP of I think just north of a million a day? What's the, what's that decline curve look like? Where is that doing?

That well is not on production at this point in time. It's in; it's in one of the newer pilot areas.

That's right I remember that.

And we've been a couple things there. We've been continuing to solidify our position there. But we haven't got it on production. We'll be hooking up the equipment on that and probably be coming on sometime in April.

Okay. And then last question then I'll hop off. Just in terms of your program, is another step-up from last year? You've got a lot going on. You've got a lot of good areas to operate in. What's the your view on what has happened to either availability and/or cost and quality of rigs and crews? Or do you feel like you've got enough of a focus area where you maybe avoided some of the pitfalls of the service companies being stretched pretty thin?

Well I guess just the big picture of it. In our core areas, the Arkoma basin conventional activities, the East Texas, we're pretty well set there. We've had working relationships with various of the vendors that are in place and will support those ongoing programs. To this point in time we've not encountered difficulties in our Fayetteville Shale, which would be one of the areas that would be growing in activity levels and we're still finding equipment there to serve the pace of activity that we've been wanting to carry on there.

That's great and thank you guys appreciate it.

Welcome.

And our next question comes from Friedman Billings Ramsey, Amir Arif. Please go ahead.

Good morning guys, a couple questions for you. In terms of the horizontal well that you're drilling, can you give a sense of timing in terms of when you would have it drilled and when those results would be made available?

Amir, this is Richard. You know we're currently drilling it as we stated, I would think we would be at TD sometime in the next couple weeks. A little harder to say because it is the first one we're doing. But -- and then probably another 30 days after that, looking at starting to test it.

I guess, Richard, just a little comment on that. It would be fine to say that we, we've drilled the turn. And we're basically kind of in the horizontal part right now. And we, so far it's gone pretty well the drilling to this point in time.

Okay. And then, would the horizontal well and the additional 10 wells you've drilled relative to your last release, can you give us a little more color on the geology you're seeing? Are you seeing a lot of variability in terms of thicknesses and physiology?

Well, I think we're still seeing some geologic variability. The overall thickness of the Shale, that we're seeing, is more predictable. I think it's for the most parts, the new wells are coming in with about the thickness that, that we pronged for them. So that's a little bit more predictable. But we are seeing some geologic variability with some faulting and in the performance of the wells, which is kind of built into that those are average data we have there. And we're still trying to learn, you know what when we have the log on one of these wells, what does it really mean and what can we discern from those logs and start to understand. And we're doing that by calibrating where we've taken whole cores and sidewalk cores, and trying to cross-plot that with the log data. So that when we have a log, we can better understand what it means.

Okay. And then, the outside operated well that you participated in the shale play; can you give us any more information on that?

Well the operator is Yale, which is small independent in the basin. We have about 40%, 45% working interest. They're operating and they proposed the well to us and we participated. It kind of provides a little bit of a kind of a new pilot for us because it is not right in with our current pilot areas. So and that well is waiting on completion, I believe.

Okay and just moving away from the shale play here. The transmission line failure you mentioned it would be fixed here back up and running by the end of March. But is there any risk that this would affect 2Q volumes?

Well, I mean it's -- you know it's in the hands of the pipeline operator. So I guess you would say there's always there is some risk there. You know the repairs are actually finished. Just to kind of clarify that a little. The repairs are finished and that line is subject to regulation by the DOT. And really, the hold-upright now is getting clearance on the DOT to bring it up to its former operating pressure. But we also doing some other things with other gatherers in the area right now. We have some other projects going on that would increase capacity for Overton fields. So we should be Okay. But it's not totally in our hands, Amir, and there's some risk there.

I understand. One final question, just on the average differential that's widening, can you point us to which area you're really seeing that pressure, in terms of the differentials? The basis differential?

Amir this is Greg. We really saw the basis widening effect, all of our operating areas and the Arkoma basin; in fact it was between $0.50 and $0.75 wider than historical averages for a lot of those periods. December was the worst month. And basis widening in the Arkoma to a little over $0.80, East Texas, about $0.85 and our differential in the Permian was about $1.45. So all of those were up, you know, in the smallest increment from November was $0.30 and the largest was about $0.75 higher than what just the differential had been as recently as November.

Okay. And Greg, while I got you on the phone here, just to clarify, did you say the average differential was going to be $0.30 to $0.50 in Q1?

We expect for calendar 2005, it to be $0.30 to $0.50 lower than the average Nymex stock market price. And our first quarter estimate is that it will range between $0.50 and $0.60 in Mcf.

I know are you actively hedging this? Or is this just your expectation of where you think it's going?

Well, we have actively hedged our first quarter of this year to where we have 75% to80% of our basis protected and we are actively hedging in the out months, also.

Okay. Thanks a lot, guys.

And we will now move on to Michael Bodino, from Stern Agee and Leach for our next question.

Good morning, guys. I have a handful of questions myself. First of all, in the non-operated well in the Fayetteville shale, did the operator do anything different on the drilling or completion of the well?

This is Richard, Mike. It's a vertical well. So and nothing really greatly different in the drilling part that I know of. And the completion, we haven't started on that yet.

Okay. Would 16 wells being projected in the first quarter of 2005; can you still get to the 160, to 170-well target in the Fayetteville shale in 2005?

I think what we said earlier is that we would invest the $100 million approximately, up to $100 million and drill up to 160 wells. And I think, I think we'll just have to see how that goes. You know, we're trying some horizontal wells. We've never really spelled out how many would be horizontal and how many would be vertical. We would like to keep our options open there and see what kind of results we're getting from the horizontal wells. And you know, the effect of all of that, if we could create better returns on those, then certainly we would want to move towards that. So that would affect the overall number of wells.

Richard, as you get into the optimal drilling program and we quit taking this full suite of logs and you start moving forward with the development program here, how many wells per quarter per rate can you drill?

Wells per quarter per rig?

Yes, sir.

It would depend on the, on the area that we're drilling. Because of the depth differences. And it would depend on the vertical versus horizontal. I think if you looked at the verticals, you know, we can on the shallow area, we can probably do a well every 10 days to 2 weeks. It would be kind of the quickest.

Okay. And in the deeper area?

I would have to look at that for a full quarter, Mike. I don't have that in front of me.

Okay. On the horizontal well, do you have an estimated A.F.E. for that well?

Yeah, we think it's probably the first well, we have engineered kind of the conservative manner to make sure that we, we get a lateral section of the shale drilled. And we're about $1.6 million, I believe for that well is our estimate.

Okay. And my last question, one of the new venture areas, in Nacogdoches County, the Travis peak well, is there any other opportunities, is there opportunities in the cotton valley or cotton valley lime as you move over to Nacogdoches County?

Primarily we're interested in the Travis peak there. But it wouldn't be, it wouldn't be out of the ordinary for there to be some secondary cotton valley.

Okay, thanks guys.

I just wanted to summarize this number of wells. One could anticipate here. In the Fayetteville shale. The words that I've used to describe our activity here would be flexible. And the words we've used to describe it in each of our press releases has been up to 160, to 170 wells. And I think Richard covered that. But I want you to understand that you know, clearly, if horizontal wells, give us a better P.V.I. than vertical wells, we could wind up drilling significantly less wells here than 160, to 170.

And you know, we're going to react to what the data is showing us and to how the wells -- which kind of wells are performing which way. And what we find as we drill in new areas. So our program, you know, although we've said we could drill up to 160, to 170,we've also, the up to is an important part of that statement. And so most people kind of pass by that. But there can be a lot of flexibility in the number of wells we drill here this year. And as well, the up to $100 million implies some flexibility in the amount of capital that we could put in here.

I think to give you a little more, in our shallowest areas, Mike, you know, we're drilling some of those wells in 3 to 4 days. And then in the deeper areas, depending if we have problems or not, those are more like you know, 7 or 8-day wells. And that's coming down as we go.

Okay. Thank you.

And we'll now move on to Shawn Reynolds, with Van Eck Global. Please go ahead.

Good morning. I wonder if you could elaborate on why your gas realizations or gas differentials are blowing out? I know it's not unique to you. I wonder if you could add color to that.

Our basis widened primarily in November, December due to the market dynamics that existed. It created a wider spread between the cash prices and all of our operating areas. And the closing prices on nimex. In both of those months close to $8 in Mcf. So the difference between the cash prices and the market prices jumped about $0.50, to $0.75 at Mcf from historical averages. And it's not something that we're the only company that experienced it. It's all of our core operating areas have those issues. And I think most of the continental United States did this winter. And they've historically, basis differentials in 2003, were quite a bit lower than what we had experienced, beginning towards the first part of 2004. And they stayed wider than historical, all of 2004. And they are so far, now, also.

You don't see any reason for that reverse back to historical averages?

It's, its too hard for us to say. We typically, you know, see them moving back down a little bit in the summer months. Typically the widest in the winter months so. We're hopeful that they will return. But it really is a function also, as gas prices, when the nimex price spikes, the basis widens. That's just a typical event.

Right.

Really talking about 2 moving, 2 parts that are moving. One, what's happening in the nimex, in the marketplace and the other is what's happening in the physical markets.

Right. Thanks. Question I had was, you made the comment that a vertical well drilling program, is economically feasible. Do you have an idea of how any, well locations that would entail at this point? How many?

Well we've drilled in 5 pilot areas. And 6 pilot areas now with the outside operated well. And we can clearly drill more locations there. We could drill more vertical wells there. We haven't seen, I guess I would say we haven't seen the limit. I don't know the limit, the upper limit, by any means within those areas. We will just, in those current pilot areas, we'll continue drilling. And then those pilot areas that we've drilled in are represented very small percentage of the total acreage that we have. And throughout this year, we'll be drilling an additional pilot areas.

We're still leasing acreage right now. And we've been reluctant to step out and spawn another well somewhere. Because each time that we do, we get people coming in to try to pick up bits and pieces of acreage. So we're still consolidating our position. And across the areas we haven't drilled in. And then at the end of the day, the answer to your question comes down to drainage areas. And you know, we're a long ways from knowing all the answers on that. Obviously there could be a lot of wells.

Just, just sticking to the pilot areas only, I mean do you have an idea of how many locations that would be? If you just kind of drilled --

I really don't have. And here's the reason why. If you just think about this from day one, we drilled one well, let's say in a pilot area. And then we drilled another well a mile away. And then we drilled another well a mile away. So what happens is, around each one of those wells, depending on how they're spaced, you just get multiples, you start doing the math and get some big multiples. There's nothing when we say a pilot area, there's nothing that limits that. If you understand what I mean. There's nothing that limits the extent of it, because we've drilled there. But we can just continue to drill outward from there, until we either don't find the shale or we find some limiting factor.

And here's the interesting thing. Each one of the places we've drilled, we've encountered gas. And we're producing gas. So it's not like there's, there's shale but there's no gas in it. Each one of the places we drill, there's a thickness of shale. That's mappable and it has gas in it. It produces gas. So what our job, of course is get on with development and in a reasonable fashion. And we're trying to be prudent with our capital figure out the way to get the highest return in each one of these areas.

Great. Thanks a lot.

And we will now go to Buckingham Research and Bob Christensen for our next question. Please go ahead, sir.

The question is, you say you're going to react to the data. 2 ways to read that. You know, based on your earlier comments. One is we're slowing down. You know, 16 wells from 25 in the first quarter. You know the availability of the data. You know, doesn't let you proceed as quick. On the other hand, you know, you got this horizontal well going down, and maybe you're so encouraged by that, you going to get by with fewer wells. I mean, how would you guide, glass half-full? Glass half-empty?

I'm going to let you play the glass game; Bob but I'll answer the question to the best of my ability. The horizontal, we have no results on, except that we're drilling on it and we've made the turn and we're -- so mechanically, it's going Okay. What we know from the Barnett shale, in some areas of the Barnett, definitely, you get a lot better economic result from a horizontal well. Then you do a vertical well. And that's become the well of choice over there.

So you know, we could, we could just, we could throw Rigs out here and drill vertical wells right now in these pilot areas But if in fact we get better returns by drilling horizontals, then that's going to be what we'll want to do. And so, you know, when we start, when we build our plan and announced our activity level in our last round of press release before this one, you know, we knew what we knew at that time. And so we're, we don't have a result of the horizontal well. So it might be that you know, horizontals aren't the way to go. I also would tell you, I don't think one horizontal well is going to tell us the answer. In this business usually you need to do more of one thing, of something than one thing.

So if we do that, we'll be drilling another one following this one. And it is, a prudent way to act, I think. As you know, since we got this horizontal drilling now, you know, if we get 2 times the rate and reserves or 3 times or one time, or 4 times, we need to know what that answer is. Because if we drill a bunch of verticals and say, we put that money into something that wasn't as well used as if we had drilled horizontals. So we don't know the answer yet is what it boils down to. Butt rationalization of how we got there is that.

Why was that particular location chosen? Because I saw it, about a quarter mile away from the other Vaughan well, which appears to be one of your better wells? What was the logic, originally that was filed as a vertical well. What changed to saying this is the spot for the horizontal, anything?

Bob, this is Richard. Are you talking about the drilling the horizontal well?

Yes, about quarter mile away from what I reckon to be your second-best well so far revealed in the play. And originally the first well was, was supposed to be vertical. And you changed your mind and went horizontal. What went into your thinking?

I think there's a lot of different factors you have to look at there to do that. Some of them are just, you know, strategic in nature. Other ones are regulatory. We for one instance, in the Griffin mountain field, we have field rules. And we know if we drill a well we can produce it. So that, it takes away any kind of delay or obstruction you might have related to the regulatory thing. That's part of why we went and did it there. And the other thing is we have more control in the Griffin mountain field in that pilot.

So we wanted the significant amount of control. So that one we drilled this first horizontal. We took away some of the geologic risk. And we want a sample, you know, we want to be right on top of another well, either or so. A lot of different factors there, but we've landed it, in the shale. And we're horizontal. And so it looks like some of that control issue stuff was mitigated by that.

When, when you do the completion in the horizontal well, just can you give me sort of what the basics are involved? I mean, I take it it's an open hole. And you know, can you give us some of the -- without giving away secrets; maybe there are none to give away. But you know, how does it -- physically done? With bridge plugs? Or what happens when you fracture stimulate 2,000 feet of lateral leg? What keeps the rock from collapsing into the hole and that sort of stuff? Just some layman's things and what happens there.

Sure, there's a lot of different technologies you can deploy. And it depends on you know, where you are and what the particulars are. I can tell you that what our plan is, is that it will be a case hole completion. So we don't have hole stability issues. So we'll be perforating the casing and fracture-stimulating through perforations in the casing. The technology in horizontal completions is a lot of new technology coming out, very interesting and timely. What we're planning on doing is, what I call, say to my comments is a multistage completion and the technology is there to isolate in the casing, sets of perforations and stimulate them, and then move to the next set of perforations and isolate them.

And stimulate them. So we can nicely have about 4 stages that we would think we would try to do here. It depends on how much lateral we achieve. But about 4 stages. And then we would have you know, sets of perforations separated within each stage, like may be 3 sets of perforations that we would be pumping into, trying to create a fracture in each set of those.

Okay. Now, one final question, if I may. The, let's go back to some of the Wells that have been on for a while. I mean you've had some wells on, I mean you flow-tested them, let's say, in September and October. Wells that you know, I see float tests based on your filings, in the 400, 500 range, a day. Now where are those wells today? I mean, I'm trying to understand what you mean by this decline rate. What does it look like?

Well maybe, maybe a way to just -- like Harold said, maybe we could get some more modeling information out in this later. Another way to look at it is if you look at the, we talked about the first average 30 days production. Of being about 375 Mcf a day. So certainly they're starting higher than 375 and they're ending the first 3 days lower than that to get to that average. And then when you go to the second phase of that or if you look at the first 60days, you know, you get a lower population of wells. And I think that number is down around 260, 265 Mcf.

In other words, the wells start out at let's say 500. 30 days later they're way less than 400. Because the average is 375. And 60 days later, they're averaging 260. I'm just trying to get an understanding of what a well's first 3 or 4 months looks like, if it comes on at let's say 500,000 a day?

Well, I think you've just described it fairly well.

Okay, and then when does the flattening -- you don't know when the flattening begins yet?

Well, I mean like Harold said, we have some data that 150 days of production. We're seeing certainly, we're seeing flattening of the decline curve, lower decline out in that longer period. And all of that is built into our best estimate of what an average result is when we're saying that that we think we've got an economically viable.

What happens with compression in the field? Let's say we're out 200 days on a well and it's 100,000 a day. Do you have to put in field compression to, you know, get this up to pipe? I mean, is this going to require tremendous amount of field compression, this whole Fayetteville shale play? And are you ready for that operation?

Yeah, I mean it is certainly, the type of play, is shallow gas play, with low reservoir pressure. And not lower than anticipated, just basically you know, what you would surmise for something of these depths. We're going into higher-pressure transmission lines. These kind of plays at these kind of depths, you're compressing from the start. And we've been doing that.

We've been building infrastructure in the pilot areas to start to build towards the centralized compression per pilot area. And get all the efficiencies we can. Out of you know, out of that compression thing. But compression is certainly a big part of the play. It's built into our economics. When you see the statements we're making here. We're including the cost of doing those kind of things. But compression and gathering will be a very significant part of it.

Will you own it or lease it? The compression? I mean, assuming 1,000 square miles over many years, that this play works, will you, I mean you've done this business before as a company. But will you decide to use -- I mean, what's do you own or lease? Have you thought that far out?

If you look at our operations, kind of companywide, we have some that we own, and some that we lease. Right now to be flexible, I think we've been looking in most of the employing leased compression. And it's, you know, it just depends what's more economic. Right now, I would say to be flexible, we're leasing. What we've done so far.

Gas price to make this play economic? Is there a, you know, can it work sub$4?

Well, clearly, we clearly believe we don't need as high a price as what prices are today. And the end result of all of that, I'm hesitant to say. Exactly what price is needed because we don't know the outcomes of various things we're trying. In terms of horizontal wells and other things right now.

Got you.

But it works at today's prices, it works at prices lower than what we're seeing today.

Thank you, gentlemen.

And our next question today comes from Joel Alman (ph) from RBC Capital Markets. Please go ahead, sir.

Good morning, everybody. What about thick water flags in the Fayetteville shale?

This is Richard. I think we're certainly not at the conclusion point on what the best stimulation is here. I think you'll see us continue to, to try different designs. And to modify what we're doing. Which might include some more of that. We've only done a couple of those. And the results have not been clearly better. One well is probably less than average. One is more like average. So hard to say right now. We certainly are going to be studying the results of the wells we're stimulating right now. And trying to best understand the best way to go about it, which could some more of that.

And then on your horizontal well, what's the threshold in terms of production? And/or reserves that would make the horizontal well economically viable, given the costs you've identified?

We won't know that until we see some production from it and what its decline looks like. It's just the production itself, production rate really won't tell us that answer. So it's too early to answer that question, Joel.

And then in terms of the acreage, I mean based on what you've seen so far, what percentage of your acreage would you say is subject to faulting or has other characteristics that would preclude you from drilling there?

We haven't seen any, I mean, we aren't precluded from drilling anywhere based on faulting that we know of. In the Griffin mountain we've seen more faulting than we have in the other areas we've drilled in. The way that tends to reflect itself is a little bit more drilling problems.

I think like Harold said, I don't think anything is precluded. It's, you know, it's understanding how the faulting affects you in, another thing we're doing is, we have some plans this year for requiring some seismic data. And we'll be using that to help get a better structural picture of the areas where we're drilling that are kind of new and have less control.

Okay. And then, on the ranger incline, based on your results so far, I think you're drilling, you know, 43 or so wells this year. And then do you still have the 132 or so contingent wells beyond this year?

I think that's a fair assessment. And the way we've described them and I know that's been talked about. You know they are contingent on what we see this year. We certainly have a lot of acreage there, that could be developed, that would support you know a number of greater than that. But I think that's a fair statement. And it will indeed be contingent on the results of these next 40 or so.

Gotcha. And then one for Greg. In terms of differential, you know, the -- if you look at the stock price, Henry Hubs versus Nymex, it's pretty close right now. So I mean are you seeing the widening still in your basis? Or has it really narrowed quite a bit at this point?

Well, Henry Hubs should be right on Nymex all the time, Joe. It should be very, very close. As you move away from Henry Hub, is where the basis differentials widen and all parts of the country, and I mean what we're seeing in the first quarter, is been fairly similar to the fourth quarter and that's why our guidance is that we expect it to range between $0.50 and $0.60 in Mcf. I think we averaged about $0.60, a little over $0.60 in the fourth quarter.

Henry Hub, I mean when the contract expires, they're supposed to converge. But in the latter part of '04, we saw some big variance between spot, Henry Hub and the Nymex, which of course is based on the Henry Hub. But I mean Greg what would be the best kind of benchmarks or local hubs to you to represent your production?

Well I mean our Arkoma Basin production is really priced off Reliant East. And it's been over $0.50 on Mcf versus historical number that's definitely closer to $0.20. Our Permian production, is about averaging right now in the first quarter about $0.75, a large part of our Overton production is priced off at Texo and on Houston ship channel, I'm sorry and then in Houston ship channel has been averaging $0.45 to $0.55 so far in the first quarter. So you really, I mean we've got production that is spread all of our different core areas. And between Houston ship channel, Reliant East and Texo, it's probably the bulk of our production and then we -- whatever is coming out of the Permian is about a $0.75 differential right now.

Okay. Al right. Thanks for your time.

Thanks.

And we will now take a question from Round Rock Capital's Peter Vick. Please go ahead, sir.

Good morning. My question, Richard, and I think you talked around is the rough rule of thumb in the Barnett is a horizontal its going to cost twice as much and you are going to get 3 times the rate and reserve. Is that kind of a pre-drill prognosis and I guess a corollary to that, the million six for the first well is a little bit of a learning curve. Where would you think that cost would shake out through time?

Well it's really hard to say. Peter, I mean it depends on, you know, what we're trying to learn, we're trying to learn a couple different, several things with this well. Mechanically, how does it behave? I think your model of the vertical versus the horizontal, in the, in the Barnett is also my understanding, which is obviously the attraction to the economics. But I think you know, where we'll end up, there's a lot of factors there. What we're trying to understand mechanically right now is you know how do these rocks work when you start trying to build angle to them and drill a flat, horizontal well over a pretty substantial distance?

And like I said, we approached the first one conservatively. There's a lot of different ways to do it and you can drill, you can drill deeper, and then have a shorter radius build, a quicker build into the horizontal and awful those kinds of things, which affects your casing program and so it's really hard to say. What we're trying to understand here is that -- hard to say where the cost would land. We're trying to understand mechanically, can we build the angle? Can we actually drill a significant lateral in the shale without a lot of mechanical problems and then start working on the completion side. So it's, you know, it's really hard to say where those costs will land. There's give and take on all that.

Okay. Another question, on this well that tested over a million a day, that's so anomalous compared to the norm. Are we talking about a greater thickness here? Are we talking about greater depth barrier? What's the difference in this well, B2B these other wells with their rate and reserve?

Well it's in a different area. It's in a different pilot than the bulk, than the majority of the wells that we've drilled. It's, it's slightly deeper. It's not a lot deeper. But it's slightly deeper and those are -- those are, I mean those are the kind of -- those are the main things, but geologically there may be something different there than in the other areas. But you're right; it's an anomalous test, yes.

Okay. Kind of a second thing, in the recent Barnett wells, I'm talk these wells that are you know 6 and 7 million cubic feet a day. You know initial 30-day rate. There seems to be some corollary between that and completing and zones that have either a high quartz content or almost approaching sands. Do you see that kind of availability within the Fayetteville section itself?

Well, you know I can't comment directly about the Barnett. I have read the affects of having a higher silicon -- silica content in those wells and how they respond to fracturing. You know we're seeing, we're seeing availabilities in the rock itself in the Fayetteville. Some of that variability is probably in the percentages and distribution of clay versus more silica-rich materials. So I would say we are seeing some of that variability.

Okay. Those are all of my questions. Thank you very much.

You bet.

And at this time there is one question remaining in the queue, and that comes from Hibernia and that is David Heikkinen. Please go ahead.

Good morning, guys, for staying focused to this long call. Congratulations on that. The Nacogdoches County just a quick comment question, your acreage there and is that included in the 47,000 exploratory acres that you acquired last year?

No that would not be included in that, David.

Okay.

Most of the you know most of these other East Texas project areas we have were you know, we have 4 or 5,000-type acres that we've kind of assembled.

Okay.

In individual projects.

Okay. That was it. Everything else answered. Thanks.

At this time, gentlemen, there are no further questions; I would like to turn the call back over to you for closing or final remarks.

Well, thank you all for joining us today and it's been one of our longer conference calls, I think. We appreciate everyone staying here with us. And without any really any further comments, I think we'll bring it to a close. Thank you.

Thank you everyone for your participation. That does conclude today's conference.