先鋒自然資源 (PXD) 2002 Q2 法說會逐字稿

Good afternoon. My name is and I will be your conference facilitator. At this time, I would like to welcome everyone to the Evergreen Resources Second Quarter and first half 2002 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise and after the speaker's remarks there will be a question and answer period. If you would like to ask a question during this time simply press star, then the number one on your telephone keypad, or if you would like to withdraw your question please press the pound key. This call will be available for replay beginning at 4:00 p.m. Eastern Time today through 11:59 p.m. Eastern Time on Saturday, August 31st. The conference ID number for the replay is 4925768. The number to dial for the replay is 18006421687 or you may dial 7066459291. Speaking on today's conference will be Mr. Mark Sexton, President & CEO and Mr. Kevin Collins, Vice President of Finance & CFO. I would now like to introduce Mr. John Kelso, Director of Investor Relations. "Mr. Kelso, you may begin your conference".

Thanks a lot and thanks for everyone for joining us today for our Second Quarter Conference Call. We appreciate your interest. I'd like to start off with just some of the usual things, that this conference call is being broadcast live on the Internet. Our address is Evergreengas.com and it's got an accompanying slide show that might be of interest to you all. Over the next half hour or so Evergreen management will be talking not only about the second quarter results but also what figures look like for the second half of 2002 which of course includes some forward looking statements. These forward looking statements are made under safe harbor provision established by the Securities and Exchange Commission. Of course there are risks and uncertainties involved with these forward looking statements are described in more detail in the companies most recent annual report and on form 10K which was filed with the FDC.

With that I would like to turn it over to our Chief Financial Officer Kevin Collins.

Thanks John, good morning. once again we are very pleased with our quarter results, quarter ended June 30th 2002. Evergreen reported earning per deluded share of 17 cents and we had cash flow before changes and operating acids and liberties of 52 cents per delude share. Our production for the quarter was approximately 9.5 Bcf and that is on slide 9 of the internet slides. Our average daily production was approximately 112.4 cubic feet per day.

The 9.5 was on the higher end of our guidance that we previously provided in the first quarter of 9.3 to 9.5 our current net sales are approximately 109.17 cubic feet per day and that was for the month of July. Our production guidance for the remainder of 2002 is unchanged from previous estimates on November 2001, on February 28th of 2002 and on May 2nd of 2002 at our conference calls we provided guidance and have not change production guidance all year long.

We estimate that guidance for the third quarter will be 9.9 to approximately 10.2 Bcf. Fourth quarter production will be 10.6 to 10.8 Bcf. Our total production for the year is estimated to be 38.8 to 39.3 Bcf our actual rate for 2002 in terms of net sales will be 120 million cubic feet per day as we previously noted the estimated production for 2002 is approximately at 25 percent increase over the 2001 production results. All of this increase is due to organic growth through our drilling and complication in 2002.

Our production guidance for 2003 remains unchanged from our previous conference calls and is bases on our program. As we prepare for our 2003 drilling program we may adjust these numbers to reflect changes in the number of wells we to drill. But the quarterly projected production are as follows: for Q1 for 2003 we estimate 10.9 to 11.1 Bcf, Q2 is a 11.2 to 11.6, Q311.6 to 12.2, Q4 is 12.3 to 12.7, for a total of 46 to 47.6 Bcf for the year ending December 31st 2003.

Our original drilling plans for 2002 was approximately 152 wells as of today we have drilled 114 wells. Due in part to our results that we have encountered in our deep test wells we will increase our drilling program up to 165 wells for 2002 the additional 13 wells will be drilled to the deeper unconventional gas formations is the basin.

With respect to gas prices and hedging for the second quarter we had originally guided analysts to about $2 and 27 cents for our hedging of the gas for the second quarter of 2002. However due to our gas marketing ability to flex gas to various markets which have better gas prices, we're able to increase those prices by about 12 cents, this is due in part of the fact that we can market gas in different places, different from where we have contracted to sell our gas under those hedge agreements. Our guidance for the third quarter in terms of gas prices are as follows; in July our gas price was approximately $2.85 pr Mcf, we estimate that August would be around $2.65 plus for the month of August, September we estimate to be around $2.60, these again will change as the gas price fluctuates but that is our best guess as of today.

On slide 16 we have the result for, of our operating costs and projected prices, projected costs for the remainder of 2002, we have not changed those costs significantly during the year, costs for the second quarter of 2002 where on the higher end of our previous guidance and this was due in part to three major overhauls on compressors we had in the second quarter totaling about $300,000 and the additional pumpers that we had to hire due to our increased drilling program.

Our capital costs for 2002 are shown on slide 17, even though we are looking at increase in our drilling program for 2002 at this point in time we may not have to increase our capital budget, we'll watch that as the year goes on, we've changed some of the individual components of our cap ex budget but as of today we think we might be able to spend $106 million for the year ending December 31st 2002. A long term debt at the quarter totaled $230 million as of yesterday long term debt was approximately $228 million; based on our guidance provided for operating capital costs production and estimated future gas prices as of July 31st we estimate that long term debt at year end will be in the $228 million to $234 million range.

As we discussed in our last quarter's conference call we had anticipated having a mid year reserve report that was audited by , that reserve report was completed as noted in the press release our reserves where up 8 percent over 2001 year end reserves to approximately 1.134 Tcf of gas reserves the company added approximately 101Bcf during the first six months. There where no net downward revisions to the reserves for the six month period, the reserves where in line with our previous expectations and our previous guidance and basis on our future drilling locations for the second half of 2002 we estimate the reserves at the end of the year will still be in a range of 1.2 Tcf to 1.25 Tcf. Mark I'll turn that conference call over to you.

Thank you Kevin, I'd like to point out a couple of things that where probably not in the press release; on the infrastructure side as everybody knows we have been investing heavily in our gathering system and compressor station and we do not believe that we need anymore compressor stations based on our hydraulic model of the field now and 2002 will probably represent a peak year for a significant capital out lace for gas collection and compression in a re-toned base and we expect that component of our budget to be much lower in the future.

We'll still be putting in large pipe in some of the northern and western edges of the field but we probably will not be adding compressor stations, we certainly have no plans to do so, so we are going to start to see economies of scale in the infrastructure in the infrastructure that we currently have in place. We do believe the takeaway capacity from the Raton Basin will continue to exceed and production for still quite a few years and give us plenty of time to plan for any need for future expansion. I would like to remind everyone, we can't say it enough because we keep getting the question enough times, how did the Rockies price their which are extreme to say the least. How does that affect Evergreen? The answer is it doesn't. In fact it has provided an opportunity for us to actually make a little money by using some surplus volumes to buy and sell gas off the Rockies and sell into the Mid Continent, where all of our gas is sold currently, except for that minor portion of our gas that is sold to the local municipalities.

We currently sell all of our gas in the Mid Continent region, those prices are $0 20 roughly off the Henry Hub on average. As everyone is aware we made that strategic decision several years ago to access those markets, we did it for two reasons, one is we simply needed the pipeline takeaway capacity out of the basin and we wanted access to better more reliable markets and we have had, and both of reasons have proven to hold up, not only for just a few years into the future up till now, but also for the next few years.

We indicated in our press release that we're very excited about some of the results we're getting. That's particularly true in the UK, where we believe that two of the coal mine methane wells that we have drilled, one at Manor, and the other one at -- and the other one at an area -- it's hard to pronounce, it's Welsh term, Llay. It's L-L-A-Y. But those two wells, we believe those wells have demonstrated commercial productivity, will be successful. The methane content of the gas is in excess of 90 percent on each well, in fact, I think it's in the 94 to 98 percent range, which means that it's virtually marketable gas. We're going to be marketing that gas to end users where we can and where we cannot easily market to end users, we'll be converting that to power. One of the coal mine methane wells is currently scheduled for sales to a local end user that's about a mile away.

The other well will be used to generate power to demonstrate the commercial success of generated power there. Values for gas are much better if you sell into the pipeline or sell directly to end users, where current prices are about the equivalent of $3.00 per . If you generate power with it, there's a current surplus of power in the UK, and current short term, the prices would be in the range of $1.50 to $2.00. As we've indicated in prior conversations, however, our plan is to carve out or spin out our UK operation into a more efficient UK model, and that will mean combining with other assets and/or other companies in the UK. And giving Evergreen more of an ownership than direct operations control over what we're doing in the UK. We've held onto the UK this long because we honestly believed it would work. It appears that, with the success of the coal mine methane wells, we have demonstrated that commercial success. We'll probably increase the turns we will get and the value of what we get for the carve out or the spin out, which is why we were waiting.

But we have signaled to the market, we think this is the appropriate thing to do. Given the current regulatory environment in the UK, it's clear that we will not be able to drill wells as quickly there as we can in an area like the Raton Basin or places such as Alaska or Canada or other places that are set up and friendlier for oil and gas operations. So we made the strategic decision to carve out or spin out this asset, and now we have the favorable results that I believe will get us a premium value for our shareholders.

In Ireland, we indicated that we did complete five of the six exploratory wells in Northern Ireland and the Republic of Ireland. Those wells have been cracked. The results are mixed, as we indicated. One of the wells that -- the best well, we obviously cracked into a natural fractures and the well produced heavy production which looked good. Sustained rates were on the order of about -- were in excess of 100 a day. The sands that looked the most interesting were not the primary objective, which was the Mullaghmore sand, but turned out to be a deeper objective that was actually a secondary objective called the Dowra sand. And that sand actually looks like the best opportunity to be commercial at this point. We believe the Mullaghmore sands, which exist everywhere, will probably be productive in other areas, but we tended to drill where we thought we would have a good permeability enhancement by proximity to fractures or structural developments. And it turns out that for the areas we need to focus on for the Mullaghmore in the future will be areas that are probably not defined by structure but more defined by and defined by depth of burial and other geologic factors in the face.

we're going to be focusing in Ireland in the future, mostly seismic for 2003, although we may drill a few wells. We do plan to drill additional wells in '03 or '04. However, the number of wells we drill will depend on exactly what we find as we do the seismic, and we're going to test three concepts going forward. So far we have yet to test the sands, which we believe exist in some of the northern areas. We're going to be testing those in the future. We're going to be looking for the Mullaghmore in areas that are normally pressured or over-pressured. The areas we drilled happened to be under-pressured. And we're going to be defining and delineating the extent of the Dowra sand, which actually looks quite promising.

Following our lead, however, for what we said before in international operations. Going forward in Ireland, we're going to seek a partner, particularly a partner who can make things happen in Ireland, and in particular, one who can help with the gas marketing infrastructure and help us get that gas to the best possible market. It's a little -- it's quite an open market right now for natural gas in Ireland. Ireland clearly needs all the domestic supply of natural gas it can get, and I think will be very receptive to an on-shore natural gas . But our indications are that we can provide the technical expertise, we can provide the equipment, but we're going to want local savvy with the logistics side. We'll want to be doing ventures with local businessmen.

In Alaska, we indicated that we plan to drill wells this year and we actually have eight wells planned in two four-well pilot programs in the pioneer unit. Drilling is currently expected to start September 15th. We're sending equipment to Alaska to drill and complete the wells. The wells will be completed in the fourth quarter, and we'll be testing those -- I don't know if we'll have recoverable reserves, economic reserves, to report from Alaska by the end of the year. It'll be a function of how good the wells look on the . We're guessing that we really won't have information to report on Alaska on the success there until the first quarter of next year.

We've also indicated in the press release that we're very encouraged by the results that we've had from the deeper formations below the coals, the upper and middle Crutaceous Age formations for unconventional gap. Typically, these are tight shales, and fractured shales. We'll be particularly targeting formations below the goals such as the . So far, a test in the Dakota has proven to wet, but the shows we got in the the other formations that were mentioned are so encouraging that we've decided to drill at least 10 additional wells this year at the end of our drilling program, and drill deeper wells to test these four or five deeper formations below the coals.

We're picking out the specific sites now. All the sites that we will be drilling are on land that we've already leased, and in the parts of the basin where the bulk of our acreage is already held by unit, or held by lease, or held by production. So we're very encouraged by some of the we've received on some of the deeper wells we've drilled. Some of these wells were drilled initially as water injection wells, and on the way down we encountered such good good that we're going to go ahead and set up and drill at least 10 deeper wells throughout the basin in strategic places and really start to test and develop the deep potential.

We're also very encouraged that for the first time, we're booking reserves that are not purely coal reserves. We're booking only two BCF from the deeper formations, but it does show that we do have some deeper potential, some proven reserves, and it is enough to encourage us to want to drill quite a few more deeper wells. We're also encouraged by the results that we're getting from sand development in many parts of the , and the Raton sands are also an area that we're starting to complete separately as well. And we're very encouraged by the results of this.

And while it's too early to know exactly what we're going to have in the Raton sand, we're already booking five BCF in the Raton sand, so we're signaling that appears to be economically productive as well. The total for the Raton sand is a matter of speculation, but best guess it will add another, ultimately, another 100 to 200 BCF, potentially more. But that's a number fairly comfortable speculating about at this time.

So we have a lot going on. Our coal production is right on target, and our reserves and production growth, as Kevin indicated, are exactly what we forecast almost a year ago, with virtually no changes. It's been like clockwork. We'd like that to continue and we'd like to continue to poke around in areas where we can create additional value for ourselves and for shareholders. With that, I think, , I think this is probably a good time to open it up for questions.

At this time, I would like to remind everyone, if you'd like to ask a question, please press star, then the number one, on your telephone keypad. Your first question comes from the line of of AG Edwards.

Good morning Mark, good morning, Kevin.

Hey, Greg.

Good morning.

Hey, I have a couple of questions here. Let me start out by talking about the number of wells you drilled in the first half, 101 wells. How many of those locations, Mark, were actually and developed? In round numbers.

It's a good question. But , we'll just have to look it up.

It's roughly half, .

Roughly half. OK. So we shouldn't be measuring reserve additions based upon the number of wells. Is that fair?

Well, that's right because a lot of those -- there's two things going on and both Kevin and I will address that, but a lot of those wells drilled early on were wells, or were setting up simple in-field type extension wells that didn't necessarily set up other PUDs. We were looking at wells that made sense for the infrastructure that we have in place. We're trying to -- since we have been spending so much money on infrastructure, we've been starting to drill wells that dovetail more closely with the gathering and collection system that's already in place. So a lot of those wells simply didn't set up additional undeveloped locations.

Also two, keep in mind that a number of those wells were wells that we had signed less reserves to, historically. About 17 of those were wells that we just booked less reserves on. At the moment, we're only booking about a BCF per well on the extension -- or on the wells, versus the typical 1.5 BCF on an extension well.

And that would be 100 acre spacing?

Yes, roughly 120 acres. It's five wells per section, sometimes a sixth well, but usually it's a fifth well.

OK.

before, though. We think that you can additional recovery with six wells per section, but that our best analysis suggests that gas prices need to be $4.00 or better to make that look very attractive. So right now, the plan was five wells per section. In a $4.00 gas price environment, the decision would be six wells per section.

OK. On the 700 locations that we have in our inventory, which I assume is virtually all coal bed methane, about how many of those are PUD locations?

, you've been our press release. Of that 700, there's probably about 333 locations that are included in that 700 ...

OK.

... reserve report.

Sorry, I must have missed that in the press release. OK, in -- on a deeper tone, Mark, just a couple of questions. I believe Burlington did some drilling in the past, looking at the shale, and below the coals there. Were you aware of that, and what do you know about those results and how would that have affected any of your drillings or decisions you made regarding drilling in the deeper Raton, looking at upper and middle Crutaceous.

Well, we've been aware for some time that at the time drilled, which of course is not Burlington, but at the time, drilled wells to test the Dakotas, the shales, and the , and the initial results they got were quite good. The wells came on, some of the wells kept at over a million a day but fell off very rapidly. And we think that -- we're not sure whether that was reservoir completion related issues. And we've been aware that the gas is there for some time, and we've been signaling for some time that we want to test the deep Raton, and we still do.

Our own tests on our own wells that we've drilled deeper, again, are sufficiently encouraging that we've just decided to go ahead and increase our drilling program and intentionally drill at least 10 strategically placed deeper wells to at least the top of the Dakota throughout our acreage position to start really getting a good handle on how extensive this might be. But we are starting to book deeper reserves. And while it's only 2 BCF from a couple wells that were drilled deeper, you know, it's a signal to us and our shareholders that, you know, some of this is going to work and some of it's going to be economically recoverable. The size of that recovery is purely conjecture at this point, but speculating, I'm going to guess that the deep potential of the Raton basin will add at least 100 feet Bcf and may add as much as 500 Bcf just in the areas we already have held up that we have held under lease.

Would that include the Raton that you mentioned earlier.

Yes that's completely in addition to the Raton which are of course inter-bedded in the Raton coal formation and are a totally separate but also a more conventional type gas a more conventional type gas flow.

So your completion techniques are going to different than or you expect obviously to have different results.

Absolutely our completion techniques will be different to the and we're clearly for different results in the same way our completion techniques in the coals were different from Amoco and Amoco and Meridian's and did produce very different results for us in the coals.

OK just moving on to Alaska for a minute on the time line that you disclosed in the press release you know giving indications that we would know something in the first quarter is that you know well what can wrong with that timeline and then also could you address the gas markets up there. My understanding Anchorage is a principle gas market for that property, how well supplied is Anchorage at this time given what's going on in the ?

Well Anchorage is, I'll address those questions in reverse order Anchorage is clearly nervous openly nervous about where their gas supply will be coming from in the next three to five years given the projected declines in the Cook Inlet from the offshore platform there that have been around for the sixties and while some companies are making nice gas discoveries up there such as and others, they're mostly extensions to existing fields, they're not really large new gas discoveries. any very large gas discovery Anchorage is going to have a real problem five years from now supplying gas to all the people who are going to want it and we think, obviously, in the that methane could fill that gap quite nicely. We've been told by locals there is a pipeline that runs through the southern portion of the pioneer unit and we've been told that if we'd like to 20 or 30 million cubic feet a day into that tomorrow they would, they would be glad to take it. As far as the price, that's a complete matter of negotiation. Some of the older contracts have gas sales around a dollar fifty, though newer contracts tend to talk about gas around three dollars so it's a completely open market right now.

Our best guess is that long-term gas sales in the Anchorage market will be in the 250 to 350 range.

You get a pop line you say.

Yes.

OK. Then lastly, so somebody else can ask a question. On Ireland, you know, you mentioned results have been mixed yet you did mention that you may need some drilling in '03 and '04. How should we interpret this at this point in time?

If you have better information than we do, give me that interpretation, but at the moment cracked a lot of wells and found a lot of gas that was under pressured and very tight. Had the pressures been better, I believe the gas flows would have been better based on what we know from these sort of tight under, these sort of tight reservoirs. We have a lot of look-alikes, as we indicated in and in and in the North East and it's clear to us that we need to target the Mullaghmore not first, not in structural areas but in areas and particularly look at blocks that would have been more deeply buried and subject to normal or even greater than normal hydrostatic gradients. So, that will be the next target for the Mullaghmore. We also have not yet tested the sands to the north and we're very interested in doing that. The sands are productive offshore and we haven't tested those yet on this . That's a so it's a different depositional environment in the carboniferous age, Mullaghmore and the carboniferous Dowra. The Dowra turned out to be a pleasant discovery and I think that we want to try to delineate the extent of the Dowra . If it's expensive, we're going to have a nice there. We find the Mullaghmore in areas that are normally pressured or over pressured we're going to have a nice . If we get anything close to what some of the people discovered in the sands based on offshore discoveries we would have a nice , so we found plenty of gas, we just, the concept we were trying to drill, which was to look at areas that were close to some of the faultings, turned out to be, perhaps, too close to the faulting because there were, they were under pressured and so, obviously, those were not faults and, obviously, we need to discuss the, you know, test different concepts for we have three areas to go investigate with some encouragement and we're going to do so. We're definitely going to run seismic in '03 and we will drill wells in either '03 or '04. We're not finished with Ireland, but following comments about the UK it is clear to us that still to get a grip there we are going to have to find a partner that is going to be able to help us to get things done logistically so that we can go out and drill 10 or 20 wells and talk about the results of that instead of the results of five or six wells that took a year to drill and complete.

So I wouldn't say Ireland is exactly encouraging enough that we are definitely drill more wells, we are just going to three different concepts, that is all.

OK, well congratulations on good production growth that reserve in the first half, thanks.

Thank you Gregg

Your next question comes from the line of of Stifel Nicholas

Hi, David Tameryn of Stifel Nicolas, congratulations on the good quarter as Gregg said. A couple of questions about the deep what type, I think you said booked a couple of Bcf of reserves associated with a couple of wells. Is that kind of reserve target we need to make this successful is it a little bit under Bcf to make it economic I should say.

No these wells are being drilled where there is existing infrastructure, I assume that Gregg there would just want to confirm that.

The answer to both your questions is Yes

And that we are drilling these wells where there is infrastructure because we are drilling the wells where there is infrastructure, the amount we need incrementally up the pipeline, the location and all the roadwork in place, Bcf so he is economic and we would be happy to continue to drill wells so we are only at Bcf we have the infrastructure already in place, and the nice thing about the wells of course is the Bcf actually look more economic than a Bcf from a coal gas well because we will get production quicker because the profile will be closer to a fractured shell instead of a goal gas system. So we are pleased with what we have seen, enough so, that we said hey we have got some time let's drill ten deeper wells and lets drill them in strategic places where we can get the most information, and we have been talking about the deeper and we have been talking about testing the concept we finally have enough positive encouragement to get serious about it.

OK

But not wild and crazy yet, next year might be the wild and crazy year depending on the results we get from these ten wells

OK well thanks very much, wild and crazy could be good, appreciate it

Your next question comes from the line of

Thank you. Hi Mark, hi Kevin. Question in regard to the UK and Ireland. Would you be putting these together as a package or separating Ireland because of early days there as yet?

The answer is we have been exploring both options Barry and it turns out that the best deal that I am aware of at the moment would be to segregate the two because the financial investors that are interested in Ireland are not interested in the UK, the ones that are interested in the UK are interested because it is coalbed methane and would not be interested in Ireland. We will deal with what is in the best interest to shareholders but at the moment bifurcating the two appears to be our best option, although that could change as negotiations change.

Mark, could you give us some idea as to the value proposition over here for a coming in, what sort of lumber might be attributable to the contribution being made by Evergreen in its UK assets?

There is only one comp at all in the UK that anyone could use as a model and that is a company called Alkane, and they have about 5 MMcf a day coming from three or four different coal mine methane systems and I believe their current market valuation is around £100 million pounds.

Draw what ever conclusion you want from that the two wells we have each tested over a million cubic feet a day and I believe would sustain over million cubic feet a day depending on what back pressure you put on the system. These wells are a little ticker to evaluate than the typical coal bed not playing well because you have to pay particular attention to the and the gas rate are going to be quite a bit higher than a coal bed nesting well but there are not going to last nearly as long expect a five, or six, or seven year productive life instead of a 30 year productive life but at much higher rate. At least half a million a day and probably closer to a million a day would be typical for a good coal mine well.

One of the most practicable EMP companies in the sector has being Evergreen and that is what makes it so attractive for people to look at. What will the deeper tone do to the coasting, the finding cost, the risk and the returns you might be looking at here?

This is all speculation of course.

Go ahead.

But a deeper take 300 to 400 thousand to drill complete depending excitably where it is of course it has some of the deeper wells are only 400 thousand feet some are 700 thousand feet. I am sure that concepts of describing 400 to 700 thousand foot well sounds silly to some one who is use to gulf coast drilling but you know for only 300 or 400 thousand we can, if we could reliably get a Bcf statically that is a very active play to us. It is complete consisted with our 30 to 40 cents finding in development costs over time. And like I said the infrastructure is already in place, the well sites are already spotted would be very easy to go in a drill play and that is of course why so active play because we have use the in development and extension to get this is place. So if we have well whether they are Raton or Raton coals again that infrastructure is in place and most of that is already sub costs as we have indicated. So I think we are going to start to see some nice economy of scales going forward as we continue to drill up the Raton Basin at the moment it appears that will still have five or six years of drilling inventory in front of us just in the coals just in the Raton and the and if you add deep drilling to that could extend the drilling program two or three years.

I think I am hearing you say that is not a from you business model?

I think this completed consisted with our business model and it is right in our back year which is even nicer.

Terrific thank you gentlemen.

Thanks .

Your next question comes from the line of of .

Hi Mark I wanted to talk about the hedging policies and in particular I was wondering on the how your counter party is on the 60 million a day and where is the off take price. It says here the waded averages you have got a 2594 and 387 dealing is this are those prices are your counter party going to give you those prices at CIG or is bases on a ?

Neither. They are actually based on a mid price a delivered price to the mid .

OK and how is your counter party?

Our counter party on those hedges is one of the banks in our bank group.

Oh great!

If not with the marketing company.

OK, well I think I've come to the conclusion of the best person to hedge with is your own bank.

That occurred to us too Jason.

Just a great incentive for both parties to perform.

Yes.

And what about then, what do you do, your delivering it but your prices are being paid at mid continent, do you have firm transportation into the mid continent?

The answer is yes, that's why we have plenty of pipeline capacity to get to the mid continent. Southern ends of the system has been upgraded several times through the wire lateral, the lateral and loops and expansions in compression upgrades to each of those laterals and we have participated in all those expansions, right now total sales out on a re-toned base are about 180 to 190 cubic feet a day. the current system could easily take 230 and they turn on the compressor that would add, that would take it up to close to 300 million a day, so we have plenty of room for growth and all of that gas does come out, does go out of the Raton Basin and into mid continent market.

In those unusual situations which have happened from time to time that the price differential in the Denver market is within 30 cents of these mid continent markets we can also flex that gas to the Denver markets and get a better net price, but we still have, at the moment we have plenty, for now and for the foreseeable future we have plenty of pipe line capacity and we're all smart enough to see how fast it's growing and to anticipate that and to suggest upgrades to the system well in advance when they're actually needed and we see no problems getting that gas into the better markets in the mid continent either now or over the next three years.

OK, and your bank is willing to do further hedging on the same terms in the mid continent?

Well that's one of the reasons that particular bank was picked as they where able to give us a financial hedge, and all of these are financial hedges, they where willing to give us a financial hedge with at that delivery point save taxes which allowed us to lock in the basis risk as well at the same time.

OK, and they're willing to do more and the reason you haven't done more for 2003 is that you don't think the prices are attractive enough?

We are starting to move in that direction and we're getting aggressive more than a couple of collars than in the fixed price , when you look at the press release you see most of the volumes are cost less collars and we're moving in that direction, we're simply watching the collars every once in a while the collars get particularly attractive and I'm not sure exactly the reasons why but we look for those spikes and try to layer in the collars around some of those more attractive spikes.

OK, so you're working on it right now?

Yeah we're still actively pursuing it, and we're watching that market very closely and we expect to layer in more collars in the same range, which you see there.

OK well I think that your hedging strategy so far has been excellent, I think that you should continue it.

Thank you, it's not been perfect but it's been pretty good and it's allowed us to by unwinding last year it allowed us to nicely finance an acquisition of additional properties in the Raton Basin but that's not why we did it we again to first and foremost protect our capital budget, second to lock in returns on any acquisitions we make and third when we're in an obvious like we were 18 months ago we just had to do it and that's the philosophy we don't go wild and crazy about it but we think it's an important part of delivering predictable returns and cash flow for the company. Next year is a very nice year for the company if gas prices stay at about the level they're at now or go higher we expect that we will cash flow for the first time on an annual basis more than our capital budget even with our extension plan. So next year is a nice point for us as well.

OK great.

Thank you .

Your next question comes from the line of Bear Stearns.

Good afternoon.

Afternoon.

I think most of my questions have been answered just two that I had quick ones, Mark could you tell again what were the productive in the deeper Raton and you said that Dakota was what, what was productive?

There are actually four different formations target, below the have coals and the above it's Dakota with .

OK and also lastly what's the timing do you expect on whatever it is you ultimately with your U.K. venture?

We're working on it now something could happen on it this year. I'd like to see something happen this year, if not this year then early next year.

Great thank you very much.

Thank you .

Your next question comes from the line of of .

Good afternoon, actually all my questions were asked and answered thanks a lot, good quarter.

Thank you .

Your next question comes from the line of of

Hi Mark, how are you here.

Hey.

Couple of questions previously John's been breaking up for me the production that came from what we call the core assets versus the acquisition of the can you are you able to break those down for me?

Yes we have the numbers almost exactly Kevin Collins.

The average daily sales for the quarter ended June 30th for the core Evergreen properties was 72.3 cubic feet a day.

OK.

Primero in was 27.8 was 4.3 so those last two items were ones we acquired and that's about one third two thirds and that's up about 3.5 percent over the prior year.

Right OK excellent thanks for that I appreciate it. Mark looking back at this section and asked some of the questions I had. When you're booking the reserves in the lower Raton are you are you right now are you booking from anyone one of those four units or not yet.

Well we actually have booked a couple of Bcf out of two Bcf out of that reserve number, was booked in what was the or the as it's referred to locally and the other and that was about a Bcf and the other Bcf roughly came out of the .

OK, good and you also mentioned the Raton sands were you, you said that you booked five Bcfs from there.

Yes.

And is that different from the Raton coals or were you just.

Yes, that's completely incremental, in terms, I'm surprised we haven't found the Raton sand earlier in the development program, but we part of out Basin model in our program was to not only develop gas from so we decided to find quite a bit of sand in and around the coal, that would have been charged by the coal and would have additional gas that would have migrated away from the coals and is not available to the coal . And as we drill into the deeper parts of the Basin we're finding that sand development more consistent with some of the deeper parts of the Basin, near the Basins incline; I'm surprised that the sand development has so far been concentrated there but actually it's nice that it turned out that way because that's the deeper part of the basin where more pressures are available and more gas in place in available. So I guess if you could have that Raton sand development anywhere you would want it exactly where we are finding it, which is in the deep parts of the Basin.

And what do those wells look like, as far as costs and reserves and deliverability?

We're experimenting with all that now and I hope that it becomes an increasingly more significant part of our overall reserve, well I'm sure that it will percentage wise. You know there's Raton sand there about as costly as the Raton coals, there just in a little deeper part of the Basin, they still need to be cracked, they just need to be fractured, but the are extremely comfortable the floats however are much greater than the Raton sands relative to the reserves that we're booking and I could give you a profile. But whatever I gave you would look like a typical type gas and type fractured sand profile so...

But you're from those sands at present?

Yes.

And what's the total volume coming from the Raton both sand and coal combined, or what percent of your total volumes is it right now?

Well from the Raton it's about 9 percent over our total reserves, if you include some of the coal Raton that are hard to differentiate that we acquired from and others where they had opened them up together that number rises to a little over 12 percent. The average Raton production that we would attribute to the Raton for July was about 10 percent.

OK, so that's really holding pretty steady, that's good. and what kind of productivity for the and the as much as we both preserve so, what are those wells producing?

Well they come on like gangbusters but just a hundred Mcf a day.

OK.

Which is typical, which is exactly what we expected.

Right.

What's encouraging about it is that it's right about exactly what we expected it would do which is simply a nice "bread and butter" development if it works out.

Right, back to the UK for a second. I didn't get the name of the well that you where referring to, that's kind of hard to pronounce, the one, the Cheshire Basin that...

There are two coal mines, methane wells, one is in a place called and the other one is a place called which is actually a Welsh term which is spelt L-L-A-Y.

Right, OK, you spent a little bit of time in Wales. And you said you where going to try to achieve evaluation above, I didn't understand your, I'm going to have to re-listen to the call, but can you go back over how the evaluation you might hope to achieve with a spin out would exceed what it would be as a wholly owned enterprise within Evergreen?

Well we have about $30 million invested in the UK by the end of this year call that a rough number. I would expect that what we can show in terms of coal methane and what I hope will be the result of some interactive wells have recently cracked that we are cleaning up right now I believe the package has a value . So we will be starting from there and except there will be a question of how much of interest Evergreen has and what end and what industry .

OK a couple of more questions well I am sure you will not want to answer it much but the two shelves that are outstanding what's your thinking these days on how you might employ that opportunity?

One of the shelves forward for $50 million targeted for going out at that using stock. And my preference would be to get prices stay low for a while so that money doesn't come back into our industry have a opportunity to use that and use our stock to acquire cash flow in areas that have a lot of stagier up side that could be inside the Raton basin or put the corporal type plays that allow us to get total some where else.

As far as the other self we have no plans to use it, it is just nice to have it there we have plenty of credit capacity under our bank facility as Kevin indicated with finishing the year around 230 gives us additional 70 million of death and we preferred not to use them unless we have a good reason to do it. To acquire some properties that have a very good cash flow have usually good level of inventory of drilling locations. We are actually seeing both right now don't extent us to run up to the and in any of those at the moment but having said that there is a number of very, very good coal bed nesting want to be play out there and we think we should probably pay more attention to developing them working with people who are in the stages of developing them, and are having trouble of coming up with capital in the current environment.

But more in the North America rather than over seas but should?

Yeah I think seems to be more North America I think we have signal with what we are doing with the UK and what we plan to do with Ireland that we can provide the check technical support put certainly we can not run those think from and probably should not be trying probably should be staying in North America that short of parts of Alaska, Canada, that other basins in the Rockies or it could . I mean any coal, gas that makes sense to us we will take a look in North America.

OK and lastly in the 10K you talked about that 11th circuit case that may involve some EPA involvement and I have not heard any think on this issue for six or seven months can you give us a update on where this is going or is going to go away quietly or is still some thing that is out there?

There is a couple of cases out there that involve the EPA referring to discharge or are you referring to crack or stimulation?

Just the crack and stimulation.

Well the venue for resolving that is the and we are just watching to see what happens there it probably in my mind is going to require . I don't know if the will fix it or not but with the legates always does when they don't know what to do they study it and that study I believe will not be released until some time next year.

OK thanks I appreciate your view on that .

Your next question comes from the line of of Wachovia Securities.

Hi guy. Just curious if you had a number on to date capital investment and gathering and compression, along those lines, if you're spending less on that next year and the years out, do the coal bed methane economics i.e. finding costs, start to come down?

Yes, in general terms. You'd probably need to see our costs coming down over time, we certainly expect they will, but, you know, the only reason we would spend more capital is for good news because we're more aggressively developing other formations such as the Raton sands or the , so, you know, we'll, proportionately less capital will be spent going forward on gas collection and gathering than it has been in the past. I think, I think we've peaked this year with the dollars that need to be spent or collection and compression versus drilling. Go ahead Kevin.

, we've got about $146 million in our gathering system right now.

OK. That's great, thanks.

Again, if anyone would like to ask a question, please press star then the number one on your telephone keypad. You do have question from the line of of A.G. Edwards.

follow up question Mark. After everything that's been said here it has been, you know, brought to my attention in a few situations that people were concerned that things are not working outside of the Raton Basin. We haven't found anything significant either in the coal bed front or in the U.K. at this point. I was just doing some math on the envelope back here on the remaining upside in the Raton based on the remaining locations that you guys have. And I came up with, oh, somewhere between 800 and 900 (Bcf) of upside potential, just want to walk you through that and see if that's, do a check on it, is that a reasonable expectation and what, the way I get to that number is. You know, take the 700 locations that you have left over, subtract the 333 and I get 367. I take that times 1.2 per location, round numbers, that's 440 (Bcf) from the coals, I picked the mid point range on deep conventional 300 (Bcf) and then the mid point on the Raton Sands at 150 and so the precise number I come up with is 890 (Bcf) of reserve potential upside on your existing Raton acreage. Is that a fair number, and if so, could you comment on that.

Well, that number is completely consistent with what we said at the beginning of the year where we said at the beginning of the year we had 1.05 (Tcf) and thought we had another (Tcf) with probable reserve. So if anything, that you've added value in for, the deed, your number could even be light by that based on what we're looking at for the, for the total Raton. I believe that number is a very good estimate, but I also believe it, I believe that number ultimately could end up proving out to be on the light side.

OK. If that were the number, over what time frame could we expect to get those reserves booked?

Well we're going to continue to drill on about the same pace we're drilling now. And it looks like we, each year we've, as we've indicated we've pushed ourselves each year to drill more wells and we'll continue to drill more wells each year and this year our drilling has been so good that we have plenty of room left over to start drilling more exploratory wells. Expect our drilling pace to continue or accelerate from this level but having said that we're going to be drilling for four, five, six, seven years even at these levels that's how long it's going to take to drill all this up based on what we know right now and at the levels we're currently drilling we could go faster but that would cause us to run our debt up and we're not interested in running our debt levels up beyond the points we've indicated we're comfortable.

So there's a nice balance here and still allows for ever increasing acceleration of our drilling and hopefully our production and our reserve growth. Our reserve growth should continue fairly steadily while we're doing all this and drilling wells at these rates expect to see there and we said we expect to finish the year between 1.2 and 1.25 Tcf. That's still a very good estimate and you know that would involve 150 to 200 Bcf per year annual growth net of production and I expect that to continue.

OK thanks.

Thanks .

Your next question comes from the line of of .

Thank you Mark I was hoping you could give us an updated I guess opinion on the potential assets in the Raton Basin. And you've mentioned that as a possibility before and in the past you said you're were waiting until the systems more or less complete to your liking. Sounds like you're close to that and was wondering if we might a sale of that asset going forward.

Well it's closer to the end than it is to the beginning but we saw 150 million in it roughly it's still going to take another 50 million to bring the system to the level we want. I'd like to see the system in place before it makes sense to it out or it although it's always available if you want to do something. We have looked at some of the recent deals that have gone on and at the moment I don't think that's in the best interest of Evergreen shareholders but it's something we're always taking a look at.

If you did sell a gathering system what would be the impact on your in terms of gas realizations relative to what you're getting now.

Well there would obviously be a cost of being passed through and consolidation on our income statement right now.

Right.

That's what you're referring to go ahead Kevin you might want to ...

There could be a slight negative impact to our financial of course would go up because we'd have to pay a gathering fee ...

Exactly.

Our expense would go down because we wouldn't have a gathering system and so would our interest expense. But in the transactions that we've looked at just as a kind of due course of taking and addressing this issue, we really felt that it is going to it would add no monetary impact to Evergreen at this point in time.

Two other really quick questions did the percentage of reserves change appreciably mid year versus year-end and number two Mark based on that 100 to 500 Bcf potential in the deep Raton Basin does that imply 100 to 500 locations, is that your best guess at this point?

That's pretty close and the, we actually were more conservative booking mid-year than we normally do, let's take our end of the year percentage was 38 percent 2001 decrease a slight amount to 32 percent as of 630 so there's a very slightly decrease.

Perfect that's all I had. Thank you.

Your next question comes from the line of

Good morning, just a quick question on the lines of additional opportunities in North America. There is trace of the Thunderball joint ventures announced last week in Canada. Are there additional opportunities out there similar to this, or is this something Evergreen would be interested in pursuing?

Yes and Yes

OK thank you

There are no more questions at this time, are there any closing remarks?

Thank you Michael, yes this is Mark Sexton and I would like to echo some of the comments that were made earlier that the positive results that we have seen with our deeper wells in the Raton. And finally, the economic results we have seen from the UK we will continue to do what is in the best interest to shareholders, and right now that is to continue to develop the Raton coals on a consistent and predictable schedule. Just the growth in reserves and production that you would want to see, that we want to see and we are looking now at finding slowly other projects that will turn into the next Raton basin.

We think we actually have another version of that that we are sitting on and the deeper potential in Raton already and we are starting to look very aggressively at coalbed methane and unconventional projects in North America and start developing those while we have a good time to put those projects together. I see no reason why in terms of reserves and production we won't continue to report record results and prices being what they are make this industry very transparent for investors, not just Evergreen but I think the energy industry in general. We'll probably come out of this market looking very very good from this point because exploration of production companies are very transparent compared to some of these other companies that have had some notorious problems of late.

So thank you all for participating, thank you all for your interest in support of Evergreen and this concludes the second quarter conference call.

Thank you for participating in today's Evergreen resources conference call. This call will be available for replay beginning at 4.0 p.m. Eastern time today through 11.59 p.m. Eastern time on Saturday August 31st. The conference ID number for the replay is 4925768. The number to dial for the replay is 1800 642 1687 or you may dial 706 645 9291. Thank you, you may now disconnect.