先鋒自然資源 (PXD) 2002 Q1 法說會逐字稿

Thank you. Thanks for joining us today for our first quarter 2002 conference call. We appreciate your interest. I'd like to start out by mentioning a couple things, that this call is being broadcast live over the internet and you can get there by visiting our home page, which is WWW.evergreen.com. I also need to mention that we will be discussing or making some forward-looking statements and we're making those under the safe harbor provisions established by the Securities and Exchange Commission and for more detailed information on that, you can review our recent report on Form 10K, filed with the SEC. Also like to mention our annual shareholders meeting will be held this Tuesday, May 7th, at 10 a.m. to be held at the Pinnacle Club located on the 37th floor of the QWEST Building in downtown Denver, 555 17th Street. I'd like to turn it over to Evergreen's president and CEO, Mark Sexton.

Thank you. Kevin Collins prepared a very comprehensive and ever-expanding press release to discuss the quarterly results and Kevin Collins will take us through the highlights of our results for the quarter, which we're real pleased about and we're optimistic about the -- not only the success we're continuing to have in the Raton Basin but what we hope to have in other areas. Kevin Collins, Evergreen's chief financial officer will take us through highlights of results.

As Mark mentioned, we're very pleased with our first quarter results. We reported earnings of 12 cents per diluted share and cash flow before changes in operating assets and liabilities of 44 cents per diluted share. Production for the quarter was approximately 8.828 BCF, which was an average of about the 8.1 million cubic feet a day. Substantially all of this increased on a quarter-to-quarter basis. These results were in line with our guidance previously published of 8.9 to 9.0 BCF for the first quarter. Our current production is approximately 102 to 103 million cubic feet per day. Average net sales for April of 2002 are approximately 3.0 BCF for an average of 101.5 mean cubic feet per day. Guidance for the remainder of 2002 is unchanged. From our estimates we provided on November 1 of '01 and February 28 of '02. On page 5 of the slides on the web that the -- for the quarter ended June 30th, we estimate 9.3 to 9.5 BCF of sales. Q3, 9.9 to 10.2 BCF and Q4 10.6 to 10.8 BCF. Total year-to-date sales then would be 38.6 to 39.3 BCF. We anticipate that our extra rate for 2002 will be approximately 120 million cubic feet per day. This production represents an increase of approximately 25 percent over -- for 2002 over 2001 and is due all to organic growth in our production. Our production guidance for 2003 remains the same as we noted in our 2-28 conference call. Q1 of 2003 will be approximately 10.9 to 11.1 BCF; Q2, 11.2 to 11.6; Q311.6 to 12.2; and Q4, 12.3 to 12.7. Estimated sales then for the year ending December 31, 2003 will be 46 BCF to 47.6 BCF. Our drilling program as we discussed is 152 wells for '02. In Q1, we drilled 50 wells which exceeded our internal goal of 34 wells. In Q2, we plan on drilling 35 wells. This is a decrease from the first quarter due to drilling deeper wells of approximately 4,000 feet as compared to previous depths of about 3,000 feet. Q4 will be 40 wells. Excuse me, Q3 will be 40 wells and Q4 will be 27 wells for a total of 153 wells for '02. As of today we drilled 63 wells year to date. On slide 15, we have a listing of our heaviness in place. As we discussed in our 2-28 conference call, we just entered into a series of swaps for the second quarter of '02 in late February when gas prices were projected to fall substantially during the shorter months of the second quarter and at that time, we were trying to project our capital budgets for '02. For the hedges we entered into for April and June of '02 were approximately 80 million cubic feet per day as an average price of $2.32 and we have an existing physical hedge of approximately 10 million cubic feet a day at an average price of $2.50. Total percent of our gas pit for the second quarter is 87 percent. For the period July through December of '02 we entered into a series of several [inaudible] collars with a floor of $2.59 and a ceiling of $3.87. Total amount hedged per day for those cost of collars was 60 million cubic feet per day. For the analysts in their modeling purposes, if you reduce the amount we mentioned by 3.5 percent, that will give you the approximate amount for fuel usage and then if you take the floor of $2.59, multiply by 3.5 percent, you should reduce the $2.59 by 9 cents. Total percent of gas hedged for Q3 is 63 percent, total percent of gas hedged for Q4 is approximately 60 percent. Only a small portion of our gas for '03 is hedged. We have a small physical hedge and with that in place for a couple of years at $2.50 per MPF this is a -- for 10 million cubic feet per day through 3-31-03 and represents about 2 percent of our estimated '03 production. On page 13 is listed out what we estimate our unit cost to be for the remainder of '02. Our LOE costs we estimate will be 38 to 32 cents per NCF; transportation costs, 30 to 32 cents; production and property taxes depending on what the gas price is is approximately 5.5 to 6 percent, and that would be about 12 cents to 16 cents per NCF. CNA costs, 21 to 25 cents per NCF and interest expense of approximately 22 to 26 per NCF. Total cash cast is $1.23 to $1.41 and [inaudible] expense of 52 to 54 cents per NCF. Our capital expenditures for the year remained unchanged. We anticipate still spending $106 million for the year ending December 31, 2001. Originally, we had talked in the 2-28 conference call about reducing our capital budget of gas prices. Looks like they were going to continue to be at lower levels and possibly be reduced during the year. Based on current gas prices we believe this budget will probably stay intact for the rest of '02. During the first quarter, we spent approximately 35 million -- $35.8 million the breakdown is noted on page 22. We had originally estimated that we would spend 26.8 but [inaudible] accelerated our billing program, we spent a little more than anticipated. We don't see increase in our costs, we are just reallocating those costs that we moved up into the first quarter, so we reallocated the costs as noted on page 22. Long-term debt at quarter end with 198 million in debt as of 5-2-02 we are currently at 209 million, which includes 109 million under our line of credit and a hundred million under our senior convertible note. We are extending our line of credit to July 1 of 2005 and we'll have our new debt agreement completed in the near future. There's no significant changes in terms of the debt agreement and or borrowing base will remain at $200 million. Last week, we filed two shelf registration statements. One was a universal shelf registration statement which provides for the offerings to the public from time to time of debt securities, common or preferred stock in an aggregate amount of up to $300 million. We also filed an acquisition shelf registration statement which would allow the company to issue common stock in connection with acquisitions or other businesses and/or assets. The aggregate amount under that shelf is approximately $50 million. We filed both of these registration statements as we believe this is good corporate finance to have various financing options available to us at this time. Currently we've not identified any projects with which we would need to draw down any funds [inaudible] as of this date. In the press release, I have a condensed balance sheet which does not break out all the current liabilities since liabilities -- current liabilities increased over March 31, 2002, over December 31, 2001. I thought I'd give you a little more information with which to evaluate that. The reason for the large increase in the current liabilities is just due to our accelerated drilling program, the increase in our costs from future periods into the first period. This accounted for about $5 million. We have a derivative liability of about $8 million which are marked to market adjustment for the hedges we have in place and also had accrued interest on our senior note which amounted to $1.2 million. The interest is paid semiannually in June and December. Increasing the current liabilities due to a timing issue. We believe it will still be reduced throughout the year as cash flow increases and our spending decreases throughout 2002. Turn it over to you, Mark.

Thank you, Kevin. We are pleased at the result of the quarter. The first quarter is generally a little difficult for us because of weather-related issues and just gearing up. We've hit our production goals. Costs did not get out of hand as we have been concerned about in prior years in the first quarter. Things are moving forward efficiently in the Raton Basin and no reason not to be optimistic. No reason not to believe that we're easily going to meet our targets for the year in the Raton Basin. As indicated, our exploration wells in the Raton Basin are being tested now and we hope to have results, do a midyear update. I'm guessing that we will probably be able to talk about and quantify the results of that at our next quarter conference call. The same thing is true for the -- five of the six wells we drilled in Ireland and in Northern Ireland. As you're aware, we drilled six wells last year in that area, plugged one of them and found five of them interesting enough to fracture stimulate in this type gas sand play [inaudible]. Moving forward, we're conducting bottom hole pressure and flow back tests as we indicated and we'll be doing build up tests and trying to get the very best information we can on these type tests and wells to determine how many -- how much proven reserves are appropriate to book and how economic this will be going forward. There are a number of faulty sub-basins in this area. We're encouraged by many of the things we're finding but it's a process and a technology play and it's too early to quantify the results, although we hope to be able to do so again on a conference call probably around the first of August. We finally got the UK on track after some problems last year first with truckers strikes then with hoof and mouth disease and then of course the events of September, it's been difficult to get things done in the UK. We have gone back in and have fracture stimulated three wells, drilled near one of the old mines in the [inaudible] area near Liverpool to test coal bed methane concept. We believe we may have as many as a hundred wells to drill in and around mined out areas or what we call mine/gas interaction wells. The concept there was to drill in areas that had -- where fractures had been created by the existence of the mine itself. The concept worked so well that we lost the cement in those wells into the fracture system. We went back and recemented those wells and now we have we believe properly fracture stimulated them and we're testing them and while we're encouraged by the results, we can't yet quantify it. We'll also be trying to drill a couple more wells into the mined out gob areas and there's a different type of production testing going on there. These wells have to be produced on a mild vacuum and we'll be experimenting with different pressures on those wells and different production rates. Overall, given the deep potential of the Raton Basin and our renewed interest in Ireland and our soon-to-be drilled wells in Alaska, we're excited about the potential we have for talking about reserves, proven reserves other than coal bed methane this year. And I think with that, we'll just open it up for questions.

At this time, if you'd like to ask a question, please press 1 on your touchtone phone. If you would like to ask a question, please press the 1 on your touchtone phone and if a question is answered you may withdraw the question.

I wonder if you could comment on the basis differential blowouts that we have seen in the Rockies in the last month or so and if that's affecting your gas price realizations at all.

In a number of the conferences we've told investors that they should be aware of glass price blowouts in the Rockies, because when that happens all the Rocky Mountain producers get pulled off. We're a Rocky Mountain producer, we are a mid continent marketer and all of our gas gets marketed in the mid continent area and our basis differentials are tied to really closer to the panhandle basic differential than anything else. There's the transport and field cost to get there so we're largely unaffected from an operational or revenue point of view by these blowouts on the Rocky Mountain basis differential; however, we noticed the market knee jerk reaction is to sell off the gas-intensive stock in the Rockies. We get sold off and everybody remembers that we don't really market gas in the Rockies and we're not really affected by it so there are certain short-term inefficiencies in the markets I think people are taking note of but one that's a major part of our plan going forward was simply to make sure we had plenty of capacity, pipeline capacity to get gas out of the Rockies. We've given CIG some firm transportation agreements to get them to build and upgrade repeatedly both their [inaudible] wire and [inaudible] laterals out of the Basin into the mid continent market. That strategy worked very well and we still have several years of excess capacity left in the pipeline before we even have to revisit the conversation with Colorado Interstate Gas, although I will say they have been and continue to be a very responsive transporter of the gas and have been very proactive in looking forward to think of future expansions for the out earn ends of their system that would benefit Raton Basin production and producers. We have been happy to be the lead in underwriting a lot of these expansions through our firm [inaudible] commitment which by the way we're way ahead of.

Thank you.

Thank you, Chris.

Now go to Ellen Hannan with [inaudible]. Go ahead.

Good afternoon.

Couple questions. One is, Mark, can you talk about the timing of when you're going to [inaudible] the wells in Alaska and are you planning to ship equipment from either Ireland or the UK to do that?

It depends on what we decide to do in Ireland. At the moment we are planning to bring the equipment back from the UK and send it over to Alaska. If it needs to be -- if there needs to be any refurbishing we may bring it in for a little shop work before shipping it over, but the plan at the moment is still get the equipment there by August and try to be drilling by the end of August and probably no later than September. We just applied for permits on three different pilot areas in the pioneer unit and we are going to -- on the basis of those permits will affect which wells get drilled first and whether we drill six or eight or ten wells as planned. We're also planning to do a little exploratory work on other acreage in and around that area and north of that based on some commitments we've made to the Alaska Division of Natural Resources. There won't be production tests. We're going to do some core tests and we're going to look at some other type gas or coal bed methane, certainly unconventional gas plays in other parts of Alaska where we have the opportunity to get the gas to market so we're not only looking at the pioneer unit, also looking at other projects we can be doing in Alaska. The equipment is going to be sent there, will be on track. We're negotiating now to decide whether we send our own drilling rig up there or one of the rigs that we leased in the Basin that's been very effective at drilling wells for us in the Raton Basin so everything's pretty much on track there. Hopefully the equipment will be in good shape, we won't have to refurbish it and we can just send it right to Alaska. There might be an interim stop before it goes but the plan is still in place.

Alaska's a fourth-quarter event, essentially.

Well, yes, in that we probably will start drilling before the end of the fourth quarter but won't have much to talk about until the first quarter.

And just a quick question on your cash flow statement. Your text mentions 35.8 million in cap [inaudible] and the [inaudible] says 28.5.

That's purely a cash issue. From the 28.5 on the cash flow statement is the cash flow expense being 35.8 would include amounts that were accrued for and not paid.

Very good thank you very much.

Thank you.

To [inaudible] with RVC Capital Markets. Go ahead.

Good afternoon.

Good afternoon. We're curious as to what your question is do we have a technical difficulty? We seem to have lost that.

Mr. [Almond's] line is open.

Is that better?

Thank you.

The -- in the Raton Basin, the additional drilling, is it any different than what you -- when you previously drilled in terms of reserves per well or production per well?

Yeah, the future coal bed methane. I know you're going to be drilling in the Raton formation more but in terms of in-field drilling or extensions, will they be any different in terms of reserves and production for a well?

Yes, the answer is they will be different. The in-field wells are showing higher initial rates as expected. We modeled them as lower reserves. We think the in-field wells are more likely to produce around an incremental BCF rather than the 1.2 to 1.5 BCF we have been seeing in other parts of the Basin in the Vermejo coal. Extension to the Vermejo coal drilling should be as they have been historically. The Vermejo is fairly ubiquitous throughout the Basin but we -- as we starting to drill the edges, we're starting to see a little more variability. Some of it's good, some of it's not as good. The really encouraging -- in addition to the encouraging results we're getting from the in field drilling program, the Raton coal wells in the Basin are also very encouraging, especially the deeper areas where the Raton has -- it has quite a bit of thickness and enough depth to have enough pressure to have enough entrained gas in place. We have been sort of signaling to the market that those wells could be about .9, maybe 1 BCF, and it certainly looks like on average they'll be at least that. I actually expect they will be better. Although we don't have a large enough statistical data base of new Raton wells yet to project a higher number at this time. Everything is fairly much on track with what we have been saying. There has been a little fall off in the recoverable reserves per well over time, but not enough to deter from continuing to drill aggressively in both the Vermejo extension and the Vermejo in-field. In the Raton wells continue to look encouraging as well, so, you know, we -- what does all that mean? Means we're about halfway through our drilling program.

So I mean based on what you know now, I mean, do you think -- how much time do you think you still have in terms of how much inventory do you have in terms of time?

Probably five or six years of drilling.

Okay.

Depending on how fast we drill but we're primarily drilling about 150 wells a year so five years would be another 750 wells.

Okay. Thank you.

If you would like to ask a question, please press 1 on your touchtone phone. Question from John [inaudible] from Wachovia Securities.

Hi Mark. In terms of the deep, deep, deep, deep [inaudible] drilling, any sort of idea what the economics would require in terms of reserves and production rates? And also, are there any infrastructure needs to handle gas production from the deeper.

The good thing about the infrastructure, whether we're talking about shallow Raton coals or deeper type -- type gas or type shale drilling is that the infrastructure is largely in place. There will be some areas because of the geologic differences where the coals won't be so good and the deep are potential is likely to be better and vice versa. We have a very large, very extensive infrastructure system and plenty of pipelines take away capacity in the Basin in the areas we're likely to be drilling, so we're getting great operational leverage off of the deeper drilling or at least we expect to. And we expect that all of those well pads in place and there will be well over a thousand well pads out there will all be prospective locations for us to consider putting a deeper well with the road and location and gathering already in place. So we're going to [inaudible] nice operating leverage, which it probably will not need even one BCF per well in order to justify a very aggressive deeper drilling program but we'll find out when we can quantify the results of our drilling, we'll provide a little more guidance on that. The nice thing about the deeper wells is that they'll behave like tight gas sand or tight shale wells with high initial production rates and higher initial rates of return than we see from coal bed methane wells. They shouldn't require as much in terms of recoverable reserves in order to be attractive to drill economically.

One more. Any [inaudible] for acquisitions property-wise in the Raton?

Always. Got some properties you want to sell us?

We are still looking at properties not only in the Raton Basin but, as we've indicated, we're looking at unconventional gas sites throughout NOrth America and Europe, particularly North America, particularly coal bed methane, and we have some ideas and as we've indicated before, when we get -- when we're fortunate enough to do a deal or get a couple hundred thousand acres in the right area, we'll be prepared to talk about it more but we're still very receptive to adding prospects like that.

Thanks.

Thank you.

inaudible] with Nicholas.

Good afternoon. Mark, you had a lot of success at the end of the year with your in-field drilling program I think you said in December, and correct me on these numbers -- I'm sure you will, but I think you said something along the lines of 8 percent of coal production was in-field drilling related at the end of the year.

I think it was probably -- well, it was. We were getting results, we were getting results from the in field wells and the estimates were about 8 percent there and a little higher for the Raton well.

It's about the same at the moment because we've actually been more aggressively drilling other wells. The in-field wells, where they have reserves they don't tend to add per layer as much reserves as extension drilling. We still have quite a few extension wells left to drill. We put a rather large infrastructure in place and adding our 8th compressor station as we speak and that will be tied in in operation before we have our next conference call, so we're -- we're seeing -- we're seeing what we want to see but in order to get the most benefit from the rather large accelerated infrastructure, big pipe and other compressor stations that we have been putting in place, we need to be extending the limits of the field, not just resting on our laurels for incremental results, though, we have been more aggressively refracturing, restimulating and recompleting wells that we've acquired and wells that we drilled and completed early on with improvements in our own frag program and taking advantage of things we learned, the new equipment that we have. I think that a lot of the -- a lot of the nice production increases we're seeing were actually results of better attention to detail and more tender loving care to the older wells. In fact, the -- we have ordered another coal tubing unit and it is dedicated specifically to the restimulation and recompletion of older wells that we've drilled or that other people have drilled. That's how well the program's working and we felt it was worth the investment and even more stimulation equipment to -- so that's where we're getting the best bang for the buck in terms of production versus capital spent where as we're getting the most bang for the buck in reserve increases on the extension drilling so we're trying to balance both of those.

And now we had a question. The Interior Department ruling concerning the marathon leases. Any comment on that?

That doesn't affect us in the Raton Basin at all.

But just as far as the Rockies in general, what's your take as far as the whole region goes?

I'd like to step back one point further and say since the environmentalists have been successful in delaying ANWAR and development there, they've now turned their attention full force to the Rockies and we can expect the Rocky Mountain areas, particularly the areas that are restricted right now, to be the biggest battleground between the development and the antidevelopment forces going forward. Interestingly enough, they are picking on natural gas, unconventional gas and conventional gas, picking on natural gas rather than oil, which strikes me as odd since by all accounts, conservation will not get us to where we want to be as a country. Our appetite for natural gas will increase from 23 TCF a year to at least 30 TCF. I just don't know if it's by 2010, 2020 or the year 2030. So with all this going on, unless people wants to open this up and see and encourage natural gas drilling, there's not going to be enough gas and $10 in NCF is going to look cheap to these people a few years from now if they continue. What is interesting at the same time is in the latest -- in the Senate tax bill which encourages unconventional energy development including clean coal technology there is a reinitiation of the section 29 tax credit. We'll see if that survives, but I say there's plenty of coal bed methane drilling going on and we don't really need to encourage coal bed methane drilling. Companies like Evergreen are doing it quite niecely on their own but the reality is we do. If you want stability and security in the national energy supply and less volatility in natural gas prices, what better than an annuity-type production such as coal bed methane? So coal bed methane has gone from being is zero percent of the US proven reserves 20 years ago to being 10 percent of proven US natural gas reserves. And if the country is smart, as part of its energy policy, it will encourage it to go to 20 to 30 percent if we really wants a stable, long-term energy supply so that's my take on all of that and that's just -- it's a marathon situation, June of many battles that will be fought. The Rockies will be the battle grounds and ironically natural gas is, which is what we should be encouraging now.

Appreciate it.

Thank you.

Howard [inaudible] with Raymond James. Please go ahead.

Hi, Mark, this is Wayne Andrews here. Quick question. I want to find out what is your current inventory of drilled wells that are waiting on hookup? I know you're very active here in the first quarter and is that higher or lower than your normal inventory?

Thank you. It's been over 50 wells and that's what we have been running for the last year or so. That's just extended drilling rate at our 150 wells a year, we're always lagging by about 50, 60 wells that are waiting on some stage of fracture stimulation or pipeline hookup. A little review of the process. The wells are actually drilled fairly quickly once the location is built, the wells are drilled in less than two days, the rig's in and out. The fracture stimulation operation with our new equipment is also a one or two day process. It's really getting the right [inaudible] in the pipeline hooked up that are the critical path.

Thank you very much.

Thank you, Wayne.

We're going to Pierre Conner with [inaudible].

Good afternoon, guys. First a comment, Mark. Anytime an E and P company talks about gas blowout, it makes me nervous. But I wanted to ask you Mark may have missed it, was there anything about the central tax credits in the UK relative to utilizing gas for power generation that would impact your activity there.

It's been discussed. It's not officially [inaudible] there's an emerging idea that from zero emissions credits which would include gas from gob wells, there's some conversation on either tax credits or -- or modification to the tax system to encourage that. That's -- that is in play. I don't know what the final outcome will be but it looks very encouraging and it might be extended to coal bed methane should coal bed methane ever be proven to be economic in the UK and should we have the patience to keep screwing around with salamander and newt studies and everything else that's come into the operation over there.

So it's not as you say enacted but there's the possibility of something that may be beneficial to you.

Being actively discussed especially at that use to generate power.

Along those lines maybe a question for Kevin. Are there any requirements to test your [inaudible] costs in UK or Ireland at the end of the year and make any decisions on development or not or is it basically up to you to decide if we're still continuing to get those [inaudible] costs?

As far as I know, there is no requirement.

Okay. So it's really our decision? And Mark, do you feel -- you mentioned you could get some results coming forward. Is it something you feel the end of the year is a cutoff time for you, or it depends on the results as you go?

Depends on results as we go but we have openly asked ourselves the question and discussed openly that are we really even -- even if the UK is technically successful for CBN development are we really the best company to be doing it? And should we be spinning off those assets to another entity to run the [inaudible] or run what's already there with the idea of monetizing the value for Evergreen Resources' shareholders. We thought about it but we think it's premature to move too quickly since we believe we will have some measure of technical success, I just don't know what yet, we thought we'd get the results and know more about specifically what we're talking about and what vehicles are open to us on the basis of that information.

Make the decision then, great. Thank you very good. I appreciate all insight. Thanks guys.

Thanks, Pierre.

Question from Bill Miller with Hartwell.

Hey Mark. Curious about the acreage out in the west. Outside of the 25, what kind of sequential acreage is there that acquiring? Is that an active area of it for you? I mean, 20, 30, 40,000 acres or can you quantify it in any way for us?

I'm not sure I understood the question. We're always looking to lease more acreage even in and around the units that we have. There was a little hiccup as you were asking the questions. More specifically, what are you referring to?

Well, just the fact that you chose these five exploratory wells going down deeper than you normally do in various parts and it looked as though you were making an effort to put them out in what I guess I need to reference I25? Is that the route?

I understand the question now, Bill, and the fact is that for the deeper formations, what we think of as the outcrop of the Raton Basin is really limited as the Trinidad sandstone contact, and that's what you see when you drive south on I25 and the nice escarpment you're really seeing the coal and the Trinidad sandstone outcrops. But the Dakota and the Niber and some of the other formations of interest don't outcrop, they subcrop and the Basin is much larger larger when you look at it from their perspective. It's always interesting to test the edge of the Basin, and that's what we did with three of the deep wells. Two of the wells were drilled actually right in the -- in the purgatory valley area so two were drilled in a place we're already comfortable with and three were purely reaching out to test the limits of the Basin.

Okay.

It's highly likely that the areas that are the best for coal bed methane may or may not be the best for other forms of unconventional gas because the other forms of unconventional gas will be more controlled by structural and stratographic considerations than the Vermejo coals have been which are fairly ubiquitous throughout our acreage position in the Basin. Thanks for the question.

That's it.

Last question comes from Greg McMichael with AC Edwards. Please go ahead.

I want to tell you nice quarter, by the way.

Thank you.

Thanks for beating our estimates, quarter after quarter. It makes it easier. I want to talk about Ireland's for a second, Mark. Specifically, you know, the timing of when you think information will be available. As you mentioned earlier, tight gas sands plays typically start out at really high rates of production and the lead time between drilling and fracture stimulation is not typically that great, at least in the US. I was wondering if you could help us understand the amount of time that's required here to get some idea of where we are with that project.

You bet. It's a brand new play with a brand new Basin. We have gone in and applied a different form of fracture stimulation than is typically tried and we just want to build these wells up and get the very best build up we can and separate us so when we release the information, it's as accurate as possible. Typically, you know, to do a -- for tight gas sand, 30 days is not un reasonable for buildout, but then we want to flow the wells for a while, another 30 days or so and then do another 30-day build up and make sure when we come out with reserves here, we got the very best possible number. So we have been estimating. You have to just keep in mind that it's easy to get things done in the US and the most trivial thing that we're doing over there when there's no infrastructure just takes more time. There's nothing wrong with it, it's just that there's no real infrastructure to depend on like there is here, so we're not trying to push it, you know, we're -- our production test has been, you know -- even if -- to quantify the results, even if we're successful, we're probably talking about looking reserves that are on the order of 1 percent of our proven reserves if we [inaudible] 10 BCF over there. So while it's a priority for us, it's not as active a priority because there's no immediate production associated with it. And the decision to drill more wells will probably be made to continue to drill more wells just based on the encouragement we've seen so far. I would like to be able to quantify the results before we look at all of our options over there. There's huge interest in on-shore Irish natural gas reserves because the country needs it so much. There are landowners and end users in the area, people with cement plants and glass factories, the desire for additional power generations. There are proposed pipelines spanning the country to link the current field up the northwest coast to the gas supplies that are coming on from Scotland and from the Kinsale head field to the south of Ireland. Ireland needs gas, needs power, and we just want to make sure that if we're going to kick this thing into high gear that we, you know -- if anything, we've over studied it. And that's what we're going to do and the timing of that would be -- the other wells that will be -- we're in the process of completing and testing in the Raton Basin, you know, just makes sense to do a midyear reserve update and it will probably be effective as of July 1 but, you know, we probably would be putting out the results late July or early August or about the time we have another conference call. So if it seems like we're taking a long time we are because we don't want to hype the significance of these plays. We're excited about the upside potential but we don't want to release numbers prematurely and then lose credibility that we feel we've worked for years to establish with the financial community and the analysts.

It sounds like you have natural gas or at least you've identified some natural gas in the play but it's not necessarily been determined that it's commercial at this point and that you just need more time based upon the explanation you just gave us.

Well, we may be a little over-sensitive in these post-Enron days but we already released -- [inaudible] works, it has as much as [inaudible] as upside potential, so I don't know how I could -- I don't know how I could be more optimistic than that in quantifying it. But we know today a little more than we knew before we started drilling. We know there's already gas in the sands there. There's two very nice -- there's two objectives, the original [Mossmore] stand and we found some encouragement in lower [inaudible] sandstone but I just can't quantify it yet. Before we release the [inaudible] we want to make sure we do. We want to make sure we have done all the tests we possibly can. It's not an area that anyone is active and it's not an area that -- it's a little outside our normal expertise. We're very good at predicting coal bed methane reserves but I don't want to jump the gun on predicting type sand or type [inaudible] reserves. You're right, normally it's faster in the US. Again, even the simplest things take longer in the UK and Ireland just because we have to bring all the equipment in and bring the people in and just can't call a service company and say go test this, you have to do it yourself and logistics are -- we're just not Exxon and not going to drill 200 wells before we know a lot more about it.

Okay. Thanks very much.

Another way of answering your question is we know there's gas in the sands but actually we knew that before we drilled the well so before we quantify it we just want to make certain because the signal that we'll be sending is that is economic or not economic, but it's always encouraging to start in a place where you know there's hydrocarbons in the reservoir.

So you think that signal can be given by the end of July?

Yes.

Okay. Thank you.

Thank you, Greg.

There are no further questions at this time.

Thank you all very much. Normally first quarter is -- if you look at the history, been a little difficult for us, but with our accelerated program and the very good people we have in place and the attention to detail that's been going on, as Greg indicated, we've been able to beat most estimates for the quarter or come right in line with them and we expect as we indicated in our press release that quarter to quarter, we'll continue to post improvements in all the categories you would like to see us posting improvements. Thank you very much. This concludes the first quarter conference call.