先鋒自然資源 (PXD) 2002 Q3 法說會逐字稿

Good afternoon. My name is Jeff and I will be your conference facilitator today. I would like to welcome everyone to the Evergreen Resources third quarter earnings conference call. All lines have been placed on mute to prevent background noise. After the speakers' remarks there will be a question-and-answer session. If you would like to ask a question, simply press star and the number one on your telephone keypad. If you would like to withdraw the question, press the pound key. Thank you. You may begin your conference.

Thanks, Jeff and thanks for joining us for the third quarter conference call. I would like to mention this call is being broadcast on the Internet with accompanying slideshow. To view the webcast go to evergreengas.com. Over the next hour, Evergreen management will be discussing our third quarter operating financial results and in doing so, some forward-looking statements will be made. I would refer everyone to our most recent 10-K filed with the Securities and Exchange Commission, for more details on that. Kevin and Mark will recap third quarter and then we will try to leave as much time as possible for Q and A after that. So, with that, over to our Chief Financial Officer, Kevin Collins.

Thank you, John. We are pleased with our financial and operating performance for the third quarter ending September 30, 2002, from continuing operations. For the quarter we reported net loss of $15 million or 79 cents per diluted share. If you look on the slide on the webcast, slide three and four. We use basic shares outstanding to calculate the loss per share for the three months ended September 30 as use of diluted would have been antidiluted for loss of share calculation.

Turn to slide five, we have a reconciliation of the impairment charge net of tax of $22 million added back to the loss, which would have shown a $7 million profit from continuing operations or 36 cent per diluted share earnings. That compares with 37 cents from the same period in 2001. On slide eight, we have the cash flow per diluted share calculation for the three months. Cash flow from operations -- before operating liabilities was 89 cents per diluted share. This compares with last year's cash flow from operations of about $1.06, before an adjustment for commodity swap proceed we feel should have been excluded from the cash flow per share calculation as it was SFAS 142 133 adjustment. Last year would have been 79 cents compared to this year's 89 cents. In our press release, we had a small clerical error.

If you will turn to slide 11, we had included the cash flow from operations for the nine months and calculated it as being 36.1 million. It should actually be 36.5 million, which was the same information included in the text part of the press release. If you will turn to slide 12, production for the quarter was approximately 10.192 BCF, which equated to daily production of 110.8 million cubic feet a day. This is on the higher end of our guidance we provided for in the previous quarter of 9.9 to 10.2 BCF. Our October 2002 net sales are estimated to be about 3.5 BCF for the month or daily volume of 13 million cubic feet. Production guidance for the fourth quarter of 2002 is unchanged from previous estimates. We have not changed our production guidance for '02, since we gave our guidance back on November 1st, of 2001.

Our production guidance for Q4 is still at 10.6 to 10.8 BCF. Turn to slide 14. Our production for the year will be between 39.1 to 39.3 BCF. Our exit rate for 2002 is estimated to be 120 million cubic feet per day. This increase for 2002 over 2001 represents about 27 percent increase and this is organic growth. Our preliminary production guidance for 2003 remains unchanged from previous conference calls. It is currently based on a drilling prom. Our Q1 production is estimated at 10.9 to 11.1 BCF. Q2 is 11.2 to 11.6 BCF. Q3 is 11.6 to 12.2 BCF. Q4 is 12.3 to 12.7 BCF. Total estimated for 2003 will be 46 to 47.6 BCF. We will have a conference call in the first half of December to provide additional details for guidance for 2002 financial and operating projections. We will get out a press release before the conference call starts in December.

We originally planned to drill 152 wells and have drilled 151 plus three water disposal wells. The increase to the drilling program will be to 161 to 162 wells for 2002. On slide 15, note the hedges for the remainder of 2002. Our 2003 hedges and also our 2004 hedges. Currently we have estimated our October gas price to be $3.16 net to Evergreen per MCF. On slide 19, unit operating cost remain -- we haven't changed those much in the last -- for the last quarter. We still believe that LOE in 40 to 42 cents, transportation costs 30 to 32, property taxes 16 to 19 cents per MCF. G&A 20 to 22 cost. Interest expense 20 to 22 cents. D&A will be 54 to 55 cents for the fourth quarter.

On slide 20, we have outlined our capital expenditures for the first three quarters and also the estimate for the fourth quarter. As I mentioned in our last conference call in August, we were unsure whether we would increase capital expenditures for the additional drilling. Based on where we are today, we will have to increase capex for '02 to approximately $113 million for the year. The changes are due in part to drilling and completion. We increased it from 36.6 million to 40.1 million, increase of 3.5 million due to additional drilling that we had anticipated for the rest of the year. Collection and compression increased from 31.2 to 35 million or increase of 3.8 million, just due to additional lateral hook-ups. Pipeline well service equipment will decrease from 9.8 to 8.4, reduction of 1.4 million.

Other costs will increase from 10.3 or an increase of 9 million, due to recompilations in the field. The expiration product in U.K. and Ireland increased to 12.3 for total of 2.7. Domestic expiration has gone from 8.6 to 6 million, decrease of 2.6. The decrease is due to the completion of the wells in Alaska that probably be completed in '03 versus the remainder of '02. We estimate capital expenditures for 2003 to be at about 90 to $100 million. We will have a more definitive capex number when we give guidance call in December.

Long-term debt totaled $233 million at September 30. Currently as of today, long-term debt is 244 million. Based on the guidance for capital cost and production we estimate future and estimated future gas prices, we estimate long-term debt will be 230 to 235 million by end of the year. Turn to slide 22. We did an internal reserve calculation to determine where we were at on September 30. We had an audit done of reserves on June 30th. We were 1.13 of TCF of gas reserves. As of September 30, internal numbers show we have approximately 1.2 TCF of gas reserves. That is a six percent increase over June and 14 percent increase over 12/31/2001. Our estimated year-end reserves are estimated to be about 1.225 to 1.235 TCF, which is ahead of our previous indication of what reserves might be at end of 2002. Mark, over to you.

Thank you, Kevin. Well, as Kevin indicated, production is up. We have already met effectively our goals of the number of wells we expected to drill this year. We have increased that. So, we are going from -- have drilled 151 wells in the Raton Basin and expect to finish with 160 wells. We are right on track there. As Kevin indicated we finished higher end of the estimate for third quarter on the production. Net sales are currently running 113 million today compared to 111 in third quarter. We have over 800 wells producing now, compare to 646 wells a year ago.

We have indicated that we think the future of the company is going to be focused in three different areas. The deeper Raton, plays like Alaska and other projects we are developing at the moment. We think as we have indicated, that we are finally going to get the economies of scale from capital spending on infrastructure in the Raton Basin and that is one of the reasons why with our expanded drilling program for next year, cash flow will exceed our projected capital needs for organic development. Testing results on the five of the deeper exploratory wells in the Raton Basin are encouraging. We have drilled them, are cracking them and testing them now. We hope to book reserves on them at the end of the year and talk about how we will drill the deeper wells next year.

At the moment, it is same encouragement we indicated earlier, except we have a few well bores down. They look about as we expected. Which means to look for us to start drilling more and more of the deeper wells next year, as well as experimenting with more of the shallow Raton wells and shallower Raton sand wells, as well as Raton coal wells. Even though we are talking about deeper wells, FYI (ph), these are unconventional type sand, stones, drilled to total depth between 4 and 7000 feet. Mention that this continually comes up. Take away capacity from the basin will exceed basin production for the next several years, even with the projected growth.

In Alaska, we attributed continuous drilling operations on Monday this week and we're down about 3000 feet on the first well. We had Tded (ph) at that point, except we got a pleasant announcement -- not announcement, but approval from the Alaska regulatory authorities we will be allowed to drill the well deeper. We are going to take it down to about roughly 37 or 3800 feet, the length of the drill pipe on that rig. We found about the amount of coal we thought we would get. You have been hearing me say we are at average coal thickness in the Raton Basin and typically a number like 28 feet. We expect coals in Alaska to be in the Pioneer unit, around 100 feet of total thickness. So far, we have 94 feet of net coal through the first 3000 feet and expect to pick up some more as we go a little bit deeper.

Drilling operations are going fine. We have all eight of the pilot wells ready to -- the roads are built, the conductor is set and we are just drilling continuously and it looks like it will take about three or four days per well. We will be done in about a month. And have logged the wells. It is not clear how soon we will fracture stimulate the well. That is partly the function of the weather in Alaska. We would like to go in as soon as possible and fracture stimulate one of the pilots and learn everything we can about it. That will probably be done after the first of the year. Depending on how well it goes and weather, we will probably follow up and fracture stimulate the second pilot in the spring.

So, hopefully we will have some quantifiable results by mid-year next year on the Alaska play. And as we indicated, we are looking aggressively at other projects and prospects in North America for coal bed methane and other forms of unconventional type gas and type shells. We are looking throughout North America, both at companies and acquiring acreage, as we speak. When we get to the point where we can talk specifically about those, we of course, will. I will also mention before we open up to questions that we -- as we indicated, we felt European prospects and Falkland Islands, Chile, the U.K. and Irish drilling projects were probably not the future of the company. We've taken impairment and elected to spend those out. I will say that so far people are showing keen interest toward those projects because I think people recognize that while we didn't hit the grand slam homerun that we had hoped to on the first pass, there is value there and there are people who are willing to work with it and look at what makes a proper business model for each of the opportunities. With that, Jeff, we will open up for questions.

At this time, I would like to remind everyone in order to ask a question, press star and one on your telephone keypad. We will pause for a moment to compile the Q and A roster. Your first question comes from Greg McMichael with A.G. Edwards.

Hi, Mark. Question on the reserve numbers

you reported as of September. Did that not include deeper Raton reserves?

There was very little in that number. There was already couple BCF previously and we have not -- that number has not been adjusted for additional deep reserves.

Okay. That was my question. You had some in the number, right?

Couple BCF.

You said you are hopeful that you could book additional reserves from -- would that be five more wells or how many do you think by year-end?

Depends how many wells we drill. We will try to book between 5 and 10 wells, we are guessing. We will have reserves associated with them at the end of the year.

Okay. In terms of what you booked previously, was that in the neighborhood of BCF per location?

Yes, roughly.

Okay.

Even with success in the deep, it is still very small portion of our total. It just signals it is working and that it will be an economic adjunct to our CBM drilling program.

Okay. Mark, in terms of the coal bed methane production, forgetting about what you might get in the deep Raton, but all coal beds, where do you think production on your properties peaks? At what level? And when would we expect that to occur?

Uh, as long as we are drilling production will continue to incline. Looks to us like we have about 4 to 6 years of drilling ahead of us. Realistically, these are rough numbers, the number of producing wells we hope to double. The amount of total production, we hope will double and the amount of proven reserves we hope will roughly double. That will occur over the next 5 or 6 years.

Okay. So, we could see --

That's our internal outlook for what we hope and expect to see happen.

We could see 200 million per day?

Yes.

Okay. With regard to Alaska, could you just address the market for the gas in Alaska? I know it is Anchorage. In terms of how many incremental gas can be put into the market and are we competing with gas coming on in the cook inlet? If so, is that something we should be concerned about?

Good question. The answer, of course is it depends. The fields are declining and have been declining for sometime. Some companies have been announcing new discovers in the inlets. A lot of discoveries getting the most attention in the Cooke inlet, which is the source for supply in Alaska and surrounding areas. A lot of discoveries are oil, rather than gas. The gas discoveries are more extensions than large development. There are rumors of big gas fields to be discover [SKP-D] have been for the last 20 years.

We have been advised were we able to put 20 million a day into the pipeline that runs through the unit, that the local distribution company would be quite happy to take it and I am guessing longer term market prices will be based on how fast the industrial development is allowed to gear up. It is little expansion going on to the industrial base dependent on natural gas, while people are openly worried about where are they going to get gas in 3 to 5 years. So, looks to us like a long-term price in Alaska is going to be in 3 to 350 range. Some gas sales over $4. There could be some under $3. I am guessing 3 to 3.50 is about right for this area and this market based on what we know going on now, Greg.

Mark, if you are successful in Alaska with drilling in terms of deliverability (ph)and reserve and so forth, what is realistic timeframe to expect volumes to go into the pipeline and actually be sold?

Well, as we indicated, cracking the wells first and second quarter next year, with encouragement at all will be getting the wells hooked up and sales into the pipeline by the second half of next year and will be drilling more wells there. So, you will start to see some sales by end of next year and then just a question of how fast we ramp up and how prudently we can ramp up based on the regulatory environment there. I will say that we have spent a lot of time working with the administration and the legislature in Alaska to improve the regulatory environment. It was obvious to us that rules and regulations and practices made very good sense for deep drills drilled directionally in the north slope that set of rules and regulations made little sense for coal bed methane drilling program in the Masnuska (ph) River Valley Area.

The Alaskans recognize that and are trying to work with us. No one wants to make a mistake. There is one reason why the drilling program was delayed about 6 weeks. We spent a little extra time setting conductor casing and doing other things necessary to make sure we were going to do it right and get it done the first time and get it done with proper regulatory approval. We don't want to step on toes, but want to encourage positive relationship we have with the Alaska regulatory agencies. We hope that will continue. We are -- one good example of that was their consent to let us go ahead and drill deeper today, which is -- we had T Ded that well this morning. With them allowing us to drill another 7 or 800 feet, we will td it before tonight.

That was good example of their willingness to cooperate. We think they recognize how important incremental gas supply is for the area and recognize as they have been through the Raton Basin and seen our operations, we are going to do it right. So, right now, it is hard not to be excited about the upside. The markets there, the geologic information has been confirmed with our own drilling of the wells. We haven't been able to do petrophysical (ph) analysis yet. It is too early. The market is there. The regulatory environment is paying attention to what is needed and Alaska is very cooperative and trying to encourage this type of low-impact natural gas development. I hope I answered the question, Greg.

You did. Thanks again and congratulations on a great quarter and thanks for beating our estimates.

Next question comes from Barry Sahgal with Brean Murray & Company.

Question in regard to your water disposal cost on per unit basis. Can you break that out for us?

Our water disposal cost on unit basis are down to about 3 -- let me get that for you real quick. Give me a second to get that. If you have another question, I will have that in a second. Maybe Mark can comment on G&A expenses. Are you getting the benefit of economy of scale and why wasn't G&A expenses breaking to upper unit level?

Barry, I would like to answer that one. We are trying to get economies of scale. As we keep growing and seeing additional needs where we have to fill in spots to just deal with the issues we have to deal with these days, with the Sarbanes-Oxley Act (ph)and the New York Stock Exchange accountability and listing standard, we are evaluating what kind of costs will be added because of compliance to those. As part of those, we will add internal audit groups and additional accountants we need to hire. So, there is I don't think a lot of people realize the impact of what it will cost company to comply with new standards. We are doing everything we can to keep costs down, still something where we may see increases in the future.

Barry, we share your optimism that we ought to be able to do this and are looking at ways to do it. If the Alaska project takes off the way we hope it will, that will be available to us with the so much of the technical operations and technical expertise already here in the company. Go ahead on the cost.

Water hauling costs are now down to 2.4 cents, which is down from 4.6 cents from last year. What we have done is expanded our water hauling capabilities and added new disposal wells. We increased number of locations to discharge water. So, we have been efficient in water management practices and because of what the group has been able to do in the field, we have been able to decrease that significantly. We also added water gathering system to reduce cost. So, we are doing everything we can to keep the costs down.

Great quarter. Thank you, gentlemen.

Your next question comes from David Tameron with Stifel Nicolaus.

Congratulations on a great quarter. Couple of quick questions. Most have been answered, but one question about debt to cap. You are in the low 40s, like you mentioned. Where do you see yourself being comfortable? You mentioned next year you expect cash flow to exceed capex, so, that is the first question. Second question, see if I can probe a little more, Mark, we do this every quarter. Trying to get a better feel for what you are looking at as far as expanding your asset base. Obviously your first preference is methane, but how do you feel about going into unconventional areas you haven't been before as far as applying your expertise?

I will try to address both questions. I will start with the last one. We have found we have a good well service company. We do a good job in the Raton Basin. There are other good quality service companies that may be better at fracture stimulating coal bed methane wells around the world. I believe nobody is better at well surfaces than we are in the Raton Basin. Because of that focus, we would like the opportunity to apply that focus to other areas. We are looking at -- as we are signaling with our greater focus on the deep Raton Basin, we will be paying more attention to tight gas, tight gas, tight shell, stones. We are looking at unconventional gas just about anywhere in North America.

We are not afraid to go to Alaska as long as the markets are there. Of course, we are also interested in keeping on top of what is going on in Canada. We think it makes sense for us to have a major presence there as coal bed methane starts to development in the Canadian sedimentary basin. We don't want to do it on our own. We would like to go on with a Canadian partner that knows how to get things done in Canada. We have the proper equipment, expertise, and capital necessary to kick off a program there and could help someone in Canada accelerate their own program. There is a big land grab in Canada and we will see how it shakes out. We are looking for partners there and other prospects. We are leasing in other parts of the U.S. and will continue to do so. When we feel we've consolidated that, we're looking forward to talking about it. It will probably be next year, based on how rapidly it is coming together.

We have been offered a number of opportunities and reserved a few other opportunities for getting involved in unconventional gas in other basins in the U.S.. It makes sense for us to do so. The biggest concern is anything we do, we want it to be accretive (ph). Not only the net asset value, but production, reserves, earnings, cash flow and we're going to really look carefully at those deals. What we won't do, one thing holding up the development is our self-imposed reluctance to run up debt. -- So, that debt to cap calculation makes perfect sense for those companies. Look at Evergreen, net asset value of in ground assets is twice what book asset value is. If you look at value, debt to value, it's less than 20 percent, probably 19 percent. So, it is really not a high number.

What we pay particular attention to in borrowings and have indicated this before, but we thought we should remind ourselves. Let's make sure we keep borrowings to less than three years projected cash flow. We don't see how we can get in trouble with these assets and this sort of company, especially when money is going into the ground. That is the thing we look at the most, is not debt to cap because it is misleading for Evergreen because we have been so successful in turning book assets into greater net value. We pay particular attention to cash flow and we're going to adhere to that discipline. If borrowings at the end of this year, including the 100 million of convertible debt will be about 230 to 235 million dollars roughly, Kevin?

Correct.

About 100 million will convert in four years, anyway. While it is debt, we treat it as debt. That means that we have already signaled that free cash flow will be at these prices, looks like in excess of $100 million next year. So, we're really not coming anywhere close to that. We are borrowing and using debt and using it prudently and not getting wild and crazy about it.

Okay. Thank you very much.

Your next question comes from John Wolff with Wachovia Securities.

Hi, guys. Just thinking about your GAAP and net asset value seeming to be growing as three and five-year future surges. Markets are not paying $4 gas for your stock. Since you are more play on growth than the commodity, does it make sense to get more aggressive on the hedging front?

The answer is probably. For the very reason you mentioned. If you are not getting valuation, you might as well get cash flow benefit. We've signaled earlier this year as gas prices go above $4, we will start layering in hedges and some swaps and fixed price contracts. We have started doing just that. There is a slide that articulated our hedging position. You know, you can see for '03 we now have $10 million today under fixed price contract and $20 million under collar. We looked at doing the same in 04. If prices continue to go up, as we believe they will, then you know, for every 20 or 25 or 30 cent increase in price, expect us to layer in a little more and little more and little more.

Ultimately will probably be about -- if prices take the run I expect they will, possibly this year, but certainly I am bullish on gas prices next year. I believe we will see at least temporarily $5 gas in the lead, I just don't know early '03 or late '03. I believe we will see it. I honestly hope we do not have the spike we had a couple of years ago because it was not healthy for the industry or the economy. We will layer it in. Expect us, if prices continue to go up in sort of a fully hedged position, we would be one-third fixed and one-third collared and roughly one-third left unhedged. We might consider longer term hedges, depending on the tail of the curve. In the past we have kept hedges to about a year or less. We started looking further out into the future and think it makes sense for a company like ours. If the market is not going to give you $4 valuation, yet you can lock in the prices, for the reasons you are inferring in asking the question, I think we need to look seriously at that. Because with $4 gas price next year, we will have a great year.

Do you think there is upside to capex if you see things that you like in the deeper Raton and maybe that gives you more impotence to hedge more?

If we were more fully hedged we might be able to get more aggressive on borrowings if that is what you are getting at. One of the reasons why -- we are comfortable at these levels and are cash flowing more than capital needs on organic development, even with growth. We could get more aggressive if -- we could get more aggressive if prices were not as volatile as they have been in the past. It is that volatility that keeps us at the three-year cash flow discipline.

Okay. Thanks.

Your next question comes from Ellen Hannan with Bear, Stearns & Co.

Can you hang on a second? One real quick question for Kevin. Can you give us guidance on fourth quarter and '03 relative to what you are looking for in light of the impairment charge?

Well, that refund will add to our NOL position. We projected out when we think we might start paying cash taxes. I think you are saving your modeling assumptions to use for the fourth quarter and use the same percentage for '03. We will start probably with the higher gas prices, start eating through the NOL significantly next year. We have been able to put off paying cash taxes because of the additional drilling we have done and the additional IDC deductions. In 04', we will pay cash taxes in the last half of 04'.

You don't look for negative deferred tax other than in the year?

That is correct. Yes, some point in time, we will not get the benefit of the impairment until a later date.

One last question. Can you give a break down of the reserve you audited internally for 930 percentage PDP versus PUD Huds?

Yes, I can give you numbers on that. We had total of 737 PDP and BCF -- excuse me, 737 million cubic feet. 26 million cubic feet in PDMP and 434 in PUD. Percent undeveloped, about 36 percent.

Very good. Thank you very much.

Next question comes from Bordon Putnam (ph) with East Born Capital (ph).

Bordon Putnam (ph): Kevin, if I could ask you for quarterly breakdown that you sometimes provide for different production by what we call the Lacore (ph) and KLT (ph) in Lauren Sito (ph). Do you have that handy?

I do. At some point, the numbers will go on and get cloudy because of additional drilling and work going on in the areas.

Bordon Putnam (ph): I expected that.

Basically the breakdown is core pre-Lauren Sito (ph) acquisition is 77.8. That is for 2002. That compares to 55million cubic feet per day for increase 22 million cubic feet or 39 percent. For Marilyn Rita, 28.8, compared to 26.4 for increase of 2.4 or 9 percent. Lauren Sito (ph), 4.2, compared 3.6 or 17 percent.

Bordon Putnam (ph): Excellent. Thanks. Appreciate that. Mark, if I accounted dig into Alaska a little bit, could you indulge me on that? I was looking over the packet you left with me about a month ago. I am intrigued with this thing and the state has done work up there. You mentioned you were drilling these -- got approval to drill down to 3800 feet. The well drilled by the state in 94 went to 1200 feet. Found coals with maximum thickness of 6 feet. I wondered -- I know there is 18 or more greater individual coals. But, they are in the sands. Clearly, you guys are the best at completion and since Mitchell is owned by Devon, probably no way to compete with that. How do you manage that when you have thinner coals than you might have in the Raton, unless I am confused and blind off the sand so you can complete and infract the coal and deal with the sands.

Thank you for that softball. That is why we have a coil tipping unit and have refining procedures. One of the things that allows us to do is exactly that. Isolation of the coals and the sands. I will say that there are sands and is sand development. I can't quantify it yet, but it is there in addition to the 94 feet of coal we have seen so far. We will drill deeper. I don't know what we will add to that, 10 to 30 percent, probably. And that will be the total coal thickness. There is obviously embedded in the formation. You know, it depends on sort of the hydrodynamics and pressure going on there. The more information we will want to get. To avoid cross-flow, we don't want to open everything up initially.

We want to produce the coals -- we want to test the coals and produce in an orderly way and get as much information as we can to make sure that we are maximizing the productivity. If in this case there is not a lot of water development from the coal, we will be able to produce the gas and the sands with the coal -- methane. And should work fine. Tom Brown has been having good results in some of the deeper plays they are developing. I think in the Green River Basin. They are doing exactly that. We actually have that in the Raton Basin, as well. It is just that as the Raton formation sand packages continue to develop as we drill in the deeper parts of the field, we realized this was a viable play in and of itself and deserved to be treated as such. We are doing some of that in the Raton coals, in particular. It works pretty well. Main thing is making sure there is good conformance and pressure and you don't have down hole problems. With That is something we have to be sensitive to.

Bordon Putnam (ph): You are probing for coals deeper than the ones the state talked about?

That is correct. We are looking at sands deeper than the ones the state had indicated. The coals are pretty much as we thought they would be because of a couple of wells drilled in the past by Unical.

Bordon Putnam (ph): Okay. Couple more and please forgive me, maybe this has been covered by other people. Some reserve I quit getting after the last conference call. I may be redundant here. But, was it ocean that drilled the two wells and then the water disposal well and you are using that well in this program, is that correct?

Almost correct. It was Ocean and Unical that drilled the well, 50/50 joint venture. We purchased both interest in the Pioneer unit in May of last year. We are recompleting that injection well now and expect to use it as disposal source for water. But, quite honestly, it is a pretty tight well and if we get the injectivity (ph) we want, we will use it. If we don't, we will look at another source for produced water. We don't know how many produced water is appropriate.

Bordon Putnam (ph): Are the test wells you are drilling in 18 range 18 town and to west where the coal looks thickest and reflectance is the highest or what can you tell me about the location of the wells?

Deeper wells?

Bordon Putnam (ph): I'm sorry, you ones you are permitted to drill, this eight well program. Where are you focusing with that?

Oh, okay. There are two pilot wells. Two four-well pilots and each of the pilots has four wells that are spaced with one in the middle and the others roughly 120 degrees separate about a 1000 feet away. That is a little bit arbitrary, but a good place to start. They are both located right up there near Wasvilla, Anchorage (ph). If you drive on the parks highway to Houston, you go through one of the paths. The other is close to Wasvilla (ph), itself.

Bordon Putnam (ph): Okay. Running out of questions. You are not using the whole ocean reentered blt-1. Do you know what ocean found or didn't find?

They found a lot of coal and a lot of gas in the coal. For reasons we are not sure we understand, they chose to never fracture stimulate or try to complete the wells. Our examination of the well board, we felt that the method was not of sufficient quality to allow us to reutilize the wells. You know, that BLC well you are referring to, the sands were awfully tight in the well.

Bordon Putnam (ph): Off to the Southwest?

Yes.

Bordon Putnam (ph): To northwest, near Houston, there was a program, small pattern drilled by GRI, Australian company renamed two or three times and is now View Resources and trading 8-10ths of a share. They drilled pattern of five wells and left and the state had to file to get a bond to do the work in their absence. Do we know -- I haven't been able to find out what they found and they drill to sort of 2000 sphoot (ph) depths. Do we know more about what they did or was it lost?

The problem was they did not fracture stimulate the way we would fracture stimulate or try to complete the wells. Obviously drilling deeper than they drilled and we are -- have found that what we are going to new areas like Alaska we find ourselves doing pentance (ph) for other operators and have spent time working with the state and local land owners for that reason. In fact, we have very, very good relations with local land owners as we do in the Raton Basin because we make the extra effort. We don't abandon locations without rehabilitating them.

It was our understanding those wells never established any dysfunction pattern that there was never produced long enough to actually create distortion pattern. So, the answer is whatever data they have is probably lost, but I don't think they had meaningful data anyway. Because as we discovered, you know a lot about the type of coal, the mass role composition, a lot about pressure, temperatures and gas content, but until you establish the distortion pattern, you don't know what you have. Nobody in Alaska knew what they had. We're the first group going into this with the idea of hydrolically (ph) fracturing and stimulating the coals and establishing disorption (ph) pattern for the data we need. You know, we can -- one thing they did that was -- we called it interesting, they were trying a new water disposal method. They were through packard (ph) combination had completed deeper zones below the coals and were injecting produced water into the zones without the water coming to the surface.

Bordon Putnam (ph): I saw that permit by the state. I never saw the issue.

It looks great on paper, but just not very efficient. I don't think they put away very much water and I don't think they had a good way to measure how much water they actually produced or disposed of, which is why -- it is an intriguing method and something we should probably keep our eyes on. I don't -- you're right. Between what they did and what Unical and Ocean tried to do, there were half-hearted attempts to establish CBM, but there were very important problems that apparently they had with the completions or operations and as you would expect we are going about it a different way, we are drilling the wells differently and completing the wells differently and will operate them differently, as we discussed in the past, why we think we were successful in the Raton Basin, versus methods that others had used that worked fine in the stand alone basin, but didn't make sense for the Raton Basin. We see what other companies have done or not done in the tionic (ph) coals in Alaska and Matuskus Valley (ph), to be almost a perfect analog. For reasons you would expect, we hope it is Deja Vu.

Bordon Putnam (ph): You commented on the community. Inhale is pretty inhabited and I called realtors up there and saw the greater amount of residents and recreational lakes in the area you are trying to work. Looking at photos of the Raton Basin and the Sanjuan, just to see what your drill pattern looks like. I am wondering how can you put the same drill pattern with -- here we are 800 wells online right now. Granted, it is early, but wonder how the local inhabitants how that will interfere with your ability to create an orderly drill program that is prerequisite for the play. The full development is going to be more problematic or not?

It might be accepted. If you think about this area as swampy lamp. There are times of the year when to get maximum land use you will want to drill when it is frozen because you won't want to drill on the marshy land during the summertime. We expect the winter -- we're going to have to learn a bit about Alaska operations. We can operate efficiently at 10 or 20 below in the Raton Basin. We don't always like it, but we can do it. It will be a way of life for us in the winter in Alaska. Recall that almost all of the Canadian drilling occurs in the winter.

Bordon Putnam (ph): Absolutely.

For the reason you are mentioning. If you look from our perspective, few locations are not accessible if you look at drilling them when the ground is frozen and that is something we are looking closely at. As far as visual impact, it is easier in Alaska than the Raton Basin. You can drive through the Raton Basin and you wonder where all the wells are because they are drilled in areas and artfully disguised to the extent we can. In Alaska, it is pretty flat and the areas we are drilling in are fairly heavy for the most part. You could drill through the middle of the field through Wasilla and Houston and wonder where the field was.

Bordon Putnam (ph): Good. Good luck. I will look forward to hearing results in first and second quarter.

Real estate is attractively price indeed Alaska.

Bordon Putnam (ph): I learned that myself.

Next question from (inaudible) with Goldman Sachs.

I assume that is Alexandra (ph).

Thanks. Let's see here. I lost track of what I wanted to ask. Looking at year-end reserves and thinking about the nature of the program that has been getting you there throughout 2002, now, remember there were two or three things adding reserves in the Raton coal and then importantly, in my mind, extensions to the northwest. Can you give us some sense for how the extension to the north as worked out? I remember you had talked about the coals being deeper and potential for maybe more costly for this and getting more reserves out of the wells. Can you give us some sense for that?

Yes, the Vermayo (ph) starts to thing--thin in that area. We developed the Vermayo (ph) coals because it was analogous to the fruit land formation associated with the transgressive Vermayo (ph) environment. So, the Vermayo (ph) coals tend to be fairly uniform, but firm, roughly 10 feet to 40 feet of thickness. As we drill in some of the deeper parts of the basin, we are seeing areas where the Vermayo is thinning. At the same time, though, we indicated we would drill the Vermayo (ph) because we got a free look at the coals, which had to be completed separately because of pressure and other differences and the Raton coals are more variable and can be zero feet thick to a hundred feet thick. And in a very nice way, as we have gotten into deeper parts of the basin, we have seen thinning of the Vermayo, but thickening of the Raton. And the best Raton wells look like in the deeper parts of the basin. In addition to thicker Raton coal development, we are getting massive sand development, which causes us to look at it as separate play in and of itself instead of combining the Raton sands with the Raton coals as we have in other areas. Overall, --

It is working.

It is working. It is cumulative. That is a qualitative description, but accurate one.

Yeah, if I look at implied (inaudible), that is consistent with your history?

Yeah, and as we -- what would be nice -- what is nice about the deep play, even if you get a BCF per well on average and let's say it is going to cost incremental half million dollars, which I hope is on the heavy side of cost estimates, that is still 50 cents per MCF, still a better number than industry is reporting, just not quite as good as great CBN numbers we were reporting. Overall, I expect several factors some of which suggest cost will go up slightly and some suggest development costs will come down slightly. We will start seeing -- we are seeing greater economies for the infrastructure we have invested because that gathering system, the 800 wells producing today was built for the 800 wells and to also accommodate the next 800 wells that have to flow through the same type.

As I think about the production plan that you have laid out for next year and let's just say conceivably that the deeper stuff continues to work and maybe at some point you might consider shifting some of the capital plans for next year toward more deep and less coal. Is it conceivable to think that that would help at the margin your near-term production outlook?

It could if we focus on -- if we get strong results on the deeper drilling then that is a nice complimentary profile to the Raton -- to the coal bed methane profile, where the wells come off slowly and incline for five years. It would be nice to get a nice mix of tight gas wells either in the Raton Basin or some other basin where we could get a nice mix and start to blend production. Right now, as you are aware, we had largest RP ratio in the industry. I don't think the market is giving us credit for that. I don't think the market knows how to value that. It may be the best thing we can do to create real asset value that translates into share value, is to find ways to shorten reserve life. We can do that through in-field drilling and deeper drilling to tight gas wells and also by focusing on other basins with more of orientation toward tight gas and drilling.

Okay. One final --

Couple of other facts is as we drill in deeper parts of the basin, the Raton coals are -- can be 1500 feet deep and can be 3000 feet deep in the deepest part of the basin. They can be -- they are at the surface at the shallowest part of the basin. It appears we have more coals to work with. There are more developed in a way that can be correlated and more gas in place. So, it's -- there is little to be pessimistic about. While the Vermayo (ph) is thinner, we have more Raton coal to work with, deeper, thicker, gasier, we have more pressure to work with, which is why there is more gas in place. We have got more sand development, which is worth separate drilling program and we are getting encouragement on the deeper drilling. So, mother nature is still full of tricks, but you know, everything we find is causes us to be positive in our outlook for drilling inventory.

Okay. Well, that's very good to hear. Thank you, guys.

Your next question comes from Larry Bustnarto (ph) with Peachtree (ph).

Mark, deeper wells in the Raton Basin, what (inaudible) are they going to?

Larry Bustnarto (ph): We are targeting four different formations below the coals. The coals, there is easy way to break the coals. They sit on top of the Trinidad sand. The Trinidad sand is wet throughout the basin and has so far not shown to be very interesting as separate play. Below the Trinidad, the other cretaceous aids, formations of interest are Pierre shells, Greenhorn, these are what we are targeting down to the Dakota. We haven't drilled a Dakota well where the Dakota itself looks interesting, but drilled to the Dakota where we find two or three or four zones below the coal that look interesting.

Larry Bustnarto (ph): What is completed cost of going to deeper zones?

I think I mentioned, but don't want to imply that the Dakota is in and of itself looking that attractive as a target, but a number of zones above the Dakota but below the coals are. As I mentioned, the Dakota is pretty wet. The targeting we are talking about wells 4 to 7000 feet deep. I was speculating the incremental cost was less than half a million. I think it will come in between 4 and 500,000. If we get about BCF per well, that is finding and development cost of 40 to 50 cents MCF. Keep in mind, we have the pipeline in place and roads and locations in place that we are using to drill the deeper wells.

Larry Bustnarto (ph): Switching off to Alaska again, do you have any sense of how long the deep watering period may take or a function of getting the wells drilled and seeing how they produce after you have them completed?

Not just a function of how the wells look, but how they crack and which formations we are getting the water out of and which formations we wish to isolate. Other companies in the past and other basins have taken the attitude let's open up everything and try to get everything to produce and that has created problems because of well bore conformance problems and well bore integrity. We have taken the opposite approach. Let's get this established and test a few seams. This pattern was spaced more closely than a full development pattern will be. As I indicated, we have four wells per pattern. One in the middle. Three around it, spaced at 120 degrees around it, about a thousand feet away. That's closer than you would expect.

If we were out drilling wells on one 60 acre spacing or 120 acre spacing, which we have been doing in the Raton Basin, it is tighter. It is tighter specifically to get the information you are looking for. That is not optimum in my mind, but optimum for getting more information quickly. So, we've gotten good at modeling the wells. That is how we ascertained in the Raton Basin you go from four wells per section to a fifth or 60 well per section. We have a lot of confidence in our models and believe we can apply the models to what we find in Alaska. But, those wells were deliberately drilled on unusually tight spacing pattern to accelerate absorption to get good information on permiability (ph) and how much gas in place we are likely to be able to recover. And the answer is we will know when we know. But, you know, it will be sometime next year.

Larry Bustnarto (ph):Okay. One last one. You may have mentioned this before. What are the wells going to cost in terms of completing them?

Unfortunately, as everything else, the first go around was more costly than we would have liked. We probably have made the locations a little bigger than they need to be because we need to make sure we can move around and get things done. We have put in -- we stopped or deferred drilling for about six weeks while we went back in and set conductor pipe to 3 or 400 feet, which was not expected. But, it is real smart to do to reserve the ground water there in that part of Alaska, as well as to make sure that you have no loss of drilling fluid while you are drilling through the porous tills and cobblestones. So, these wells will be more expensive. This well pattern plus the injection well, the run over -- between 5 and 6 million dollars, all in cost for the first group. I am guessing from the actual well cost is going to be typically 7 to 800,000 per well in the first round. If we are as successful as I hope we will be, I hope we get the numbers down by half, as in the Raton basin.

Larry Bustnarto (ph): Thanks.

As this time, there are no further questions. Are there closing remarks?

Thank you again all of you for your interest in what we are doing and Kevin or John, do you have comments? No. This concludes the third quarter conference call. Thank you very much for your participation.

Thank you for joining today's Evergreen Resources third quarter earnings conference call. You may now disconnect.

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