先鋒自然資源 (PXD) 2003 Q4 法說會逐字稿

Good afternoon. My name is Jody, and I will be your conference facilitator today. At this time I would like to welcome everyone to the Evergreen Fourth Quarter and Full-year 2003 Financial and Operating Results Conference Call. Presented by Mark Sexton, President and Chief Executive Officer, and also Kevin Collins, Executive Vice President and Chief Financial Officer. All lines have been placed on mute to prevent any background noise. After the speakers' 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 1 on your telephone keypad. If you would like to withdraw your question, press star then the number 2 on your telephone keypad. Thank you. Mr. Kelso, you may begin your conference.

Thanks, Jody, and thanks to everyone for joining us today for our fourth quarter 2003 conference call. We certainly appreciate your interest. I'd like to remind everybody as always this call is being broadcast live over the Internet with an accompanying slide show. To view the webcast, please go to our website at www.evergreengas.com.

Over the next half-hour Evergreen management will discuss the press release which provide the operational and financial results for 2003 as well as estimates for the year ending December 31st, 2004. These forward-looking statements are made under Safe Harbor Provision established by the Securities and Exchange Commission. The results and uncertainties involved with these forward-looking statements are described in more detail on the company's most recent annual report on Form 10-K filed with the SEC. I'd like to also mention our next 10-K, 2003 10-K will be available in mid-March. With that I'd like to turn it over to our Chief Financial Officer, Kevin Collins.

Thank you, John.

Today our conference call will consist of highlights from the fourth quarter results and also an overview of some of the changes to our guidance for 2004 which we originally gave in October of 2003. If you'll turn to the website and follow along with the -- speaking mostly to the slides that are presented and l will talk to those slides as they're numbered on each one.

We're extremely pleased with our year that we had with Evergreen. We had a great year in a number of areas where we set record performance and revenues, net income, earnings per diluted share, production, and total proven reserves. We reported 17.6 million per diluted share for the fourth quarter. On slides 3 and 4.

On slide 5, we've listed out our historical net income for the past three years. And again I'll note this is a record year for Evergreen with net income of $72.6 million for the year.

Slide 6 notes our historical per diluted share results and again, this is a record year for Evergreen with total diluted earnings per share of $1.77.

Slide 8, our actual production for the quarter was 12.829 BCF, our guidance for the quarter was 12., 13.3 BCF, production was in line with our guidance on the lower end. On slide 8 our historical net production is shown. We've increased significantly since started the Raton Basin in 1995.

And on slide 11, you see that our average daily net production has increased significantly over the past several years. This is a 35th significant quarter which we've had production increases. We had 130 million cubic feet total production, average daily production in the Raton Basin, and with the Carbon acquisition in the Piceance/Uintah Basin we had 5 million cubic feet per day for two months and approximately 8.6 million cubic feet per day in Canada for two months also for a total of 13.6 from the Carbon acquisition.

On slide 10, total production for the year was 46.3 BCF. Of that 46.3 BCF, 45.4 was from the Raton Basin. This number was right in line with our guidance provided in our conference call on January 13th of 2003 where we had estimated production of 44 to 46 BCF for 2003. The total increase year to year over 2003 was 19% as compared to 2002, and based on the new guidance we anticipate that overall production will increase 37% to 62.2 to 64.4 BCFE in 2004.

Slide 11 shows our net realized gas price by quarter for the quarter ended December 31st, we had a net realized price of $4.68 and we had 87% of our gas hedged for the fourth quarter.

Slide 12, lease operating expenses. Our total consolidated lease operating expense guidance was 49 cents to 51 cents per MCFE for the fourth quarter. Our LOE was on the lower end of the guidance at 49 cents. LOE for the Raton Basin was 46 cents per MCF. For the Piceance Basin was 99 cents per MCFE, and for Canada was 91 cents per MCFE.

Slide 13, our quarter end in 2003 operating costs, G&A for the fourth quarter was estimated 30 to 32 cents per MCF. G&A came in higher than our anticipation due to the information noted in our press release, in addition we continue to add staff to you are infrastructure and starting to ger up for our growth in other areas. All these items are causing an increase in G&A for 2003.

For DD&A our guidance for the quarter was 68 to 69 cents per MCFE, DD&A came in at 68 cents. We previously had 54 cents per MCFE through nine months of the 2003. However, due to the acquisition of the Piceance and Canada proved oil and gas properties DD&A increased to 68 cents.

Interest expense was in line with our previous guidance and our debt levels came in lower than we had estimated. Our previous guidance for debt levels were 265 million to 275 million. Debt was 249 million at 12/31/03, and was lower than guidance due to lower than projected cash Cap Ex in the fourth quarter by about $18 million. Our debt as of today is approximately $255 million.

On slide 14 our Cap Ex for the quarter was 122.5 million. Again this was about 18 million lower than was projected. This was due to less cost in the Raton Basin, drilling 21 wells in Kansas versus 40 wells, and timing on the completion of the Kansas well service equipment. That service equipment will be completed in 2004. Total Cap Ex for 2003 was $247 million as compared to a Cap Ex budget of 275 million.

On slide 15, as noted in our press release last week year-end reserves were at 1.495 TCFE. This amount was in line and on the lower end of our guidance we previously issued of 1.5 to 1.5 TCF. Since 1996 this represents a compounded annual growth rate of 39%. During 2003, Evergreen replaced 653% of its production at an all sources cost of 8 cents per MCFE, excluding acquisition and exploration costs, funding and developments costs were about 50 cents per MCFE. Based on our estimated drilling program for 2004 our guidance for 2004 is estimated to be 1.7 TCFE to 1.75. We've raised the lower end of our guidance that was previously given of 1.675.

On slide 16, we've included oil and gas reserve changes. This is been given to you just as a comparison and a focal point for our discussion. As noted by a number of companies in the past few weeks many have taken reserve write-downs and reserve reclassifications. And as noted in our press release last week we've had no reserve write-downs or reclassifications to our reserves nor have we ever had any write-downs or reclass in the Raton portion of the -- in the Colorado portion of the Raton Basin. Our reserves have been audited by an independent engineering firm for the last several years, Netherland Sewell and Associates. Netherland Sewell and Associates have been involved with the reserves in the Raton Basin since day one. NSAI knows our reserves inside and out, and is recognized as one of the few independent firms who actually understands CBM reserves. Their audit covers 100% of our proved reserves where as most companies only have audits of approximately 80% of their total reserves. Our reserves comply with SEC guidelines for reserve categories, constant prices and costs, and our prepared in accordance with generally accepted petroleum engineering and evaluation principles.

We've been very conservative in booking PUD's as we ensure that each is a direct or diagonal offset to an existing well. Our PUD's as a percentage of total proved reserves have been in the 35 to 40% range, total proved reserves for the last several years. Approximately 76% of our PUDs that we have been -- that have been booked were generated in the last few years, 2001 to 2003.

As noted on slide 16 we've listed out the changes in proved reserves over the last four years. This year's reserve revision estimate is less than 1/10th of a percent. Overall the reserve revisions have been insignificant over the past several years. We still believe we have in excess of 1,000 drilling locations and we will continue to generate additional reserves for next four to six years.

On slide 17, it's important to note that our weighted average shares for the fourth quarter should have included a weighted average dilution for the conversion feature of our convertible debenture. Those debentures are now convertible into Evergreen common stock as the conversion feature has been triggered because the stock has exceeded the conversion price by -- it's been 110% of the conversion price for the first 20 trading days of the first 30 trading days of any quarter. I think in your future calculations for diluted shares you should include at least 4 million shares for the contingent conversion feature. We estimate that for the first quarter of '04 the total diluted weighted average shares with the contingent conversion should be about 48.3 million shares.

Page 18, our 2004 drilling program. We believe that based on the following guidance we anticipate another record year at Evergreen. Next year will be better than -- 2004 will be much better than 2003 was.

Our petroleum program has increased to an expected 200 Wells for 2004. In Kansas we have increased our drilling program to 61 wells which include a 17 well carryover from the 2003 drilling program and we've reduced our drilling program in Kansas for the following reasons. One is weather problems in Kansas causes us to have substantial delays in the amount of wells we can get drilled. We've had several contractor delays that has taken longer to drill wells than anticipated, and our penetration rates are slower than were expected by the contractor. All of this caused only 21 wells to be drilled in the fourth quarter 2003 and to date in 2004 we've only drilled six wells in Kansas. In addition we'd like to slow down the pace of our development in the Kansas area so that we can take more time for a prudent approach to allow for the experimentation of different types of fracture stimulation methods. In addition we've delayed the delivery of our coil tubing drilling rig until July 2004 as a result of the design changes to increase its capability to drill in this area and to overcome the problems that have been experienced by the current drilling contractor.

By the end of 2004 we hope to have eight water disposal wells completed and 92 wells on production testing. The 92 wells will consist of the 2003 and 200 drilling program and other wells that were acquired in the recent acreage acquisitions. The drilling program in the Piceance and Uintah Basins have not changed from previous guidance and we've tweaked the number of wells from 72 to 65 wells for 2004.

On page 19, slide 19, we changed our estimate for 2004 to 62.2, to 64.3. The change was for the following reasons: As we stated in our press release we've had a number of delays and several operational areas. Due to the slow start in Raton Basin we're increasing our drilling program to up to 200 wells. We're currently adding two more drilling rigs which we expect to arrive in the near future and additionally added more pipeline crews to help reduce the time it takes to hook up newly drilled wells. The production for the Piceance and Uintah Basins has increased slightly due to a small acquisition completed in December, and the Canadian production has been revised to reflect a lower first quarter estimate as a result of the delay in hooking up new wells.

Major change from the last press release that we issued and the last guidance issue is we've taken out any production from Kansas. We probably should have been a little more conservative in our approach to this area. While we believe we should have production reserves by the end of 2004, we've just taken out sales all together until we actually start incurring sales.

On slide 20, we've listed out our production by area and by quarter. To help with your estimates.

Page 21, slide 21 indicates our hedging position for 2004. We noted this information last week in our press release. We have about 86% of our production for the first quarter is hedged. Approximately 129 million cubic feet per day at a net realized price of $4.79.

For second quarter we have 75% of our production is hedged at $4.66. This represents 123 million cubic feet and for Q3 we have 123 million cubic feet at $4.66. Q4 has 77 million cubic feet. We've not hedged very much of the November and December months and those hedged prices are at a net $4.54.

Slide 22, operating costs, generally our operating costs have stayed the same from previous guidance, however due to lower production profiles, LOE in the first quarter has increased on a per-unit basis, not on an absolute dollar basis, and there have been no changes to Q2, Q3, or Q4. DD&A was adjusted for final year end reserves in 2004 and increase in 2004 over 2003 is the result of the purchased assets in the Piceance/Uintah and Canada areas. G&A, no changes to the dollar amounts, only increases to the per unit costs due to the reduced production guidance.

Slide 23, indicates our reallocated Cap Ex budget. We have not made any changes to these total Cap Ex. However, we have reallocated some of the reduced costs in the Kansas area to various areas. And I'll note those.

Raton Basin we increased the Cap Ex budget to 109 million from 90 million due to increase in numbers of wells 200. In Kansas we reduced to 33 million amount of expenditures, this is due to drilling 61 wells versus 150 wells. The Piceance/Uintah area we had minor changes, increasing it from 27 million to 33 million for anticipated acreage acquisitions. In Canada there have been no significant -- no changes from previous guidance. Also of note, we've recently changed our name in Canada to Evergreen Resources Canada Limited, and in Alaska we've reduced the cost for the five stratigraphic wells we plan to drill, and therefore that cost has been reduced to $2.3 million. Overall our Cap Ex budget will be 220 million for 2004.

Mark, I'll turn the call over to you.

Thank you, Kevin. We've had some questions over the last 24 hours about what's changed recently. The answer is very little.

Given our inability to acquire the data we want in Alaska and Kansas, we've simply decided to scale back the operations until we have the data necessary to go forward as bullishly as we had originally projected.

In Alaska also we've had requests from the administration, the regulators and the legislators to go slowly while they work out the new rules in Alaska, and we've agreed to accommodate them and we're going out and getting the geologic data that's necessary for us to be more aggressive about where we want to drill in the future on the 300,000 acres approximately that we have under lease in Alaska.

In Kansas, we originally stated that we were looking forward to drilling about 40 wells by the end of the year, and if we had slid over into January and gotten those 40 wells done, then fine, but the reality is we only got 21 wells drilled in Kansas. We're only on the 27th we will today out of that 40-well program, and the data is neither positive nor negative, it is simply not yet available, especially the permeability data we need on the coal, the shales, and the tight sands, getting the production data that we were looking forward to. Our plan in Kansas that while we still want to increase the acreage we have and we still want to consolidate what we have in Kansas, the reality is we're just not getting things done.

We believe part of that is -- a big part of that is not using our equipment and not using our people. While we're using an excellent contractor, obviously the results are going slower than they expected and advised us, and, therefore, our plan is simply to say we'll get this done, we'll get it done more efficient well our own equipment, and that equipment won't be available until the middle of the year.

Regarding our outlook, we're very positive about the results we've seen in the Piceance, Uintah Basins, and in Canada, as evidenced by the very large capital commitment to those project areas, particularly relative to the size of the Carbon -- to the expenditure of acquiring and merging with Carbon Energy. Qualitatively, it looks excellent. It looks as good as we thought it would -- as good or better than we thought it would. When we made the original acquisition decision. We're very pleased with what's going on there, and we're going to focus on that because the production results should be more immediate.

In the Raton Basin, we're simply taking care of business there. If you go back and look at slides 8 and 9 you see that every first quarter is relatively flat, or only up a little bit from the prior fourth quarter. That's the case again this year.

Because of Evergreen's -- because of the nature of unconventional gas and the need to get relatively small volume wells hooked up quickly we're a little more sensitive to some weather-related issues that always seem to occur. For some reason it always gets cold every winter. For some reason we always seem unable to adequately predict that as we would like to and get the results -- production results coming out of the field, and we're looking for ways to continue to improve that, but the reality is fourth quarter and first quarter are always fairly comparable, and that's the same this year.

There is -- I think it's especially to note there is absolutely no change in our overall budget or overall reserve goals. In fact, we're more confident of our previously projected year-end reserves which is why we increased the lower end of guidance to 1.7 TCF as Kevin indicated.

We're focusing and refocusing on the most important items including short-term production. That means focus on the Raton Basin, Piceance, Uintah, and Canada. We've noticed that the U S obsession with quarterly reports is going to force to us do that because we simply don't have the time to wait to get the information we need in places like Alaska and Kansas, which we think -- which we still think will be great projects, which we are still looking forward to dag but quite honestly we have to put our priority where we're getting if results.

We received a lot of questions about what has happened in the Raton Basin recently because of El Paso's reserve write-down. In their quarterly conference call or press release they noted that coal bed methane reserves were booked by 511 BCF equivalent. I have no inside knowledge of El Paso's reserves except I am speculating that they wrote off about 900 BCF in the Raton Basin to about 400 BCF.

What does that mean to Evergreen? It means absolutely nothing.

First, I applaud El Paso for their decision to restate reserves. Were I in the position of the new management I would have done exactly the same thing. Start with the very solid base. I will note, however, that the number they have written their reserves down to is completely comparable with Evergreen's currently stated reserves. If you look at the number of wells that they are producing from versus Evergreen's wells, look at the production levels that they have and the sales coming out of the basin versus Evergreen's production and sales and look at what I infer their new reserve level to be versus Evergreen's stated reserves, it's all about 2.5 to 3.5 times ratio in terms of Evergreen having 2.5 to 3.5 times production and number of wells, so it's completely comparable.

One item of note however, El Paso stated that they felt they were only getting 80-acre drainage. We know for a fact that with our complete methods we're able to get drainage on 160 acres and that as we've previously stated to the public, if we have about four wells per section we were getting about 65% recovery of the gas in place. Our models show that with our methods with about five wells we're increasing that recovery of the gas in place to about 70%. With the sixth well, 75%. All rough numbers, but you get the idea.

The reality is that if El Paso is correct and they have a lot of reserves behind pipe or on undrained 80's, then that represents a very strong opportunity for us and for them and I hope one that leads to possibility of working together since, obviously, we think with our equipment and completion methods we're able to efficiently drain a larger area.

So the restatement of reserves is completely in line with where we are already. Kevin's already gone through the fact that our numbers have been audited year-over-year after year and not just most of our reserves but all of our reserves by Netherland Sewell, one of the most reliable of the national firms in terms of stating coal bed methane reserves. Netherland Sewell understands what's going on in this basin, and they get it, and we've had very very few revisions, and not at all significant year after year after year.

So we're very pleased by the results of last year. We tripped a little bit coming out of the blocks this year. We figured it out quickly. We're on it. We're focused on where we need to be focused, and we're going to have a great year and we predict that 2004 will be another record year for Evergreen.

With that, Jody, we're going to open it up for questions.

At this time, I would like to remind everyone in order to ask a question, please press star then the number 1 on your telephone keypad. We'll pause for just a moment to compile the Q and A roster. Your first question comes from Brian Singer from Goldman Sachs.

Good afternoon.

Good morning or afternoon, Brian.

Two questions. First, can you just give a little more detail on your plans in the Piceance and Uintah in terms of, A, kind of where you see production by the end of this year, B, to the extent which costs have come down from the historic energy levels, and, C, your general commitment to acquiring new properties there, and second, if there's any more detail on the timing on Alaska of acquiring data and how that could lead to further drilling and eventually production, that's great.

We seem to have some problems on the questions, Brian, start with the easiest answer first.

In Alaska we simply are -- we have committed to drill five core holes. We have about one-half of a core hole actually drilled. To do this right in Alaska, we had to set surface casing through the [spatial till] zone, we wanted to make sure that we -- because of local concerns of -- because of lack of local drilling in the area people are very concerned about possible contamination with local water wells and water supplies. We believe that industry in Alaska has done an excellent job and that there have been no problems and we're making an extra effort, as requested by the regulators to make absolutely certain that this cannot happen.

So in Alaska we simply want to make sure that we're going slower as we indicated at the request of local legislators and regulators, and we're extra careful, so we've set surface casing on the five wells and we're -- we have about half of a core to date, and it's going slow. Once we have those five cores, we will evaluate them, get the geophysical and petrophysical data analyzed and figure out where we're going to start our first core program. Again, since it's an exploration area, while I expect to know something hopefully something significant by the end of the year, until we actually get the data we need, there's no point in making a prediction.

Same is true in Kansas. Simply going too slow there. We expect to have our own equipment available for us by the middle of the year, and until we have our own equipment, it's clear that we can't get the number of wells drilled that we plan, so we've come out with a more realistic number based on what we know today.

Again, the data is not positive or negative, but as you know with unconventional gas you have to really pay attention to the geology, the hydrology, and the reservoir considerations. To do it right you have to drill wells, you have to get that production data, get that permeability data, that resorption and positive interference data, and that takes time. So as Kevin indicated while we expect to have production reserves by the end of the year we're taking that off of our projections although we still are going to go forward. We think aggressively in Kansas with the program.

Our plan in the Piceance/Uintah Basin for 2004 is anticipating about 21 conventional wells and about 38 unconventional reservoir tests. I won't go into the details of that for competitive advantage but one of the reasons why we were attracted to Carbon was that the Carbon gave no reserve value to the unconventional gas potential that we saw, and we and Netherland Sewell sat down and agreed that there was substantial upside value which is one of the reasons why we were so attracted to this acquisition opportunity.

Of course, we're going to go back in. We have an aggressive remediation program where we're going to refrac and recomplete the existing older well bores, some of which were 10, 20 years old, and use modern day frac techniques and Evergreen's modern day state-of-the-art equipment. We're also, of course, going to infill and development drill to add to exploration and since this area benefits from 3-D seismic programs we've included that as well.

The main thing, though, is identifying and acquiring the producing and non-producing strategic properties and we have our eye on a number of things that we're looking forward to acquiring and developing to compliment the very large acreage position Carbon already had on an area, and as part of Evergreen's typical plan of operations, we will be constructing our own equipment to, in particular to complete the wells and to drill, if necessary, but certainly to complete, and we are going to construct and acquire the gathering facilities necessary for us to control our destiny in this area in the Piceance Basin, which is also typical of our vertically integrated operating structure.

So I hope I answered your questions, Brian.

Thank you. Yes, you did.

Your next question comes from Joel Southern from Alaska Public Radio Network.

Mr. Sexton, you've mentioned the problems here that you've had in Alaska, or having in Alaska. Just basically from a business standpoint, are you finding Alaska at this point to be more hassle than it's worth?

Actually, we're finding Alaska to be pretty much what we expected Alaska to be. Very independent, very determinant that a company coming in from the outside do it the Alaska way, do it right, treat the Alaskans the way they want to be treated. We find that the people in Alaska, they're refreshingly candid in their opinions, and that includes both the pro-development and the anti-development people.

And there's been a lot of negative information disseminated about coal bed methane as reported, for example, in the "New York Times". That information you see on the "New York Times" is generally -- generally reported on the Powder River Basin, not the Raton Basin, not Alaska, not the San Juan Basin, not other areas. And I find that there is a rather strong bias in the press to believe that somehow coal bed methane must be raping and pillaging the environment because the "New York Times" has described the Powder River Basin as becoming a desolate wasteland. That's simply not true. Anyone who's been there is actually impressed by the wonderful relationship that industry has with 90% of the ranchers there.

We're also very proud of Evergreen's relationship with the community in Las Animas County, Colorado. We've given a lot of tours a lot of Alaskans and a lot of other people, of our operations, and typically we take them out in the middle of the field, and they say when do we get to the wells? They're standing out in the middle of a thousand well field and don't even know it. Then we take them to a very high point and let them look around, and see, and from a very high perspective, they can only see maybe one well. If we show them exactly where to look. So we're very proud of our operations.

We're very sensitive to the fact that Alaskans want to see this done right and I think I'm happy to address concerns because I know a lot of Alaskans are in on this call but this is really Evergreen's call to talk about our business results and our plans for the future. And I think it's -- we think Alaska is a good place to do business. We have certainly not given up. We have very high expectation but we are going to do it right, and while I appreciate the concerns of all Alaskans, I'd like people to respect that this call is really to talk about more financial results.

Okay. But let me just ask one thing about that. I just want to make sure I get your numbers right. You're talking about. In terms of capital expenditure in the coming year, did you say -- did Mr. Collins say $2.2 million?

2.3.

2.3, and that's down from 7 last year, right?

That's correct.

That's correct.

Okay. Thank you very much.

Your next question comes from Ellen Hannan from Bear Stearns.

Thank you. Few questions on your -- the drilling program now that you plan Kansas, Mark, you said you've drilled 27 wells to date and you plan 61 wells in '04 which would give you a total are 88, but looks like --.

No, that's actually not quite correct. That 61 wells includes 17 of the 40.

How do you get to 100 by the end of the year?

Ellen, this is Kevin. We had drilled 21 wells in the fourth quarter and we anticipate -- we have the carry-over of the 40-well program into 2004 so we're going to drill an additional 61 wells. The way we get to 100 wells is part of the acreage acquisitions we had acquired some existing well bores in those acreage acquisitions and we're re-completing those wells and that roughly is about 12 to 16 wells.

Okay. In terms of the Cap Ex on -- wait. In terms of, again, getting back to the issue of having your equipment, do you foresee any issues in the Piceance or the Uintah basin in terms of having the rigs that you need?

Well, as you're aware, as we indicated, we will be subject to local contractors more so than we are in the Raton Basin. The answer is we'll be using our own equipment for stimulating the wells, which is a critical part of the process. This would be -- the biggest issues in the Piceance and Uintah basins will be, we'll doing more work on federal lands and the permitting process with the BLM takes longer than does it with virtually any state. And this issue has been addressed and is being addressed, but, you know, you have to build in the fact that it just takes longer to do things when you're doing it on government lands, and that includes not just the wells but the seismic work necessary just to figure out where to put the wells, so you're going to be delayed on seismic issues, delayed on getting the seismic, delayed on getting the specific permits for specific wells. Doesn't mean we're not going to try. We are. But every operator that's operating in those areas on federal lands is experiencing the problem. Our ability to get things done is quite a bit quicker than the regulatory process can move. But hopefully we've factored in that properly.

Also on the capital spending in the Raton, you have other costs, quote unquote, other forecasted at 27 million this is on slide 23. Other than drilling, completing, compression. What are these other costs, and are they recurring or are they non-recurring?

Ellen, of that $27 million we've talked about in the last couple of calls about our refrac and remediation program. We're refracing anywhere from 160 to 200 wells per year just to go back in and stimulate new zones and older wells that have now de-gassed and de-watered a little more, and what we've been able to do is increase reserves and increase production in those wells, so we've got about $16 million allocated for 2004 for that program. In addition to that we've got a fairly significant program this year for Scada system which will allow us to remotely identify and monitor well progress and production from our office versus actually visiting each well. We think that program will help us enhance production and give us more consistent run in production times. So that -- those two are the biggest items for 2004.

And then moving on to Kansas, you've got 15.8 million budgeted for equipment. Again, is this kind of equipment that you need to spend money on routinely throughout the program in Kansas or is this a non-recurring?

Generally this is building a new frac fleet along with a new coil tubing drilling unit which we have not had before. We're spending about $5 million for that coil tubing drilling unit. We can use that coil tubing unit anywhere in any of our areas. We can take that over to the Piceance/Uintah, and also in Canada. In addition, we're building a new frac fleet of which we can probably use in the Piceance/Uintah, Canada, Kansas, any one of our projects, so that equipment will not be recurring all the time as we continue to add more wells we may build another fleet or two just to service additional wells, so we have plenty of flexibility with those capital costs.

One last question for you. Housekeeping item on your balance sheet on the change deferred taxes versus what's on the income statement. Is that something to do with the step-up of the basis of the Carbon assets?

Yeah, the Carbon transaction was a non-taxable transaction, and that, since it was a stock for stock deal. The tax basis of the Carbon assets did not change, so due to purchase accounting we had to gross up the purchase price by the amount of estimated deferred taxes, and, therefore that created another 33 million of deferred taxes on our balance sheet, and the offset to that went to the proved oil and gas reserves.

That's it for me. Thank you very much.

One thing to mention, Ellen, on this Scada system, the simple share volume of wells suggest the faster we can respond to the data coming from those wells the better we'll be able to keep production levels growing. Each -- estimates vary but each Scada system projects substantial performance. If we do that will be great. We haven't built that into our numbers. That's about $8 million of that non-recurring costs. The other is, you know, because of the attention to detail we like to keep we're still going to have the pumpers go by, look at every well every single day, and that's just part of our business model to pay attention to details. But a lot of these costs are non-recurring. But expected to improve production and performance.

Great. Thanks much.

Thank you.

Your next question comes from Greg McMichael from A.G. Edwards.

Good morning. Still morning. Mark, wanted to ask you a couple of things about the additional acreage that you acquired in the Piceance and Uintah as well as in Canada. You mentioned in the press release that start out with Piceance/Uintah, you increased your acreage position there to 194,000 gross acres. Can you tell us what you added there?

Well, you know, mainly there was the biggest part of that was an acquisition of a field called Castle Gate that we acquired from a couple of operators where we acquired 75 to 100% interest. We got a little bit of production, we got about 36 to 37,000 acres out of it. And the -- That's a coal bed methane play as well as other unconventional gas plays that we're expecting, such as shales, but the coal play there in particular is a deeper set of coals that we think has substantial up side potential. Previous operators had spent over $26 million on the field. Didn't have the results they wanted to show for it. We are hoping, of course, that with our -- what we believe to be our improved frac techniques that we can go in and figure out optimum way to drill and complete new wells and turn it into -- turn it into something very cost-effective for us. So that's a little bolt-on acquisition.

The fact is, everything we're doing is, we're also acquiring infield acreage all around this. Carbon didn't have the completely contiguous acreage position that Evergreen enjoys in the Raton Basin, so we're planning infill acreage acquisition in all of the areas, and obviously for obvious reasons prefer not to talk to specifically where.

In Canada we're looking at a new coal bed methane play. There are -- obviously a lot of companies believe coal bed methane could be the next big play to come out of Canada. We are one of them. We are aggressively talking to companies about acquiring acreage, possibly some other companies. We've already acquired 25,000 acres in Canada since the beginning of the year. Just on the open market. That acreage has strong conventional up side potential as well as CBM potential. We're talking to a number of operators in Canada about joint ventures that would allow us to expand our operations there more quickly and allow coal bed methane to develop more quickly than it's already developing in Canada.

Okay. Switching to the Raton, Mark, I see you're planning to drill 200 wells in 2004. That's up from your previous estimate, is that right?

Yes. From 160, 165, it's up to 200. Maybe we'll drill a few more if we have a little cash left over like we did this last year.

So you're taking cash allocated to -- the 25 million, I guess, that you had the reduced in the Forest City Basin and putting it in the Raton?

That's correct.

That and other areas, yes. The majority of it came from Kansas.

Okay. Given the much slower rate of drilling in the Forest City, what should we assume in terms of when we might get a better sense of the commerciality of this play, de-watering status -- de-watering and whether, in fact, it's got commercial coals?

It's hard to predict exactly how long it's going to take to de-water when we can't even get the wells drilled but we know that we'll finish drilling the wells that we had originally scheduled and we'll be anxious to hit the ground running with our new equipment at the middle of the year. We've also restimulated some existing wells that we acquired from others. Given the fact that these coals are, you know, under pressure, certainly undersaturated, we can expect continuous de-watering of at least three and probably more like six months to get significant volumes of gas and that's what we're projecting internally. So by, you know, losing effectively three months of data and holding off the decision to drill more, we simply push towards the end of the year when we think we'll have meaningful -- it's going to be the fourth quarter before we're talking aggressively about results from Kansas. We also have -- we have some long-term leases in Kansas and we feel like we don't have to do too much too quickly because of the leases we're acquiring aren't going anywhere quickly. And we have the time to do it right, so we're going to.

Is it fair to say that reserves that you anticipated booking in the Forest City now will be replaced with reserves in the Raton?

Well, we're going to more than replace reserves from the Forest City with reserves with the Raton because we really weren't projecting very much reserves in the Forest City, and by simply eliminating then, looking at the dollars we're going to spend in other areas such as the Raton, what we can expect to -- what we can expect to get from that, that's why we increased with confidence the lower end of our reserve guidance.

In the past, you've talked about a run rate in the Raton of 160 wells per year. Now with the ramp-up to 200, does that present any logistical problems as far as getting that many wells drilled on production, et cetera?

The only logistics problem is what we just experienced this winter, which was getting wells hooked up as quickly as we wanted to. The -- so we're dealing with that problem, we're increasing the number of crews, both contractor crews and our own that are hooking up wells in the basin to make sure that that does not continue to be a problem. So the answer is we -- if we think we've already dealt with it. Also, a lot of these wells will be more of the nature of infill wells that we've already talked about so they're going to be easier to drill and hook up because the infrastructure isn't very far away.

Okay. Thank you.

Thank you, Greg.

Your next question comes from Ray Deacon from First Albany.

Mark, I had a question on kind of talking about Greg's question. What do you think reserve additions, will they mainly be from the Raton this year? Sounds like that's going to be the vast bulk. Other than the Raton, what other areas do you feel pretty certain you should see reserve growth this year?

We're going to see strong reserve growth in the Piceance and Uintah Basins and in Canada but as Kevin indicated, we also expect to see reserves out of the -- we do expect to see proven reserves out of the Forest City Basin. We're very bullish still about the Forest City Basin, in terms of the geology, the hydrology, the reservoir characteristics, you know, the fact that there's a lot of gas in a lot of coal and shale and tight sands. We may, as we go forward and get more data we will change our expectations as terms of the mix of sand, shale, and coal, but the reality is, there is no negative news, there is no positive news. There's just no news. So we know about as we knew before except that independently we can't get wells drilled by others as quickly as we and they projected. So that's the only thing that's different. So once we have our own equipment there we will be getting after it, and we'll be getting after it aggressively, and I'd be very surprised if we don't book reserves out of the Forest City Basin, but in the absence of getting any data at all it's hard to say how much, I really believe that -- I really believe that the Forest City Basin is going to be a very nice core area for us going forward, and we have not lost sight of that. What we have acknowledged, however, if we can't get things done faster in the Forest City Basin go back to the comment I made earlier about the U.S. business communities' obsession with quarterly results, our opinion is that the market won't sit around and let us take all the time we want with Kansas without showing results somewhere else. So we're simply taking care of business.

Great. Okay. And what's the latest you've heard as far as the revival of the section 29 tax credits? I've seen some guesses by people that the energy bill was going to be scaled back, but if those credits are revived what would it do to your PB-10, or how could it affect your drilling plans?

The latest incarnation of the tax credit if passed would have added a couple bucks to our PB-10.

Right.

But the reality is I've given up trying to predict what Washington will do since I was promised an energy bill two years in a row and for reasons that had to do with one party, it didn't pass the first time. Reasons having to do with the other party it didn't pass the second time.

So the reality is I continue to hear that there's going to be an energy bill that's going to have tax credits that will help unconventional gas. I certainly want to believe that. I want to believe what everybody has to say about it, but the reality is, we have -- I have noticed that we are in an election year, and I think that it will be difficult to get a fully comprehensive energy bill in an election year but what we'll probably get is, you know, energy bill-Lite this year, if we get anything at all, in that it may or may not have credits for unconventional gas. It probably will have credits for clean coal and a few other things, but, you know, quite honestly the energy bill got klutzed up with things that had more to do with ethanol and MTBE rather than anything that benefited any E&P company.

Thanks.

Thank you.

Your next question comes from Thomas Connelly from Penn Square Research.

Good morning. Or good afternoon, it's Tom Connelly in New York. Couple of non-operating questions, mostly for Kevin. Kevin, once again would you just spend a minute with me on the derivative instruments. It's now almost $18 million on the balance sheet compared to a million and a half last year. How does that affect the reported earnings?

Because our derivatives qualify for hedge accounting there is no effect on our earnings at any point in time. At 12/31 we have to record the fair market value of those hedges which is at this point in time is a liability so we increase our liability in the -- and the offset goes to other comprehensive income in the equity section, so it doesn't affect our P&L because of the hedge accounting. That number changes all year long. We've entered into hedges for the entire year. As the market changes that number will change up and down. Just an indication that any one point in time of what we effectively if you looked at it 12/31 looks like we gave up $17 million in income, but that may not be the case as the year goes on. But generally, just to answer your question again, does it not affect our P&L in any way because of hedge accounting.

Right. Is that number about 18 million, is that about as big a number as you had?

I think early last year we entered into some hedges early in the year that had been higher than that but by the quarter end of the first quarter it had dropped off substantially.

And if I understand what you've said, it has no inherent ability to surprise you, because you are able to offset it.

Well, yeah, I mean, it doesn't happen until we actually realize and sell the gas. And ultimately we get, as I noted in one of the slides, we get that hedged gas price for those periods.

Right.

So --.

Would it be fair to say it's a lost opportunity number?

I don't think it's a lost opportunity. We hedged -- let me give you our -- quick and dirty hedging philosophy. Generally we hedge for three reasons. One is to protect our Cap Ex budget. Earlier this -- or later in 2003 we saw that gas prices were moving up nicely, we saw NYMEX in excess of $5, we felt that it was prudent to lock in a significant portion of our 2004 budget. If -- NYMEX doesn't stay above $5 all that long. We wanted to make sure we had an aggressive drilling program for 2004, we wanted to make sure that our cash flow was anywhere from 200 to 220 million which was approximately close to our Cap Ex budget so we locked in a significant number of gas. The second reason why we hedge is to ensure return on our investments. We hedge some of the gas from the Carbon acquisition just so that we could guarantee that return at fairly high rates. And the third thing we use for terms of hedging strategy, if we see a spike in the market we'll hedge some of that gas. When gas hits $7 NYMEX earlier in -- sometime in January we hedged February and March at $7, so we just took an opportunity when gas price reached a certain level.

At $7, you're saying.

$7 NYMEX, so that certainly did not represent a lost opportunity considering that where gas is today for March.

Well, it's a gained opportunity. I was just trying to understand the number. I was not challenging, Mark, your ability to hedge. We've talked about that before. Speaking of NYMEX, if NYMEX is selling at $5 the nearby month, what's the realized figure for Evergreen? Without hedging. In other words, if it went to sell gas today, what would it net to them, to us?

Well, generally taking off basis differentials and fuel costs and so forth it's probably anywhere from 40 to 60 cents depending on whatever situation out there. That's a mid continent. A little more in Northwest Rockies for the Piceance/Uintah, that's probably 70, 80 cents maybe including everything and the same amount for Canada on ACO.

We actually seem to do a little better than that, Tom because we've noticed that hedging, while we prefer to have perfect hedges and not have a problem with surprises in basis differential versus NYMEX, we may not hedge basis at the same time we hedge the actual NYMEX price on the financial trades and we've actually been able to do pretty well with that.

Okay. Back to the balance sheet just quickly, Kevin, the senior convertible notes, do I recall that they're convertible at, what, $25?

Yes, they are. 2006, December 2006.

Right. And the coupon on that, is that 5?

Well it's 4.75 but we have some other interest we pay so right now about 5%.

And what's the company's ability to call the notes now?

First call date is December 2006.

And no conditions other than that if it sells at 150% or anything like that?

No.

No. No other call --.

That's correct.

-- ability. Last question, will you be at the IPAA?

Of course.

I look forward to seeing you and shake your hand, congratulate you on a good year. See you in New York.

Bye.

Your next question comes from David Heikkinen from Hibernia Southcoast Capital.

Hey, Mark, just calibrating reserve growth model. Your Drilling in the Raton, what's the split of wells, PUD versus new reserves? 50/50, kind of in line with the amount of PUDs you had booked with the amount of total locations?

Actually, historically our PUDs in the Raton have always been 35 to 40%, and this year is no exception.

I'm talking about location. You have 468 PUD locations and 1,000 drilling locations, so from a split of 200 wells.

We actually have more than 1,000 drilling locations remaining, Dave. We actually have 13 or 1400 drilling locations. We've just high-graded those 1000 because it's easier to say we have a 1,000 wells and we'll drill another 1,000 wells instead of we have 1027 wells and we'll drill another 1123 wells.

So you're going to drill kind of 50/50 PUDs and new reserves with the 200 wells?

We're paying attention. We're going to infill drill to make sure we get it done and that's going to increase production but we have to have a balance. When we drill, we do a -- we take a careful look at our reserve growth and our goal is to maintain the reported proved undeveloped between 35 and 40% of total proved, so our drilling program is oriented around that.

Okay. On --.

Obviously since we've already stated to the market that, you know, we're going to drill about 100% more wells and have about 80% more production at peak and about 50% more reserves than we are at today, you can figure out where those numbers are going to in the next four to six years. But instead of just going out and drilling wells that will only add reserves that will be difficult to hook up, we will add a balance of wells that add reserves versus wells that are, you know, already with the existing gathering system and we've always done it that way and we will try to finish out drilling program that way over the next four to six years.

And those are still five and six spot wells depending upon where you are?

Yes.

Okay. The acquisition in December just a dollar amount, do you have that, Kevin?

5.5 million.

I missed the LOE splits that you listed per region, Kevin, you went through that.

46 cents for the Raton Basin, it was 91 cents for the -- I'm sorry. 91 cents for Canada, and it was 99 cents for the Piceance/Uintah.

I appreciate that. That was it. Thanks, guys.

Thanks, Dave.

Your next question comes from David Tameron from Stifel Nicolaus.

Good morning. Or it's afternoon now, Mark, you're correct. Can you talk a little bit about, obviously your activities are accelerating tremendously. How do you manage that from an internal perspective? How do you manage personnel? Do you have the people, the bodies in house to rach up production this much and ramp up activity this much? Can you just touch a little bit on that?

Well, that's exactly the issue we were confronted with at the end of the year where our efforts to go into our areas and our ability to get things done and rely on non-Evergreen personnel to get things done was causing us to question the -- that exact deployment. Also, too, as Kevin indicated, G&A increases in the fourth quarter. We're partly responsible for the ramp-up in people to go out and do those new projects. Of course, those projects aren't yet producing, so they're not generating revenues to allocate against those increased costs.

But I think that that is our real challenge this year, is just to make sure that we, as we expand, that we do it in a prudent way that we don't lose the continuity of what we've accomplished, do we have such a -- you know, we've proudly said in the past that we are control freaks, and proud of it. But the reality is that it's one thing to say, it's a whole other thing to get people that buy into that philosophy and make sure that that attention to detail is getting passed along and that the attention to quality control and quality assurance. So I think we've got a great group of people and we're looking for people who fit and we're looking to hire and we are hiring. And we have filled several key slots, and now we're looking to fill self more slots that aren't quite as key, but managing our growth is our only real challenge this year. We have the cash flow, we have the access to capital, we have the credit capacity, we have the project to go drill, we just to have execute and we have to do it and not lose who we are in the process.

Okay. Fair enough. One more question. Did you guys, you know, Great Plains/KLT has had those properties on the auction block in the Forest City Basin, did you guys take a look at those, and anything you can say along that front?

Actually bought about 10,000 acres of it.

Okay. And, I mean, I take it it's adjacent, same county to what you guys have out there today?

Yes, it is.

Care to say what you paid for that acreage?

I forget.

All right. Thank you, Mark.

Thank you.

Your next question comes from Supin Lee from Putnam Lowell.

Hi, I just have one question. Do you have any financing planned in the near term from --?

What answer keeps us out of jail?

So how are you going to finance the -- through cash flow generated from next year?

I think we're always looking at our financing alternatives. Generally we try to do to ensure this year was that our Cap Ex would be 220 million and our cash flow would be anywhere from 200 to 220. Currently we have a $200 million line of credit, a credit facility in Canada, so we have more than adequate credit facilities. The only reason why our credit facility is 200 million, is because we didn't really need more. We could have 300 or 400 million if we needed to, so we are always looking for the best way to finance these project but generally I think we'll be able to finance them out of cash flow.

Just a quick question on the lease operating expenses. The increase in the most recent quarter, is that mainly related to the -- that you use out that contractor, or what's the [INAUDIBLE] to be higher?

The increase in Q4 was that we had projected that back in October because we had delayed several large compressor overhauls that were scheduled maintenance, and those were delayed to the fourth quarter. Therefore, our LOE in the Raton Basin increased to 46 cents from 40 cents in the third quarter.

We had also anticipated that the Carbon property that we acquired have also generally just have higher LOE costs than we do in the Raton Basin for a couple of reasons. One is about a third of the outside costs are owned by -- or really -- or derived from third-parties of which we don't own the gathering system, so we incur gathering costs, we have no control over, and other non-operated properties, so their costs are generally a little higher. Plus, we just really haven't had the economies of scale to reduce that on a per-unit basis. We anticipate in the future we'll be able to help that and we'll continue to try to reduce the non-operated portions of that, and also look at the gathering side of things to see would we can do to enhance and reduce our costs.

I also wonder, for Alaska, are you using any like new equipment or any equipment with newer technology than what you are using currently?

We're using equipment in Alaska in a contractor in Alaska that has a lot of experience drilling wells generally north of where we're drilling, but the contractor has a lot of experience in Alaska and is run by Alaskans, and that's why we were using them. At some point if we go into full development mode, given how slow things are going we'll probably have to purpose-build equipment to fit the project to -- we expect if the project goes into the development mode we expect to the go into that we will probably be constructing equipment specially designed for Alaska geology.

Okay. Thank you.

Again, I would like to remind everyone in order to ask a question, please press star then the number 1 on your telephone keypad. We'll pause again for just a moment to compile the Q&A roster. Your next question comes from Joe Allman from RBC Capital Markets.

Hi everybody.

Good afternoon.

Could you give us an estimate of your unbooked reserve potential first in the Raton, then can you take us to the other areas?

I think we already did when I said we expect reserves to grow another 50%.

Okay. Do you -- could you break down the Raton first a little bit, Mark, just from the coal seams and then maybe from what you're looking at for other -- the interbedded?

That's all coal seam, gas or interbedded gas with the coal seams.

How about the deeper stuff below the coal?

We've given no value to that and that is not in that 50 percent estimate.

Then in Kansas what are we looking at at the resource potential there, on your acreage?

We think it's TCF potential but we've given some guidance in the past that we expect these wells to be about 200 to 400 million cubic feet. Not -- or a quarter to a third of a BCF. Per well, and that are all-in costs to get them, including gathering, will be about, in a full development program, about $175,000. So when you do the math you get very good F&D costs, and if the program works and we are still bullish that it will, that, you know, we expect Kansas to be another wonderful core area for us.

All right. Any shot at what Alaska might provide in terms of up side?

Well, you know, if you look at the coals there in the gas in place, it's clear that there's over a TCF of resource, and given the amount of acreage we are going for minimum of a half a TCF to about a TCF of resource there, but, of course, it's really -- that's just wild speculation to answer your question, because reality is we don't have the data we need to more precisely estimate what that is, what the gas in place is, but that's just based on published geology.

Thank you.

You bet.

At this time, there are no further questions. I would now like to turn the call over to Mr. Sexton for closing remarks.

Thank you all very much. We add very, very good year, very pleased with the results, as indicated we expect to have another record year, really looking forward to this year in our growth and expansion into other areas as well as our continuing growth in the Raton Basin and we think we have a business model that's clicking along well. We acknowledged we tripped a little bit coming out of the blocks but we are hitting our stride, we know what we need to do and we expect to -- expect that the guidance we give will meet or exceed and looking forward to another great year. Thank you very much for following us. Thank you for your participation and your support. And this concludes the conference call.

Thank you. This concludes today's conference. You may now disconnect.