先鋒自然資源 (PXD) 2002 Q4 法說會逐字稿

Good morning. My name is Jeff. I will be your conference facilitator today. At this time I would like to welcome everyone to the Evergreen Resources fourth quarter and year end 2002 conference call. 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 that time, simply press star then the number one on your telephone key pad. If you would like to withdraw your question, press the pound key. I will now turn the call over to John Kelso, director of investor relations

Thanks, Jeff. Thanks everyone for joining us today for a conference call to discuss year end 2002 financial and operating results. Certainly we appreciate your interest. I would like to start off by mentioning this call is being broadcast live over the Internet with accompanying slide show. You can go to the home page at www.evergreengas.com to take a look at that.

It also will be available for replay in the next month. Over the next half hour or so Evergreen management will discuss the press release which provided our operational and financial results for 2002 as well as estimates for 2003. We need to point out these forward-looking statements in the 2003 estimates are made under safe harbor provisions established by the Securities and Exchange Commission.

And that the risks and uncertainties involved with these forward-looking statements are described in more detail in the company's most recent annual report on form 10-K, which is filed with the SEC. We should have the new 10-K filed at the end of March. Actually, the middle of March. We will try to leave as much time for questions after a review of the press release and with that I would turn it over to our Chief Financial Officer, Kevin Collins

Thank you, John.

I will be referring to webcast pages. If you have a chance, you can refer to it. I talked through Nevada some of the important items in the press release. As noted Evergreen reported $1 million or five cents per diluted share. On page five of the webcast we noted excluding the after tax impairment charge of $11.2 million net earnings would have been 12.2 or 62 cents per diluted share.

In September of 2002 the company impaired approximately $34 million for the International properties. For the quarter ended December 31, 2002 we impaired the remaining value for the United Kingdom and Northern Ireland in the Republic of Ireland, which accounted for approximately 13-18.3 million. And this amount was offset by a foreign currency exchange in 1 million, which was related to the Irish project. Because the company wasn’t able to confirm the transaction that allowed Evergreen to exit the UK project, and allow us to complete focus on US developments.

The company believed it was appropriate to impair the remaining value of the UK assets. The property is being offered for sale, which conclude by the end of the second quarter and any proceeds from the sale would be reported as a gain. However, at this time we are unable to estimate what that amount might be.

Evergreen's completion of the sale and the plugging of certain wells will be completed by 2003. P&A costs and other costs were estimated to be $1 million for this year. This $1 million will be offset by foreign currency exchange gain of $1 million which is related to the UK project.

On pages 14, 15 and 16, production for the quarter was approximately ten-point BCF or 114 million cubic feet a day, or about one day sales below the guidance of 10.6 to 10.8 last year.

The total for the year was 39 BCF. As we discussed in the company's 2003 guidance call on January 13 of 2003, production goals were not met in the fourth quarter due to pressure and volume restrictions in certain areas of the gas gathering system. As the existing system did not keep up with added pressure and volumes from the new wells take were brought on line.

In addition, line freezes and above ground gas gathering lateral reduced production from approximately 40 to 50 wells. During December and also the first part of -- the first quarter of 2003.

Production for January of 2003 was 3.535 BCF or 114 million cubic feet per day. Current production is about 118 million cubic feet per day. Exit rate for the first quarter is estimated to be 120 million to 121 million cubic feet per day and production estimates for the first quarter will be in the 10.5 to 10.6 BCF. The upper end of the guidance has been reduced to 10.6 from the 10.7 BCF originally discussed in January of this year.

There are no other changes to the production guidance for 2003. As previously noted the drilling program for '03 is 160 Raton Basin wells and as of February 26 the total number of wells drilled to date is 36.

On slide, on the webcast slide page 17, this is an update of the hedging program for 2003. The numbers shown on this page are net of the realized -- the net realized prices that Evergreen Resources will receive in 2003. As of today the company hedged about 60 to 70%.

Our guidance for the first quarter has been increased to 40 - 45 cents per M C F from the original 30 to 40 cents per M C F. This is due to the work over costs we incurred in January for the 40 or 50 wells affected by the lateral line freeze in December.

Capital expenditures are noted on page 22. Total capital expenditures for the year totaled $130.7 million. This is an increase over our original cap ex budget by about $24.6 million. The increase is due to the following: We added about 10 to 12 deep test wells in '02 which added about 3 to $4 million in our drilling costs. We also drilled additional water disposal wells which added $1.5 million to our drilling costs for '02.

Collection and compression was up $5.8 million. This was due to additional well laterals and water gathering lines laid in 2002. Other Raton Basin costs were up from 10.3 to 13.6 for a total increase of 3.3 million. These additional costs were due to additional re-completions that were done in the fourth quarter to help stimulate production for the remainder of the fourth quarter and also for '03.

Included in these amounts was one to $2 million for 2003 budget costs. Exploration project in the UK and Ireland, $5 million over our original budget and domestic exploration projects we increased from 8.6 to 9.8 million for an increase of $1.2 million. This increase was due to additional acreage acquisition costs.

Year end reserves, year end audited reserves were 1.23 BCF and were in line with our previous estimates. The company had minor down revision of approximately 20 BCF. Extension and discoveries increased significantly in 2002 as compared to 2001. Extensions and discoveries were 247 BCF in 2002 compared to 168 BCF in 2001.

The increase is 79 BCF is primarily due to the net Raton on coal well reserves increasing from .7 BCF to 1.2 BCF in 2002, or an increase of .5 BCF per well.

In addition, sand discoveries, Raton sand discoveries added from 15 BCF to the net reserves.

Oil refinery and development costs were 42 cents for the year as compared to the industry [inaudible] of approximately $1.60 per M C F.

As of January 1, 2003, the company was required to implement accounting standards 143 which is the accounting for asset he retirement obligations. This requires the fair value of a liability for an asset return obligation shall be reported in the period in which it is incurred.

In addition the associated net asset retirement costs or capitalized as part of the carrying amount of the long lived asset.

January 1, 2003, the company will report a cumulative effect change in accounting principle change of approximately $700,000. Additionally, the company will record an increase in the property equipment account of $3.6 million and a plug in and abandonment liability of $3.6 million.

For the year, current estimates for the effect on the P&L are a creation of the plug and abandonment liability of $300,000 or approximately $75,000 for the quarter.

Additional D D.A. expense of $120,000 for the year or $30,000 per quarter. These amounts are immaterial to Evergreen's P&L for 2003. These estimates also will be adjusted on a quarterly basis depending on the drilling activity. Mark, I'll turn the conference call over to you.

Thank you, Kevin. We are excited about the positive year we are going to have. One of the reasons behind our decision to go ahead and write off the rest of the UK is we are going to have such a great year in '03 we didn't want anything out there that could cause any impairment.

We obviously do expect to book a gain based on whatever transaction we do there. We indicate that the some of the joint venture deals we have been talking to would have involved Evergreen staying more engaged than we might have liked going forward. And whatever we do in the UK, other assets, we want to make sure it does not cause a distraction to us in the very positive projects we are working on, continuing development in the Raton Basin.

Continuing our testing and evaluation of Alaska, and looking at other coal bed methane and gas industries in the U.S. and Canada. We don't have a lot to talk about yet on our Alaska project. Except that we will be fracture stimulating one of the pilots. We have eight wells up there that we drilled, oh. One of those four well pilots will be stimulated in its entirety. One of the wells and an additional pilot will be stimulated to give us some idea how that will treat differently.

We want to learn as much as we can about pilot one before we fracture stimulate pilot two. Our goal is to have, to establish proven reserves and try to get production into the local line on or about the end of the year, simply depending on gas quality, how fast we can get it hooked up and some of the things that are going on up in Alaska. We are very pleased that the Alaska legislature and the Alaska regulatory agencies have completely embraced the need for shallow natural gas development in Alaska, particularly coal bed methane.

We are working with the legislature right now on coming up with rules that make more sense for shallow gas wells that look more like water wells by their standards, drilled in Alaska versus high pressure, highly directional wells drilled from offshore platforms or on drilling platforms up on the north slope. [Audio Gap] So the business climate is excellent in Alaska. They still recognize the need for additional incremental gas complies in the Anchorage area and we are obviously pleased to be able to take part in this opportunity.

We think that fight gas and coal bed methane in Canada is also an area that a lot of coal bed methane and unconventional gas oriented codes ought to be paying particular attention to. We are looking for the right Canadian opportunity to get involved there.

The more work we do in the Raton Basin, the more we find, and we are very pleased. The Raton coal wells are going to recover more based on geology and hydrology. We would like to think our drilling and completion an operating techniques, we are extremely pleased to see that the Raton wells that previously, Raton coal wells were previously averaging .7 BCF and are more likely to average in excess of 1BCF and Kevin threw out 1.2 as the average in revisions.

We are starting to get production and reserves from the Raton conglomerates and embedded sands. We are pleased with that and still testing the deep potential. But with so much to do in the Raton coals and Raton conglomerates, our deep glaze is going slower, especially as we upgrade the gathering system to be able to handle incremental gas volume.

We think we are about 50 to 65 percent through the Raton Basin. We still think we have reserves in production there going to probably close to double from where they are today and if we are wrong on that estimate, they will be up at least 50%. There's still a lot to do, still several years of inventory there as we look at continuing to expand our very productive business model to other areas and other unconventional gas basins. With that, we are going to turn this over for questions, Jeff.

At this time I would like to remind everyone, in order to ask a question, press star then the number one on your telephone key pad. We will pause for just a moment to compose the q&a roster.

Your first question comes from David Tameron with Stifel Nicolaus.

Good morning, everyone. Congratulations on another good quarter. Couple quick questions. The reserve revision - Can you talk a little bit about what that is? Obviously with the prices, the revision maybe headed the other way? Give us a little color on that?

I'm not sure if I understood the question. Are you referring to the 20 BCF?

I'm sorry, Mark, the 20 BCF.

It's the existing wells, looking at the [inaudible] performance, as we drill some parts of the field where we emphasized and found some surprises in the Ratons coals and sand. Those reserves were thinner and we backed off a little bit. Not very much. It is not material to our reserve base.

We plan to drill quite a few veer may who wells, hundreds more veer may who wells, but increasingly production and additional reserves will come proportionately from the Raton conglomerate an sands and Raton coals. It's areas that we drill last year tended to be better in the Raton and the veer may who, we thought, should be backed off a little bit.

Now, I will say that if natural gas prices stay above four dollars, our numbers show that we will have hundreds of wells, additional wells to drill, because as we've discussed in the past, we were drilling four wells per section. Our rest reservoir model showed that five per section would be more optimum in terms of recovery and rate acceleration. And if gas prices stay above 4 bucks, that's better

18% to be more exactly. That's not a bad number for the year. I didn't mean to pull the negative out there.

It's worth addressing. It's really a minor statistical blip. I wouldn't read anything into it.

Okay. Along the same lines, did you -- we heard from western gas, El Paso, at all, that everyone has taken a more by the book approach to book an reserves. Did you see any of that?

We took the same by the book approach all along. In other basins it has been become common to book more than one offset away from an producing well as a location. We have not done that in the Raton Basin. And if you go back and look year after year after year our proved undeveloped locations as a total percentage of proved is 35 to 40%. That continues.

One last quick question and I'll let everybody else jump here. On hedging, you guys mentioned you are 60 to 70%. How high will you guys go? You go out and lock five bucks on the mid continent? What is your thinking on that?

In light of the fact that the price us have been so robust, but the general market consensus seems to be the can't stay that robust, except that gas prices continue to defy graphite if I while oil prices are high. If you look the areas we might be weak, if we do more hedging it will be along the lines of the summer strip.

Thanks very much.

Next question comes from Greg McMichael with A.G. Edwards.

I want to thank you guys for beating our estimates.

Our pleasure.

Canada, Mark. You talked briefly about it. Some of the feedback we've gotten from Canadian coal bed methane is that the reserves per section are relatively low up there.

Specifically with regard to the operations of quick silver and enCANDa. What I am hearing or have heard is one to two BCF per section. That's well below what you are getting in the Raton. Are you seeing any evidence of higher recoveries up there anywhere else? Do you still have... Are you optimistic about the potential in Canada?

Keep in mind quick silver and enCANDa, while they have explored a large area, one million acre block, a large area that was in their original joint development area, you know, it is a very small percentage of the entire western carbon section up there.

There's evidence with more thick coals with a lot more gas. Now, because gas is thicker, there still will be problems compared to the [inaudible] compared to the powder river basin and purely gas in place numbers are not the primary tool here. But there's plenty of coal bed methane opportunity in Canada, as well as tight sand, tight shale that we think are attractive opportunities for a company like us with our equipment and our expertise.

We are just looking for the right opportunity to get involved. It's just not necessarily -- you know, coal bed methane will go through a dump stage in Canada. Everyone will believe at some point, if you talk to the promoters up there, they have a bunch of cubic feet of reserves under their property and they want to be paid for it.

Quick silver and enCANDa made an effort in an area that neither condemns nor concludes the existence of coal bed methane in Canada. There's a lot of areas where coal bed methane will be very attractive and others where it's disappointing in Canada like it is in the U.S. It's up to companies to go up there, start drilling wells and experimenting with the processes and plays and get into different geologies, hydrology, rock mechanics and characteristics and see what works in different areas. They have to go through the same dumb stage that we did here

Would you say there's a better than 50 percent probability that you will announce a Canadian program in 2003?

What answer keeps me out of jail?

Okay. Let me move to the deeper Raton for a minute. Based on your drilling results in the deeper Raton, the conventional gas below the coals, what is your latest assessment of the reserve potential in the deeper Raton?

We said all along that we think the wells, if economic, will probably be around a BCF a well. They will probably have it all in cost, 450 to $500,000 as an incremental cost given the infrastructure we have in place. Finding development costs are likely to be 45 to 50 cents. If it works, the deep is not as ubiquitous as the coals, but definitely gas in place and we expect, if it works, that we will have several hundred drilling locations.

We have thrown out prior estimates of 200 to 500 BCF incremental. I have no information to change that estimate.

With regard to the remaining coals on the western edge of your acreage, is there any reason to believe that those coals are thicker than what you've seen on the eastern side of the basin?

The veer may who coals are deeper and do have more gas in place per foot of coal. But there's some thinning going on in the basin sin Klein. They have also -- we get into the deeper places, we find that more of the coals are intruded and with some of the volcanic intrusive and have been coked.

So we just happen to hit an area where that occurred, which is why we backed off a little bit on some of the estimates. We got into areas where they were more [inaudible] and intrusive. We decided to reduce the reserve estimates in that area. It's a local phenomenon.

Is that on the western acreage.

In the western area, yes, but we are nowhere close to drilling up that acreage. I can't say that that statement generally applies to the San Christo unit on the west side.

We nowhere evaluated all the acreage in that unit. We in 2002 hit an area where we had more intrusive. We expected to find some and found quite a few. It appeared to have a slight negative and very nice positive. The slight negative was we decided to back off a little bit on our, we decided to back off a little bit on our veer may who coal estimate. It also caused us to raise our estimates in the Raton coals and to start booking reserves in the sands and conglomerates that are embedded there. I think all of our wells; we expect to be drilling through the [inaudible].

Last question. On Alaska, in the press release you talked about 100 feet thick of coals that you encounter up there with eight wells. Could you speak to the permeability up there? And also with regard to, what are the imply takes of 100-foot thickness of coals relative to what you have on the Raton?

As we have thrown out in the past, the veer may who coals average 25 to 30 feet thick. Raton coals are extremely variable. That's why we get a peak at them after drilling the veer may who. They could be 0 feet thick or over 100 feet thick. And so compared to the veer may who average, recoveries are about one and a half BCF per well.

Looking at Alaska where we have over three times as much coal and not quite as gas, but there is more pressure. We are looking at much less gas in place. Apparently numbers around 100 standard cubic feet per ton versus 400 standard cubic feet per ton. All in all when you adjust for all of that, based on macro gas in place numbers we would expect wells in Alaska to be as good as the veer may who drilling, maybe slightly better depending on permeability. That exactly of course is what we will be testing when we test the wells early this year

Thanks and congratulations on a nice quarter.

Thank you, Greg.

Your next question comes from Adrian Daws whit Hair Well.

Congratulations on a good quarter. Looking at CAPEX and CAPEX guidance for 2002, there was about $14 million or surrounding up of drilling down on the Raton basin project. You split out from the other activities. Were they primarily the deep wells? Is that an indication of what had been spent on the assessment wells?

A lot of those costs came from the deep wells in the fourth quarter. A lot of the losses were because we geared up so much and drilled so much wells, a lot of those costs started coming through in the fourth quarter for us.

Should we expect to see a continuation of those in the early part of this quarter, just given all of the de-bottlenecking as well as the other drilling going on?

We are only going to drill about three deep wells in the first quarter.

Okay. In terms of the --

But you bring up a good point. There is not much point in, we have so many wells to drill in the shallow program and working on larger macro expansions to the gathering system.

Obviously doing some further firms help to sum up the reserve estimates as we go through the year, though.

Yes.

In terms of the spending on de-bottlenecking and improving the pressure characteristics of the pipeline, when do you expect all of those initiatives to be fully deployed and therefore we see further up tick in production volumes?

Well, we thought we had it figured out last year until we got into some higher pressure wells that were a surprise, except that they tended to complete with the lower pressure wells in the gathering system.

So the answer is we are re-looking at the gathering system to look at both right now. It's going to depend on, as you would expect, where we find it and what this particular expansion to the gathering ought to be.

We have eight major compression stations down there. Most of them but not all of them are tied together in some way. Our goal is ultimately to do everything we can to get the best compression benefit. But we are seeing, you know, areas that we drill might have to be in a few pockets it may be that we want to put in separate systems, higher pressure systems for some of the higher pressure wells if they are sufficiently extensive.

We are still looking at that. We decided to go ahead with the aggressive expansions this year. Next year, we won't know until we see the results of this year's work. We will make sure that our system can handle it. It's just, you can drill wells out there and crack them a lot faster than you can go lay pipe.

Great. Thanks.

Your next question comes from Ellen Hannan with Bear Stearns.

Good morning. I think actually Greg nailed most of my questions. One other question I had was, I got distracted at the beginning. Mark, you think you won't have anything in Alaska until the end of the year? Are you will have something by year end?

We will have information by year end, we will have cracked the wells and production testing them and hopefully able to book reserves by the end of the year. It is not clear to me we will have actual sales by the end of the year, but we are striving to have proven reserves by the end of the year. If we can get the gas into the local distribution system and help the local communities around [inaudible], we will strive to do that.

What is the amount of your capital budget spent in Alaska this year?

We spend about $6 million in Alaska in 2002.

And for '03?

Seven to eight million allocated for '03.

Ellen, we are sufficiently encouraged about what we are doing in Alaska, and we do plan to drill another four-well pilot this year.

And Kevin, one last question. Have you given guidance, based on what your hedges are going to give you, the outlook for gas prices, the percentage of taxes to be deferred in 2003?

All the taxes in '03 will be deferred. And probably, depending on if gas prices stay up high, we could possibly pay taxes at the end of 04. We projected 05 before we start having to pay cash taxes.

Great. Thank you very much.

Thank you, Ellen.

Thanks, Ellen.

Next question comes from Barry Saghal with Bream Murray and Company.

Mark, are there any opportunities or threats from the ongoing financial problems that he will pass so is facing?

I hope so.

Can you elaborate a little further?

What answer keeps me out of jail? I'm not trying to be smart, but obviously Williams and El Paso are two companies that have indicated they are ready to sell assets. Williams has indicated that their properties are for sale in conjunction with over $2 billion in properties sales to pay certain debt requirements that everyone is familiar with. El Paso hasn't come to that conclusion. We hope they do and we would very much like to talk to them about purchasing those properties as well.

What is the approximate dollar value of transaction that might be anticipated for both Williams and El Paso?

Here we are in a competitive bid situation and you're asking me what I'll bid?

No, I'm asking, are we talking $100 million or 200 million? What magnitude of reserves are we talking about?

Well, I think the magnitude of reserves, Williams put out they believe they have 133 BCF for sale. We are trying to confirm that as we speak. And we'll, that will probably go into whatever the market value for coal bed methane assets is. It's well documented. I'm not sure what the value and the reserve potential that El Paso has. In their conference call they indicated they took a revision and we are not able to book other reserves because of SEC and other requirements. It is not clear to me, I have an estimate what I think their reserves are and it will stay with Evergreen as part of our strategy, but I don't know what they think their reserves are, Barry.

Next question pertains to the expectation of production, especially relative to what you had shown up in your slides a couple of years ago where different well sets would have peaks and then attenuate over time. Has that experience been born out or do you feel like you need to be a little more conservative?

We have been a little more conservative lately, not because of reserve issues, but just because of production issues. You have several different types of wells, you have Raton wells, which behave differently from Raton conglomerate wells, which behave differently from the veer may who wells which behave differently than the deep wells we brought on line.

We have four macro profiles and inside each of those, inside the veer may who coals, for example, the data shows we have three or four different type curves in there, too. That's factored into our reserve and production growth, what we are finding out, though, is that we have a very, very complex gathering system with over 900 wells producing into it.

We are trying to design it for not just these 900 wells but for the next eight or 900 wells we will put into it. In retrospect we wish some pieces of pipe were in different places or bigger or some of the compressors were tied together differently. We are adjusting for that. It's the nature of gathering systems that they are always evolving, as is ours. So the answer is we have been a little more conservative on our production projections, mainly because of the interactions between the wells competing for space in the gathering systems.

Terrific. You have a wealth of opportunities. I wish you all the very best.

Thank you, Barry.

Thank you.

Your next question comes from Wayne Andrews with Raymond James.

Good morning, gentlemen. Hopefully I'll ask you a question that won't end you up in jail. Mine was really looking at the reserve replacement costs for the year being 42 cents versus 51 a year ago. That was surprising to me they were that low. Maybe you can comment on why you think that was the case and again congratulations on a great year.

Well, I think our costs were pretty much the same year-to-year. The big reason for the decrease in the cost per M C F was due to the significant increase we had in the amount of reserves we had for extensions and discoveries of 247 BCF as compared to 167 BCF. That in it really helped us draw off the cost per M C F. We are able to find more reserves with the same amount of dollars.

I realize that. I was thinking maybe you could point to the fact that you were getting, is it an area that you were drilling in was better? Or was it possibly the deeper additions that really contributed and drove that number down?

It's primarily the areas that we are drilling now. We are drilling more towards the west and the north areas of Anchorage. Those areas have higher reserves per well. The deeper wells only added about, we booked two BCF per two wells for the deep wells. That in it did not add additional -- didn't help reduce the costs in '02.

Another way of looking at it, Wayne, it's a minor statistical aberration where we wrote down the veer may who where the areas that were intruded were offset pi the pleasant and positive results from incremental recoveries in the Raton coals not to mention the various existence of the Raton complex and sand complex.

That's extremely good news. Most companies tend to be drilling the sweet spots first and run into Randy reservoirs and moving out of the say sweet spot. To see you guys moving into even more productive regions in your acreage position is very encouraging. I’m glad to see it. Thanks.

Thanks, Wayne.

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

Two questions. You’ve alluded to this, Mark, with the discussion of a potential acquisition, but given commodity prices you can generate cash flows beyond CAPEX, basically use of that will be to reduce debt. And bull a cash balance?

It will be except as you can tell from some of the prior questions we are coming under increasing pressure to add to the reserve base through future consolidations not only in the Raton Basin but in other areas.

So the answer is yes, we will try to use that capital prudently and pay off some of the debt, perhaps. But debt is almost free right now. And the money we put into paying off debt only generates 2 or 3% return that we are paying off. I think our shareholders want to see us get a higher return. We are going to probably put that incremental money into incremental projects, but we have no desire to police officer pay for anything.

Right. The target or comfortable level of debt, total cap that you are comfortable with is what?

We always capped, the debt cap ratio doesn't mean much for Evergreen because our asset value is greater than our book value. We will keep our stated philosophy has been and continues to be to keep borrowing within three years of projected cash flow.

Very good. Thanks a lot. That's it.

Thank you.

At this time I would like to once again remind everyone, in order to ask a question, press star, then the number one on your telephone key pad.

The next question is from B Putnam from East Border Capital.

There's 161 as well as drilled in 2002, three of those were water wells. In the fourth quarter of the 17 there were two that were waters? Fifteen were gas wells?

Well, go ahead.

I'm not sure when the water wells were drilled. They were drilled throughout the year. I don't know how to answer the question.

I was doing the math and backed into it for the fourth quarter.

We continue to drill water injected wells.

Maybe I should get with John and ask him what went on in 2001 and maybe I can fix the model an find out what are the water wells. The 160 wells for '03, how many of those will be water disposal wells?

Those are all intended to be producers. We have a water injection stemming working well. We will only drill water well if we need another one.

Can you breakdown the on the as I've asked in the past, breakdown the [inaudible] for me on the Lawrence and T M C.

Core Evergreen properties pre-acquisition, we had approximately 81 feet a day. The [inaudible] area, [inaudible] seat area 1.4 [inaudible] cube feet a day.

Do you happen to have the number of units that each of those wells is producing at the present time?

In the net producing wells in the region Primero area is 146. And in the Lawrence seat area there's 68.

So the core, I'm missing a piece. You combined core and --

What would the core be, Kevin?

Core would be 623 wells. That's a net number.

623 net and 146 on 68?

Yes, that should be 837. That's our total net producing wells at 12/31.