Filed by Pioneer Natural Resources Company
pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Evergreen Resources, Inc.
Commission File No. 1-13171

     On May 4, 2004, Pioneer Natural Resources Company (“Pioneer”) and Evergreen Resources, Inc. (“Evergreen”) announced the proposed merger of a wholly-owned subsidiary of Pioneer with and into Evergreen. Set forth below is a transcript of the second quarter earnings webcast conference call held by Pioneer on August 2, 2004.

Pioneer Natural Resources Company’s
Second Quarter 2004 Earnings Conference Call
9 a.m. Central, August 2, 2004

OPERATOR: Welcome to Pioneer Natural Resources’ Second Quarter Earnings call. This call is being recorded. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Timothy Dove, Executive Vice President and Chief Financial Officer; Rich Dealy, Vice President and Chief Accounting Officer; and Susan Spratlen, Vice President, Investor Relations and Communications.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pioneernrc.com. Again, the Internet site to access the slides related to today’s call is www.pioneernrc.com. At the website select “Investors”. Then select “Investor presentation”.

The company’s comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer’s news release, on page 2 of the slide presentation, and in the most recent public filings on forms 10-Q and 10-K made with the Securities and Exchange Commission.

At this time, for opening remarks and introductions, I would like to turn the call over to Pioneer Chairman and Chief Executive Officer, Mr. Scott Sheffield. Please go ahead, sir.

MR. SHEFFIELD: Thank you. Good morning. Again, we appreciate everybody taking the time and effort to listen to our second quarter call.

Beginning on — ones that have access — on slide number 3, we did report a net income of $70 million or 58 cents per share with record cash flow of about $265 million. We continue to reduce debt, getting debt-to-book below 44 percent. Reduced debt about $65 million and $164 million for the six months.

Obviously, what’s most important for the quarter is that we announced in May a merger with Evergreen Resources, which I’ll comment more about how the process is going and the integration. We did complete a debt exchange offer with three series of outstanding senior notes, essentially issuing 527 million and extending out those terms out to 12 years at 5.875 percent.

We continue to buy back stock. Again, second quarter we have repurchased a little over half million shares the first half of 2004.

We did achieve in May first production from Tomahawk, Raptor and Devil’s Tower. Devil’s Tower we just have two wells producing. We’ll have several more wells coming on by the end of this year. Announced a couple of discoveries at Thunder Hawk in the deep water Gulf of Mexico and another successful well where we’ve had 100 percent success rate in our block with ENI, the Dalia #1 in Tunisia, which is already on production.

We did enter a joint venture with ConocoPhillips and Anadarko in NPR-A, and acquired leases of more than 800,000 acres. We picked up a 40 percent interest in Block H, and will be

operator covering 400,000 acres in Equatorial Guinea. And then we awarded all of our leases that we were high bidder on in the Gulf of Mexico lease sale, Central Gulf of Mexico lease sale, where 14 of them are in the deep water.

My next slide, number 4, updating you on the merger with Evergreen. Obviously, we feel like it was one of the best assets in onshore North America, gas assets. It does rebalance Pioneer’s drilling program, provides over 2,000 drilling locations extending our RP ratio, provides us a lot of unconventional gas expertise that we’re already starting to leverage in both — in the Rockies and in Canada.

We expect to mail in the next two weeks, by mid-August, to shareholders and close sometime mid to third week in September. Based on discussions with the SEC so far and comments, we did clear Hart-Scott-Rodino already so obviously we will expect to close in mid to late September.

Slide number 5, we’ve had extensive on-site meetings every week since we’ve announced with the Evergreen staff both in Denver and in Trinidad to ensure a smooth transition. We have made plans — obviously, to accelerate development that we discuss — discussed. We’ll be drilling approximately 300 wells in the Raton Basin in 2005. A lot of that, obviously, is ordering the additional stimulation fleets and also coiled tubing units that we have already ordered and being constructed for use in the 2005 drilling program. We’ve identified several key Pioneer employees that are moving to Denver, and, also, we still expect our estimated cost savings of about $8 to $10 million per year by the combination of both companies.

Slide number 6, again, the importance of this transaction, it does increase our presence in North America. You can see what it does in regard to our lower risk onshore base on slide number 6. Onshore base be about 43 percent of the company’s production with the keys in the Raton, the Piceance/Uinta, obviously, coming from the Evergreen transaction. Providing a fairly good growth profile through 2010, both coming from primarily the Raton Basin and also in Argentina. The impact to the onshore U.S. base by Evergreen is discussed on slide number 7. Production increasing, roughly, about 150 million per day, and when you look at pro forma for the second quarter, increasing percent of company production from 36 percent to 43 percent. As I mentioned already, we’re adding over 2,000 drilling locations to our base, increasing that to about 4,500 locations and extending the RP ratio in our onshore U.S. base to 23, based on pro forma production from both companies second quarter of 2004.

Slide number 8, obviously, Argentina is continuing to hit record levels. We have seen a movement up in gas prices, as we had mentioned, in May, continuing to increase over time. Argentina is importing gas from Bolivia at $1.60 per MCF. As you can see as footnoted, we do not — the residue price right now is 40 cents. When you look at our gas in the Neuquen Basin, on our rich gas, it’s about 55 cents additional coming from the liquid content in several of our more recent discoveries.

In addition, Tim will discuss a new oil agreement in regard to Argentina that was negotiated in late May. In regard to reducing our percentage, we used to — since all of our crude is sold locally—we were getting about 90 percent of WTI. Now above $36 we’re getting 80 percent. Tim will talk more about that and the affect on the quarter and on future quarters. But, again, Argentina continues to grow, ramping up gas production, as you can see, with both our discoveries and also with the continued increased demand in the country.

On slide number 9, just re-emphasizing our offshore producing asset base, continue to see a great performance from all of our key assets, both Canyon Express — Devils Towers still has

several wells coming on over the next six months. Falcon is still performing obviously at record levels and then Sable with our recent injection well being drilled, we’re seeing much better performance out of Sable over the last several months.

In regard to commercialization, the status of several projects, on slide number 10, we’ll be making a decision by the end of the year on our Oooguruk discovery in Alaska, continuing to negotiate our final numbers on a production handling contract for Ozona Deep, and evaluating options for Thunder Hawk, both in regard to evaluating the seismic and when we’ll drill an appraisal well.

Continue to evaluate the gas markets on the gas discoveries that we have made, both in our oil discoveries that are behind pipe and also with our two wells in Anaguid and in regard to bringing on that gas production over the next several years. In Gabon, we did receive approval of our EEA, and we are getting final bids on our numbers here shortly. That project’s still coming on in 2006. South Africa gas, we’re in final negotiations there on our final gas contract price and getting final bids on our development cost, both those projects should be completed in regard to those current negotiations and finalizing plan of developments for both projects by the end of this year. Showing a fairly good ramp up in production in 2006 and 2007 from the series of these projects.

On the exploration side, as I mentioned already, we’ve continued to add acreage both in the Gulf of Mexico and the North Slope of Alaska. We’ve picked up more acreage in West Africa. Still anticipate picking up additional blocks in deep water in several countries, as we are finalizing negotiations, both with ourselves and also with our Kosmos Joint Venture. Ghadames Basin, we’re planning on several wells in Tunisia over the next several months. We’ll drill at least two prospects this winter in the North Slope, plan to drill about six to 10 wells in the Gulf of Mexico in the next 12 months, and then we’ll be probably drilling our first wells with Kosmos and drilling some other wells in West Africa in 2005. From a risked exploration profile, you can see, — on a risked exploration success, the impact to the company’s production over the next several years.

Slide number 12, when you put together each of the characteristics, both — especially with the Evergreen transaction, you can see that we feel very confident that the company can easily grow at 10 percent annualized compounded growth rate over the next several years. In addition, we have several — at least over a billion just in the next two years of excess cash flow in 2005 and 2006. And we have modeled, as we have averaged, about a hundred — a little over $100 million a year of acquisitions. We’re continuing to look at acquisitions in our core areas. In regard to what we could do with that excess cash, we’ll continue to look at buying back stock. Obviously, the first amount of cash flow, which Tim will talk about with a slide, will be used to reduce debt, and that will completed by the end of first quarter of 2005. But obviously, we still have a lot of excess cash flow in this environment.

Let me stop there and turn it over to Tim to go over the second quarter.

MR. DOVE: Thank you, Scott. The second quarter was a solid operational quarter for us, as we reported record production and operating cash flow for the quarter. Earnings, as Scott mentioned, did come in at the lower end of guidance for three specific reasons that I will cover in the next slide.

On slide 13, we show, again, $70 million of net income, about $.58 per share, and operating cash flow of about $265 million. That’s up 39 percent from last year’s second quarter. DCF, discretionary cash flow, we reported $295 million. That’s $2.45 per fully diluted share. And in

the case of EBITDAX, we reported $326 million for the quarter. That’s basically on our projected run rate of $1.3 billion per year.

Turning to slide 14, I thought I’d cover some of these items in a little bit of detail, just to give you a feel for these items that did affect the earnings. There were three main items, two of which were mostly noncash charges that caused earnings to come in at the low end of our earlier guidance. As Scott mentioned, at the end of May, we got some information regarding oil realization changes in Argentina. As you recall from some of our prior discussions, the government imposed a 20 percent export tax on crude oil during 2002. And through time, because of that, we have diverted most of our sales into the domestic market where prices had gradually returned close to parody with WTI, as Scott mentioned, about 90 percent of WTI. During the latter part of the second quarter, the government, of course, has been faced with a very difficult dilemma, as they’ve been trying to keep a lid on domestic gasoline prices, despite the fact that crude oil rose from $35 to $40 — over $40 a barrel. And, as a result, the government has implemented a new pricing structure — again, Scott covered some of this — for domestic oil sales during the quarter, the latter part of the quarter specifically, that, in essence, has lowered the domestic prices to export parody. And the result was, for us in the quarter, we reported a differential of almost $14 per barrel off of WTI for Argentine oil sales, including some prior period adjustments. And you can see some more information on that back on slide 31, where we provide supplemental information on the differentials. Although, in the future, we don’t anticipate the differential remaining this high, we are concerned about how the government’s going to roll this structure forward into, perhaps, this quarter and maybe thereafter. It’s very unclear right now exactly how long this situation will last.

But I thought I’d give you some information on how the formula works. It is only in place and applicable in the case where WTI is between $32 and $42 per barrel. In the event that WTI is over $36, the producers receive 86 percent of the price they would otherwise receive. And for WTI below $36 — I’m sorry — for over $36, the producers receive 80 percent, and below $36, the producers receive 86 percent of the price they would otherwise received. So, as an example, if you just use a WTI of $42 per barrel and you take into consideration the normal quality and transportation and differentials we have shown through time—about $4 per barrel, this would yield a net price in Argentina of about $38. So with the new structure, the producers receive 80 percent of $38. This is in those cases where WTI is over $36, or about $30 per barrel. And that then, represents about a $12 differential off of WTI. Obviously, we’re not very happy about this. It’s a significant tax on producers and will have a negative impact on our Argentine results as long as it’s in effect. Hopefully, it will be offset somewhat by plan increases and gas prices that we have already begun to see, as Scott showed you in that one slide.

Secondly, the second topic relates to exploration expenses. Overall, exploration expenses came in near the top of our range, including all categories of expense. We reported about $40 million or so of exploration and abandonment expense, along with G&G for the quarter. In addition to new investment and seismic in Argentina and Alaska, we did drill a dry hole on our first well in EG, which represented about $6 million of exploration and abandonment expense.

In addition, we also have the right to recoup about $5 million of additional costs that we incurred in drilling the well from one of our partners from future production. But because the first well was successful, we have to write off this receivable as other expense during the quarter. And what we’ll have to do is wait for a future exploration success in EG that establishes revenue in order to re-establish that receivable as an asset. So, as a result, other expenses were hit by that amount. The other expenses also included a noncash charge of about $2 million related to some oil hedges that were FAS 133 ineffective and over a million dollars in relation to expenses for our senior note offering.

As Scott also mentioned, we have filed and the Gabonese government has approved our EEA, and, as a result, we were forced to abandon a well that was drilled in 2002 along the southern portion of the Olowi oil rim, which is not a part of the current development plan, and that led to a noncash charge of about $9 million during the quarter.

Finally, we report a relatively high income tax provision of about 43 percent. This is higher than what we’d normally have in U.S. statutory—and this is federal and state rate of about 36 and a half percent, mostly because of these international exploration and abandonment expenses that I just discussed. In the case of the EG well expenses, the deferred tax benefits that were created by the dry hole, we can’t recognize until we have future revenue that will allow us to use them. Now, in the case of Gabon, we don’t pay income taxes. Actually, taxes are sort of boiled into the royalty, so we pay a higher rate of royalty to account for them. So the expensed well that I mentioned on the southern part of the oil rim doesn’t provide any tax benefits. So in both of these cases, although we incurred the expenses, we received no corresponding reduction in our income tax expense. And, actually, for the third quarter, we’re forecasting more of a normal range, say 36 to 39 percent income tax provision, based on our current spending plans. Obviously, as we look ahead, it’s going to be important to be calculating country by country spending and tax rates in those countries in order to get the tax provision estimates accurate. It is important to note, I think, that our cash taxes for the quarter were just under $5 million, due to our significant tax attributes, so most of the things I’m discussing on these tax items are noncash. We anticipate that cash taxes will be somewhere in the range of $4 to $8 million in the third quarter.

Turning to slide 15, going through some of our normal slides, revenue was essentially flat during the quarter with the first quarter. Even though production was up slightly, we did have the Argentine oil realization effect and hedges, which had the result of keeping overall revenue essentially flat.

On slide 16 covering production, again a very strong production quarter. Overall gas sales up to 722 million cubic feet a day—we were up in both the U.S. and Canada slightly. U.S. production was 558 million cubic feet a day for the second quarter, as compared to 550 in the first. And Canada was up to about 41 million cubic feet a day, up slightly from 40 in the first. So overall production in North America, 599 million cubic feet a day. Argentina had a tremendous quarter, of course, as they’ve had great winter demand—122 million cubic feet a day. We anticipate their demand to be also strong as we go into the third quarter. If you take a look at oil in the blue, oil’s 45,000 BOE a day. That’s down slightly, principally just because of timing of Sable oil sales. If you take a look at the effects of the new production, Tomahawk and Raptor did not begin producing until mid-June, so they really had little effect on the second quarter. They’ll have a larger effect on the third. And Devils Tower, even though it came on in late May, it was only with one well, and now we have two wells producing, so it didn’t have much of an effect in the second quarter. Each will have a bigger effect in the third as we bring on two more wells at Devils Tower and you get the full quarter for Tomahawk and Raptor. As a result, our production range for the third quarter should be 185,000 to 200,000 BOEs per day.

All of the numbers I’m referencing here exclude Evergreen. In fact, all of the numbers we’re showing you for the third quarter estimates do not include Evergreen. Upon the successful closing of an Evergreen transaction, we would come out and revise guidance at that time.

Turning to slide 17, daily production volumes—again, you see the effect in Africa of a reduction in production down to about 10,000 BOE per day, again the timing of South African cargo liftings. We do anticipate the production being up in the third quarter due to the reasons I

mentioned, but also it will depend — the range will depend upon how many cargoes of both South African and Tunisia oil actually can be booked for the third quarter.

On slide 18, we show pricing. I’ve already discussed the effects in terms of oil, and you can see that in the bar where our realization drops somewhat to just under $28 per barrel. In the case of gas, even though NYMEX was slightly higher for the second quarter, we did have a higher component of Argentine gas at a lower price during the quarter, and, of course, you have the normal hedge effects.

On slide 19, production costs, our production costs were up slightly. They’re in the range for the guidance for the second quarter. The real reason for this is really identifiable to one project, and that’s Devils Tower. When we bring Devils Tower on production in May, we began to make fixed cost payments for both May and June, even though our production was limited for both of those months, just a contractual relationship between us and the spar provider. As a result, that explains almost all of the increase in the base LOE. We’ll begin to see that come down through time as the Devils Tower production ramps up, of course. We do anticipate that the range will be similar in the third quarter, $5.40 to $5.90 per BOE.

Slide 20—other costs, we show G&A having been $17 million for the second quarter. I anticipate a similar range slightly higher in the third, as we will have the expensing certain integration costs pertaining to Evergreen. In interest, $21 million for the quarter. It should come up a little bit in the third quarter because we don’t anticipate any capitalized interest during the third quarter. DD&A for the second quarter was $8.37 per BOE. That’s in our range of guidance. Third quarter we anticipate being slightly up, $8.75 to $9.25, as we again get the effect of higher production in higher basis wells, Tomahawk, Raptor and Devils Tower being the principal ones, will have more production impact. Those are higher cost basis projects, and at the margin increase overall DD&A rates.

On page 21, I pretty much already covered the whole business of exploration and abandonments. We did have significant seismic expenses during the second quarter, principally Alaska and Argentina. Of course, those are, as I would say, investments in the future, and we’ll have the same in the third quarter where we some substantial expenditures in West Africa, deep water, and Alaska that will hit the third quarter earnings. The range we’re posting is about $25 to $45 million for the third quarter, and it will include those seismic charges.

On page 22, we incurred about $185 million of capital during the quarter. A couple of notes regarding acquisitions—we were able to close a $20 million Spraberry small tack-on acquisition, and that number that’s shown of $52 million for acquisitions and land also include our acquisitions of Gulf of Mexico leases, as well as Alaska, the NPR-A and related matters.

If you then turn to page 23, Scott already covered our debt reduction results, $65 million down for the quarter. We are on target to meet our debt reduction targets that we announced pertaining to the Evergreen transaction about $600 million. And I anticipate, looking at our modeling, that that should be sometime by the end of first quarter. We’ve already achieved $164 million, which leaves $436 remaining, and I feel very comfortable we’ll meet that target in early 2005.

On page 24, we show our hedge position. Really, there are no changes to this hedge position. It does not include any hedges that were put in place on Evergreen’s books that were made after the merger announcement. These are just the Pioneer hedges. As already mentioned, we do have supplemental slides as usual. Those are slides 27 to 32 in which we cover the typical

items such as non-GAAP financial measures and the impact of terminated commodity and interest rate hedges and also this business of the oil and gas differentials.

So with that, I’ll pass it back to Scott.

MR. SHEFFIELD: Thank you, Tim. We’ll open it up for questions.

THE OPERATOR: Thank you. The question and answer session will be conducted electronically today. If you would like to ask a question, please press star 1 on your touch tone telephone. If you are using a speaker phone, please make sure your mute function is turned off to allow your signal to reach our equipment. Once again, it is star 1 to ask a question.

We’ll go first to Brian Singer of Goldman Sachs.

MR. SINGER: Good morning.

MR. SHEFFIELD: Hey, Brian, how are you doing?

MR. SINGER: Good, how are you? A couple questions. First, on Evergreen, any more clarity on your expectations, assuming that the merger does complete, for production growth or how — you know, to what extent you want to invest money in Evergreen’s CAPEX and to what extent you want to grow production in 2005?

MR. SHEFFIELD: We will not come out with our 2005 budget, Brian, probably until late November, mid-December, and we’ll give out target ranges at that point in time. But, really, based on what we’re seeing in 2005 and what they’ve stated publicly, we don’t see much of a change. Obviously, we are going to be accelerating the drilling activity and will factor that in, in regard to when we give out estimates in late November, early December. But we will be accelerating the activity in both Raton, and it looks like with some initial results up in Canada and some of the coal activity that we’re seeing already with the re-completions, we may be accelerating that activity also.

MR. SINGER: Great. With regard to Argentina, can you talk more about the cost structure there and how your returns compare versus some of the other regions, especially in light of the oil price issue?

MR. SHEFFIELD: Yeah, the — in regard to oil drilling, one of the big benefits we’re getting is the fact that we’re still way below 2001 cost because of the devaluation of the peso, so it is still our lowest finding cost division. So that’s the big plus. It’s also our lowest operating cost division. So even though revenues are less than, for instance the U.S., obviously, we get those two big benefits. So we’re still seeing tremendous economics on oil drilling, continuing to run several rigs. On the gas drilling side, in most of our new gas drilling, we’re essentially getting $.65 to $.70 escalating to a little bit over a dollar over the next 12 months. When you add somewhere between $.40 and $.65, we’re seeing — and the fact that the finding costs are only about $.25 an MCF on the gas side, it’s very, very economical.

MR. SINGER: Has your LOE at all ticked up with the tick up in gas prices, and can you be specific on what your latest LOE rate is?

MR. SHEFFIELD: Yeah, it’s not much. It’s still running about the same.

MR. SINGER: Great. And I know you mentioned that Devils Tower and Tomahawk/Raptor did not contribute that much to second quarter production, but are there any specifics on the contribution to oil and gas production from each of those projects?

MR. SHEFFIELD: We’re not going to give out details, but it’s very insignificant. You only have one well producing for — you know, I think it produced about 15,000 barrels a day. We only had 25 percent of it for 30 days. Tomahawk and Raptor came on like expected and we’re producing over 300 million a day gross at the Falcon area. So it will have a lot more impact during the third quarter.

MR. SINGER: Great. Thank you.

THE OPERATOR: We’ll take the next question today from Ray Deacon, Harris Nesbitt.

MR. DEACON: Hey, Scott. Can you tell me, what are the next steps in Oooguruk in Alaska to establish commercialization there? Is it more drilling? Is it, you know, is it acreage acquisition, or —?

MR. SHEFFIELD: No. It’s really we collected lots of core and log data and seismic data from an agreement with ConocoPhillips, and then we’re combining the recent discoveries with Kerr McGee, to see if there’s any potential of tying both projects in together and making that decision. So that’s really the key driver. In addition, we are going to the state and asking for some royalty incentives also, so there’s several things working on both the reservoir — reservoir end, royalty end, and also with Kerr McGee’s discoveries that were involving all three components.

MR. DEACON: Okay.

MR. SHEFFIELD: But the crude — if you look out at the strip market, in the crude strip out in the 2007 and ‘8 and ‘9, it’s up to about $33. So as we continue to make that decision, the long-term crude environment, obviously, where we could easily hedge is getting better and better.

MR. DEACON: OK. Can you talk at all about, you know, your plans on the Evergreen assets for the coal bed methane potential in Canada and what they had in the Piceance/Uinta. Is there any capital plans for that?

MR. SHEFFIELD: We’re putting the teams together on all three pieces. We have not officially increased any activity at this point in time. We’ll make a decision in November or December. But we’re trying to solve some of the issues that Evergreen has had in regard to gathering in regard to Piceance/Uinta. We’re assigning a lot more people to evaluate the opportunities to accelerate the drilling, and we’re doing the same thing in Canada.

MR. DEACON: Okay. Great. Thanks a lot.

THE OPERATOR: We’ll take our next question today from Andrew O’Connor, Strong Capital.

MR. O’CONNOR: ‘Morning, Scott. ‘Morning, Tim.

MR. SHEFFIELD: Hey, Andrew. How are you doing?

MR. O’CONNOR: I wanted to know, given current spot and futures prices for oil and gas, and looking ahead to next year, how are you guys inclined to change what you currently have hedged or is in place for 2005?

MR. SHEFFIELD: Right now, the only thing that we will do is unless there’s a project specific, I think it’s too tight a supply and demand in regard to prices, crude is still in extreme backwardation going —

MR. O’CONNOR: Right.

MR. SHEFFIELD: — going from $43 to $33, so we’re probably not going to do any hedging at all on gas or crude unless it’s project specific. For instance Oooguruk, if we sanction that project at the end of the year, you’ll see us do some hedging in 2008 — 2009, to lock in the economics at $32-$33. We will probably not do anymore hedging.

MR. O’CONNOR: Okay. That’s helpful. Thanks, guys.

THE OPERATOR: Now we’ll hear from Richard Frairy, Delphi Capital Management.

MR. FRAIRY: Yes, good morning. I think in the early part of the call you mentioned something about 10 percent growth, and I’m wondering if that’s production from the drill bit or what that number means.

MR. SHEFFIELD: Yes, almost all of our growth over the past five years, we’ve averaged about 12, has been organically through the drill bit.

MR. FRAIRY: All right.

MR. SHEFFIELD: And most of it going forward will primarily be through the drill bit over the next five years.

MR. FRAIRY: I see. Very good. Thank you.

MR. SHEFFIELD: Okay.

THE OPERATOR: And once again, if you do have a question today, please press star 1 on your touch tone telephone. We’ll hear next from Louis Parks of Chesapeake Partners.

MR. PARKS: Hi, good morning. Just as it relates to Evergreen and after the completion of the merger, can you just go through the options that you will have for the Forest City assets that they were unable to get an acceptable bid on. Do you intend to keep those or some further divestiture in the future?

MR. SHEFFIELD: Yes, we’ll make a decision at closing whether or not to try to — I think there was some interest in some smaller acreage parcels in regard to some farmouts, whether or not to farm those out. We’ll have to make that decision at the time and evaluate the current opportunities.

MR. PARKS: Thank you.

THE OPERATOR: We’ll take the next question from Mark Meyer, Simmons & Company.

MR. MEYER: Morning, Scott. One question.

MR. SHEFFIELD: Yeah, Mark.

MR. MEYER: I guess the change in the Argentine oil price formula sounded like it was a bit of a surprise. I just wanted to know any thoughts on whether the risk to actually capturing some of the higher gas prices has gone up, given what you see on the ground there in terms of the economic pressures that the country is experiencing.

MR. SHEFFIELD: No, because the — on the gas side, even though it’s probably getting up to a dollar — including liquid prices will be up between $1.50 and $1.75 within about 12 months. With them having to rely for the first time on imports from other countries, such as Bolivia, and paying $1.60, they’re going to have to allow prices to continue to increase higher because they’re only alternative is fuel oil or LNG over a long period of time. They have still a lot of gas potential in Argentina. They did put a 20 percent export tax on in regard to gas prices. I think as they allow prices to escalate, the government will be able to capture — as they see the price increase, capture any profit there on exported gas only. So in regard to crude, the time — obviously, we didn’t see crude going to $42 a barrel in late May, so we saw it as a 4 percent reduction. We were getting about 90 percent of WTI. So under the agreement, it was 86 percent, but, obviously, with crude over $36, that it’s down to 80. I really see that staying about the same.

MR. MEYER: Okay.

MR. SHEFFIELD: So, as long as we don’t see the pressure on the cost side of the business, projects are still very economical on the crude side.

MR. MEYER: Scott, one more real quick one. On Devils Tower, the first two wells, what was the completion time, start to finish?

MR. SHEFFIELD: I’ve got a couple of people in here. I’ll have to let them address it. Start to finish, I got Bill Hannes in here and Jay Still. Do y’all know? 25 to 30 days per well.

MR. MEYER: Okay. Is that being used as an assumption going forward?

MR. SHEFFIELD: Yes, in regard to our modeling for the other six wells, so you’ll see probably a well come on every month.

MR. MEYER: Okay. Very good. Thank you.

THE OPERATOR: We’ll take the next question from John Selser, Maple Leaf Partners.

MR. SELSER: Yes, good morning.

MR. SHEFFIELD: Hey, John.

MR. SELSER: On the shares outstanding, you noted that you had re-purchased a half million shares, but the number went up quite a bit in the last six months. Were there new shares, or was that all options?

MR. SHEFFIELD: Yeah, we have options that expire-they have short term-5 years, and any new shares that were issued were options.

MR. SELSER: Thank you.

THE OPERATOR: The next question will come from Rehan Rashid of Friedman, Billings & Ramsey.

MR. RASHID: ‘Morning.

MR. SHEFFIELD: Hey, Rehan.

MR. RASHID: Quick question on Evergreen, and I don’t mean to get too nitpicky, but I think the guidance from Evergreen for the second quarter production was 12.3 to 12.4. They came in at 12.1. Any thoughts on that front? Anything in particular going on, just inter-quarter variation?

MR. SHEFFIELD: I think they were within their guidance, Rehan. They’re at the low end of their guidance, and it happened to be from a couple freezes they had in April, snowstorms, and also the fact that they hadn’t completed one of their main trunk lines yet in regard to tying in about 54 wells that haven’t been tied in yet, so those are the two reasons Piceance in Canada performed better than expected.

MR. RASHID: Got you. Thank you.

THE OPERATOR: Next we’ll hear from John Zaehringer, Loomis, Sayles.

MR. ZAEHRINGER: You don’t expect to capitalize any interest in the third quarter. What did you capitalize this quarter and did you capitalize any G&A expenses as well?

MR. SHEFFIELD: Yeah, capitalized interest was $700,000 for the second quarter. We do not anticipate capitalizing any for the third quarter. We did not capitalize G&A.

THE OPERATOR: Mr. Zaehringer, did you have anything further?

MR. ZAEHRINGER: No.

THE OPERATOR: Okay. At this time, if there are no further questions, I’ll turn the conference back over to our speakers for any additional or closing remarks.

MR. SHEFFIELD: Okay. Again, thanks, and we appreciate everybody taking the time and effort to listen in. We look forward to seeing people out in conferences and on the road. We’re obviously very excited about closing this transaction in September and moving forward. Looking to another great year in 2005. Again, thanks. Please call us if you’ve got any questions in regard to the call or the press release. Thank you.

THE OPERATOR: That does conclude today’s conference. We would like to thank you all for joining us today. Have a great day.

Legal Information

     This filing contains forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, particularly those statements regarding the effects of the proposed merger and those preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” or similar expressions. Forward-looking statements relating to expectations about future results or events are based upon information available to Pioneer and Evergreen as of today’s date, and neither Pioneer nor Evergreen assumes any obligations to update any of these statements. The forward-looking statements are not guarantees of the future performance of Pioneer, Evergreen or the combined company, and actual results may vary materially from the results and expectations discussed. For instance, although Pioneer and Evergreen have signed an agreement for a subsidiary of Pioneer to merge with Evergreen, there is no assurance that they will complete the proposed merger. The merger agreement will terminate if the companies do not receive necessary approval of each of Pioneer’s and Evergreen’s stockholders or government approvals or fail to satisfy conditions to closing. Additional risks and uncertainties related to the proposed merger include, but are not limited to, conditions in the financial markets relevant to the proposed merger, the successful integration of Evergreen into Pioneer’s business, and each company’s ability to compete in the highly competitive oil and gas exploration and production industry. The revenues, earnings and business prospects of Pioneer and the combined company and their ability to achieve planned business objectives will be subject to a number of risks and uncertainties. These risks and uncertainties include, among other things, volatility of oil and gas prices, product supply and demand, competition, government regulation or action, foreign currency valuation changes, foreign government tax and regulation changes, litigation, the costs and results of drilling and operations, Pioneer’s ability to replace reserves, implement its business plans, or complete its development projects as scheduled, access to and cost of capital, uncertainties about estimates of reserves, quality of technical data, environmental and weather risks, acts of war or terrorism. These and other risks are identified from time to time in Pioneer’s SEC reports and public announcements.

     The proposed merger will be submitted to each of Pioneer’s and Evergreen’s stockholders for their consideration, and Pioneer will file with the SEC a registration statement containing the joint proxy statement-prospectus to be used by Pioneer to solicit approval of its stockholders to issue additional stock in the merger and to be used by Evergreen to solicit the approval of its stockholders for the proposed merger. Pioneer will also file other documents concerning the proposed merger. You are urged to read the registration statement and the joint proxy statement-prospectus regarding the proposed merger when they become available and any other relevant documents filed with the SEC, as well as any amendments or supplements to those documents, because they will contain important information. You will be able to obtain a free copy of the joint proxy statement-prospectus including the registration statement, as well as other filings containing information about Pioneer at the SEC’s Internet Site (http://www.sec.gov). Copies of the joint proxy statement-prospectus can also be obtained without charge, by directing a request to: Pioneer Natural Resources Company, Susan Spratlen, 5205 N. O’Connor Blvd., Suite 900, Irving, Texas 75039, or via telephone at 972-969-3583.

     Pioneer and its directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of Pioneer in connection with the proposed merger. Evergreen and its directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of Evergreen in connection with the proposed merger. Additional information regarding the interests of those participants may be obtained by reading the joint proxy statement-prospectus regarding the proposed merger when it becomes available.