Good day, everyone and welcome to the EOG Resources 2008 Second Earnings Conference Call. As a reminder, this call is being recorded. At this time, I would like to turn the conference over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second quarter 2008 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates on this conference call and webcast including those for the Barnett Shale and North Dakota Bakken plays may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. An updated investor relations presentation and statistics were posted to our website this morning. With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President of Investor Relations. The theme for this quarterly call is consistency. As you can tell from our financial and operating results, we continue to deliver what we promised to you at the beginning of the year. That's been a company hallmark and we are proud of it. We filed our 8-K with third quarter and full year 2008 guidance yesterday. These projections are consistent with the guidance we provided earlier in the year and I'll discuss them in a minute when I review operations. I'll now review our second quarter net income available to common stockholders and discretionary cash flow and then I'll provide an operational review.…

Thank you, Mark. For the second quarter 2008, total exploration and development expenditures, including asset retirement obligations, were $1.15 billon with $6 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $108 million. Capitalized interest for the quarter was $10.1 million. Year-to-date exploration and development expenditures, including asset retirement obligations, were $2.27 billion with $35 million of acquisitions. Total gathering, pipeline and other expenditures were $196 million. At quarter-end 2008, total debt outstanding was $1.147 billion and the debt to total capitalization ratio was 13%. At June 30, non-GAAP net debt was $1.039 billion or net debt to total cap ratio of 12%. The effective tax rate for the quarter was 28%, and the deferred tax ratio was 58%. The press release also highlighted a dividend increase of 12.5%. This is the second dividend increase this year and the ninth time the Board of Directors has increased the dividend in nine years. Yesterday, we filed a Form 8-K with third quarter and full year 2008 guidance. We also filed the second quarter 10-Q which has our updated hedge position. With our current hedge position as outlined in yesterday’s 8-K filing, for every $010 change in the average 2008 Henry Hub strip, EOG's 2008 net income and cash flow is impacted by approximately $20 million. Similarly, for every $1 move in the average 2008 WTI strip, EOG's 2008 net income and cash flow is impacted by approximately $10 million. For the full year 2008 the 8-K has an effective tax range of 32% to 36% and a deferral percentage of 65% to 75%. Using the midpoint of the updated 8-K guidance our full year 2008 unit cost for lease and well, DD&A, G&A, total exploration, net interest expense and excluding transportation and taxes other than income, our forecast increased 4.4% over 2007. Estimated capital expenditures for 2008, excluding acquisitions are now $4.75 billion, reflecting a $370 million increase. Approximately $100 million of the increase is related to increased gathering and processing activity in the Bakken and Barnett. The increase in exploration and development expenditures is due to drilling activities and significantly increased leasing costs in new areas. Now I'll turn it back to Mark to discuss the gas macro, hedging and his concluding remarks.

Thank you, Tim. Regarding the worldwide oil supply demand picture, we believe oil prices will be highly volatile but will move directionally higher over the next five years because we see oil demand, particularly in Asia and the Middle East outstripping worldwide supply growth. In our mind predicting the North American gas market is more difficult because of the big influence of winter weather. Although there are current figures about domestic supply growth, we see the market as currently balanced based on the last nine weeks of storage injections with only one week out of range and that week was slightly affected by the July 4th holiday. As we mentioned in the last quarter, we still expect November 1st storage to reach 3.3 Tcf to 3.4 Tcf which will be a bullish harbinger for 2009. I'm a big believer that winter weather has a very large effect on ensuing years gas prices so if someone could tell me how hot or cold next winter will be then I will tell you the 2009 gas price. I will also comment regarding North American supply growth in a macro sense. We see the overall total Barnett field gas production peaking in 2009 at about 5 Bcf per day and then plateauing in 2010, 2011. Therefore, new resource plays will have to be the growth driver after 2009 and we don't see the British Columbia Horn River Basin filling that gap until 2011 plus. When you view supply growth in this context, the possible emergence of new domestic resource play is more digestible. Our 2008 oil and gas hedge position is unchanged from the last earnings call. We have added to our 2009 gas hedge position and as a percentage of North American total… North American natural gas production we are currently 36%…

[Operator Instructions]. We will have our first question from Bian Dale [ph], Bernstein.

Hi, Mark.

Hi, Bian.

I had two questions, one was on the China assets. If I'm right the gas price domestically in China is set around $3.25. Is that what you're receiving and do you believe you are going to see upside in there as the government tries to raise the domestic gas price?

Bian, the gas price that you mentioned is not the gas price we are receiving but it's not totally out of the range either. Gas prices in the Sichuan basin are controlled by the government, but it's a negotiated formula and that formula is confidential, but it is tied somewhat to exports and somewhat to local consumption. I would say that the price is kind of at the high end of what would see as long-term prices in Trinidad right now. The gas demand, as we see it, is definitely increasing in China with time. Gas prices are on the upswing there. So, we are happy with the gas price that we currently have negotiated and feel like we can make a very good rate of return on the asset there as long as we can make the horizontal program work.

Do you mind telling me whether it's above or below the $3.25?

We are not really going to tell you the exact number, but it is certainly… right now in Trinidad I think our 8-K number is like $3.17, $3.20 something like that and we are in a range above that.

Right. And my second question was just on some of your oil shale plays. I was trying to get a feel for what sort of oil price would make a moderate activity in those plays? I think, Mark, you commented before that you believe the economics are still pretty good at $70 a barrel. Is that just sort of a number that you’d be looking for before you would change your activities there?

Yes, we… $60 a barrel something like that, Bian, would be a number where we would start to think twice about it. I mean, at the current $120 a barrel we are making extremely high reinvestment rates of return on all of our oil shale plays. So, there's a lot of fat in there is the way I would describe it.

Okay.

Economic fat.

Okay. Thank you.

We will go next to Thomas Gardner, Simmons & Company.

Good morning. Hey, Mark, you mentioned in light, you mentioned that you've increased your natural gas hedges in 2009. So, when you look beyond 2008 are you still bullish on North American natural gas or do you see the possibility of strong supply growth leading to gas on gas competition? And what do you see the governors to North American and natural gas supply being?

For 2009, Tom, my sense is we'll start the heating season with between $3.3 and $3.4 in storage which will be a little bit lower than last year, but not a crisis point lower. And then, I believe it's really kind of a weather call. I think if we have a normal winter or a cold winter we are going to be, at least in E&P comp, we will be very happy with the 2009 gas prices but there is a risk that if we have an extraordinarily hot winter I think the whole sector will probably be a bit disappointed in the gas prices. I really… the point I would make is that I think in a lot of analysts’ minds the Barnett Shale which has been by far and a way the biggest single growth driver of domestic production growth for last three or four years, I think, a lot of people believe the Barnett Shale is just going to continue to grow indefinitely year after year after year and our view is that the Barnett Shale as an aggregate probably has one more year of decent growth and that's 2009. And by year-end 2009 we believe Johnson County is going to be pretty well drilled up buy all operators on about 35 acres spacing. And that's going to remove a lot of the thrust. There will be continued drilling in Tarrant County but that's an urban area and the rate of drilling there is not going to be anything to write home about. So, when people view the gas macro 2009 and later, you ought to assume in our opinion that the Barnett is just not going to be the big driving force except for one more year.

Thank you for that. Jumping over to the Bakken, you mentioned that your 80 million barrels booked ties to your core area but there's the potential for 320-acre down spacing and you have got the periphery that May be also incremental. Can you paint a picture of just how big that could be net to EOG and assuming that works out, what sort of… how long does that perpetuate a growth trajectory in your production and the play?

Yes, the first point there, you mentioned 80 million barrels booked, we haven't booked anywhere near that. We booked just a small amount in relative terms so that 80 million barrels net is what we think the reserve size will be. I think we booked about 20 million barrels to date in there. In terms of the Bakken and the possible expansion, I think we need to view that as kind of two different things. In the core where the primary production is 80 million barrels and we are getting these really, really high per well initial rates, we've defined that early enough, we believe, to now it just boils down to two questions. One, can it be down spaced from 640s and 320s, and two, whether or not one is applicable, can we figure a way to get more than about 10% of the oil in place recovery and a 10% is what is about 80 million barrel count number. So, it's really boiling down to a pure reservoir engineering analysis there and we've said that it's probably going to be early next year before we can get some definition on those two items. On the second way that the Barnett can grow is by drilling outside this core. And this earnings… this conference call kind of notes we have drilled some wells outside the core. We are very optimistic with the results but until we watch the wells a little bit more closely for a little more period of time we are not going to give a number on a potential side. But, I think that the directional trend on at least the resource plays that EOG has captured would infer to me that just kind of like Johnson County where we started out saying, well, we have X Tcf we are going to capture in Johnson County and we up that number. The Bakken is looking like it's going to fit a similar trend. And we hope some of these other big resource plays such as British Columbia, such as the Barnett oil play we hope those will also follow that trend but it's just too early to tell.

Great. Thank you for that. And just one last question on the Horn River Muskwa and then I will hop off here. Can you just make a comparison, if you will, of the Muskwa versus the Barnett just in the key shale properties and I will hop off?

Yes, we provided an IR presentation kind of a slide that has logs [ph] from the Barnett, in fact the power logs from Barnett that we show normally show and in our typical catalogue for the Muskwa in which we point out that the thickness is actually greater in Muskwa. Average thickness is about 530 feet in the Barnett, the thickest part of the Barnett in fact is Central Johnson County, at least thickest part. We control acreage on it about 350 feet. So, it’s quite thicker. Permeability is about the same in the 200 to 300 nanodarcie range, which is quite good for a shale. Gas-filled porosity is roughly equivalent. Maturities are roughly equivalent. Silica content, which is quite important we think in determining the fracability of the shale. That’s actually slightly better in the Muskwa than it is in the Barnnet. So, the bottom line, when you add all those together and also the fact that the Muskwa is over pressured to a greater extent in the Barnett as you can pact more gas molecules per square mile in Muskwa than you can at Barnett. So, [inaudible] of about a 2x multiplier from our best Barnett to the Muskwa average of our 840,000-acre position. So, the bottom line is it’s a really good quality rock and there is more in a higher pressure than in Johnson County.

Thanks for that.

We will go next to Joe Allman, J.P. Morgan.

Hi, good morning, everybody.

Hi, Joe.

Mark, what do you think about the prospectivity of the Three Forks/Sanish under your acreage and do you have any plans to test the Three Forks/Sanish? We have tested the Three Forks/Sanish in a couple of wells in our Parshall area and a couple of our step-out wells around Parshall. We recognize that is an additional reservoir potential in the area on our 320,000 net acre position, but I would say in the Parshall area itself we have not found it to be a quality reservoir and are not [inaudible]. It’s kind of spotty in its distribution around the basin we believe. It’s probably the part of the same self… basin centered oil shale as the Bakken and so we will be exploring four days as we go forward on the remainder of our acreage.

Okay. Do you think in your Parshall fuel wells and Austin Wells do you think you are getting some contribution from the Three Forks/Sanish?

I really don't think we are. I mean we have penetrated in a couple of places and as I said, the porosity development, particularly the permeability development in that particular zone is pretty spotty. And I don’t believe that it extends to integrate a step under our main Parshall field, at least from the data we have so far. Now, as I said that covers maybe 100,000 of our 320,000 acres. And there is a lot more to explore for you.

Gotcha. I might have missed what you said, the test you have done outside of Parshall, have they been more promising?

We are not going to comment on Sanish potential and wells we drilled outside of Parshall at this point. I think it’s still too new to draw any conclusions and we probably muddy the waters more than we clear it if we try.

Gotcha. The strong well that you reported recently in the Austin area, are you using the same techniques that you have always used, just a single… I know you have done a single long lateral on 640 and in small factors?

Yes. We… that's directionally, Joe. But we haven’t… in the last six months we haven’t further refined our completion techniques there. I think we are obviously, if you look at those effect, I think you put out something on the best wells completed in the market. I think whatever we are doing, it seems to be much better than most other companies out there in terms of initial rate and we think also in reserves.

Okay. And then the wells that you are drilling outside of the core area, are those on the border of Montréal and Berk County?

We are not going to develop anything other than our outside the core right now because there is still additional acreage we may tend to pick up.

Gotcha. Appreciate that. And then, are you… so that was my next question, so you are buying some more acreage?

Yes.

Okay. Got it. And then just on… your comment on the Barnett Shale peaking in late '09. For EOG you need to make up for that growth wedge, do you think the Bakken and the Barnett oil make up for that in the near term and then following that would be the Horn River Basin growth?

Yes. Actually we had a chart in our February analyst conference that kind of show that what happens is our Barnett gas begins to flatten out in 2009, but that's when the Barnett oil kicks in. So, we expect to have many years of continued aggregate Barnett growth but the lift is going to be more towards liquids going forward. And just another comment, when I discussed item up about the Barnett peaking in '09, people say, well can’t you [inaudible] refrac or couldn’t you drill on, let’s say, 15-acre basin. We believe, particularly in Johnson County, the refracs are not likely to work and so you are not going to get any big surge from that and that we also believe that drilling the wells on even ore concentrated spacing is probably also not going to work. So our view with the Barnett currently in Johnson County is it’s kind of a one-time shot and until we get some new technology that we are not aware off is not necessarily going to be a second round there. We think that also applies to other parts of the core area.

That’s helpful and then lastly could you just comment on the recent trend for drilling and completion cost and also comment on the availability of steel to develop your various programs.

The drilling costs they have been fairly flat through first half of '08 and we are starting to see a little bit of increase. Yes, the tubular and fuel cost, that's in the East Texas. Rocky Mountains, we are starting to see a little bit of increase in stimulation cost because of sand shortage there. Forward area the cost are pretty flat, rates are starting to tighten up a little bit there. So overall, our costs have been lower first half '08 compared to '07. But we may see cost increase slightly here in the second half given some of those gains.

And on that tubular question, the tubular situation not as tight as we have seen it in the last 20 years to 30 years. We are literally in a mode on many of our wells of kind of just in time delivery to get the pipe there to the well side literally hours before we have to run it in the well. Whether this tightens further, which could actually reduce drilling activity, we don't know. We generally expect it to remain tight but not to be a pinch point where in a macro sense people are laying down rigs so they can’t get pipes, but we're not an expert on the tubular market.

Fair enough. Well, thank you.

We will go next to Brian Singer, Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

Wanted to see if you could provide any additional color on the Barnett oil play, you highlighted briefly in your remarks, but I guess what incrementally is driving your level of confidence that this can be a major wedge, I guess looking out into 2009, probably and more importantly 2010 or 11?

Yes, in terms of... and I know people who would love to hear a lot more details on the oil play or at least have some other kind of peer company confirming the oil play. As we mentioned, this is the one play where we pretty well locked up vast majority of the acreage before we went public with it. And we are aware that at least one other peer company went in after analyst call and attempted to gain an acreage position and then pulled out after several months when it realized that it will be very difficult for them to get any sizeable acreage position. So we're... we pretty much control this play at least among the public companies and what we are currently doing is, we are experimenting with the completion techniques on both horizontal and we are also looking at vertical wells, as I mentioned there are some private companies that have completed some vertical wells and they are 100% reinvestment rate of return wells. So, we are open-minded enough to say well we look at horizontal wells or look at vertical here since there is track record of successful vertical wells. But the problem we have is we can't get any sustained test on much of anything there because there is pretty much... pretty close to zero capacity for anybody to take the gas up there in Montague County. And so we just... we have to wait until we get our plant built before we can really do much with these things. So, I would just say the reason we're so excited about the play is that we continue to confirm that the oil in place per square mile there is huge, over 30 million barrels per square mile in some of that area and if we just get a small percentage of that 2% or so, you can end up with some pretty big numbers. But everybody just have to be patient until the year-end or the first quarter before we can provide any more specific details on it.

And could you just refresh us from your analyst meeting whether and I apologize and I'm recalling just whether it is just really just for now a oil [inaudible] call or are there any… is there any even initial production rate data or initial declined data to speak out that gives you the confidence?

At our analyst call in February, we talked about our initial, I think it was eight wells if I'm not mistaken that we did drill eight horizontal wells. And we showed in our first quarter, we talked about the IPs of those wells ranging from 150 barrels to 350 barrels of oil per day and 0.5 million to 1 million cubic feet of gas per day which yielded a direct… a cash rate return of around 65% and that's really all we put it out Brian at this point.

And have those wells then producing, or are they constrained because of the gas issue and I guess if they have been producing, can you talk about what you've seen?

Yes. Most of them have been constrained, most... all of them basically have been constrained, was just in a minute production is best. But the very limited production data we have still confirms those kind of estimates. But we're really suffering from a positive data until we get more infrastructure out there. And I'll note that when we presented this to everybody in February, we said this is the 2009 event, it’s not a 2008 event. So, that's kind of our information that we can provide to you at this time.

That's great. And then separately on the higher CapEx which seems to a lot be on increased leasing, can you just start providing more color on whether that represents acreage acquisitions in plays you've discussed versus working upon new resource plays? I think you mentioned you've seen some sharp increases in leasing costs. So, maybe we should interpret that represents Bakken, Haynesville and Marcellus, I don't know if there is any color you can provide there?

Yes… I mean in the Marcellus specifically, we're not chasing any additional acreage up there at this time. What we are seeing though is that as you guys on the sell side are well aware that every peer company wants to have a stable full of resource plays and so that the acreage costs even for first movers on potential resource plays, the acreage cost has gone up dramatically. And so, what we're doing is, we're trying to be... to not chase the hot plays per say, but even the front-end costs in some plays that we thought would be kind of under covered plays. It's costing us more to get acreage there than we would have thought. So. a big majority of that money that we are talking about is in plays that we really haven't currently disclosed and will be evaluating over the next year or two.

Great, thank you.

We'll go next to David Tameron, Wachovia.

Good morning, everyone. A couple of questions. If you look at and you have kind of alluded to this, Mark, but if you look at your 2009 growth target that you guys laid out kind of 13% to 15% number, how confident are you today in that number? Is that a P70 number or a P50?

Yes. I'm pretty darn confident in the number. I don't know if I want to put a P specifically on it, but it's a pretty reasonable number and that number was 13% to 15% production growth for 2009. The components for that growth really are... we've got a sustained drilling program in the Burnell area there, Uintah Basin that just beat one more year of kind of a standard program. The Bakken is currently outperforming the estimates that we provided in the February analysts call and we expect the Bakken will continue to outperform throughout all of 2009 based on what we stated already on this call. And then, the Barnett oil should be coming on during that timeframe as well as the rest of our play. So, the only absence from the extraordinary events such as unavailability of rigs, unavailability of steel, some unusual collapse in hydrocarbon prices, I think we're pretty well set up for the production growth for 2009. And really, we've watched a lot of companies’ strategy here over the course of this year and there seems to be a lot of companies that are paying really premium prices for either acreage in hot areas or producing properties in hot areas. We sit back and say, just look at the inventory we have in hand today even if we never added another resource play, we're pretty well set up well past 2010, just developing the assets we already have and have disclosed. So, we just don't see any need to block there and literally spend billions and billions of dollars on chasing some of the assets, and so it's extremely unlikely that we will do that either this year or 2009.

Okay. Thanks. And then along those lines, so you have obviously net debt-to-cap targeted sub 10%, any more commentary on what’s your thoughts on with the cash balance that you have committed there or you are kind of projecting right in the break-even cash CapEx over the next couple of years?

Yes. I mean, preliminary thought for 2009 would be... if you just took today's NYMEX prices for 2009 that we probably end up roughly cash neutral… cash flow neutral program in 2009. So, the game plan will be to continue to have very, very low levels of debt, net debt in 2009 and later. Probably we'll continue to have the best ROCE that appears than the peer group and lowest unit cost as well as a lowest debt. And then 2009, 2010 debt adjusted production gross per share, we may not be in first place in that, but I believe we'll be in the top quartile every single year. And frankly, we just don't see the need to… for growing the company at 14%, 15% per year. We are just not that anxious to lever up the company in a monstrous way so that we can say, we've got production growth in the low 20s per year. We much rather have an extremely low debt and high ROCE to growing the company with normally 14%, 15% per year.

Okay, refreshing view. And the last comment, a lot of talk on sell side and buy side as prices trend down on natural gas side of the costs over the last month. What do you believe that marginal costs for suppliers right now in the U.S. kind of from the natural gas standpoint?

In the Gulf of Mexico, it's probably currently $8 to $9, I would guess, with the way the marine equipments costs have gone up and any onshore areas you probably look at $7.50, something like that, maybe $8. So, the issue I think on the... this comment on gas prices, a month or so ago they were $13, $13.50, and personally, I was wondering why they're going up so much, because I couldn't see any fundamental supply demand situation that would drive them up toward $13, $14. So, my sense is they were just overpriced a month ago and now they're back in the... in my mind, the price is $10, maybe $9 is probably a more rational price assuming the kind of a normal winter for this coming winter. So, our views have collapsed as they collapse from the price that was more of an emotional price there of $13.50.

All right. Thanks, nice color.

Thanks.

We'll go next to David Heikkinen with Tudor.

Good morning. One quick question, the 100,000 acres you have in the Haynesville, can you give us any description of where that's located?

It's... I mean, some of it's in North Louisiana, some of it's in the East Texas part, and it kind of just... it's a pretty good spread, but I'd say, the 100,000 acres are in areas that some other companies have deemed that would be perspective. And I'd say, we just have no first hand results ourselves about the Haynesville, and so we just... and I know there is kind of a big argument going on in the industry about, is the Haynesville a really big player or is it a localized player if it play at all. And we just seem to stay out of that whole kind of argument until we get some data on our own.

And if we look at your existing production in those fields, I mean, you have some legacy fields between [inaudible] if you just take that line, is that the majority of the acreage you're talking about because it is mostly held already or is it new leasing?

The majority... the vast majority of 100,000 acres is just a legacy acreage.

Yes. Okay.

But maybe about half of our acreage is kind of in that area that you just described there.

Okay. You've given that already a few times. The other question I had just thinking about the Bakken and defining the extension area, talk about 100,000 acres that are in this primarily core Parshall, how should we think about… you may even want to get into the direction of the extension areas you're still leasing but, we've have thought of the crescent sort of that the Bakken has developed. Is that… how do you think about what or where we should think about that extension area heading?

Yes, we would like to leave that as murky as possible, regarding the geometries, outside expansion, frankly the geometry as a core area, we think we understand now what… pretty well what the boundaries are on a really high-quality core area and as we said before, there are...there is a rind of somewhat lesser quality, but still economic acreage around that core area. And the geometry, as we understand it, is better defined now but it will expand, we believe, in rind area, particularly it will expand in we've driven our comment on what directions that might go.

Okay, and everybody is keeping their eye on Barnett oil and it looks like the majority permits there more in Montague County as opposed to Clay and Archer. Is that just an indication of where infrastructure is located now, more so than quality of wells or can we read anything into the concentration of EOG permits further to the east?

Well, I'd say that there is a similarity between Montague County, which is the farthest east, and then you go to Clay and then you go to west, got to Archer as move west. There is a similarity to the Barnett gas and that as you move out of Montague County going west the zone gets thinner and you lose the viola [ph] which insulates you from the [inaudible] of water. So, out of the reserve estimates that we kind of put out so far, the biggest single contributor that by far is Montague County. And so we've done some drilling out in the west but, like I said, more wells in Montague in west and that's where as these oil play develops I think Montague will be the name you're hearing a lot more frequently than Archer play.

And that's helpful. And then on the balance sheet side, do you guys think at all about or how would you think about share repurchase programs and where that would fit in your capital allocation process?

Yes, I mean with the stock price decline, what kind of puts back on the table is something that we have in our arsenal. I'd say that at this point, it’s still more likely that we'll run the company with low debt as supposed to attempting to kind of lead anyone to believe that we're going to jumping into a big share repurchase program in the future. The preference would be to just run the company at very low debt in 2009, 2010, 2011 and to have kind of a balanced program, cash flow versus CapEx post 2008. But depending on how the stock reaction whether it directs further in the negative direction, we certainly have the fast hour to do something about it in terms of repurchases. We're just still watching that everyday.

Just one additional thing, on the Barnett gas peaking in 2009, make sure we're all measuring from the same point, what is current Barnett gas production as you guys are measuring it compared with the 5 Bcf a day?

We think it's probably somewhere, if we just took like a current June, July number, we think it's somewhere probably in a range of probably 4.2% right now.

Okay.

And we think it'll peak out at about five something like that.

And how much liquids are… are you including liquids in that or is that just straight gas, just trying to make sure?

Gas, really.

Okay. Okay. Thanks a lot guys.

Okay.

We'll go next to Eric Hagen, Merrill Lynch.

Hi, good morning. First, thanks for a very measured instead of same view of gas markets in growth. In terms of questions, can you give us an idea of the volumes out of the Bakken currently and how many wells you are producing?

Yes. We don't want to get into specifics on there because... and the main reason we don't is, if we give a specific volume now then somebody will ask for the next quarter and if it happens to be 500 barrels a day lower then that somebody has projected that and then somewhere around sell side right up to say Bakken less than expected for the third quarter or so. So we just don't want to [inaudible] this Barnett, we'll give an annual goal, and we have provided an annual goal in the February analyst conference for this year for the Bakken and what we can tell you is we're going to beat that number but we're not going to give specifics.

Okay. Great, thanks. And the other question I have is on the Marcellus, besides infrastructure issues and permitting and what not, is there anything in terms of the geology or consistency of results that makes you more negative or more measured on the play?

Yes. I'd say that we are a little more measured on the play than perhaps some others that you are reading out there in that the thickness is quite a bit less than we see and obviously than that we see in a Barnett. And it's a good quality rock and it's well distributed over a broad areas. But as I said the thickness is an issue, in some case pressure is an issue but probably the most unknown risk factor that we and others are dealing with right now is frac efficacy, frac barrier containment in the Marcellus itself. The kind of results that we are hearing about in parts of Pennsylvania that we're showing 3 Bcf to 4 Bcf of oil that really does not confront well with kind of IPs that we are seeing in rest of the play and really the way we model the plays north of 1.5 Bcf to 2 Bcf of oil kind of play, particularly if you're looking at big program averages. It's really, really difficult to average 3 Bcf to 4 Bcf of oil over a whole play.

Okay. And in terms of that… the frac efficacy, is that the lack of a frac barrier in certain areas that you can’t contain the fracs or is there some sort of embedded shale that’s interfering with fracs, any more color you can provide on that possibly?

Really, that is specific because I've cared to get. I think there are differences in the frac barriers throughout the play, from geographic area to geographic area and next I think the biggest unknown in the play right for most of the operators.

Well, great. Thanks for that color.

Okay, Eric.

We'll go next to Leo Mariani, RBC.

Yes. Thanks. The question on the Bakken here. You guys talked about some peak rates in your press release from three new wells at 2.7, 1.9, and 3.2 [inaudible]. Trying to get a sense of what the term is on those rates, those one-day peak rates or where do we have investment in that?

Those rates, I mean for the Bakken, are you asking about the Bakken there, Leo?

Yes

Okay. You quoted some numbers there, I'm not sure where those numbers came from 3.7… I guess that’s 1000 barrels a day, okay. Yes, those are just initial rates, probably the first three to four days rates and these wells will decline at pretty sharp rates and to some degree that's… you can't use that number and say that's going to be a yearly average and anything like that but what they do, if you kind of compare those initial rates with what we've seen from some or the peer companies up there you’ll find that they are considerably higher in many cases, double, triple, five times initial rates from some of these other companies. And it just shows that there is a correlation between the initial rates and the ultimate reserves on wells. The higher the initial rates, the more reserves you're going to get out of the well.

Okay. I am... due you guys have enough data in that play to talk about what to expect for the first year annual decline rates?

Yes. We do and I'm not sure we can quote it and give it to you here. We could probably, if you want to call Maire later on, we'll dig it out, but the answer is, yes we've got a pretty accurate tight curve on that.

Okay. Jumping over to the [inaudible] play you guys mentioned two recent wells that came on production here. Any indication of what those flow rates are and I guess are those producing at this point without restriction?

Yes. British Columbia?

Yes.

Yes. They are producing without restriction. I'd say, they have only been on about two weeks. We really don't want to give any flow rates or anything on them other than to say we're pleased. And I think by next quarter, we can probably give a much more detailed assessment for you of what we are talking about up there in BC.

Okay. Just to clarify on your comments about the Barnett gas here. You talked about industry peaking at some point in 2009, do you also expect that EOG's volumes in the Barnett would peak in 2009? Are you guys going to have I mean do some more lights on that?

Well, in terms of the Barnett gas volumes, yes, we expect they will probably peak in and then plateau in 2010 and 2011and then we expect to have the oil volumes slated in. But generally we think we will be similar to the industry in the Barnett gas portion.

Okay. Thanks a lot.

Okay.

We'll go next to Gil Yang, Citi.

Hi. Just couple of quick questions. In China, did the earthquake have any effect on either the operations there and/or the plans to move forward with that in the future with concerns about infrastructure and susceptibility to earthquake?

Yes. The answer to that is no. It was in an area far enough away from the stuff the field we are dealing with that there was no effect either on the down hole equipment or any on the surface, no pipeline related issues or anything like that.

Okay and Loren, you commented Muskwa has… is over pressured and I am not sure you said it's two times pressured or was that overall between all the things twice as good?

No. That's an overall twice as good, twice as much gas in place per square mile.

Okay. What is the full pressure in... full pressure grading in Muskwa.

It ranges from the East to the West side of the basin but all of that basin is more over pressured by gradient than is the Barnett. And Barnett may be in 4.8 to 5.2 range and Muskwa is substantially higher than that.

Again 0.7 range.

Really not given actual number for that. It does vary across the basin and that's kind of one of the controlling parameters for gas in plays?

Does that potentially mean that the decline rates are going to be higher, too if it's more over pressured?

I think so, I think it just is going to pack molecules into the core structure that you have. The decline rates... we don't have long-term productions. Some others have a little bit longer-term production than we do. And they don't look how ordinary it is.

Our guess, Gil is that the decline rates will be similar to Barnett gas type curve coupon rate.

Last question, I have sort of a macro question for you, Mark, is, you're saying that maybe gas ending inventory is 3.3, 3.4 and I think you've been saying before 3.2, 3.3, if that's right, what has changed that? It's a little bit... obviously it is less than last year, but still a little higher than your previous estimate, what has changed in that interim?

On the previous earnings call, I did not use 3.2, I said I expected it to be 3.3. So now I'm saying, on average 3.35. So…

Okay.

That's within around the accuracy, but I don't recall every saying 3.2.

Right. Okay. So, you are introducing no major change there?

Yes. We really don't think there is a major change, I think as everybody knows, the comps there in August, we're going to be really tough to be relative to last year's August. But I guess, if I just stand back and look and say, okay over the last nine or ten our storage injection reports, in my mind we have one disappointingly various report which was one or two weeks ago. And that may or may not have been affected by the July 4th holiday, but other than that the rest of them have been pretty much in line, some over, some under, but it doesn't indicate the way we've got this massive oversupply situation. I think it's just more psychology right now that oil prices have fallen a bit, people know that last August was so hot and this August will be really doubtful. So push the sell button for gas features is what some people appear to be saying, but I don't think the fundamentals are particularly weak at all there.

Given you generally bullish outlook, can you just, maybe you said this earlier and I missed it. But could you give some rationalization of why you're actually taking your hedges for '09 about your hedges in percentage terms at least over '08?

Yes. We... on the last earnings call, I believe we were 30% hedged for '09 and we said that we would likely add to those hedges and now we are currently 36% hedged at a $9.71 price, kind of we view that as kind of a reasonable price. We're not at the camp that says, gas next year is going to be $12. We think $10, $9, $9.50 is probably more reasonable gas price unless you have a really, really cold winter. So, that's why we blocked in some of that, we blocked again what we think is a rational gas price for next year.

Okay. Thank you very much.

Okay.

We'll go next to Ellen Hannan, Weeden & Company.

Good morning. Actually my questions have been answered, thanks.

We'll go next to Marshall Carver, Capital One.

Yes, a couple of question on the Marcellus. I didn’t catch your acreage positions there.

220,000 net acreage.

And the 1.5 Bcf to 2 Bcf per well, is that... do you think that you can get higher recoveries in certain areas and no other operators just talked about 3 Bcf to 4 Bcf a well in Northeast Pennsylvania and Southwest Pennsylvania?

I mean, we'll comment in just a general sense there that if you look at the rock it's considerably thinner than the Barnett, and basically in Johnson County, the average in Johnson County is not three to four Bcf well, it's less than that. And so, when you are dealing with Marcellus, which is less geo-pressured and much thinner, it just doesn't make good reservoir engineering stands that you're going to get recoveries of 4 Bcf well when that hadn't been average in Johnson County. So, we just think that that number is probably the number that's we believe is unrealistic. And then, you clearly do have a problem with containing the fracs within that relatively thin zone. You have more of a problem in the Marcellus than you do in the Barnett. So, that's another reason for caution.

Okay, that's helpful. Thank you.

And we have no further questions in the queue at this time. I'll turn the conference back over two Mr. Papa for additional or closing remarks.

I just want to thank everyone for listening and we'll continue to just stay on a very consistent game plan. Thank you.

That concludes today's conference call. You may disconnect at this time. We do appreciate your participation.