Good day, everyone, and welcome to the EOG Resources 2008 first quarter 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 first 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 in 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 US 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 last night. 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, Investor Relations. We filed an 8-K with second quarter and full year 2008 guidance yesterday. These forecasts were consistent with the details provided at a recent Analyst Conference. And I'll discuss them in a minute when I review operations. I'll now review our first quarter net income available to common stockholders and discretionary cash flow, and then I'll provide an operational overview. Tim Driggers will then discuss capital structure, and I'll close with the gas macro overview and a summary. As outlined in our press release, for the first quarter EOG reported net income available to common stockholders of $241 million or $0.96 per share. For investors…

Thank you, Mark. For the first quarter of 2008, total exploration and development expenditures including asset retirement obligations were $1.122 billion with $29 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $88 million. Capitalized interest for the quarter was $9.4 million. At quarter-end 2008, total debt outstanding was $1.185 billion, and the debt to total capitalization ratio was 14%. At March 31, non-GAAP net debt was $980 million or net debt to total cap ratio of 12%. The effective tax rate for the quarter was 35%, and the deferred tax ratio was 65%. During the first quarter 2008, we repurchased remaining $5 million of our preferred stock. We no longer have any preferred stock outstandings. Yesterday, we filed our Form 8-K with second quarter and full-year 2008 guidance and our updated hedge position. For the full year 2008, the 8-K has an effective tax range of 32% to 36% and a deferral percentage of 55% to 75%. Using the midpoint of the updated 8-K guidance, our full year 2008 unit cost for leasing wells, DD&A, G&A, total exploration, net interest expense, and excluding transportation and taxes other than income, our forecast increased only 2% over 2007. With our current hedge position, as outlined in yesterday's 8-K filing, for every $0.10 change in Henry Hub, EOG's 2008 net income and cash flow is impacted by approximately $20 million. Similarly, for every $1 move in WTI, EOG's 2008 net income and cash flow is impacted by approximately $10 million. Now, I'll turn it back to Mark to discuss the gas macro, hedging and his concluding remarks.

Thanks, Tim. Regarding the North American gas macro, we think prices will remain strong throughout the year, because overall 2008 net supply growth will be essentially flat with 2007, while demand growth will be up about 1 Bcf a day. Given the flat overall net supply and current storage, we think that November 1st storage levels may only reach about 3.3 Tcf, which will be a bullish signal for 2009 gas prices. To me, the most intriguing piece of this equation relates to LNG import levels. To-date this year, we've noted that non-US, LNG demand is significantly stronger than most people would have predicted a year ago. It's a harbinger for stronger than predicted non-US LNG demand in 2009 and later periods. We now know that LNG import tunnels are being constructed or considered in Argentina, Kuwait, Dubai, Chilly, and Brazil. A few years ago, no one would have predicted that these countries would have been importing LNG. This critical area of non-US, LNG demand growth, I believe, is something we need to watch closely, because if this demand grows continues to surprise on the up side and that is a bullish sign for North American long term gas prices. Our 2008 and 2009 financial hedge position is only slightly changed since our February Analyst Conference and that we added a few more 2009 GAAP hedges in late April. For the period June 1st to December 31st, 2008 we are about 30% hedged regarding North American gas at an $8.52 price. For 2009, we are about 24% hedged at $8.80. For the period May 1st to December 31st, 2008 we have about 28% of our total company oil hedged at $92.19, no oil hedge is beyond 2008. At some point, we may consider adding more of 2009 gas hedges. Now,…

[Operator Instructions]. We will go first to Brian Singer at Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

Wanted to focus on the Bakken, with the two wells you talked about, and very strong results there. I know you still need a few more months, through the rest of the year to fully finalize what the resource potential is. But can you add any more color on what you think those rates mean when looking at… when thinking about recovery rates or thinking about how far the play extends?

Yes. I guess what I would say at this point, Brian is that what we've seen from the drilling that was done to-date in the play is a pretty surprising amount of consistency in terms of pretty much in both north, south, east and west parts of the play that we've drilled, all have very, very strong wells. Now these Austin well that we highlighted, I repeat it, over 3000 barrel per day, they are towards the north end of our accumulation. And we've now got a group of, I guess about, 4 or 5 of this Austin wells that are uncommonly strong, I would say. But the surprising thing to me has been that there is a pretty good degree of uniformity in this accumulation, that's in other words is not… the north end isn't dramatically greater than the south end, although it's slightly better. In terms of expectations and I know there is a lot of expectations out there regarding what's going on with downspacing well and so on and so forth. What I would say is, frankly we just need some time to evaluate this. As I mentioned, we are drilling our first 320 acre downspacing wells, and in fact it's being completed as we speak. But kind of regardless of what the initial rate is on that well as a reservoir engineer… that's not going to mean a whole lot to us, what's really going to mean more to us is, what are the pressures in the well and what's the well look like after three or four months of production, and has that effected rates for the surrounding wells. I will say also, that we are taking a hard look at secondary recovery here. In other words our estimate of recovery factors, this reservoir, the 80 million barrels correlates to about a 10% recovery of oil. And in most oil accumulations you can get considerably more than that by a secondary recovery program. So, we will be evaluating that throughout the year, but I would really just advise everybody to expect that the next meaningful update we have regarding the size of that accumulation is probably going to be in early 2009.

That's helpful. Taking a step back when you look at the various… really you opportunities in terms of extending your technology, how vast do you think that potential is? And how price sensitive is that when considering what oil prices have become?

Brian, I would say that the oil potential for horizontal drilling is large, but not as large as for gas. We are taking the plays from the same place that they use the gas and we are looking for what we call basin centered accumulation, areas where oil from source rocks have been matured to the oil level, but not to the gas level. And that does occur in several basins, probably half a dozen basins around the US, were encapsulated tight rocks can be accessed with horizontal drilling. And we have a number of those kind of plays on our plate right now that were maturing from the stages of generation to capture and we've talking about those in subsequent correlations. I'm sure. In some we have to say… I think the oil potential out there is substantial and we are moving in that direction.

Yes, kind of that, just to give you a little more color on that. Brian, we always have in our closet an inventory of potential horizontal resource plays, that's kind of our cheechee list, which we never disclose to analyst until they're actually technically proven , but our current cheechee list, about 50% of once on that list are oil and the other half of gas.

Great. And then, any sense on price sensitivity or these projects that when you are considering, you are going to need or what oil price did you think you generally need for?

Frankly, at any oil price over about $70 a barrel… these things work.

Thank you.

Okay.

Next we move to Gil Yang of Citi Investment Research

Hi, so following along Bryan's questions about the Bakken and may be more philosophically, at the meeting, Loren, we talked a little bit about your returns, the Bakken returns are 100% plus, given that at some point, downspacing would resulting in smaller wells. The trade off would be that you get the higher volumes at smaller wells and so smaller returns. How far down the returns curve would you be willing to downspace to? Would you… if you get a 40% returns and downspace in the Bakken, would you be willing to go that far or would you want to keep it at some higher levels of rate-of-returns?

Yes, Gil, I guess the best way, I'd look at that is, we're looking at the downspacing in conjunction with secondary recovery, in other words, pumping some fluid into these wells and if we technically conclude ultimately that this reservoir is amenable to secondary recovery then the downspacing is kind of a fate accompli, it will happen. But you really can't flood this reservoir 640 acre space. So I would say that we'll be looking at the downspacing… the downspacing, if you just run it on acceleration economics, probably its going to look pretty good. But what we need to sort out is how much incremental oil do we really recover with that, but I would tend to have people focus on, I think the key question that we have to answer in it that the sales side, my side should focus on is, is this residual amenable to secondary recovery. And, then the downspacing will be part of that.

I guess my question is, really what's the interpretation of the word amenable, if you could do it at, if you could downspace and secondary recovery at 40% rate of return-of-return, is that amenable or?

Absolutely, yes.

Okay. That's fair. And second question on China, can you give us an idea what the gas price you would expect under current market conditions there… to receive out of that area?

Yes. The current situation we have in China is this acquisition is funded, it's essentially a done deal, but it hasn't technically, legally fully closed. And so, until that occurs we are really under some confidentiality provisions and we can't give any other color other than we provided you. So, I know that's not a satisfactory answer, but wisely on the next earnings call we'll be able to provide the color that people want regarding China.

All right. Thank you very much.

Next we'll go to Joe Allman of JPMorgan

Good morning, everybody. Mark, in terms of the Bakken, are there any other opportunities to branch out further there and get more acreage, would it be your desire to do so?

Joe, we currently have I think 320,000 net acres in the entire Williston Basin and the field that we always talk about, partial field including those 3000 barrel a day, Austin wells, really only it comes to about a 110,000 of those 320,000 acres. So, answer to your first question is absolutely, yes. We believe that there are other perspective areas within the Williston Basin that we have currently leased and we will be testing in the future for oil prospects. And we are continuing to lease in partial area that's a pretty hard thing to do, but other parts of the basin where exploration prospects are available we are accreting acreage curve.

Okay. That's helpful. And then, could you give comments on the dynamics for cost these days. A lot of operators are talking about drilling and completion costs, flattening out here, are you seeing the same thing, could you give some color on that?

Yes, for the first quarter here we're probably seeing improved cost reductions and improved efficiencies lowering our cost about 5% overall. But with tubular cost increasing, fuel cost being higher we're saying that we'll probably give that up overall through the balance of the year.

Can you comment on fracture stimulation cost?

Stimulation costs have not gone up for us. As a matter of fact, in the Barnett area there are some surplus frac equipment and we're seeing being pretty flat elsewhere. Another thing you know that… you'll remember, we have in place these vendor agreements through the year 2008, so they are staying flat for EOG.

Got you. And then, on China, I know you talked about comparing that to the Wilcox play in South Texas and you mentioned 0.5 Ts net to you. And so, is it similar in size net to you as well, and can you comment on the potential size net to EOG?

Yes. The 0.5 Ts is what we think we captured in South Texas. It's really got nothing to do with the China number and we really can't provide a China number probably till the next earnings call, Joe.

Okay. I appreciate that. Thank you.

Okay.

We'll move next to Ben Dell at Bernstein.

Hi, Mark.

Hi, Ben.

I have a quick question about the Appalachians. Obviously, there's been a lot of talk about the Marcellus Shale. You've obviously just entered the Appalachians. Have you taken a look at that and do you have any interest in that or do you think the quality of the shale is not as good as the other stuff you're seeing?

Yes, Ben. We've talked about the Marcellus some in the past, and really our position there hasn't changed. We currently have about 230,000 net acres primarily in Pennsylvania and primarily in North Western Pennsylvania. We did sell our shallow production in the Appalachians, but we maintained our deep rights under those leases. So currently, as I said, we're at about 230,000 acres. We've drilled a total of probably 9 wells out there. 4 of those are horizontal. And we plan to drill another… probably 5 wells in the balance of the year, some of which will be vertical. Some of those will be on 100% EOG land, some will be in combination with Seneca Resources on a large JV that we've entered into with them in Northwestern Pennsylvania. I'd say we're encouraged by the results we hear announced by others in the play. Our own results have come fairly slowly. When we get our new rig there in middle of May, we hope to accelerate those results.

Okay. Can you give us an indication of IPs that you've had on the wells you drilled the horizontal?

We're not really prepared to release any IPs at this point. I think I would say that the numbers that are being thrown around in the industry, they are 2.5 Bcf a well, seems a little strong to us. Our own modeling of our own test results would indicate more like 1.5, maybe as much as 2 Bcf a well, which is still going to be quite strong economically. We hope and expect the play will work, although we do believe that the volumes are going to come out fairly slowly from that play, both for us and for industry as a whole, mainly due to just logistical reasons, lot of topography, lot of regulatory work, a lack of people and equipment, that kind of thing.

Okay. On a separate topic, historically, you've had better returns on your assets within the US than outside the US, specifically Canada, Trinidad, UK. With China, what's sort of leading you to increase the international expansion at another country? And it appears that money would be better spent at home. Are you limited in terms of how much you can grow and do in the US?

Yes. I would say, Ben, I'm not sure I'd agree with kind of the predicate of your question there. We look at returns in terms of what kind of after-tax reinvestment, rate of return we've gotten on our money that we spent there, and we're very happy with the returns we've gotten in all three of those areas, Trinidad, Canada and the UK over time. And they have been generally quite comfortable to the returns we've gotten in certainly in the US, except maybe for the last year when US gas prices went up. The idea in China is one that where we've looked at areas where there is an energy short part of the world, we believe that this onshore horizontal technology is going to be amenable to places outside North America in uncovering pretty substantial pools of hydrocarbons. And what I'd say on the reinvestment return in China is, if it works, we expect it to be comfortable with some of other investments in the company.

Okay, great. And just lastly, a quick one, there's been some talk about sort of Eastern European type gas basins and the gas strictly around Ukraine. Is that another area you're taking a look at or do you see Eastern Europe in the horizon for you?

Specifically, the Ukraine, no, we're not looking there, mainly just because of political issues. But we are looking a bit in some portions of Eastern Europe, although not that far east. Whether we come up with something, I don't know, but I would say that there are parts of Europe that are on our radar screen. And somebody is probably going to find some substantial basins centers gas accumulations that are amenable to the horizontal drilling in those areas.

Okay, great. Thank you.

Okay.

Next we'll move to the David Heikkinen at Tudor Pickering.

Good morning. I had a question on the comments of finding the Bakken North, South, East and West. That is in 110,000-acre area of consistency around Parshall, not the 320,000 acres. Correct?

Yes, that's correct, David. We -- yes, we've got what I'd call other ideas on acreage outside that 110,000 acres and we'll likely be testing some of those in the second half of this year.

Okay. And as you think about secondary recovery, what would be a barrier, reason why it wouldn't work in the Bakken?

Yes, I mean the two biggest barrier… potential reasons are that: One, if this thing if we deem that it has in-situ, high degree of fractures, natural fractures, that's a barrier. And then the second reason is on the converse, if we deem that it's got shockingly low permeability, that would be a barrier. On the positive side, in a typical oil reservoir and I'm saying a typical sandstone or so, you usually get something like 15% or 20% on primary recovery or the recovery of the oil in place and initially we are only dealing with 10%. So, we've got 90% of the oil that we are not going to get out as it stands now. And that's a pretty big prize for us to chase.

Is there a relative permeability to oil versus relative terms of water issues that you have identified or --?

No, we're just… yes, we are just looking at all that stuff.

Okay.

Now, it's probably too soon to comment really.

And then just going to the Atoka, you talked about 50,000 net acres and 400 Bcf. Is that… what's your growth acreage there, ability to continue to expand that? Is that a concentrated area or and then spacing assumption?

Yes, I guess, I mean the rock spacing assumption there is well every 320 acres. And this particular zone is pretty sand, so it's not obvious that we will be able to come back to you in a few months and say, "Wow, we can double that to 160 acres." But I'd say, on adding incremental acreage, we've got a chance to take that 400 net Bcf up to a number probably like maybe 600, maybe 700 net Bcf.

Okay. And so how much money are you going to spend for additional leasing this year now?

Well, the total number that we have that we released in 10-Q last night for all of our leasehold acquisitions for this year is about 360 and really will stay pretty close to that number.

Okay. So, you don't think that leasing is going to be something that has an uptick in here above $4.4 billion budget?

But if it does, then it will likely be down by other downticks.

Okay. And then final question, as everybody wants to know about Bossier and Haynesville Shale, can you talk about anything you are doing in Louisiana, Texas trying to test the shales on floors there?

Yes, I would say we've got a position of about 63,000 net acres in that play area. We do not intend to drill any Haynesville horizontal wells this year. We're just going to take a wait-and-see attitude and see if that play develops and comes to us. But we have not that much data ourselves. We really can't shed much light for you, David, on the essence on the overall play.

I appreciate that. Thanks you.

Our next question comes from Leo Mariani at RBC.

Yes, a quick questions here on the Bakken for you guys. I'm trying to get a sense of how many wells you've drilled so far and what's in the budget for number of wells to drill in 2008?

I think our total number to date on Bakken completed wells is about 38. And I think the total number for the year… those are gross wells by the way. On a net well basis, for 2008, we have like 50, I believe. And on the gross, it's going to be in the mid-70s. Is that right, Gary?

80.

80 or so, gross.

Okay. And what's you current production out there in the Bakken?

It's 12,000 to 12,500 barrels oil per day net.

Okay. A quick question on your North East B.C. plant there, how long did you hedge your three wells that there are on production?

They are not on production. The wells that we have were just extended slow test that we did during the winter. Our first production is going to commence this summer. So, we will have those wells on production, plus probably one or two others that we are currently drilling.

Okay. And I guess would you guys probably anticipate stepping up your drilling there in 2009?

Yes, the logic path there is that we've got 40 million a day of available pipeline capacity, and we're drilling up wells to fill that up in a relatively short term. And then it's probably going to be about an 18-month period to loop that pipeline to allow us to have a significant step-up in capacity. So if you kind of play all that out, it translates to maybe mid-2010 before we're really going to have enough pipeline takeaway to really a see big volume ramp-up there.

Okay. Last question here on the Barnett, just curious what you guys are seeing these days in terms of EURs on your Western County extension well, as well as cost out there, and what you guys are seeing at Hill County in terms of cost in EURs?

Yes. In terms of the Western Counties, we would still stay with the number that we've been kind of quoting for the last year, which is about 1 net Bcf per well in the Western Counties, and well cost out there are running out probably $1.5 million or so in terms of that. In terms of Hill County, the reserves there look considerably stronger. I would say probably 2.25 Bcf well is kind of what we're seeing. We're seeing a little bit different set of characteristics in Hill County and the wells don't come on as they kind of monster initial rates, like in Johnson County, but they don't decline at the very high rate that the rest of the Barnett does. We're really completing in a different facies of the Barnett there. And so, what we get per wells that have initial production rates of maybe 2, 2.5 million a day but they're relatively flat as far as declines.

Okay. And what were your costs out there on the wells?

$2.4 million, $2.5 million range for Hill County.

Okay. And can you just remind us how many wells you guys have drilled in Hill?

I would guess about 12.

Okay. Thanks a lot for your time.

Okay.

Next, we'll move to Tom Gardner at Simmons & Company. Tom Gardner - Simmons & Company: Good morning, guys.

Tom Gardner - Simmons & Company: Mark, I wanted to get your thoughts on the recent 9/14 data and I appreciate your earlier macro comments. But, I mean, you've got 10.5% year-over-year growth, is this, I guess, running the risk of oversupply in the future and how is it likely to impact your hedging strategy?

Yes. Our current forecast, we're expecting production to be up somewhere in the range of maybe 3.5% this year for domestic production. That's certainly at odds with the monthly EIA data, although I think the EIA's annual forecast is like 3.0% growth is what they're officially forecasting for '08 versus '07. I just flat do not believe that we're seeing from full year anything close to the range of 10% growth. I've always felt that the EIA data consistently overstates production growth. But I do think that the sea change relating to horizontal drilling in gas reservoirs has pretty well put us on a path where we're going to see something like maybe 2% to 3.5% annual production growth in the US in '08, '09 and 2010, it's the forecast for three years. So I think that the sea change with horizontal drilling has changed this from an industry that could barely keep production flat in the US to one that we will have production growth in the US for the next several years, at least, in my opinion. I also think that once we get a little more flush production coming out of the offshore field that's currently offline, I think that we're to see some pretty sharp decline in that 8 Bcf a day from the Gulf of Mexico, probably beginning to manifest itself by the third or fourth quarter this year because as the level of the rigs that are currently running in the Gulf of Mexico have some recipe for some pretty sharp declines that is going to occur. So we will have a counterbalance effect I believe in the Gulf Mexico to this onshore growth. Tom Gardner - Simmons & Company: Thanks for that. On the same theme of government studies I wanted to jump over the Bakken and ask you about the USGS study indicating multibillion barrel potential, what are your thoughts on that? You've commented earlier on what you thought the price environment would need to be going forward. Are there issues outside of the Parshall area in order to achieve that sort of number or come anywhere close to it.

I think the study that the USGS did is quite well founded technically. Mr. Pollastro did a really good job of estimating reserves in the Barnett a couple of years ago. Maybe that will turn out to be a little bit light in the Bakken. I think he is taking a good approach in that he has looked at it as basin-centered oil accumulation, which is correct we believe, covering a very large area although it is relatively thin. For the number that he comes up with, I think its midpoint numbers, maybe 3.7 billion barrels of oil recoverable. It's fundamentally and technically correct, but perhaps not economically extractable. And I think, because he assumes that the entire shale will work to the tune of maybe 25,000 total locations, wells to be drilled, and that's where we think it's perhaps a little optimistic. The shale may not be intact. The basin-centered oil shale may not be intact over that entire area by our thinking. Portions of it, perhaps large portions of it may not be economic because the shale has been partially breached, so you may have water issues in some areas. And also, there will be variations. Parshall is such a sweet spot because of fracture density in the facies of the rock and that will probably not be true in very many other places in the Williston Basin. So, in summary, I'd say that the overall number is not incorrect; it's just perhaps optimistic. Tom Gardner - Simmons & Company: Thanks for that guys. Appreciate it.

Next, we'll move to Monroe Helm at CM Energy Partners.

Congratulations. Actually, my question was on the USGS study, so I've been taken care of. Thanks.

And next we'll go to David Tameron at Wachovia.

Hi. Congrats on a nice quarter.

Thanks, Dave.

Can you give us a feel for what your Barnett gas volumes are doing outside of the NGL impact on the Western extensions? Or in general, just gas volumes quarter-over-quarter and then sequentially year-over-year, I should say.

Yes, I don't want to get into -- you know, we got stung two, three years ago on given quarterly volumes on Barnett where in one quarter it was less than what the analysts expected and our stock got down. So we've gotten away from giving quarterly expectations. And we just have that number of 470 million cubic feet a day equivalent. I'll say that between what we call Johnson County and then Western County, both of them are pretty consistently on track for our forecast to hit those numbers. We have a huge backlog currently of wells in Johnson County to complete. And so, what we expect to see is in the second half of the year, we're going to see more of an uptick in the Barnett kind of in gross than we saw in the first half of the year, mainly just due to us clearing out some of the backlog of these huge number of wells that we haven't yet completed. The issue we run into there and this is the longer, in more detail, than you probably want is we batch drill when we complete these wells and if we have at least where we think we can drill eight or nine horizontal wells in a 35-acre spacing roughly each, what we'll do is we'll drill all those wells, we won't produce any of them initially, and then we'll come back and we'll frac all those wells, one after another without producing any of it. And so, then when we turn on the production, when it does come on, it's kind of like a batch of, say, 12 or 15 wells at one shot in Johnson County. And all those wells come on at 6 million a day or so. So, our production is kind of lumpy or so. But the overall point I'd make is we are going to deliver by end of the year the annual average that we promised at the analyst conference, and we are on track to do that.

Yes. Let me delve into what you said in detail, if you talk about the backlog, is it pipeline capacity or is gathering, is it processing, is it service equipment? I mean it's not unique to EOG or others?

It's really none of those, David. It's not a logistical backlog in it, waiting on the compressors or pipelines. It's really just a people availability backlog to complete phase 15 wells back to back to back to back and then get them on line. So, it's more… if is there any backlog, it's… we have only got so many people and we can only run so many frac spreads out there to supervise.

Okay, that's fair. And then let me ask you one more question. It's on the gas side. Obviously, you have some growth in the Barnett on the oil side, but big picture macro, a lot of talk about when the Barnett starts to… when that growth accelerates and it starts to flatten out and/or stabilize, when do you think that happens industry-wide?

Yes, it's my feeling that happens in 2010. I really believe that by yearend 2009, Johnson County is going to be pretty well drilled up by everybody in Johnson County, not just EOG. It's been drilled like a pincushion now, because it's such a sweet spot. And I think you'll see a shift about 2010 to more companies focusing on the Western Counties. But the issues with the Western Counties are there you're basically drilling 1 net Bcf well out there that doesn't have volume impact. And I think in the core areas, the same thing is happening there. So, I do not expect that we're going to have another five or seven consecutive years of year-over-year macro Barnett growth that we've seen in the last couple of years.

All right. Thanks for the responses.

Our next question comes from Wayne Cooperman at Cobalt Capital.

Hi, guys. Just kind of big picture question, just on… you got a view on gas prices, it looks like production starting to ramp-up again and I just was wondering if you guys had a thought about that?

I kind of talked that earlier. I guess it's my sense that clearly domestic gas production gas is rising. But it's not rising as much as the EIA raw gas data would indicate. And by our calculations, I think it's going to be a pretty good race to get to 3.3 Tcf in storage and to get above that. It can be a pretty good pace. So we feel pretty good about 2008 gas prices. 2009, to some degree, is going to be a function of whether we start storage at 3.3 or play at 3.6. But I think as people factor in your supply/demand numbers for 2009 and 2010. We need to factor in that there maybe 2.5%, 3% production growth from the US in '09 and '10, primarily due to horizontal drilling applicability of resource plays.

So you guys and your intelligence would say 2.5% to 3% as sort of the net supply growth?

Yes. This year it may be more like 3.5. I don't believe it's going to be… it's not 10, like some of that EIA data is saying, in my opinion.

Right. All right, great. That was absolutely helpful. Thank you.

Okay.

And that does conclude our question-and-answer session and it also concludes today's conference. We would like to thank you for your participation. You may now disconnect.

Okay. I want to thank everyone for staying on the call and we'll talk to you again in three months.