Good day everyone, and welcome to EOG Resources 2010 First Quarter Earnings Conference Call. At this time, for opening remarks and introductions, I would now like to turn the call 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 2010 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. Effective January 1, 2010, the SEC now permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve disclosures on this conference call and webcast, including those for the South Texas, Eagle Ford, North Dakota, Bakken, Three Forks, Barnett Shale, Haynesville-Bossier and Horn River place may include potential reserves, or estimated reserves, not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. 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. 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. An updated IR presentation was posted to our website last night, and we included second quarter and updated full year 2010 guidance in yesterday's press release. We remain on track to achieve 13% total company organic production growth this year, dominated by U.S. liquids production. I'll now review our first quarter net income and discretionary cash flow and then I'll provide some operational highlights. Tim Driggers will provide some financial details and I'll…

Capitalized interest for the quarter was $18.4 million. For the first quarter 2010, total exploration and development expenditures were $1.1 billion excluding asset retirement obligations. Total acquisitions for the quarter were $16 million including contingent consideration with an estimated fair value of $3 million related to a previously-disclosed unproved property acquisition. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $61 million. At quarter end, total debt outstanding was $2.8 billion and the debt-to-total-capitalization ratio was 22%. At March 31, we had $230 million of cash, giving us non-GAAP net debt of $2.6 billion, for a net-debt-to-total-cap ratio of 20%. The effective tax rate for the first quarter was 40%, and the deferred tax ratio was 46%. Yesterday, we included a guidance table with the earnings press release for the second quarter and updated full year 2010. For the full year 2010, the effective tax range is 35% to 45%. We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. For the full year 2010, EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas prices is approximately $30 million for net income and $45 million for operating cash flow. For the full year 2010, EOG's price sensitivity for each $1 per barrel change in wellhead crude oil from condensate price, combined with a related change in NGL price, is approximately $22 million for net income and $33 million for operating cash flow. Now I'll turn it back over to Mark.

Thanks, Tim. Before I summarize, I want to cover a few items on the capital side. We mentioned at our analyst conference that we plan to maintain a low debt-to-cap ratio while still achieving the high level of organic production growth over the next three years that have been laid out for you. We intend to manage the net debt-to-cap ratio to a maximum of 25% by either selling mature North American natural gas properties, generating $1 billion to $1.5 billion of pre-tax proceeds by year end 2010, or by taking in a joint venture partner on a large natural gas shale position. Taking either scenario into account with the current NYMEX strip, we should be in a free cash flow position by 2012. I'll now provide a few macro comments, which are consistent with our April 7 presentation. Regarding oil, we're rationally bullish; both short and long-term. We recently implemented some oil hedges. For September to December 2010, we hedged 2,000 barrels of oil per day at $91.50 and for the full year of 2011, we put in place a hedge position covering 6,000 barrels of oil per day at a price just above $93. We will likely implement additional oil hedges, should the market present further opportunities. Regarding North American gas, we're short-term moderately bullish and long-term rather bearish. We think last week's EIA-914 downward revision was only about one-third of what we calculate, so we continue to believe the market is tighter than common perception. We'll be watching the storage build this summer to confirm or disprove our thesis. We currently have only a very small 2010 gas hedge position and don't think this is the time to be adding gas hedges. Now, let me summarize. In my opinion, there are three points to take away from this call: First, the individual well data points we provided today give further affirmation that our key horizontal oil plays are performing as or better than expected. Second, although we haven't walked through any individual details today, all of our gas plays are all performing as expected. And finally, our capital plan is consistent with what we articulated in detail on our April 7. Thanks for listening, and now we'll go to Q&A.

[Operator Instructions] We'll take our first question from Michael Jacobs at Tudor Pickering Holding Company.

Mark, when I think about your planned Haynesville activity, specifically as it relates to -- not just drilling a hole, but rather maximizing activity per section to focus on efficiencies -- have you considered tempering the pace of activity in the Haynesville until prices strengthen? And if not, what would it take for you to slow down 2010 activity and play catch up in 2011?

Yes, it's -- our current rig activity there in the Haynesville is about 11 rigs and we've projected our total North American gas close this year is going to be in the range of 1% to 2%. So we're very cognizant of the fact that the gas market has got a whole lot of gas in storage right now and the last thing we need is everybody to be drilling a zillion gas wells in North America. And so what we've done is, we've tempered, significantly, our gas drilling in all those discretionary areas such as in our Rocky Mountain gas drilling area, and we've considerably slowed down in the Barnett Shale where we've got most of our acreage vested. And so that kind of leaves us with three places where we have to drill a certain amount to hold acreage. The biggest of those is the Haynesville and then we've got the Marcellus and, to some degree, the Horn River. At this stage, we're going to stick with our plan of running roughly 11 rigs and generating that 1% to 2% North American gas production growth. I guess if gas were to fall south of $4 and we were to believe that it was just going to stay there permanently, we'd reassess that. But that's not our current view right now, Michael.

My second question relates to your typical Eagle Ford well, and I know you've got two areas. But when I think about the Eagle Ford, it seems like there's two numbers, an upper and a lower Eagle Ford and that operators to the south and west of your acreage are primarily targeting the lower number. How does that compare to where you're placing wells on your Eagle Ford acreage, and where do you think you're getting contribution from?

Most of our wells today have targeted the lower Eagle Ford, which is a bit thicker, at least on our acreage than the upper Eagle Ford. But we do recognize that the upper Eagle Ford potentially may be a target, perhaps even a separate target, in terms of things. But you can pretty well mark that the vast the majority of our wells, so far, have been lower Eagle Ford completions.

You mentioned JV in the Marcellus and the Horn River; are you going to running concurrent data runs [ph] and looking for best price or is there a preference to JV in one asset over the other, outside of price?

Yes, the JV concept -- in the Horn River, as you're aware, we're working this Kitimat on that potential LNG project up there, although we don't have anything definitive to report. And so, the concept of what we do in the Horn River will be a function of how things shake out with this Kitimat LNG project. So that area is likely to move a bit more slowly in terms of a JV. The one that's on a bit faster track is the Marcellus, and we will be looking at an organized approach to screen interested parties to look and see if we can bring someone in there. And so I would say, the Marcellus, by year end, we should have an answer as to: Are we going to do one? And if so, what are the terms? The Horn River will be a function more of what happens to the Kitimat project. And then, the Haynesville, we have no plans at this time to even consider a JV in that particular area.

We'll go to the next question from Dave Kistler from Simmons & Company. David Kistler - Simmons & Company: Real quickly on the JVs, in the event that those perhaps don't come through or there's any issues selling the shallow gas assets in Canada, would you look to revise the capital budgets to maintain a goal of free cash flow positive by 2012?

Dave, I mean, that's a very hypothetical question. The way we look at it now, we've got two tracks to meet our capital plan. Either track should be able to do it on its own. The one is to sell some of these Canadian shallow gas properties, and get the price that we would hope. But, if the market for gas properties just utterly collapses, then the second thing would be to do the JV in the Marcellus. And by our calculations, either one of those will get us where we need to be in terms of the debt-to-cap ceiling. So at this stage, the question would be: Theoretically, if all of our plans fail, what is going to happen? But I'd say, right now, the best thing to do is to take the process we laid out on the April 7 Analyst Conference in terms of capital plan and the volume growth, and that is currently our best case estimate as to how this thing is going to play out. David Kistler - Simmons & Company: Jumping over to the Barnett Combo and the additional horizontals that you've been doing over there, can we just talk a little bit about what the cost of those look like and how the service intensity of those horizontal wells is increasing? What that may mean from a cost perspective as far as cost creep on the service side?

Specifically relating to that Settle well, in that vertical area? Is that what you're ... David Kistler - Simmons & Company: Yes.

I guess the best way to explain it is: This 25,000 acres that we've got, that, in our Analyst Conference we said, well that's going to be designated for vertical drilling. We always knew that was the best quality acreage, but it's also the most tectonically complex; a lot of thrust faults and so on and so forth. And we had success with the vertical wells and so we said well, because this is complex geology, you can't image in 3D too well there, verticals are the way to go, and they give a pretty healthy return. And then we said, well, before we just commit vast quantities to verticals, let's try horizontal and see what happens. And this horizontal well, the Settle well has turned out much, much better than, frankly, than any horizontal combo well we've drilled so far; and it's kind of startling to us. And so the game plan now is to -- we've got a lot of verticals that we've already drilled that we'll be completing and we'll expect to get the typical results there. On the horizontals, we're just going to see if we can replicate the Settle results. The horizontal wells are going to cost us about $3.5 million a well. The verticals would be, I believe, it's about $2.1 million a well. So you have to get more reserves. But, right now, based on the Settle results, if we can replicate that, there's a pretty fair chance we'll just eliminate the vertical program and go to a horizontal program. But we need to drill three or four more wells to see if the Settle is an outlier or is that a typical well we can expect in this area. David Kistler - Simmons & Company: Given that it's difficult to image with 3D there, do you think it's going to be necessary to be drilling vertical wells to then tie in the horizontals or be able to see the best place to lay the horizontals?

Yes, we've done that. We've drilled a fair amount of verticals, so we've got some control points. Usually, for example in Montague County, we try and target an individual zone in the Barnett and we can image in 3D and so we'll stay within perhaps a 50-foot targeted zone for a whole lateral length. We're not going to be able to do that over in these 25,000 Cooke County acres because you've got so many thrust faults and it's just tectonically more complex. But the question is, even though we can't stay in one individual layer, is the rock quality so much better there that that offsets the fact that we'll be going through multiple layers? And it's an interesting challenge, but it's fair to say right now, none of us expected the Settle well to be as strong as it is, so we're just kind of rethinking, what's the best way to deal with it?

We'll take our next question from Brian Singer at Goldman Sachs.

A follow question with regard to the Barnett Combo; when you look at the potential additional areas that the Settle well could make perspective, is it just limited to the 25,000 acres that you mentioned on your existing acreage or does it also potentially extend the play to the east, which I guess might go into acreage that you don't have.

The way to look at that, Brian; it really does not extend the acres. What it says is, for the 25,000 acres that we laid out at Analyst Conference is -- we gave a reserve estimate there, assuming it's drilled with vertical wells. And if we can really drill that with horizontal wells, and it looks like they would be pretty closely spaced horizontal wells, from what we can tell, then the aggregate reserve estimate for that 25,000 acres will go up and the aggregate rate of return for the investment for that 25,000 acres will be higher also. But it doesn't really extend the likely acreage that we consider good.

Just a clarification with regards to the asset sales, the $1 billion to $1.5 billion; is that you're expectation now, just from the Canadian shallow gas assets? Is it your expectation from total asset sales? Does the potential proceeds or carries in a joint venture get worked into that number? I know you kind of touched on it, but can you just kind of clarify how we should put the $1 billion to $1.5 billion in context with the various options you're considering for asset sales?

The potential JV is not worked into that number, so that would be something that would be added to, as to whatever these property sales are. And we're looking at -- in Canada, it's about 150 million cubic feet a day of gas. Your typical shallow gas in southwestern Saskatchewan and southern Alberta -- and there's also an amount that has a lot of down spacing potential, we feel, of the coal bed methane kind of gas in an area that we call a Twining area. It's similar to the coal bed methane areas that other companies have been developing out there. So that's our game plan and we'll just see how it turns out. We're in the fortunate position that if we don't get the prices we want, we're not that financially strapped where we absolutely have to sell it to meet the debt covenants or anything like that. So we've got a fair amount of discretion as to how we play this thing.

Can you just comment on cost trajectory, maybe even beyond the period this year, where you provided some guidance, that as you think about the oil-to-gas mix shifting and as you see current cost trends and your expectations unfolding, how should we expect those particular operating expenses as we go into 2011?

Yes, I mean, we haven't done a real thorough analysis ourselves of 2011 or 2012 unit costs on this. But directionally, what we would say is our D&A has turned out a bit higher than we've projected. That's due to some to start-up costs in plays like the Eagle Ford and some of these other plays where we've spent a lot of money on the front end to establish the play, and we don't have that much production yet. So we think that that's not a trend that you can extrapolate into '11 and '12. On the LOE cost though, it's pretty well certain that the cost to operate oil wells are going to be higher than cost to operate gas wells. So, I'm not quite as sanguine that we'll be able to contain that with gas well levels as we become an oil company over the next couple of years.

And we'll take our next question from Leo Mariani at RBC.

Wanted to clarify something on the gas-growing [ph] front in North America. You guys are talking about running 11 rigs this year and it sounds like all of those in the Haynesville – did I hear that right; that pretty much the rest of your North American program isn't going to see anything on the joint side?

No, that's just our gas rigs that are running in the Haynesville. The way to look at our capital budget is, that, of our 2010 CapEx: About 75% of it is devoted to oil or liquids rich gas; 25% is devoted toward what we call dry gas drilling, and of that 25%, the biggest single chunk of that is the Haynesville. But there are also increments in there for the Marcellus and for the Horn River and a much smaller increment in there for the Barnett Johnson County stuff.

Is there a way to quantify that Haynesville versus other on the U.S. gas side, in terms of percentage of capital?

Yes, I would guess the Haynesville might be half of that 25%; maybe 12% and then the remaining 13% chopped up among the other plays articulated there, Leo.

Okay.

It's tough call, here. It's a logical question. Is it the [indiscernible]? We do vis a vis the Haynesville, but our read is that: One, it's hard for anybody to predict long-term gas prices, we can take a stab at it, but we're wrong as often as we are right. So, at this point, we are not anxious to forfeit any of that Haynesville acreage and just give it up.

You guys talked about slowing down your Eagle Ford program in the short-term, and as you're kind of waiting for 3D seismic. Are you starting to see some noise in the rock out there, or any type of carson or faulting or anything like that that's causing your results to be suboptimal and you're waiting for the seismic? Can you just give a little more color on that?

Nothing that surprises us at all. We've got quite of lot of 2D and there is some vertical control, wo we know where the faulting is. We just want to get a better handle on how to design the actual lateral wells to take advantage of what we already know. So no real surprises there.

Some of the laterals we've drilled, because we only have 2D seismic now, going at 3D are, what we call, short laterals; 2,000, 2,500 feet. And ideally, with 3D seismic, we can make future wells in the longer laterals and it should have higher reserves per well. And then the concept of what we like to do in any of these plays is pick the sweetest part of a certain zone, for example in the Eagle Ford, there's probably a 20, 30-foot section that we consider the sweetest part of the Eagle Ford. And we want to keep the lateral in there for the whole length and that's pretty hard to do without 3D seismic. So our view is that once we get the 3D seismic shot interpreted, then we can go back and start a pretty intensive drilling program. And, there's a fair chance we're going to end up with better wells than the first 17 just because we've targeted more accurately. So that's why, if you look at that graph we provided on April 7 there, as to the production growth coming out of Eagle Ford, the 2010 production growth coming out of Eagle Ford is really pretty miniscule; 6,000 barrels of oil equivalent per day, and we really don't get cranked up until '12 to start showing significant production growth. So we've got that planned into our program, into our three-year volume growth side, and we never expected that we were going to have vast amounts of Eagle Ford production this year.

Jumping over to the Permian basin, just trying to get a sense of what your current acreage position is out there?

We've got some legacy acreage and items like that. But we don't have anything definitive to report right now on anything in the Permian Basin.

And obviously, with oil prices being pretty high and clearly, you guys are the technical leader in the horizontal drilling side, just curious as to whether or not you guys are starting to pick up activity out there?

Yes, we just don't have anything to disclose to you at this time relating to that, Leo.

On China, obviously, you had the well results you guys announced around your Analyst Day there. Just curious as to whether or not that well has actually been producing or that just in test phase at this point in time?

That well we talked about at the conference has been on production for, I would say about three months now. It's got fairly long-term history for us and it's quite stable, so we're pleased with what we're seeing so far. What we need to know is; can we replicate that? And we're in the process of drilling with that Rig that Mark talked about. Additional wells in that zone, as well as the oil zone we mentioned in the conference on April 7, and we hope to have more completions by late summer. And then we have some production history to be able to comment on those. We're targeting end of the year to really make a decision on all that.

Can you remind us; what your acreage position is over there in China?

130,000 acre contiguous rectangular block, in the center of the Szechuan basin.

And our next question is from Irene Haas with Canaccord.

This is on the wells you're working on in Montague County. The Alamo A unit 1, 2, 3? The spacing of 55 acres is roughly about 450 feet? Can you give us a little more color on how and why these wells are spaced? And how many do you have spread between Barnett A, B and C zones? Is this one of your concept of developing these wells in sort of a rolling multi-well pattern?

Yes, Irene, you're correct. Most of this area is being staggered with the spacing being in the 400 to 500 foot between laterals. And yes, we'll just comment that these three wells, the net EUR for these wells was 343,000 barrels equivalents per well, that fits our 337,000 we're seeing there for the horizontals on the average.

[Operator Instructions] We'll take our next question from Ray Deacon at Pritchard Capital.

Mark, can you talk about the gas-oil ratio in the Barnett Combo play? Does that vary at all in Cook County versus Montague?

Yes. In the entire play – we've got a bar chart in the analyst slides, but it's roughly about a third, a third of a third over the life; NGLs, crude oil and natural gas. In terms of Cook County ratio versus the Montague County, we haven't detected a big difference there from that third, third, third ratio. I'd say we [ph] keep across the whole combo play. That's the best knowledge we have today on that.

One more on the Marcellus. I saw that a lot of the acreage is in that Elk, McKean County in your JV with Seneca, and I was wondering is it just lack of activity that might explain the lower IP rates there or do you think that, that area is just going to prove to be more tight and maybe less economically attractive than other parts of the Marcellus? Or is it too early to know?

Yes, I guess the real answer is, it's too early to know. Because I'm not sure that we've put our best foot forward yet on learning how to complete those wells. We have some completions that we're going to start, actually, in just a few weeks here, from some wells we've already drilled in that part of the Marcellus play, and we would hope to improve on the results we've had to date. I think it is fair to say that it's probably not going to be as highly pressured there as it is in the deeper parts of the trough in the Marcellus basins. So, we're not expecting five, six Bcf kind of wells. I think, like we said at the conference, we're expecting more like 3.5, maybe 4 Bcf per well.

[Operator Instructions] We'll take our next question from David Tameron at Wells Fargo.

Mark, you mentioned about the lateral lengths and then maybe you're doing some longer laterals. I don't have the analyst book in front of me, but you had talked about longer laterals in the East – I'm sorry, shorter in the east and longer in the west I believe, at the Analyst Conference? Are you changing assumptions in the east? Can you just talk more about that?

The productivity seismic that we have, the geology is a bit more complex in the east of the Eagle Ford and it's a bit more simple as you go west in the Eagle Ford. And kind of offsetting that is, the rock quality in the east appears to be a little bit better than in the west. And so the point is, if we drill, particularly in the east, off of just the 2D seismic – that old 2D seismic -- there's a pretty fair chance that if we try and drill longer laterals, we're just going to cross some sort of a fault. And so, what we're doing is, particularly in the east, is we're just saying; let's just hold off a bit here -- the geology is a little bit more complex there -- until we get 3D seismic, and then we can image these fault blocks properly and decide how best to go. But probably, what's going to happen is, the average lateral length on the play, will be such that the west laterals are longer than east laterals. But in both areas, the laterals will be longer on 3D than they are, than we're capable of doing on 2D.

And the well cost, you threw out like 5 – I think you had $0.5 million less in the east rather than the west, so those $5 million, plus or minus, still good well cost assumptions?

The Settle was the one that was $3.5 million. That was the first well over there.

The $5 million is about right for the Eagle Ford.

On the Eagle Ford, you guys drew the map in your books and kind of cut the acreage off, or cut your map off where your acreage ended. To play devil's advocate, are you saying that it doesn't extend down south and west? Or, did you not test that area? Or did you look at it in the past? Or, can you just talk a little bit about outside your window there.

We showed you the map over our acreage because that where we're most confident where we have the most control. And I think it really just doesn't help us to give out more data than that, frankly. I mean, obviously, the play does continue to the west for some distance; I think others have us proven that already. The question is quality. We think we've got the better quality end of that play in terms of permeability and porosity, innate in the rock itself, drilled depths, oil content -- we just think that we studied the entire play and took our half million acres in the oil window in and the part of the oil window that we thought had the best rock.

Just on hedges, kind of what level, given that you saw – the majority of your production is still gas, what kind of level are you looking to hedge at? I'll leave it there and let you answer.

We mentioned at the Analyst Conference that on the crude oil side, for 2011, I guess in an ideal world, I'd like to exit this year with maybe about a 25% of our crude oil hedged at numbers north of about $93 a barrel. So we're looking at, if a market will allow us, of adding considerable more oil hedges. But we'd still be 75% unhedged, because we are bullish on oil. On the gas, it's really just a function of whether the EIA is right, or whether we're right on how tight the supply and demand are right now. It's our belief that the storage builds are not going to be as strong this summer as some people are predicting. Now that's not withstanding the huge storage build that we're seeing right now in April because of the weather. But, if we see some strengthening in the 2011, 2012 NYMEX for gas, at some point, we will pull the trigger on some hedges for the gas also. I'm not going to give a price point on that, but we don't think it's there on the current strip.

And will take our final question from Bob Morris at Citi. Benjamin Dell - Sanford C. Bernstein & Co., Inc.: On the Settle well in the Barnett Combo [ph] play, do you think there that you got the high rates because you intersected a karsted area?

No, we don't think we intersected any karsted area. The rock quality is just so much better in this particular area that it's not totally shocking that we got this kind of a rate on a well. And so we did measure, along the lateral, the flow rates and – the first thought was; wow, we've intersected some big fracture and all the flow is coming from one piece of the lateral. The flow rate is pretty uniform across that lateral, which is exactly what we had hoped it would be; which tells us that it's not one giant fracture that's contributing, but it's the whole length of it. So that's why we decided to highlight the well, because at least all the technical parameters we can have from one well; it looks like something that we have a reasonable chance of replicating here and it could be pretty significant in terms of rate of return impact on the whole project. Benjamin Dell - Sanford C. Bernstein & Co., Inc.: Did you fracture stimulate this well at all?

Yes, actually in this Barnett Combo as well as in Johnson County, in the gas, if you don't fracture stimulate these, you get pretty close to zero in terms of production from them. Benjamin Dell - Sanford C. Bernstein & Co., Inc.: I know you've got your capital constraints on your goals on the debt-to-book cap, but are you continuing to see opportunities to acquire acreage? And, are you continuing to acquire acreage in existing or new plays? And how much might you spend this year on new acreage?

In terms of the plays that we've discussed, whether in [inaudible] or even the Niobara or the combo play, we're not buying much additional acreage. The acreage costs, since our Analyst Conference in all those plays have gone up dramatically, in some cases tenfold, just in a month. And so we're really not adding much there. We have some other plays, potential plays, that we haven't talked about and we're testing it and that's where we're concentrating on adding additional acreage right now. I want to thank everyone for staying with us on this report today and we look forward to talking to you again in three months. Thank you.

That does conclude today's conference. We thank everyone for their participation.