Good day everyone and welcome to the EOG resources 2009 Fourth Quarter and Full Year Earning Results Conference Call. At this time for opening remarks and introduction I would 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 fourth quarter and full year 2009 earnings and operational results. This conference call includes forward looking statements. The risks associated with the forward looking statements have been outlined in the earnings release and EOGs SEC fillings and we incorporate those by reference for this call. This conference call contains certain non-GAAP financial measures. The reconciliations schedules for these non-GAAP measures to comparable GAAP measures could be found on our website at www.eogresources.com. Effective January 1st 2010 the SEC now permits oil and gas companies and their fillings with the SEC to disclose not only crude reserves but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast including those with Barnett shale, North Dakota Bakken, Horn River and Hainesville may include 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 web site. With me this morning are Loren Leiker, Senior EVP of Exploration, Gary Thomas, Senior EVP of Operations, Bob Garrison, EVP of Exploration, Tim Driggers, Vice President and CFO, Moira Baldwin, Vice President and Investor Relations, and Jill Miller, Manager of Engineering and Reserves. An updated IR presentation was posted to our web site last night and we included first quarter and full year 2010 guidance in yesterday's press release. I'll discuss our 2010 business plan in a minute when I review operations. I'll now review our fourth quarter and full year net income available to common stock holders and discretionary cash flow and then I'll review our year end reserves…

Good morning. Capitalized interest for the quarter was $16.6 million and for the year it was $54.9 million. For the fourth quarter 2009, total cash exploration and development expenditures were $836 million excluding acquisitions and asset retirement obligations. Total acquisitions for the quarter including non-cash were 501 million. $113 million were cash acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment expenditures were $85 million. For the full year total exploration and development expenditures were $3.1 billion excluding acquisitions and asset retirement obligations. Total acquisitions for the year including non-cash were $707 million. $318 million were cash acquisitions. In addition, total gathering, processing plants and other property, plant and equipment expenditures were $326 million. For 2009 approximately 37% of the drilling program CapEx was exploration and 63% was development. At year-end 2009 total debt outstanding was $2.8 billion and the debt to total capitalization ratio was 22%. At December 31, we had $686 million of cash giving us non-GAAP net debt of $2.1 billion for a net debt to total cap ratio of 17%. The effective tax rate for the fourth quarter was 36%. The effective tax rate for the year was 37% and the differed tax ratio was 54%. We also announced another increase of a dividend on the common stock. This is the 11th increase in 11 years. Effective with the next dividend, the annual indicated rate is $0.62 per share. Yesterday we included a guidance table with our earnings press release for the first quarter and full year 2010. I'll note one item on the cost side. Unit transportation costs are expected to increase on a sequential basis and for the full year. This is being driven by the projects that EOG is undertaking in-house primarily, the crude by rail operation from Stanley, North Dakota to Cushing, Oklahoma. This increase is being offset by a reduction to the WTI differentials on our U.S. crude oil that is being reflected in the guidance that we have provided. For the first quarter and full year 2010, the effective tax range is 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the first quarter and the full year. EOG’s price sensitivity reached $0.10 per Mcf change and Wellhead natural gas prices is approximately $30 million for net income and $45 million for cash flow. For each $1 per barrel change in Wellhead crude oil and common safe price combined with the related change in NGL price the sensitivity is approximately $22 million for net income and $33 million for cash flow. Now I’ll turn it back to Mark to discuss the macro and his concluding remarks.

’: Now let me summarize. In my opinion there are four points to take away from this call. First, the impact of our horizontal oil plays is clearly gaining momentum. During 2008 and 2009 we organically grew total company liquids at 42% and 28% respectively. This year we're targeting 47% year-over-year. The driver of this large growth has been horizontal oil. Last year 42% of our total drilling CapEx was directed toward oil. This year that number will be approximately 60%. From the highlights we've provided its apparent that all three of our key liquids plays, the Bakken, Barnett Combo and Westgate are performing as advertized. Additionally we continue to work on other new play concepts. Second, we haven’t neglected the national gas side of the ledger and our gas resource plays are also performing as advertised. We're especially pleased with the upside from our recent bossier. Third, EOG has a 10 year track record of ROCE leadership in a peer group and although our 2009 ROCE was a low 5% due to weak hydrocarbon prices were likely one of the few [pier NP] companies to report a positive GAAP ROCE for 2009. As we transition toward a higher percent of oil production, I want to remind everyone that the historic hallmarks of EOG focus on returns, low debt and low cost will continue. And finally, just the housekeeping item, we plan to host an analyst conference on April 7 to give an overall operational update and will also provide a 3 year volume outlook. We will also talk about our capital plans at that time. Thanks for listening and now we'll go to Q&A.

(Operator Instructions). And our first question comes from Joe Allman. Go ahead please.

Mark in terms of your activity in the river basin, targeting oil and in the northern Colorado, southern Wyoming, Niobrara Oil Play, could you comment on your activity there?

I am just going to make a comment at this time that we have got a policy of not commenting on any of our horizontal oil activities where we are still leasing acreage and so at this point I am not going to make any comment regarding that. I will acknowledge because it’s after in the public domain that we are drilling some horizontal oil wells in the Niobrara and the DJ basin. That’s as far as I’m going to go at this time till we get our acreage completely locked up.

Okay, thanks. And then even Eagle Ford Shale appears that you're pre-active with rig activity there, any comment there and at what point does it become material enough where you feel like you actually have to disclose this to the public?

What I’ll comment on relating to the Eagle Ford is similar to what I said last quarter and we’ll acknowledge that we are doing some drilling activity, horizontal activity in the Eagle Ford again that’s the matter of public record in until our lease situations tied up, we are not going to make any further comments.

Okay, thanks Mark and then you announced in the release of Rocky Mountain assets swap, could you comment on that?

Basically it was an asset swap relating to assets in Utah and it certainly clouded our accounting as we had to right up the asset received to fair value. So that was noted in report but basically it was the swap just to further concentrate our assets in the Utah area.

Okay, got you. Then lastly the revisions, around what percentage of the revisions were proved develop reserves versus PUDs?

I don’t have that number on hand Joe, maybe normally 30% were PUDs although we don’t really have it there. That basically I will note that the revisions frankly were higher than we would have expected going into this period. We really got clipped relating to tail gas for the Canadian shallow gas properties and that’s the single biggest piece where the negative revisions occurred. The good news about the revisions are that if as gas price strengthen throughout the year as we expect a lot others revisions may be all of them are going to comeback 12 months from now.

Thank you our next question comes from Michael Jacobs. Go ahead please.

Hey good morning. Mark, in the past I believe EOG is run a peak of around 70 rigs nation wide could you get to a similar level of activity in 2010?

Again we will address that issue as well as the capital issues in our April 7th Analyst Conference. Again kind of going through what we will talk about in April 7th Analyst Conference, or number one we will talk about the capital program that we anticipate number two, we will probably talking about some of our [stuff] plays where we got our acreage pretty well locked up and finalize and number three, and probably most importantly we are going to give you some volume updates both on natural gas and then on liquids for 2011, 2012. So it's our feeling and again there is probably going to be a lot of questions on these call and I am going to differ to April 7, so get ready for those of you that are in the queue. But when you walk out of there on April 7, you are going to have a pretty good understanding of EOGs overall strategy where we going with our capital structure and what kind of company this is evolving into over the next 3 years. And just I was handed a sheet here on the PUD percentage on the write downs on Joe Allman's previous question there I said 30% is really more like about 10%.

Okay. If I can move to the Bakken light area, you discussed well bore design a little bit. Can we get some color on completion designs in various portion of your Bakken light area as you think about the increasing points of improving conductivity of the well bore? How are you experimenting with various completions?

There is two things going on relating to the Bakken light areas and this would also apply to the Three Forks. The first item we're investigating are really length of laterals and accorded 640's and 960s and 1280's there on the earnings call. What that really is on a 640 well we're drilling roughly 5000 foot long laterals and between 4500 and 5000 feet. The James Hill well I referenced is about a 7100 foot lateral and then we're considering drilling laterals that would be 9000 foot laterals and with each of these, we're also looking at how many fracs to give per thousand feet in lateral and so we've got two items going on right now and its fair to say that its going to take us another couple of months to really evaluate which way to go. But directionally we're probably going to be going to the longer than 4500 foot laterals and perhaps more stage fracs along those laterals.

And as you think about the completion cartel, would you think about tailoring in some ceramic proppant as well and just changing some of the nuances of the completion?

Yeah. The vast majority of the wells we've fraced in the Bakken now and of course we're the leading producer in the Bakken in North Dakota. So I guess we've got the biggest database. The vast majority of it has been just a profit of 2040 sand. We have used a bit of ceramic proppant in some instances and we're still evaluating that but its not obvious to us that we need to go at anything more expensive than the 2040 sand.

Okay. If I can just move to the Haynesville, just a little more color on the decision to concurrently develop the middle and lower Bossier enables, are you suggesting that the two zones offer similar economics or was it more of the bigger call on dual zone development through a single well bore?

No, I don’t want to give the impression, its through a single well bore. As we see it now, we drill a separate well to develop this Bossier and then another well to develop the Haynesville. So we're not looking at two laterals in the same well bore at least at this junction. The significance of what we said is that, it looks to us based on the couple of months production performance for this sustainable forest well that the productivity and the reserves from the Bossier are about identical to our typical Haynesville well and that’s pretty critical when we frac monitored this sustainable forced well and we know that the frac did not go down into the Haynesville. What’s coming out of the well bore of that well is [two] production and not Haynesville production. And where that leads us to, if you take our 160,000 acres, our best guess at this time is that over half that acreage has both zones. So, this is a pretty big deal in terms of what it could mean for total reserves on our acreage in Haynesville.

Last question, I promise I’ll jump off. One of the things that the analyst community is going to be struggling with over the next few months is thinking about undeveloped versus un-booked locations given the new SEC rules and to help us better access EOG's net asset value, would you be willing to start providing either net un-booked acreage or locations as supposed to undeveloped to help us reconcile what's already included in your PB 10?

I doubt that we would want to do that. You get in a reporting, right now we had a lot of work just reporting under these new SEC rules and I'm not sure we want to go reporting net un-booked locations. So we'll take a look at that but my initial bossier is that that’s something we're probably not going to get into.

Thank you our next question comes from Ben Dell. Go ahead please.

I guess I just had one question which is on your PDP's. They obviously fell year-on-year and if I look at the PDP, F&D number its very high both versus your history and versus peers and its also high if I take out the revisions. Can you walk us through why the PDP number pretty much in average geography didn’t really grow or in some cases declined?

Well I mean the revisions are big portion of it there and the only other explanation I could give you other than the revisions side is that it’s a pretty open secret that we spent a lot of money on leasehold for Stealth, oil plays last year and of course all that would be reflected in whatever mining cost you calculate. So we're going to look back, 2009 I think will be viewed as a positioning year for EOG relating to horizontal oil plays and again what I would ask of you, I know everybody out there is going to calculate reserve replacement in different way but I would say you won't get a pretty clear picture of in early April of kind of a lot more items relating to EOG. So I wouldn’t take any data point right now out of context from this point.

Just a follow up question obviously we have seen the horizontal rig count now back all time high can you give us some indication of what you are saying on horizontal spot pay rates availability and also on pressure pumping rates and availability?

Yes we have been able to acquire contract the rigs that we are going to need through the next year and we have got 39 rigs under long-term that is like a year contract. Rates are starting to increase in some of the high activity areas and over the last two or three months, yes we have seen them go up anywhere from 5% to 15% and the same is probably going to relate to stimulation where you expect maybe in 2010 to see stimulation cost creep upward may be in the 5% to 15% range as well. We have been able to lock in most of our services. We have worked hard on the rigs and having over 50% of them locked in as well as locking in on the stimulation. The other thing that we did in 2009 is what we had low tubular cost EOG purchased most of all the tubular that we are going to use in 2010 as well.

Thank you, our next question comes from Brian Singer. Go ahead please.

Thanks, good morning. Can you talk a little about production trajectory? On oil it looks like a lot of the increase you are projecting is going to come in the second, third, and fourth quarters. Can you just talk a little bit about that and then secondly on the natural gas side could you comment on your uncompleted well inventory and when that comes back online or is it has already?

Yes, in terms of particularly the project production trajectory, your question relates oil as if its pretty well certain that every quarter this year our oil production is going to be going up and the big reason why its second half low that is oppose to the first quarter really relates to the Bakken. Again it's just due to seasonality on when we are going to frac a lot of the wells and it's just more expensive to complete wells in a winner time in North Dakota as you can visualize. So part of our plan is to go relatively slow on well completions till the summer and then blitz it during the weather periods in North Dakota so what you are going to see is a big ramp up at that point in time really. So that’s the biggest single driver of the trajectory other than just we have got cumulative higher rig activity that is going to curve in a drilling this year. On the uncompleted well count we have never had significant amount of uncompleted wells, we have got a few in Johnson County wells that will be completing as we get into this year. But in our view that is this whole concept of uncompleted gas wells maybe it's been overwhelm. We don’t see there is the tsunami of uncompleted gas wells out there in the industry that’s going to get common and flood the market or so.

Thank you that’s helpful and just as a follow up on the Bossier can you just provide any more color characterization as how you defining the play and kind of what keeps it to I think you mentioned in 50% of your acreage?

Yeah Brian its really just geology of where that particular zone is deposited its not present in some parts of the play or it's [clay rich] in some parts of the play and in other parts in a play cleans up and looses clay content and becomes just as good terms of frosting permeability and actually pressured as the Haynesville itself and we have mapped that out both with our own well control and lot of core base that we have taken proprietary core data as well as other industry longed in.

And do you see DeSoto Parish is been the sweet spot for the Bossier or do you see extending into other counties that you may not have acreage.

We are not really going to comment on this distribution just yet I think we are still, its not ready to talk about its total distribution yet. We will say as Mark said earlier it covers the substantial part of our acreage at least 50%.

Thank you our next question comes from Scott Wilmoth. Go ahead please.

Sticking with the Haynesville the new presentation as you guys have Haynesville Bossier production expecting the year at about 175 million a day I think previous estimates were about 200 million a day what drove that variance?

Yeah we just looking at the lead times the schedule the frac crews and factoring in some down time it's just I'll say a more precise estimate of where we're looking at. Its certainly not a indication of our well performance. What we've seen so far is that the well performance has been, indicates we have got pretty well strong reserves per well. The other nuance that got into that Scott is and you may have heard this with some other peer company's calls related to Haynesville is there is a theory out there now that you don’t want to pull these wells real hard in the first year and that will improve the ultimate recovery and at this point we're subscribers to that theory. We don’t have enough data to confirm its absolutely certain. But what we doubt in there is that we're going to pull our wells a little bit less hard, lower rates than the estimate we gave three months ago.

Okay. And then in the Bakken, do you guys have any plans to test the dual laterals and testing the Middle Bakken and the Three Forks with?

Not in one well bore. We did some of that out in the Permian Basin about five or six years ago and the mechanical complexities of that just, it sounds like a great idea on paper but the mechanical complexities are pretty darn high. So at this stage we'll be looking at developing for those areas where we've got the Three Forks and the Bakken overlaying each other. At this stage we're looking at the development of two separate wells.

Okay, and then what's the current production out of the basin in the Bakken and where do you expect to exit the year?

Our net production right now is about 26,000 or so but 26,000 net after royalty. That’s EOG and I don’t have an estimate as to where we're going to exit the year in the Bakken.

Okay and my last question, the 5% obviously has increased with the new SEC regulations. Can you give us a little insight into how many offsets were booked in your major unconventional plays?

Yes, I guess the best way to describe it is what we ended up booking is not the most that we could have done under the five year rule. In other words this whole PUD issue has really thrown up in air as I noted on my last quarter's earnings call and certainly if we would have wanted to, we could have booked a whole lot more products than we actually booked and still been within the five year rule. So, hopefully that gives you some insight into it.

Thank you, our next question comes from David Tameron. Go ahead please.

Mark just starting with the last question how do you think about as a management team, how do you try, what level of PUD is appropriate? Its look like you came within 5% of dealings number. So it sounds like you guys are rolling on the same line. Can you just talk about the thought process?

Yes, we did a very sophisticated process as far as evaluating how many prices were available. It could be done within a five year program looking at the technical feasibility of that. But I guess the best way I would describe it David is and again I referenced a little bit on the last call that we expect to see a very wide variance of long companies as to what they've done on PUD booking and what we did is I will say we took a middle ground approach. We took the SEC rules and we said well they now allow us to book considerably more PUDs than in the past rules but lets just not push that to the edge of the envelope and book absolute maximum number of PUDs that could be done under the SEC rules and then we tempered that a bit with those areas that we had done a lot of drilling in and those areas that we had done quite as much drilling in there. So its very subjective and that’s why probably we see some interesting numbers come out as companies report.

Okay and along those same lines can you split out for us how much of the upward number in reserves is due to the new SEC rules particularly the PUD's versus year ago just to give us some apples-to-apples

No we don’t have that handy David.

Okay, one more going down this reserve path, one more question, I got a macro question but, I guess two questions. One can you give me a PB 10 and then second how should we think about, your gas reserves are 80% plus it was 83%. Yet all the focus is on oil going forward. Would you expect going forward to have the re-gas reserves may be trend up a little bit and then oil take a little bigger percentage or how should we think about that if we think about this five years down the road, what would you expect those two percentages to be?

Yeah David. Relating to the PB 10, that will be issued when we issue our 10-K and on the question of percentage of total reserves that are gas versus oil versus NGOs. I think that the production is ahead of the reserves in terms of what we are talking about 47% production from north America this year, that’s clearly ahead of the reserve bookings, what you clearly see over the next five years of EOG is that the percent of oil reserve is relative to percent of gas reserves is going to go up prospectively.

And so we should see oil PDP climb in the future is that accurate?

Yeah that’s an accurate statement.

And then one final question just on the macro front, can you give us your thoughts, there is conspiracy theory coming out of Oklahoma City, EA date of the people aren’t sure if its correct or accurate. Can you just give us your thoughts on go back a year to today rig count decline we have seen declining gas market, can you give some current thoughts where your at?

We look at the non-14 data and we try and tie that back to the IHS data and we really cant tie that and it looks to us like the non-14 data is just consistently over stating particularly in the other states category the second item we look at in the non-14 data is just as balancing item and the balancing item seems to have grown over time so we have tied our internal models to the IHS data and even though the gas rig count has gone up considerably over the last 4 - 5 months what it tells us is that the production is still going to be down to the tune of about 3 bcf a day relative to December 08 throughout all of 2010 and only will it be in 2011 when you start to see the reversal due to the rig count. And then the other data point that we think is probably the clearest data point that something maybe in this with the EIA data is just the, if you look at how much storage draw down has occurred in December and January. How many bcf has been pulled out of storage and it relate that to degree days compared to last year, it’s pretty good prima face é case that we must be tighter than we were a year ago considerably on supply demand so its either got to be less supply or more demand and we kind of believe its probably less supply.

So you kind of sound like you model at the $7 gas guide for 2010, is that?

Well I think we put I think this morning on our website, something like a 6.75 price with a full year 10.

Thank you. Our next question comes from Leo Mariani.

You guys made some prepared comments about the oil differentials in the Bakken shrinking with transportation cost going up. Can you give us a sense on what the net benefit is the EOG and kind of $1 per barrel basis that putting that rail in place?

Just the Cushing pressed right now is that $3 per barrel better than what we get there locally and their average is usually running about $5 or as it differs between North Dakota and Cushing and of course we put in this crude by rail because there is times where trucking and the trucking close rail its much higher then either pipeline or crude by rail. So it’s just transportation alternative for us.

Okay and did it cost you guys to move you your barrels by rail from Stanley to Cushing.

Yeah we don’t want to get in to specifics on that other than the net of it shows up in the strong differentials that were projected for 2010.

Okay you guys mentioned in your release that you sold some California reserves is that just a kind of legacy property and can you give sense of what production and reserves were if your okay with that?

Yeah I mean the production was about a 1000 barrels of oil a day the reserves on a Bcfe basis were about 30 Bcfe and the sales price was roughly $200 million.

Okay again over to your Barnett combo plan you guys reported couple wells in Mountague County and a horizontal base this year I mean it looks like those well results were a little bit lower than some of the horizontals wells you reported in the past in Cooke County just trying to get sense that if you guys do the step out wells I think in the past you talked about sort of 90,000 acre core position in the combo has that changed has that number moved around as a result of some of your recent drilling give me a sense of that.

I wouldn’t try and compare necessarily the rates we quoted like this quarter versus last quarter the most important thing is that the reserves prevail reported last quarter and this quarter are identical that’s had 280 net as to role for the Mboe for the horizontals and about 220 Mboe for the verticals so our read is that the wells we completed this past quarter are essentially identical to the wells in the previous quarter. The initial oil rates are such that in some case we end up with a higher percentage of oil over the total mix than others but the bottom line is we are pretty pleased with the consistency in, it wont read a debt at all but we have got some degradation of the combo relative to last quarter because that’s just not true.

Last question on your Rockies property swap, talking about this briefly just one, get a sense if there is any net change as a result and then reserves the production of moving some properties off and bringing some properties in there?

On the production side it was basically an even swap, on a reserve side yeah we made some adjustment to our reserves related to that but basically what we did is concentrating in asset where we now have a much higher working interest in one of our Utah assets.

Thank you our next question comes from Ray Deeacon go ahead please.

Mark I was just curious if you could break down that the gross Haynesville and Shale wells versus the upper Haynesville or the Bossier shales I guess?

Number of wells?

Is it still predominantly Haynesville shale wells?

You know well over half of the wells we are going to be drilling this year are going to be in the Haynesville, Bossier. Kind of where we are and specifically on bossier just a little more color, there is, we have got the one well that we reported this sustainable forest well and then we are currently completing another well we are drilling several other wells to really confirm what we believe which is this zone exist over 50% of our acreage. So, we’ll definitely have more color on this but even though bossier is the new item, the Haynesville is going to be the bigger dog in terms of production impact relative to the bossier for EOG 2010.

Okay, got it. And just have you said what your return on capital employee target is going to be over the next 3 years?

No we haven’t. all we can refer people to is since 1999 we have averaged the, I think its 19% ROCE over its 10 or 11 year average including last year where it was only 5% so be proud of that as a differential and more importantly the differential between us and other companies and peer group is pretty dramatic in there and we believe we’ll be able to keep that differential and the main reason you got me started on this one right? Main reason why we believe we are going to keep that ROCE differential is that the preponderance of our CapEx on a go forward basis is going to be invested in oil related projects and simply put the value you get for a BTU of oil we believe is going to considerably exceed the value that’s received for BTU gas. So, relative to the lot of other companies who basically are going to be reinvesting primarily in gas over the next five years we are going to be dealing primarily in oil and we just think its going to be higher net back to us. So logically you would expect that we are going to generate superior ROCE just from that parameter if nothing else.

Thank you due to time constraints today we will take our final question from Irene Haas go ahead please.

Hi everybody I have a question back on the Bossier and Haynesville as such would you give us a little more color regarding sort of thickness TOC velocity its good for Haynesville presumably as dry gas and really to step back one more step is that is there a positive implication your sweet spot in East Texas because that’s probably a nice place to prospect for the Bossier Shale being little shallow than Haynesville and could we have better clay content in that Bossier.

Yeah Irene it is dry gas just as the Haynesville is I mean they are only 200 feet apart so the maturation parameters are essentially identical. TOC is fairly similar as well clay content is slightly higher in the Bossier than it is in the Haynesville at least in some areas and really other than that we are just not prepared to talk about where that switch part goes or doesn’t go today I think the well we announced obviously in sotto but we are looking at it in a number of other areas both with fresh modern logs and fresh modern core.

Once again we want to thank everyone for sitting in on the call and look forward seeing many of you in person on April 7 here in Houston thank you.

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