Good day, everyone, and welcome to the EOG Resources Fourth Quarter and Year-End 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 fourth quarter and full year 2007 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 these reserve estimates on this conference call and webcast, including those for the Barnett Shale and North Dakota Bakken Plays, may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. An updated Investor Relations presentation and statistics were posted to our website this morning. With me this morning are; Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operation; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; Willy Helms, Vice President, Engineering and Acquisitions; and Maire Baldwin, Vice President, Investor Relations. We filed an 8-K, with first quarter and full year 2008 guidance, yesterday. I'll discuss our 2008 volume forecast and business plan in a minute when I review operations. I'll now review our fourth quarter and full year net income available to common shareholders and the discretionary cash flow, and then I'll give some gas macro comments and an operational overview. Tim Driggers will then discuss capital structure. And I'll close with the summary. As outlined in our press release, for the fourth quarter EOG report net income available to common stockholders of $358 million…

Thank you Mark. For the fourth quarter, total exploration and development expenditures including asset retirement obligations were $997 million with $18 million of acquisitions. In addition expenditures for gathering systems, processing plants, and other property and equipment were $73 million. Capitalized interest for the quarter was $8.6 million and for the year was $29.3 million. For the full year, total exploration and development expenditures, including asset retirement obligations were $3.6 billion with only $20 million of acquisition. In addition expenditures for gathering systems, processing plants, and other property and equipment were $277 million. For the year, of the drilling capital expenditures approximately 24% were exploration and 76% development. At year end 2007, total debt outstanding was $1.185 billion and the total debt-to-cap ratio was 14%. The effective tax-rate for the year was 33% and the deferred tax ratio was 79%. During the fourth quarter 2007, and early in the first quarter 2008, we repurchased the remaining $43 million of our preferred stock. We had a one-time charge of $2.7 million in premium and fees related to the repurchase. We no longer have any preferred stock outstanding. Yesterday, we filed a form 8-K with first quarter and full year 2008 guidance. For the full year 2008, the 8-K has an effective tax range of 33% to 37% and at a deferral percentage of 55% to 75%. We will note an increase in our expected 2008 unit transportation cost increasing from $0.27 in 2007 to the $0.41 mid-point in 2008. This is related the firm transportation we have taken on Rocky Express pipeline and several pipelines exiting the Barnett market area. This firm transportation allows us to receive higher natural gas prices since we are now able to sell more gas closer to market hubs. You will notice that the 8-K guidance also reflects tighter differentials from Henry Hub to U.S. as compared to 2007. Using the mid-point of 8-K guidance our full year 2008 unit costs for lease and well DD&A, G&A, total exploration, net interest expense, and excluding transportation and taxes other than income are forecast to increased only 2.5% over 2007, with our current hedge position for 2008, as outlined in yesterdays 8-K filling for every $0.10 change in Henry Hub, EOG's net income and cash flow is impacted by approximately $20 million. Similarly for every $1 move in WTI, EOG's net income and cash flow was impacted by approximately $8 million. Now, I'll turn it back to Mark to discuss his concluding remarks.

Thanks Tim. Now let me summarize. In my opinion there are five important points to takeaway from this call. First, we have a 2008 capital and growth plan that provides essentially 50% debt-adjusted per share production growth. Volume growth is predicated on $7.50 Henry Hub and we may adjust this target either up or down by modulating our 2008 gas direct to drilling depending on our rate of Henry Hub gas price. Second, our liquid mix would begin to shift as total liquids production for crude, condensate, and NGO is expected to increase 37% year-over-year in 2008. We expect total liquids production to also grow at disproportionately high rate in 2009 and 2010. Third, we continue to be focused on ROCE and the bulk of our 4.1 billion exploration and development expenditures will be deployed in a high reinvestment rate of return Bakken Barnett and Uinta Basin Plays. Fourth, our capital structure is very solid with year end 2007 debt to total cap ratio of 14%. We expect the net debt ratio to decline by year-end 2008. Additionally, we repurchased our preferred stock further streamlining our capital structure. And fifth and last, we continue to be at the forefront regarding emerging technology at horizontal wells and resource plays. Our first move will result in Johnson County, the Balkans, South Texas attest to this, and we are continuing to focus on new ideas. Thanks for listening, I will remind you that our 2008 Analysts Conference in February 28th in Houston, and now we will go to Q&A session. Darrel, can you get us shifted to Q&A, please. Question And Answer

Yes, sir. The question-and-answer session will be conducted electronically. [Operator Instructions] We will take our first question with David Kistler with Simmons & Company. Please go ahead. David Kistler - Simmons & Company International: Good morning.

Hey, David. David Kistler - Simmons & Company International: Just harping in the Barnett for one second, when you guys look towards 2009 through 2011 in the presentation, you highlight companywide 10% growth. What percentage of that do you think will be driven by the Barnett given that you gave us a breakout in 08?

I can't give you a specific number on that. What I can tell you David is that during our upcoming Analyst Conference in about three weeks, we'll give you a pretty good estimate of kind of volume growth and broken out of at least specific regions for 2008 through 2010, but what I can tell you about the Barnett at this time is we expect production to continue to grow through at least 2010. David Kistler - Simmons & Company International: Okay. And following up on that, when we kind of look at infrastructure issues etcetera, with respect to the Barnett and with respect to how much you're growing your liquids production, can you talk a little bit about any potential areas which you might be concerned about as far as bottlenecks of transport, processing, gathering coming out of the Barnett?

At this juncture,we're in pretty good shape. As far as getting the gas out of the Barnett area, we've got some firm transportation. Fields cut the Golf south and center point that basically are allowing us to move the bulk of our production to sale at our locations or such as Mississippi and eastern Louisiana. So getting it out of the area and avoiding if possible flat or depressed prices in the local areas is not a problem we get that numbers from FT. As far as getting a pipeline infrastructure out in the Western counties, we are ahead of the curve on that our infrastructure is in very good shape there. As far as the processing plants, only in fourth quarter did we recently start to put a lot of our gas through the some of the processing plants so that's why you saw that jump in fourth quarter NGOs. I don't anticipate at this time we are going to have bottleneck in the processing plants here. So we are in pretty good shape as far as downstream infrastructure in the Barnett. David Kistler - Simmons & Company International: Okay, great. And then just one last question kind of building of that stuff as we look it at, your company and the many of the companies are becoming more and more levered and conventional resources with high decline rates, and we haven't had a whole lot of discussion on this in the last year, so what do you think that the ongoing trend will be for decline rates and where are you guys kind of mapping that out going forward given that over 47% of our production give or take is coming from unconventional as with multiple time higher decline rates?

On the macro side, we continue to believe that total North American total U.S. gas decline rates are continuing to jump and probably are higher than 36%, which is the last time we look with our EOG chart on there, so we believe that you're going to... decline rates at these plays are going level out the decline rate is really not particularly valid, you are going to replace the Gulf of Mexico, which is high decline with a lot of these resources plays which is also pretty high decline at least for the first three or four years of their production plan. And so that, that the difference, what I would also see there David. David Kistler - Simmons & Company International: Yes, I guess I am looking at the recent data that's showing domestic production growth kind of north of 5% and just try to get a handle on the deviation between, what we are seeing come out of the 914 and your comments on 2%, production growth in 2008?

Yes, as I have discussed from the previous earning calls the EIA 914 does not have a lot of credibility with me. I think its consistently overstates actual production growth in the U.S. and I believe if you look at EIA's 2008 forecast rate of sales was forecasted 1.6% production growth this year. But, hardly gets reconciled internally with the 914 but I am not sure. But what I would say is you know, I will make the same comments that are repeated several times. Its very difficult for me to believe the gas production in U.S. is growing at the rate to the 914 indicate, when we are drooling down stories this winter, its looks to me somewhere between 1 and 2 Bcfe a day, tighter than last year and that's after adjustment for the LNG imports differentials. So the withdrawals this year have indicated to me that we have got a system that is tighter than year ago and that just flies in the face of that 914 data. So, you reject the 914 data. David Kistler - Simmons & Company International: All right. Thank you guys very much for that additional color.

Thank you.

We'll take our next question with Joe Allman with J.P. Morgan. Please go ahead.

Hey good morning everybody.

Hey, Joe.

Hey Mark, could you give us some specific data on some of the recent Bakken wells?

Other than just that aggregates to 10 wells, Joe. I can't give you don't want to go too kind of well-by-well analysis of things. What I will say it that our analyst conference I wish would certainly a portion of it devoted to a Balkan and you'll get more, more than you probably wanted to know, relating to the Balkan but the overview point related to Balkan is. It's delivering exactly what we expected you can see that from our old forecast for this year. And what I will say is this is a multi-year phenomena and we will expect that total company crude oil production is going to grow at disproportionately high rate in 2009 and 2010 also still driven by this Balkan Plays.

Could you at least give us what you seeing as the highest initial production rate in the play?

I think its but, yeah, 2000 barrels a day, its pretty much the best we have seen the best wells that we have generated so far are in this Austin area. We highlighted the first Austin well on the last earnings call. And we have subsequently drilled. I believe it's two, just pretty much immediate offset to what's their kind of duplicates to the first well. So, the Austin area which is kind of more in the North part location relative to the most of our concentrated drilling this Austin area appears to be particularly sweet area.

And that's helpful. And then I don't want to steal the thunder from that analyst meeting. But how about other Shale's could you talk about any other kind of new Shale that you are getting some initial results from?

Yes, Joe, I don't want to set any expectations at all for the Analysts meeting, as we said repeatedly, we are working on other Shale place and you say unusual rock plates in addition to Shale that involved horizontal drilling and we will talk about those place, whenever two things have happened, one is that we have technically proven to play and two is that we've kind of stealthily leased-up all the acreage that we can low-key manner, and so and the example of when we start talking about play is Balkan basically I thinks as the Balkan play-out its going to be pretty well universal acknowledged that it's a very, very big oilfield and EOG has leased the vast majority of that field. And so as we go forward and talk about new play the keys are not going to be any timing related to the Analysts conference, the keys are going to be when its will be technically proven play and when do have all the acreage leased.

It's helpful and then lastly in terms of just the cost environment what are you seeing recently in terms of drilling in complete cost?

We are seeing a little bit of decline in Rig rates and stimulation costs and that's a function of just added rigs and also additional competition in the stimulation market and I guess overall we would say cost for 2008 are about we have seen about 5% to 10% less than 200.

I appreciate that. Thank you.

Okay.

And we'll our next question with Ellen Hannan with Bear Stearns. Please go ahead

Hi, good morning just a quick one from me. Mark in the properties that you target for sale in Appalachian, are you retaining any deep rights to those properties?

Yes we are retaining the deep rights in all the shallow gas production areas that we have, including the minerals that we own out there.

Okay. Thanks very much.

Okay.

And we will take our next question with Gil Yang, with Citi. Please go ahead.

Hi, can you tell me for the western Barnett counties that you mentioned Mark that you only recently started processing gas there. Do you own the plant or you are you processing through a third party plant at the moment?

In Barnett right now, all the gas being process is going to third party plants.

Okay. And when will you have your own plants running?

We are looking at starting some plants, maybe in about a year we may have some done, Gill the only place where we have got into the actual plant business so far is up in north Dakota for the casing that gas out there and there we expect to commence plans forward up sometime here in March.

As you look at putting capital into midstream plants and other midstream assets. You talked a lot of that in your presentation about returns. How will you bring capital into those kind of asset that affect your returns on long term basis?

The returns that we run are commensurate with our drilling and production related investments and what were... what were really narrowing our outlook at this plants to are one, areas whether the resource plays and two, areas that the alternatives or is it very costly or prohibitive so what was... I have been surprised at how high the reinvestment rate of return on these mid-stream assets has looked for us, now it may be that it's only because we are picking some areas or it might be the mid-stream area is just you know very, very strong return for an area.

And you... I mean you always highlight the Barnett and Bakken being anywhere from 40% to 100% rates of result, so you are getting incremental rates of return on that will remain at it for midstream assets?

Yes, they are not approaching the 100% number, but the range of 40% number is more realistic.

Okay. And last question is that, Gary made the comments that overall 5% to 10% total cost, yet I think Tim broke out the call and the cost will rise 2.5% percent. Can you rationalize the differences in those two comments?

Yes, the cost that Tim had mentioned, are really our unit costs, which in many cases those are different from the drilling and completion cost. Gary's response indicated our expected cost to drill wells in 2008 maybe down 5to 10% relative to that 7%, whereas Tim's cost highlighted if you look at, essentially all of our unit cost excluding transportation link '08 versus '07, they want to get that to 2.5% and one of the reasons why there is up at all cost is that our embedded DD&A is increasing each year, as we and everybody else in the industry had high refining cost over the last four five years and over the previous timeframe.

Thanks, Mark.

Okay, Gill.

And we'll take our next question with Brian Singer with Goldman Sachs. Please go ahead.

Thank you, good morning.

Hey, Brian.

Following up on Gill's question with regards to liquid you highlighted at the better NGOs coming from western Johnson County in the Western extension county. When you look at the Western extension county, is this different from your initial expectation. Have you seen any greater liquid content or is it's just in line with your growing production?

I guess the significance of the NGO impact has surprised us in the last year and the net result of a higher NGO has improved the economics in the Western Counties and its ... think about it, NGO prices generally track oil prices and what we saw last year of course was a considerable increase in oil prices which also carry the NGOs up to higher levels than we previously thought and so if you look back and compare to a year or two ago, we know where we're going to be extracting NGO's, but the relative value of those NGO's to the residue gas or that differential was not that great. Today, the relative value of the NGO is considerably higher then the residue gas. We will understand why the residue gas is trading to somewhere around 50% to beat Equivalent of crude oil, so as a consequence, what we see happening here is that the impact of stripping out those liquids has given us an indirect oil price increase if you will through the NGO which has boosted the economics of Western Johnson county and all the Western counties because they already knew that was very rich gas out there. That's a long winded answer to your question.

Now that's helpful, is it also pushing the play further west in your opinion?

No, not further west than what is indicated kind on our map in the investor relation book, so relative to our expectation of the play moving further west over a year a two ago, no, the play is not moving further west.

And if we look at your better than expected performance in the Barnett over the last year is it this NGOs that greater liquid content that you would say is the single biggest contributor or can you talk about what the other contributors were in terms of efficiency etc?

Now the single biggest contributor for our Barnett performance ... improved performance over time has been improvement in well completion efficiency and this is something we kind of practice to a fine art in Johnson County and at our analyst conference will provide what we think of kind of mind boggling examples of that. So if I would say one thing that's improved our outwork on the overall Barnett relative to a year or two ago is that we are continuing to see what I think a pretty dramatic improvement in well completion efficiency. And this is the strength that I think is a big differentiator between the EOG and the other people in the play. There is third party data, some of it some of on our website we just put out this morning, that shows that we are consistently making more better wells than any of our peer companies in the Barnett which leads me to believe that we truly have a technical completion on shales in horizontal wells.

Great. My last... thank you, my last question is on the Bakken, any additional thoughts on downspacing and then your results from pilots?

Yes. We don't have anything useful to share for you, we will shortly be starting our first 320 acres downspace well, but realistically its going to be the end of the year, Brian before we have a technical assessment on whether this field trains about 640 or 320 ex-space. So that one is going to play out kind of slowly, we are going to have to drill well get some data on it and watch the flow performance of that well relative to the offsets. Its probably about six months before we can really judge where we go, what we do know is that under our current scenario one well over 640 acres, we are recovering a very small percentage of the oil in place under that 640 acres. So in our job just few good engineering and technical input is figure out how to get more of it overtime.

Thank you.

Okay.

We take our next question with Leo Mariani with RBC Capital Markets. Please go ahead sir.

Yes, good day. A quick question here, kind of get a sense of what's been going on in East Texas in the past couple of quarters and sort of what your plans are of 2008?

Yes. Leo, I would say we have got a division office in Tyler, Texas which runs all of our operations in Texas, North Louisiana and Mississippi and just to give you a sense of production from that area and all these are organic numbers, don't hold me to absolute specifics, but directionally our production last year was up about 12% year-over-year from that division and for 2008, we expect it to be up another 8% to 10%. So in a low key way, we are showing very good production growth from that portion of our business.

Okay and did you... has there been any recent sort of increased in horizontal exploitation up there at all?

All this production increase we are generating from our Tyler area is all related to vertical drilling so far, but we all are beginning to experiment in a couple of resource plays there with horizontal drilling and we may have some good results from that in 2008, but right now its really all just vertically sourced production growth.

Okay. I wonder if you guys had any comments on as to what your new position is in Appalachian in terms of acreage that you guys own up there?

Yes, now the Appalachian area has been a little bit of a high profile area for us because of all the questions that have come up related to our deal with NFG and what we have... what we can say is we are currently drilling and testing wells in more shallow shale in a couple of areas, one area is on the acreage related to NFG and another is just on acreage that we will lease or own. And it is just to soon to give you any result, don't have enough data to have a conclusive answer relating to more shallow shale in Appalachian.

Okay, a quick question on your Bakken position, you mentioned about 21 million barrels at year end 2007 any idea what percentage of that is PUDs and what's PDP and how many wells it got maybe related to?

Yes, we're about 56% wells there, roughly 50-50... and the reserve amount properly about on the all equipment basis, that 10 million barrels on the PDP and about 10 million barrels on the PUD.

Yes, how many wells that is what the --

23 producing wells, 24 well.

Okay, 24 wells. Okay. Thanks a lot guys.

Okay.

And we'll take our next question with Ken Carl with Samson Rise. Please go ahead. Kenneth Carroll - Johnson Rice & Company: Hey guys, good morning. Just a quick question and some detail on the reserve report, looking at natural gas, you had 127 plus negative revision in North America. Any color on that in sort of any particular areas in fact those are just kind of spread across the company?

Yes, Ken its is, the one area there and I think its broken out in the stuff that we yesterday, but we did have a negative reserve revision of... some consequence was in Canada, where we basically had shallow gas fields, specifically one shallow gas in Alberta that's a drilling results and production results just haven't turned out as we expected in a that particular areas. So consequent that we ended up with a burn I think 57 Bcfe, right now in Canada relating to the shallow gas activities. The other area, as far as the U.S. gas negative reserve revisions that essentially completely offset by positive reserve revision in natural gas liquid. It becomes liquid that will come in liquid. It's a recognition that's particularly in the Barnett at western areas there, for that gas or this hydrocarbon or are going show-up on the accounting statement as natural gas liquids and less as Mcfe. Kenneth Carroll - Johnson Rice & Company: Your just switching part of your... got you. Very good guys excellent quarter. Thanks.

We'll take our next question with Brad Pattarozzi with Tudor, Pickering & Holt. Please go ahead. Mr. Pattarozzi your line is open. And we'll go next with our question with Ben Dell with Sanford Bernstein. Please go ahead.

Hi, Mark.

Hi, Ben,

I just had one question. It's really around your asset geographic distribution obviously when you look at the reserved replacement rate it once again looks like Canada is sort of diluting your performance. Have you given any thoughts whether or not there is a market that spinning those assets up and applying may be proceed go back into the U.S. market where your returns are better?

Not really, I mean... we have given a thought then kind of dismiss them... I really know Canada is and every one... throws the macro picture on Canada gas supply and our picture is not tremendously different in the group, basically forecasting flat Canada production for last several years, 2006, 07, 08. But our point on Canada is that we thank there are several areas there that are amenable to horizontal drilling of what that technology is being applied and the we believe this is a very big deal so we are currently looking at several areas in Canada to apply horizontal drilling of some cases to a resource play and so our expectation are that you know we will again have significant gross coming out of Canada as we look to the 09, 10, and later time frames primarily driven by resources that are accessible only through horizontal drilling that have been un-economies through vertical drilling.

And usually that would be a competitive F&D cost of the U.S. business?

Yeah, it should be a reasonable cost. Every area is going to have to compete with the same pool of capital but we believe that there is a good chance that we are going to have to significant Canada growth as comparative F&D costs.

Okay. And just lastly in the industry there has been some growing interest in onshore high gas in Europe, have you given any sort of look at that, obviously Eastern Europe, Ukraine but also in other areas people has been sort of showing interest?

Yes, the answer is yes, I will take it a little bit more broadly than that. Its my belief that the implementation of horizontal drilling to resource plays and I say resource play can be a very tight sandstone doesn't have to be Shale, but just the application of horizontal drilling to large hydrocarbon accumulations that don't work economically with vertical wells, we think there is going to be a worldwide on shore phenomena and so the way we are looking at areas like Europe are there pieces of acreage that are available where you have a huge assets of hydrocarbons that's never been really tested to see if it will work at using horizontal drilling so we are looking, but we don't have anything specific to talk about vis-à-vis Europe at this time.

Okay, great. Thank you.

And we'll take a follow-up with Joe Allman with J.P. Morgan. Please go ahead sir.

Mark, in terms of your Bakken position could you give us your net acreage at this point?

Yes, it's still we would say greater than 175,000 acres. We are being a little bit catty on our extra acreage position until we get a couple of other deals done but again we will probably disclose something more specifically on our acreage you will get the acreage there in February 28.

Can you give a comment about acreage west of the Nesson Anticline, any you think that improved technology can make that area commercial?

It's possible but we are really, Joe focused more on the other side and as well as you know. And it's a fast crude oil in the Uinta Basin, but some areas are going to be more economics unless we feel like we have more economic portion that scooped up.

Appreciate that and then lastly in terms of Canada I am not sure, are you spending less dollars in Canada in 2008 to get that by-production?

What we are looking at in Canada maybe I'll give you a couple numbers out of this $4.1 billion E&P budget, maybe see it, the portion that's going to Barnett is $1.4 billion, the portion that's going to our Denver division which with the all the stuff we are doing in the e-commerce areas plus the Bakken, plus our Green river Basin Wyoming area, we are going to dedicate about $1.0 billion there. The Canada allocation is going to be about $400 million and that's about flat last year.

Okay, that's helpful. Thank you.

Okay.

This concludes our question-and-answer session. I'd like to turn it back over to management for any additional or closing remarks.

Okay. Thank you. We appreciate everyone who are staying on the line and once again I want to remind everyone that we do have an analyst conference coming up here in February 28th in Houston, and our goal with that conference is to... that everyone who leads the conference have a very, very good understanding of what our three year game plan is and what you can expect in terms of a specifics relating to that. Thank you. Operator: Once again ladies and gentlemen, this will conclude today's conference. We thank you for your participation. You may now disconnect.