Good day, everyone, and welcome to the EOG Resources 2012 fourth quarter and full-year results conference call. As a reminder, this call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for taking the time to join us. I hope that everyone has seen the press release announcing fourth quarter and full year 2012 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 the EOG's SEC filings and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable measures can be found on our website at www.eogresources.com. The SEC 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 estimates on this conference call and webcast, including those for the Eagle Ford, Wolfcamp and Leonard may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to investors that appears at the bottom of our press release and Investor Relations page of our website. With me this morning are Bill Thomas, President, Gary Thomas, COO, Llyod Helms, EVP, Operations, Tim Driggers, Vice President and CFO, Maire Baldwin, VP of IR and Jill Miller, Manager of Engineering and Acquisitions An updated IR Presentation was posted to our website last night and we included first quarter and full-year 2013 guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first review our 2012 fourth quarter and full-year net income and discretionary cash flow. Then Bill Thomas and I will provide operational results followed by reserve replacement, our macro view and hedge position, and our 2013 business plan. Tim Driggers will then discuss financials and capital…

Thanks, Mark. Our Bakken/Three Forks drilling results during the fourth quarter were outstanding and our 2013 program should be one of our strongest in many years. While most of industry Bakken/Three Forks results are trending downward, EOG results are moving in the opposite direction. In other words, our wells are getting better. There two reasons our well performance is trending higher and why we expect our 2013 results to be strong. First new frac technology is improving our wells in every area of the Bakken/Three Forks. In some cases the new frac technology using our 320 acre downspacing wells in the Parshall Core has resulted in a 30% to 70% improvement in cumulative production over the original offset wells are per foot of treated lateral basis. For example, the Wayzetta 156-3329, a 320-acre down spaced well completed in 2012 has a cumulative production of 330 Mboe in the first 340 days in is still producing at a rate of over 800 barrels of oil per day. Please see our updated IR slides for an illustrative chart. The second reason to expect strong results in 2013 is our drilling program is directed to the Parshall Core and Antelope Extension areas, which are some of the best acreage blocks in the play. Two Antelope Extension wells recently completed at our Hawkeye 01-2501H Three Forks well following 2,945 barrels of oil per day and the Hawkeye 01-2501H, a Bakken well following 2,444 barrels of oil per day. EOG has 75% working interest in these wells. In addition to improving well results, we have completed our first two wells on 160 acre downspacing in the Parshall field. The Wayzetta 022-1509H and the Wayzetta 149-1509H tested at maximum rates of 1,185 and 1,265 barrels of oil per day, respectively. EOG has 68% working interest in…

Thanks, Bill. As you can see with our Eagle Ford reserve estimate upgrade and our success in the Delaware basin, we are very long on domestic oil and combo reinvestment opportunities for many years and this affects our decision to exit the Kitimat LNG project. We believe Kitimat is good project and with Chevron involved the project will likely get built. However the projected Kitimat ROR did not compare favorably with returns from our domestic shale oil projects, especially in light of our Eagle Ford reserve upgrade. We weren’t desperate to monetize our Kitimat position. We simply believe that the substantial go forward capital required by Kitimat will be best reinvested in U.S. oil shale plays. We hope this explains to shareholders our logic regarding the exit of this project. In Trinidad, our fourth quarter gas sales were lower than previous quarters due to downtime from planned maintenance and construction work on our offshore facilities. We are currently in the middle of a drilling program which includes four wells off of our Osprey platform. These wells are expected to be completed in the first half of 2013. In Trinidad, we expect natural gas production to decrease by 4% this year. This is a function of the timing of first production from our current drilling program. In the East Irish sea, we expect our Conwy oil project to start production early in the fourth quarter. I will now address two other EOG differentiators, frac sand and oil margins. Frac sand is easy to explain. Our sand plants ran at essentially 100% during the fourth quarter and met our completion needs. In the fourth quarter our U.S. crude oil price realization was $10.52 over WTI, up from $5.45 in the third quarter. During the fourth quarter and currently our Eagle Ford crude…

Thanks, Mark. Capitalized interest for the quarter was $13 million and $49.7 million for the full year. For the fourth quarter 2012, total cash exploration and development expenditures were $1.5 billion, excluding asset retirement obligations. In addition, cash expenditures for gathering systems, processing plants and other property, plant and equipment were $143 million. For the full year 2012, total cash exploration and development expenditures were $6.9 billion, excluding asset retirement obligations. Cash expenditures for gathering systems, processing plants and other property, plant and equipment were $620 million. Acquisitions for the year was $700,000. For the year, proceeds from asset sales were $1.3 billion. It December 31, 2012, total debt outstanding was $6.3 billion and the debt to total capitalization ratio was 32%. At December 31, we had $0.9 billion of cash on hand, giving us non-GAAP net debt of $5.4 billion or net debt to total cap ratio of 29%. On a GAAP basis, the effective tax rate for the fourth quarter was negative 13% caused principally by impairments reported in Canada. The deferred tax ratio was negative 157%. The current tax provision for the fourth quarter was $152 million. EOG's board increased the dividend on EOG's common stock for the 14th time in 14 years by 10% to an indicated annual rate of $0.75 per share. Yesterday, we included a guidance table with earnings press release for the first quarter and full year 2013. For the first quarter and full year, the effective tax rate is estimated to be 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 for the full year. Now I'll turn it back to Mark.

Now, let me summarize. In my opinion, there are five important points to take away from this call. First, our Eagle Ford potential reserve increase gives EOG a domestic shale oil inventory unsurpassed in the industry. As I stated earlier in the call, we expect industry-wide Eagle Ford oil production to surpass the Bakken over the next two years and EOG indisputably has a premier Eagle Ford oil position in addition to our strong Bakken position. Our 2.2 billion Boe net Eagle Ford position is not theoretical. The production results are visible on both, in EOG and industry scale. When add in our Permian and Barnett Combo assets, we have an unsurpassed inventory of proven reinvestment opportunities. Second, we have added a new Greenfield project to our portfolio with the Permian Basin and Delaware Wolfcamp, plus a significant Leonard Shale upgrade. Additionally, we are excited about additional future Greenfield shale projects. Third, as predicted, this is the year when we expect to reduce our net debt ratio based on current future prices. Fourth, our 10% dividend increase is a tangible signal of our growing confidence and cash flow stream. Finally, and most importantly, we expect our key financial metrics such as EPS, adjusted EBITDAX, DCF, ROE and ROCE to show positive year-over-year improvement in 2013. Thanks for listening, and now we will go to Q&A.

Thank you. (Operator Instructions). We will take our first question from Doug Leggate of Bank of America Merrill Lynch

Thanks. Good morning, everybody, and thanks for all the color, Mark, on the down spacing. You talked in the past about continued adverse supply and increase your recovery rates there obviously you've done a good job on that. Would you now say that 8% is that pretty much target achieved or do you think there is still more running room there and just curious as to what else you might do in terms of trying to look at your recovery rates and I have a follow-up please.

Yes, Doug. There is, no, we can't say that the 8% is the final, final, final answer at all. In terms of what we are still looking at doing on there, there is the continued work on non-potential additional spacing seeing improvements from frac enhancement and then the one that I think is the big hitter potential hitter out there is secondary recovery. In the case of the Eagle Ford, it would be through the gas injection and we have commenced our pilot gas injection project down there in the Eagle Ford, and the reason I mentioned it on the script is that it may be as long as two years before we really have a read on the outcome of a pilot project. I just only want to give a timeline on it, but its worse our investors knowing that the pilot project is underway but it's not anything that we are going to be able to provide quarter-by-quarter feedback as to how is the pilot coming or anything like that. But it is fair to say that we are cautiously optimistic that we will come up with a method of significantly enhancing the recovery above the 8% number.

Got it. Thank you for the answer. my follow-up is really, you have been very disciplined in the focus of your balance sheet and so on but when you take a right turn, obviously you are inflating your net debt to cap. It makes me wonder, given you have got so much resource opportunity, particularly the upgrade in the Leonard, is that still the right metric, the 30% net debt to cap? Is that still the label in terms of pacing your development and if you could maybe share any updated thoughts on how might try to monetize or bring forward some of those non-core assets, not much non-core, as that Eagle Ford and Bakken, through a joint venture or something? So I will now leave it there, Mark. Thank you.

The write-down cost, I think I might have said, about 2% net debt penalty, if you will. We ended the year at 29% in asset to write down. We thought we would have ended the year about a 27% number on there. So you can say we have a little tighter boundary if we stick with the 30%. I think what we wanted to indicate, if you look at the bigger picture and we have the chart in our IR slide that we released this morning, that showed years of our inventory, if we assume that we turf up zero additional Greenfield plays and we have already advised you we are working on additional Greenfield plays, that two things show up. One is the locus of future investments is likely to shift to the Permian basin more heavily than you would have expected before this earnings call just due to what we are seeing in the Leonard and the Delaware basin Wolfcamp. The second thing is that as we develop into a potential free cash flow situation starting in 2014, in other words there were questions as to what we are going to do with the free cash flow. I think that the picture is becoming clearer that where that free cash flow is likely to go is into reinvestments into both Eagle Ford and into the Permian basin area likely, which will generate additional production growth, high rates of production growth in the out years than we would have expected otherwise. So we are still at the camp and I know that disagrees with your thinking. We are still not leaning towards JVs in any of the plays that the our key plays, however. Hopefully that gives you an answer.

Yes, it does. Thanks very much, Mark.

We will go next to Leo Mariani with RBC Capital.

Hey, guys, just a quick follow-up on the Eagle Ford. Obviously you guys increased your potential tremendously here. I just kind of look at some of the numbers, do some quick math, 569,000 net acres, 5,500 locations you have identified. That equates to about 103 acre spacing. You guys are talking more about 50 acres spacing. So it is fair to say that you guys have really high graded that 569,000 acres and are excluding maybe some of the untested areas in that number. So potentially if those were to work, it will drive the number higher?

No, it's not so much high graded. All the acreage is good but by the time you eliminate all the subsurface areas such as faults and everything, and then by the time you honor the lease line that are in there, such as you can't drill wells across the lease lines, then you stay certain boundaries away from lease lines. The amount of effective acreage you can drill on is considerably less than that 569,000. So, that's really the difference between the 100 acres if that's what you were quoting there and effectively the, roughly 50 acres. It's really how much of that acreage can you really access, it's not in a geologic fault or. That's just due to lease line issues Railroad Commission limitation issues you can really access.

All right. That's helpful. I guess, just switching gears over to the Permian, you are obviously taking your Leonard Shale estimate up tremendously 65 million Boe to 500 is a pretty big job, and you are kind of doing something similar in the Delaware with 800 million Boe. Those are pretty big numbers. It seems like the results reported, you got not a tremendous number of wells. I mean, what gives you confidence in sort of putting those pretty large numbers out there?

Yes. Now, that's a good question, Leo. Both of those shales are extremely rich, the Leonard is in most places up to 200 million barrels of oil equivalent per section. And then in the Wolfcamp Shale, is even richer and thicker in some places just up to 300 million barrels of oil equivalent, so they have a lot of resource in place and a lot to work with and each play also has multiple targets and we are working with at least two targets in the Leonard on all of our acreage and in some places we have three or four targets in the Leonard. In the Wolfcamp, we are looking at lease three targets and in some parts of our acreage also, so there is a lot of potential plays zone. When we complete the wells, we're able to isolate the each individual target and we've also had really good success in the Leonard at continuing to down space. We've tested pattern from 80 acre spacing per target and we've not seen a lot of between the wells and so that's very positive also. Of the other things going on in all of our plays are frac technology is really increasing. With each wells, the wells are getting better because of that and we have a pretty strong history. We have 47 wells we've completed before the Leonard, so we have a lot of history on the actual production. Then in the Wolfcamp in Delaware Basin, as you know, there is a lot of deep penetrations by vertical wells for different plays and deeper targets of years, and so on our acreage, we have over 200 well penetrations that we have gotten valves on and subsurface control for both, the Leonard and Wolfcamp, so we have a lot of confidence that the reserve potential is there and then we've been able to continue to reduce our cost on our drilling program, so we've got a lot of confidence that these plays are really very significant plays and we are excited about. They are able to generate very high rates of return on the drilling that we've done so far right now.

That's really helpful. Thanks.

We'll go next to Evan Calio with Morgan Stanley.

Good morning, guys. Pretty helpful update. Just follow-up on the downspacing comment one more time on Eagle Ford, I know you different lease line issues or other issues that imply 45% of your operated [resource]. On that tighter spacing, but I also presume there's some risking element on the spacing, so any comments maybe on how aggressive or conservative assumption might be currently or how the risking might progress and when you might have more data to adjustments on that potential location increases, which is effectively.

Yes. If you are kind of saying can you expect on the earnings call next quarter that we are going to again raise reserve in Eagle Ford for the subsequent quarter, I would say for the year 2013, you should not have any expectations that we are going to be given another number in Sand with a number locations is going up again in the Eagle Ford, so now it's going to take some time to digest. So, there is certainly a possibility down the road, but for the next 12 months. I think the number that we have given you, the $2.2 billion is probably where we are going to sit at.

Okay, that’s helpful. Maybe a commodity question. Thanks for sharing your view on the commodity but any views on condensate pricing? I know we are beginning to see some price degradation as likely those imports are backed out of the Gulf region. Do you expect any price degradation of this higher API hydrocarbon stream? Thanks.

Yes, I will give you a comment regarding condensate vis-à-vis the Eagle Ford. We have a chart in the IR slide we rolled out this morning specifically relating to the Eagle Ford. A point that we will make is that all of our Eagle Ford production is indeed crude oil and the chart that we have shows the major producers there and relative gravity of the oil or condensate production that the producers have as compiled by IETF. What you will see from that chart is that EOG is clearly the largest producer, that EOG's production is well within the oil column, in terms of gravity but many be of the rest of the producers there are actually producing condensate as opposed to oil. But I will say is there is definitely a difficulty in marketing the condensate in the Eagle Ford area. You just have to talk to the other producers to see what kind of prices they are actually receiving for that condensate.

Very helpful. Thank you.

We will go next to Bob Brackett with Bernstein Research.

Hi, good morning. I hate to harp on the Eagle Ford downspacing but I can't resist. If I think about 40 acre spacing, you are basically picking 16 one mile laterals into a square-mile. In the past, you kind of targeted a key zone in the Eagle Ford. Is the go forward plan more of a staggered development with one offsetting in the upper and one in the lower?

The answer to that is directionally no, Bob. Its wells that are spaced the quite closely together, generally in the same stratigraphic interval in the Eagle Ford as opposed to one in, say the upper Eagle Ford and one in lower Eagle Ford. That’s where you get the issue of a question that logically it would come up, wait a minute, you were quoting 450 MBoe per well and now you are quoting 400 MBoe per well. There is some inner well drainage. Bill, you may add something to that here?

Yes, one of the things, Bob, that we have been able to accomplish is, on our frac geometry, we have been able to increase the complexity of the surplus area that were connecting with each well and we have also been able to contain the geometry on that complexity closer to the well. So we are not fracing really long wing link kind of frac. We are really keeping that frac really close to the well and just increasing the amount of surface close to the well. That really is the big driver in harvesting more and more reserves. If you can do that, keep it close to the well and then you can drill more wells without significant interference.

And what do you think about the vertical height of these fractures? Are we looking at things that are kind of tall but skinny?

Well, we have them more aggressive with our fracs. More sand and more frac rates and one of the advantages that the Eagle Ford has over many of the shale plays, it has a very good upper and lower fracs barriers. So, yes, you are right. I mean the fracs are more contained close to the well but they are fully contacting the play, the 200 or 300 feet of that play in the Eagle Ford and it is creating a lot of complexity. So the increased frac rate does help that. You could connect all the play.

Thanks, and then a follow-up. In the past, really only two world-class shale oil plays and/or plays in North America, the Bakken in the Eagle Ford. As you spend more time in the Permian, is that emerging as a credible number three or is it part of a long tail of number three?

Yes. I think it's still certainly number three, and it's still a bit different number three. Part of that is, many of the Permian plays are still a bit comb. They are not as rich in oil. Although we are making headway on that part of it too, but just the quality of the rock the kind of metrics contribution you can get them, the Eagle Ford and the Bakken is exceptional compared to the kind of metrics contribution you can get from the Permian plays. The Permian plays are very good plays, and don't get us wrong. We are not certainly down on those, but they are still I think a bit distant PUD.

We'll go next to Charles Meade with Johnson Rice.

Good morning, everyone. I want to go back to the Bakken on the question. I think Bill Thomas said in his prepared remarks was Hawkeye wells were Three Forks wells and I am curious of two things. One are those the best Three Forks wells you've seen yet and where in that Three Forks section are the place and do you see possibility for more than one bench in Three Forks?

Yes. Those Three Forks wells are in our Antelope area. And in the Antelope area, we do have a significant column hydrocarbon column in the Three Forks, and we have all four benches that have oil in them. That's just the well believe was drilled in the upper bench and it's certainly a good well. I wouldn't say it's any more outstanding than some of the other wells we have completed and we are working on that three forks development and we'll be testing 160-acre spacing and we will be testing multiple benches over the next over year or so, so the Three Forks, particularly in Antelope, where it has a lot of upside for us.

Got it. Thank you. And also going back to, I think point maybe you glanced on a few times here. crude-by-rail marketing. I think, Mark you've kind of made illusion in your comments that you might be looking at taking crude from the Bakken to the East Coast by rail, and maybe you guys are not ready to talk about that, but if you were to start that now, when should we expect that crude might be delivered to the East Coast?

Well, actually we made a few spot deliveries in the last couple months to the East Coast just kind of, (Inaudible) and where we are right now is we are really just kind of doing some strategic work as to the with a plateau of new pipelines that will be the installed during late 2013, specifically to the Gulf Coast. What does that really mean life in crude differentials and then where would we want place or Bakken and our Eagle Ford crude in 2014 and 2015, and then what would we need to do to get in place change our destination, so we are really not ready to talk about that specifically other than to provide our investors that the system we have in place and the locations, where we are selling our crude today are not necessarily where we will be selling our crude in 2014 and 2015.

We'll go next to Brian Singer with Goldman Sachs.

Thanks. Good morning. Just following up on prior question with regards to transporting crude to different destination, what if any capital commitment would be required to shift the focus of your crude going from where you have it largely going now to the Gulf Coast, and is it baked into your 2013 guidance or to the degree that you feel that there is the need to get more crude elsewhere, would you need to raise your capital budget for that?

I mean, the one thing about the crude-by-rail is, it's pretty flexible. We don't think there is any capital requirement over and above what's already included in our guidance guidance. We have already got the tanker cars which is a key thing in the track access with railroads. The offloading terminal would be the issues at a different destinations. We are working on some deals there that would probably end up being joint ventures with other people. So at this stage, we don’t think that there will be huge capital commitments either in 2013 or 2014 for the offloading terminals. So the main thing is just trying to figure out what is likely to happen with these differentials. You know, Goldman has their ideas, everybody has got their ideas, but we are proceeding on the concept that at any point in time that we will be somewhere in the U.S. where there is an advantageous differentials relative to other locations in the U.S. and our job is to see if we can make sure we can get our crude to that advantageously priced location.

That’s helpful. Then as a follow-up, going back to the Delaware basin. In the Southern Delaware basin where you reported the recent well, is that production mix that you expect going forward consistent with the production mix from that well? I think Bill until mentioned just in a couple questions ago that you are making headway on production mix and I was wondering if you could add some color to what you can do to improve the oil production mix in the Delaware and the Permian?

No, I think it is. I think those two wells are representative of what we will see in that particular acreage based going forward. The Wolfcamp does get more oily as you move to the north in the New Mexico in some places. We have not drilled a Wolfcamp well up there yet but hopefully that will be a bit more oily. The main thing on increasing the oil out of these combo plays is certainly the narrow rocking connected to the well's surface area is a big deal. We also have some production techniques we are working on. I think we are not really ready to talk about those right now but we are making some headway on helping to increase the recovery of oil there but we feel really good. I think these whole combo plays are certainly more challenging as these NGL prices have weakened but going forward I believe that we will be able to technically improve those and make those plays better in the future.

Yes, just to add a little bit color to that, Brian. For example, in the in the Leonard play out there, where we previously had shown that the mix was about 41%, although now we are saying the mix is about 50% oil, a lot of it is in the design of the fracs. We typically keep trying to close mouth about most of this stuff because we don’t want share our secrets but the concept of designing the fracs to not have fracs that are necessarily long fracs but have fracs that really increase the surface area near the wellbore more efficiently as opposed to just having long fracs that increases surface area far from the wellbore. What that does is it really likely improves the ability for oil to flow in a radius around the wellbore and that is probably what we think is causing the increased oil yield. So there is things you can do on frac designs that can modify things and help in these combo plays to get more oil out of them. So I am particularly impressed with this Leonard play. A couple reasons why they are upgraded reserves. Number one, that 55 million Boe, that’s probably have a two to three year-old reserve estimate. So it’s a very stale reserve estimate. Number two, all that acreage has been held by production. So we haven’t had any urgent lease expirations. So we haven’t been drilling frantically on it to hold leases. That’s one where even though we take our time, do our science, we purposely kept quiet, as EOG does on some of these plays until we get our Ps and Qs right, but when you take 550 million Boe at 50% oil, we have got something pretty good there and that's going to turn into a pretty significant oil play for us. And that's obviously moved up considerably on our priority list for the particularly 2014-2015 kind of timeframe for capital.

This does conclude today's question-and-answer session. Mr. Papa, at this time, I will turn the conference back to you for additional or closing remarks.

I have no additional remarks. Thank you for listening.

This does conclude today's conference. Thank you for your participation.