The deferred tax ratio is expected to decline from prior years due to reduced capital expenditures and IDC expensing. The effective tax rate will depend in large part on the relative levels of foreign and domestic pretax income. Estimated exploration and development capital expenditures for 2009 excluding acquisitions are $2.85 billion estimating gathering, processing, and other expenditures for $250 million.

For 2009, EOG has 43% of its North American gas hedge at a $9.73 price per floor including both financial and physical hedges.

For 2010 the company has 60 million cubic feet of gas a day collar or swap at an average $9.96 floor. The company has no oil hedges, and it does have a small amount of 2009 through 2011 Rocky basis swaps.

Key questions and answers from the fourth quarter fiscal 2008 earnings call conducted by EOG Resources, Inc. (EOG) on February 5, 2009.

Tom Gardner (Simmons & Company): With respect to your capital expenditure outlays in 2009, are there likely to be somewhat evenly distributed or front or back-end loaded?

Mark Papa: They will probably be a bit front end loaded simply because we''ll be in the process of shedding rigs throughout the year and so the expenditures in the first half of the year will be likely more than 50% of the total $3.1 billion CapEx.

Tom Gardner (Simmons & Company): With that 2010 recovery comes a little early do you think you might pick up CapEx?

Mark Papa: Yes. We certainly got the flexibility to do that. But the plan we''re articulating now is one based upon the assumption that gas prices remained pretty dismal throughout 2009.

Tom Gardner (Simmons & Company): Is EOG currently drilling but not completing wells in some areas?

Mark Papa: The answer to that is yes, particularly doing that in areas that are susceptible to cold weather. For example, in the Bakken play, and also in our Bakken oil play and also in our Uinta Basin gas play, we''re currently drilling wells and just going to wait for completion at least until late spring simply because to frac those wells in the winter time you have to heat the water and there is lot of incremental costs with that and we just in no hurry to rush production and cram it into a market currently has signs of oversupply.

Tom Gardner (Simmons & Company): Other operators are doing inventory in those drilled, but not completed wells, too. Do you think that''s going to be impactful to the timing or duration of the gas market recovery when it comes?

Mark Papa: I know there have been some comments by others relating to the Barnett shales. People have said they''re slowing down in the Barnett shale but they have an inventory of wells yet to be completed. We''ve done a pretty thorough modeling of the Barnett shale on the gas side. And with the recount dropping and also factoring in that there is an inventory of wells yet to be completed, it''s our belief that the Barnett shale is going to peak at about 4.9 Bcf a day in the first quarter of this year. And by the end of this year the Barnett shale will be down to about 4.3 Bcf a day.

In other words, it''s going to drop about 600 million cubic feet a day from the peak. So although there are inventories of completed wells, I think the example in the Barnett shale is that, number one, I don''t believe it''s going to go to six Bcf a day and we think the first quarter is going to be the apogee of the production growth from it. That doesn''t say that the Barnett is completely tapped out. What it says is that there is a huge amount of people who are dropping rigs in the Barnett and likely moving their activity to the Hainesville.

Tom Gardner (Simmons & Company): Just wanted to see how your view of the Hainesville has changed over time. Obviously those were sweet wells that you drilled, first two at over $17 million a day. What do you think is fundamentally different to your ingoing expectations?

Mark Papa: Yes, our prior position on previous calls, the Hainesville was what I''ll call studiously neutral. And we said that we''re not going to opine on the Hainesville until we get some EOG operated wells drilled on our own. Now that we''ve got two good wells under our belt, it''s our feeling that the Hainesville is a real play. The question is what''s going to be the total aerial extent of it. And then the other question is it impacts the gas market is what is the short-term takeaway capacity from the overall Hainesville. And at one point in time will there be an expanded pipeline system to take additional gas out of the Hainesville. But bottom line is we moved from neutral to positive play based on EOG operated well results.

David Heikkinen (Tudor Pickering Holt): A question on the rig count and dropping how quickly drop rigs and are you paying any terminations to drop?

Mark Papa: The answer on the second part is no. We''re not paying any terminations to drop. In terms of how quickly we''re dropping them.

Gary Thomas: We had a peak of 82 rigs there in September and we''re down to 64 now. We''ve got about 36 rigs under long-term contract. By year-end we''ll be down to about 13 rigs under long-term. So just us being at 64 now averaging 45, it will just be like Mark had mentioned on our CapEx, little heavily weighted first half, probably mid-year or so we''ll be down to 40 rigs.

David Heikkinen (Tudor Pickering Holt): Then on the Barnett combo play, just looking at the move towards more gas and NGLs away from oil, can you talk about how large an area you now think is perspective for the combo play and then the new resource assessment of 200 million barrels. Where have your wells been and what have you confirmed?

Mark Papa: What we feel we''ve well firmed up by the drilling we did in the second half of 2008 is an area that''s got low risk development locations sufficient to generate about 50 million barrels of oil equivalent net to EOG. And what we''re going to do this year is basically concentrate most of our drilling in this development area and drill a few step out wells to go beyond that.