There are other successful plays such as the Woodford in Oklahoma, the Fayetteville in Arkansas. The company believes that those are not the only successful plays that will be unlocked with horizontal drilling, and it has as a very high priority within the company to locate and capture acreage positions on other plays. The company is working hard on that, but rather than giving interim reports, it considers it is best that it is not going to give any reports. In a seven to ten month timeframe the company will be able to give a relatively definitive report on that.

How much are you spending on the new shale that you are not willing to talk about?

The company does not feel in the position to comment on that.

You mentioned major technical advances in the area of horizontal drilling. Could you elaborate on that and discuss the implications for service costs and changes to demand in particular services?

It is EOG’s strong belief that there are going to be a lot of resource plays in the future in onshore North America that will be unlocked with horizontal drilling, and that the company is in just the early days of that. It is still on the front end of the learning curve in the Barnett Shale as to how to unlock this asset. The company considers that at the gas in place under the Barnett Shale acreage, it is recovering a small percentage of the gas in place. EOG is going to recover a larger percentage than it is currently indicating through improved technology.

What do you need in drill rig count, in order to maintain overall domestic production on the 914 data?

The 914 is indicating that production is essentially flat for the last nine months. Projecting that into 2008, it would say that the company’s year-over-year production growth, 2008 versus 2007, is likely to be zero. It would say if EOG kept on the current pace of rig activity, rig count, it is going to have zero production growth 2008 versus 2007. To grow production even 1% or 2% in 2008, the company will need a higher rig count than the current rig count it has had for the last six months.

How does Canadian production translate to exports for the US?

The company’s view for full year on Canadian production and translating to exports is that, on a full year basis, it is estimating that exports to the US are going to average about 0.7 of a Bcf a day lower this year than last year, from about 8.8 to 8.1 Bcf a day. That is made up of about a half a Bcf a day less production, and about 0.2 of Bcf a day of an increase of intra-Alberta demand.

What do you see happening in the UK gas market over the next three to five years?

The company is not sanguine about the UK gas market for the next several years. It would be $6 gas prices over the next couple years. It is going to be relatively long on supply between LNG and imports from Norway, and so the company will be ratcheting back its activities as far as gas directed drilling in the UK. It will be drilling about less than one net well in the UK this year. Over the next year or two the company does not have a heavy focus of activity as far as UK directed-gas drilling.

You expect UK gas prices to stay low. What are your assumptions going forward on the LNG market coming into the US in volume with pricing in the US better than in Europe?

For this year relative to last year, the company is assuming that LNG imports to go from last year about 1.6 Bcf a day and they average this year about 2.3 Bcf a day. It basically cancels that, and that is up about 0.7 Bcf a day and that cancels out the drop in Canadian exports, so those two ends up a wash for this year.

How much of that do you expect to impact in Canada in terms of production?

EOG is projecting its Canadian production to be up. The 8-K is indicating about 4% production growth. The total Canadian production numbers year-to-date so far for the first four months are showing production in Canada to be off about 330 million cubic feet a day so far. That is for the first four months and for the full year, the company is projecting an average of about 500 million a day. The numbers year-to-date is tracking close to what the company’s expectations are.

You said you were not willing to take on any debt but now you seem more willing to do that. What environment did cause you to reconsider your CapEx plan?

Two things have helped the company. First, the company had indicated that it was worried about the full year gas price, and the cold weather in February made EOG feel a lot more comfortable. If the company would not have had the cold February, it would have been tempted to make some downward adjustments in its CapEx, because it would not be as positive about the gas price outlook for the year. The second thing is that the EIA-914 data is helping to reinforce the company’s thinking that it is seeing a flattening in US gas productions that tells EOG that even though it has got pockets, like the aggregate Barnett Shale production is growing strongly, in the State of Texas, production is growing strongly, but even with those pockets of production growth, there appears to be a flattening in total US production, which reinforces the thesis that the company has had all along, that it is easy to point to the production growth areas, but fighting the production declines every day, is a different story. The company believes production in 2008 is likely to be flat or up less than 1%, or even down relative to 2007, and Canadian production will struggle to be anything but down again. Taking its net debt-to-cap up to 11% does not seem to be a big issue for EOG.

What are the automated rigs doing to your drilling days?

The company is moving one of the Super Singles, or automated rigs, to Johnson County within the next couple of weeks. It has been operating with some more conventional-type rigs. It has some newer rigs in there, and has been able to reduce its days. EOG was pleased with a couple of recent wells it had drilled with Patterson, and it got them down in 12 days, and a half day for moving because the company was able to skids. Normally these wells take around 15 days. In the Western area, where the company is using the automated rigs, it is running anywhere from 7 to 13 days. They are 13 because EOG is operating in 8 or 9 counties, so when it moves to a new area it takes some time to get its efficiencies in place and to understand the rock. When the company is in consistent drilling in one particular area, it takes it about seven days. EOG’s drilling costs were down to $1.25 million as far as low, and up to around $1.3 million to $1.4 million in western counties.

You announced positive results in the Bakken play, and decided to take that play up from one to three rigs. What are you seeing over there?