Gil Yang (Citigroup): How much maintenance and activity in the Barnett is from lease expiration issues versus the strong economics, and conversely for Uinta, you do not have the lease expression issues but are there economic issues?

Mark G. Papa: In the Barnett most of the leases we have are three year ones with two year extensions. If you want to extend those leases for two additional years, you have to pay the same price that you pay to get the lease to start with. The economic decision you make is to do you drill on those leases or do you pay, the same amount of cost, get the lease in first place. It drives you since I you get a good rate of return anyway, you just keep the activity to level up in the Barnett. So you are driven there, pretty strongly to keep up fairly activity level. In the Uinta Basin, you have high rates of return, basically even at $7, you get about a 30% to 50% reinvestment rate of returns. If it was purely on economics alone, we would drive a high activity level in the Uinta Basin in 2008 and go for higher than a 13% growth rate. The dilemma that you have is why you should be pouring more gas on a market that apparently would be supply long if you were in a $7environment, and stressing our organization''s limited personnel even farther. It is not a case where you are going into an economic distress situation at $7 in Uinta you still have nice economics, but it is more a case that we just fled the market with more gas.

Gil Yang (Citigroup): Will there be any change in the quality of the well in the Barnett that you are drilling to more peripheral areas and will there be a mix shift there?

Mark G. Papa: No, that is not what we see. It is still going to be good. We are blending what we will be seeing over time as you see more of the West and more of the Southern extension stuffs about getting gradually blended in Johnson County and that is where they frac stuff. If you save significant amount for oil out there in the West, it helps your economics because there it is more of a cost driven play.

Gil Yang (Citigroup): With your capital spending variability depending on the gas price, will there be any change to your exploration activity to search for new shales?

Mark G. Papa: No. We still have our ongoing focus in activity for new unconventional plays and the key focus on that is horizontal drilling. All the unconventional plays, unconventional fields we are looking at are the key areas, all of them that we are looking involves horizontal drilling. That is still a heavy focus of the company and we keep quiet about those plays. The most recent example we have is the Bakken of a successful one. When we get one ready and set up and have all the acreage captured then we will talk about it such as the Bakken. Until then you will hear as close to zero news about it.

Leo Mariani (RBC Capital Markets): In the Bakken one of the wells you had come on around 1900 barrels a day at the end of September. What that well is doing today?

Mark G. Papa: The wells have come on and they have a decline rate. It is similar to the Barnett Shale in that the wells come on at high rates then they have a high decline and then they will settle out and they will last for approximately 15 years. A typical well will come in at 2000 barrels a day and then after a few months it will settle down at about 500 or 600 barrels a day. We do not want to mislead you and think that like this Austin wells as highlighted in the press release came on at 2000 barrels a day. It does not stay at 2000 barrels a day for a long time. It will decline rapidly. It is similar to the monster wells at Johnson County. What happens is you capture a significant amount of high rate production in the first year and it generates a reinvestment of rate of returns of 100% easily and then what you end up with is a long life well that produces between a 100 and 200 barrels of oil a day for many years. The finding cost is about $7.50.

Leo Mariani (RBC Capital Markets): Could you give color on your assumption in 80 million barrels recoverable math?

Mark G. Papa: As we continue to drill we are trying to define the size of the sweet spot. We know there is a large oil accumulation in this eastern part of the Williston Basin in the Bakken. The question is how much of it is going to be a 700,000 barrels per well, how much of it is going to be less than that is still economic. At our annual conference last year we first announced this thing at 50 million barrel as our mid point that is after drilling 4 wells. At the end of mid summer we drilled 13 wells, we have that 60 and today we are showing 80 as our midpoint after drilling 22 wells. That also means that we have added leasehold during the timeframe that we have extended sweet spot nine miles north. Parshall area itself is about six or seven miles long and three, four miles wide. We know now that the sweet spot where we can get this 700,000 barrels net per well is of the substantial size. We get to the 80 million barrel number by assuming 640 spacing and we are assuming that 700,000 barrels per well, but only in the sweetest of the sweet spot the core sweet spot. Outside of that which includes a percentage or a proportion of our 175,000 acres we are anticipating halos of lesser reserves per well. What we are doing is modeling 80 million barrels what we would consider a safe number to date. 175,000 net acres at 273 net locations you would only need, less than 300,000 barrels per well net to get that 80 million barrel number.

Leo Mariani (RBC Capital Markets): Trinidad in UK was down in production 2008. Did you have incremental volumes in 2008 in the UK or you thought there was a change that you are going to producing above contract level in 2008?

Mark G. Papa: We just put up on our website this morning the numbers that we expect the UK, Trinidad to add this year to produce 300 MMcfe next year those two to produce 290 MMcfe. The assumptions are that we just have a natural decline in the UK which is by far the much smaller component of that. That is likely to what will happen because we do not have any new production that is likely to come on there. The assumption in Trinidad is that we will be limited to our contract takes. There is a possibility in Trinidad that that we will have contract overtakes but we would guide you to just the contract takes them out. The 13% of the 17% production growth that we just are limited to contract takes in Trinidad trended and we basically go from 300 to 290 in both cases the 13% and 17% in volume from those two entities next year.

Leo Mariani (RBC Capital Markets): How many rigs do you run in the Barnett right now?

Gary L. Thomas: There are 23.

David Snow (Energy Equities): What is happening in the Wolfcamp, New Mexico?

Mark G. Papa: There is not a whole lot new in the Wolfcamp, New Mexico. We are running a couple of rigs out there and have decent results. It is supportive play for our West Texas division and that is all we have ever painted it as being, and that is exactly what it is.

John Herrlin (Merrill Lynch): Given the new sands that fit for purpose rigs or fracs, what is your average completed well cost?

Gary L. Thomas: It ranges anywhere from $1.4 million to $3.6 million depending where we are. The average might be 2.5.

John Herrlin (Merrill Lynch): If you started one of the horizontal wells January 1st in Bakken, would you average about 220-250 barrels a day per year?

Gary L. Thomas: It will be higher than that, because these wells after several months are still 600 barrels a day. Most often it is going to be ramped 350 barrels a day.