Good day, everyone and welcome to the EOG Resources 2008 Third Quarter 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 on election day. We hope everyone has seen the press release announcing third quarter 2008 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 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 the reserve estimates on this conference call and webcast including those for the Barnett Shale and North Dakota Bakken 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 last night. With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President of Investor Relations. We believe our third quarter results can be characterized as another consistent quarter. We hit our volumes projections and all of our costs were in line or were lower than predicted. We filed an 8-K with fourth quarter and full year guidance yesterday. These 8-K projections are consistent with the guidance we provided earlier in the year, and I will discuss them in a minute when I will review operation. I'll now review our third quarter net income available to common stockholders and discretionary cash flow, and then I will provide an operational review including directional thoughts regarding EOG's 2009 plan. Tim…

Thanks Mark. For the third quarter 2008, total exploration and development expenditures, including asset retirement obligations, were $1.6 billion, with $74 million of acquisitions. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment were $124 million. Capitalized interest for the quarter was $10.6 million. Year-to-date, total exploration and development expenditures including assets retirement obligations were $3.8 billion with $109 million of acquisitions. Total gathering, processing, and other expenditures were $321 million. During the third quarter, we did a bond offering to effectively term out our short-term commercial paper borrowings. We issued five year notes totaling $400 million at 6.125% and ten-year notes totaling $350 million at 6.875%. Our credit ratings are A3 and A- and our gain plan remains consistent to stay very conservative on the financial side. In terms of liquidity, we have $1 billion dollar revolver, which has never been drawn. We have no exposure to Lehman. Also included in the IR presentation this morning, there is summary slide taken from the sell slide. It shows 2009 estimated debt to cash flow, cash flow ratios using $75 oil and $7 gas. Using these metrics and these particular estimates, EOG could pay off its debt in just over three months. At September quarter end, total debt outstanding was $1.9 billion and the debt to total capitalization ratio was 17.5%. At September 30, we had $886 million of cash giving us non-GAAP net debt of $1 billion, for net debt to total cap ratio of 10%. The effective tax rate for the quarter was 35% and the deferred tax ratio was 80%. Yesterday, we filed our Form 8-K with fourth quarter and full year 2008 guidance. We also filed the third quarter 10-Q. For the full year 2008 the 8-K has an effective tax range of 33% to 37% and a deferral percentage of 65% to 85%. Using the midpoint of the updated 8-K guidance, our full year 2008 unit cost for lease and well, DD&A, G&A, total explorations, net interest expense, and excluding transportation and taxes other than income, our forecast increased 3.7% over 2007. Estimated exploration and development capital expenditures for 2008, excluding acquisitions are $4.55 billion. Estimated gatherings, processing, and the other expenditures were $400 million. Now I'll turn it back to Mark to discuss the gas macro, hedging and his concluding remarks.

Thanks, Tim. I continue to believe that the primary determinant of 2009 gas prices will be winter weather. A cold winter will likely generate $8 to $8.50 average prices and a warm winter $7. I believe 2009 North American net natural gas supply will grow at most 0.6 Bcf per day year-over-year, which comports well likely electricity demand growth. Our 2009 hedge position was articulated in our 10-Q filed last night. We are about 38% hedged at $9.71 gas price and are un-hedged regarding oil. We also have 60 million cubic feet a day and 2010 gas hedge for caller at attractive prices and have added some rocky basis hedges for 2009 through 2011. Now let me summarize, in my opinion there are five important points to take away from this call. First with the focus on the balance sheet, we are willing to let 2009 gas prices determine what our overall CapEx and total company production growth will be. We've easily got the organic capability and high rate of return inventories to grow total company production 14% next year and subsequent years, but will only do so in a high natural gas commodity environment. Low debt is still very important criteria to us. Second, we expect to continue to lead the peer group in ROCE and based upon our current inventory quality, I don't see that changing in the future. The most important criteria that gives us consistently higher than peer ROCE’s is our ability to grow at high rates organically and not rely on acquisitions or M&A to generate growth and that won't change in the future. Third, we've now verified reserve upside above the 80 million barrels net for the Bakken and has confirmed Marcellus reserves on portion of our Appalachian acreage. Fourth, we're continuing to work on new horizontal ideas and we'll disclose them whenever we’ve got acreage positions locked up. And fifth, our Trinidad, North Sea, and China components may surprise on the upside in 2009. Thanks for listening, now we'll go to Q&A. Cindy, could you queue the Q&A. Question And Answer

Okay. Today's question-and-answer session will be conducted electronically. [Operator Instructions]. And we'll take our first question today from Tom Gardner with Simmons & Company. Thomas Gardner - Simmons & Company: Hey, good morning to Mark. Mark this is... you've been pretty clear on your CapEx comments on the call. So in line with that can you discuss what you see the current environment as an opportunity time to increase your resource playing inventory. It sounds like you're just not going to go there?

I'll tell you what we are seeing right now. Tom, I've mentioned on the call that we're not really going to be making high acreage acquisitions or making mega producing property acquisitions, that’s just not our style. But, we think that whats going to come out in 2009 or are allot drilled earn opportunities on other people's acreage. Companies that either don't have the horizontal expertise or are so strapped for capital that they can’t, they’ve got expiring leases and can't go that. So I wouldn't be surprised, if you see in 2009 that we shift some of the drilling that we do away from some of our core areas to maybe some acreage that we don't really have captured at this particular time that belongs to somebody else. In terms of overall resource play focus, we are continuing to be quite aggressive chasing new horizontal ideas of both and gas and oil, but our game plan is to be the first in where you can get cheap acreage as opposed to be in the second or 10th where you’re paying big dollars for acreage. So I expect that we are going to have some upside surprises during the year on some of the resource plays that we haven't disclosed yet. Thomas Gardner - Simmons & Company: Well on that subject, given these large IPs in Johnson County horizontal. Does this change your average outlook for Johnson County reserves, for well reserves, I mean you are getting to 1.8 to 2.2 Bcf at the Analyst Day?

We might be tendering for the high end of that side. I don't think it's going to change to that 3 Bcf, so I think the key is take away Tom, for the Barnett gas is that Johnson County is a very competitive, every acre is leached there. But the Western County and Southern County, Hill County has been pretty much left wide open for EOG. People who were competitors out there, just have not been able to make good wells. And you can look at Johnson County chart and that's the reason they haven't been able to, whereas we have been able to. So we've been to have a fairly wide open field there with not much competition. So that's what's really changed in the last year is that we now view the Barnett, particularly in the western Counties and southern counties, as more of a growth opportunity than we would of viewed a year ago. Johnson County we are doing better than we expected, but growth opportunities in terms of addeding acreage there are very, very limited. Thomas Gardner - Simmons & Company: Thanks for that. And one last question. I must get your view on sort of a gas growth information that we get, in the past you've indicated some skepticism over 914 data. Can you give us a view on accuracy on that data and perhaps your view on base declines in North America ex drilling and what is going to take to balance the natural gas markets going forward with respect to rigs?

Yeah, I mean we have been skeptical of the EIA-914 data and we devoted a fair amount of efforts to analyze the IHS data versus the EIA data. I do believe EIA data is directionally correct, I just don't believe it's absolutely correct. And what we found for example our comparison indicates that the in the state of Texas, the EIA estimates may well be overstated by about eight-tens of a Bcf per day versus IHS. In Michigan unusual state, the IHS data can't replicate EIA and it’s indeed about six-tens of Bcf a day lower. And then if you look at the other states, we think there is about six-tens of a Bcf difference there, so if you add all that up, it comes out to we would say perhaps production growth in absolute terms this year is maybe 2 Bcf a day less than what the EIA stated. Now it’s still up considerably. And now I think the surprising thing that we’ve come up with is that our estimate is total U.S supply growth, including LNG, including Canada imports, '09 versus '08 is 0.6 Bcf a day. And that's comprised of, just a quick run through the numbers, we think Canada imports will be down about nine-tens of the Bcf a day. That's a combination of demand growth and heavy oil plus production decline. We think Gulf of Mexico next year drops off half a Bcf a day because rig count there is really falling versus a year ago. Rockies goes up 0.2, limited by the Rex takeaway capacity. Barnett only up 0.3 of Bcf a day next year and we still believe the Barnett will plateau in '09. And then remainder of U.S onshore up about 1.1 and then LNG imports about up 0.4. So I know everyone is looking and dreaming, I guess this is terrible, supplies glut and gas prices are in bad shape. But we think with the slowdown in drilling, particularly that the big surprise next year will be that the supply growth to the U.S is considerably lower than probably anybody has predicted today. Thomas Gardner - Simmons & Company: What was embedded rig count assumption in those numbers?

Yes, we're estimating that the rig count goes down somewhere between 200 to maybe 300, 400 rigs overall. And I'd say, we've already seen rigs being moved out of the Barnett. In fact, we're going to slow down a bit in the Barnett and probably remove about three rigs from our fleet Barnett. Thomas Gardner - Simmons & Company: Great color, Mark. Thank you so much.

Sure.

And we will take our next question from Ben Dell at Sanford Bernstein.

Hey, Ben.

I just had one question and that sort of goes around how you look at farm-in agreement. Arguably your balance sheet, your financial position is obviously a lot better than especially some of the small caps and micro caps who have paid high prices for acreage. How do you view farm-in agreements? Are you seeing a lot of that is in the industry and would you consider those especially if you are more constructive on gas going into 2009?

Yes, we've already seen farm-in opportunities and I'd expect we'll see a plethora more of them pretty soon. And the way we would view it , I'd just give a simple example, if we were going spend just say $50 million in our Vernal Utah, Uinta Basin area. The acreage is lock downed and held kind of held forever. We may say, maybe we’ll slowdown drilling into Uinta Basin area and spend that same amount of money earning into a new position in a farm entry somebody. And in that instant, what we've done is we still got all of our PUD reserves and potential in the Uinta Basin, but we've now accreted additional potential on this acreage that we've earned into. So I would say look for us to be doing some of that at least, maybe a lot of that in 2009 as opposed to taking advantage of the company needs to seel assets that badly and trying to get into competitive bidding war to buy producing properties. We just don't think that's a good reinvestment rate of return way to go.

Okay. That's all I have. Thank you.

Okay.

We'll take our next question from David Tameron with Wachovia.

Hi, nice quarter. Mark can you talk about, just specific regarding to guidance, it looked like oil differentials guidance widened in the fourth quarter. Is that a function of trucking out of the Barnet, or did you, (inaudible_, out of the Bakken, can we talk a little more about that what was driving that?

Yes and the answer to your question is, yes. Clearly, the biggest growth area we have for oil production and going into next year is the Bakken. And what's happened up there is, I don't have remind you or anybody else that not only is EOG having success in the Bakken, but a lot of other companies are having success up there. And the oil pipelines infrastructure, the oil takeaway infrastructure has just been subsumed by the EOG volumes plus the other company's volumes. And so as a consequence, we are piping about half our oil out and we're having to truck about the other half of our oil out. And I expect that’s a similar case for most other companies who are up there. We expect to get that problem fixed by midyear next year by expanding oil pipeline capacity out of there. And there will be some trucking differentials that will probably last until mid year '09. And I will also note that we're currently looking at a dense phase gas pipeline to get the very, very rich gas that we are stripping out of the oil up there to get that into alliance pipeline and get it to Chicago market and we hope that project sometime late in '09.

Is that your pipeline? Who's done the pipeline?

Yes, the dense phase gas pipeline will be built by EOG. On the oil side we are in discussions with several other companies. And we are not sure whether we'll take an equity interest in it or other parties will. That's still open at this point. But, it's a very, very high priority project for us and for other companies that are producing oil up there

Okay. Trucking it is somewhere in the $12 to $15 range, as far as less differential when all is said and done, is that a good number to use?

It's probably a little bit higher than that right now. It may be up to $18 dollars…

Okay. One more question and I'll let anybody else to jump in. Getting back to the Barnett Oil, how many wells have you drilled? I know you had initially targeted 60 to 80 back in February, but how many wells have you got down? And can you talk about when you start running into sensitivity as far as oil prices, what kind of number do you need as far as oil to make this thing work?

I don't have a count right of now exactly how many wells we’ve drilled, a lot of experimenting on a lot of those wells. But the question is that how low do oil prices have go before we get into a situation here that doesn’t look all that good. The answer is at today’s oil price and $7 gas prices, we are generating about 30% rate of return based on our typical wells that we expect, which is 100,000 barrels of oil gross, but 0.35 million cubic feet of gas and about 45,000 barrels of NGLs. So if oil does drop to 40 bucks a barrel or something like that. It's not obvious this projects going to be economic. On the other hand if it goes back up to $90 or $100 a barrel, we think it's going to be tremendously economic.

Okay, did you say 30% current kind of current deck?

Current deck, yes.

All right, thanks.

Okay.

And we'll take our next question from Brian Singer with Goldman Sachs.

Thank you, and good morning.

Hey, Brian.

What are your current thoughts on 320 acre down spacing potential in and out of your core Bakken properties?

At this juncture we've drilled one 320 acre down space well, and we're monitoring it. And where we sit at this point in the core area is that we would say that if the CO2 injection turns out to be a viable opportunity, then it’s a slam dunk that we drill the 320 acre spacing. If we find that we are not improving the recovery above that 10% with 320 acre spacing in core area, then it's more of a close call and it's not obvious that 320’s are necessarily to drain the wells. In other words, you put in the capital, but the incremental reserves there are not all that much. As you go outside the core area, some of this area that we said is now made to reserve bigger than 80 million barrels up because the well quality, the rock quality is not quite as good there, it looks like that will pretty well certainly beyond the space 320 acre space. That give you some direction on that Brian.

Yes, it does thanks. And then, in the Marcellus, what would you say changed over the last few months that's given you more confidence at least on that I think 40,000 acres you mentioned. And when you think about the $2.25 at MMcfe, you see that is a starting point from which you would expect decreases, or do you feel that the firm number?

Right now that's a program number. I mean it may improve with time. We haven't drilled a large population of wells there. Maybe the biggest thing there that has changed there and got us over the hump is kind of the completion efficacy there. We think now as we're getting a higher degree of our fracks focused in the Marcellus Shale as opposed to going outside of Marcellus Shale. In the Marcellus, as opposed to the Barnett or the Bakken, the risk appears to be greater just on relative rock strength that you can frack out a zone and waste your frack energy. But doing some tweaking to our fracks, we think at least on this 40,000 acres will get that pretty well resolved. But it is fair to say that so far we haven't been able to replicate the numbers that some other companies have been able to put up, I’ve seen some numbers of four Bcf growth, 3.5, four for Bcf growth or a typical Marcellus well. I'll be a little surprised if that turns out be the number across a wide area. But our number is more like a two right now.

Great, thank you.

Okay.

And we'll take our next question from Joe Allman with JPMorgan.

Yes, thank you and good morning, everybody. Mark can you talk about, you've been mentioned that you’re planning on dropping maybe three rigs in the Barnett Shale. Could you talk about the reasons for that, and could you talk about whether or not you're slowing down anywhere else at this point and now you've transferring rigs to another location?

We're kind of consigned activity to our planned budget for 2008 and we're more efficient with the number of rigs that we have. So we are drilling more wells with less rigs. And we just reduced there in the Barnett thus far, we're dropping a couple of other rigs. We've declined from 80 rigs down to 71, just throughout EOG. Also that's just the efficiency. You probably see on a couple of charts there our on presentation were, yes we reduced our days substantially. For instance, in the Bakken we were requiring about 37 days in 2006. Now we're down to 25 days for the average of 2008 productive wells stand in the 15 day range.

Okay. And is economics a factor here or are seeing any areas where you know, given the NYMEX prices, given wide well head differentials, the economics just don’t work out?

I think almost everything we have is economic times down to $6.00 or $6.50 in Mcf. It's just kind of a case Of we want to put our drilling in 40% projects or in 15% projects. So, it's not a case where anything has gone underwater economically today, but as just the case, as we said that if we really have $7 dollar gas and a warm winter, we are going to bust our butt as a company to push in lot of gas into a $7 gas markets. We would just sit on some of our ideas and wait for better gas times.

Got you. And where you is the service cost decline and what bigger service have been decline at this point?

We've seen some decline in just the drilling rigs. Quite a number of our rigs are not long-term committed. Some of the completion units, directional surveys, services, some of that. Overall probably just 5% decline, where Bakken required the number of service providers, I expect them to see these others of course stills going down for a lot of well. There is a stage of our inventory is increasing and there is several other spending that yes, will these things declined so you’re at least first quarter '09?

It's helpful. And then in the Bakken play, Mark can you comment on the three forks Spanish and what you’re seeing there?

Now we're still studying the three forks Spanish outside the Parshall areas. We said in the past in the Parshall area, we really don't see too much prospectively there, but that we have 370,000 acres at total Wilson Basin, of which about 110,000 in that Parshall flash Houston area. So that big slug of acreage outside of that we think is highly prospective, particularly three forks.

Okay very helpful. Thank you.

And we'll take our next question from Gil Yang with Citi.

Good morning, Mark.

Hey, Gil.

With the change or sort of variable capital spending budget between $7 and $8, I guess the question I have is on one hand if you slowdown, does that free up spare in capacity among your people and what happens and what will those people end up doing? On the other hand if you accelerate, so to speak, does it in your, I guess you've already seen this in Bakken, does the tax infrastructure either on your people or on the take away infrastructure and maybe you’ve already addressed this already, but how do you deal with the accelerating and decelerating downstream impacts to infrastructure, both people and hard infrastructure in those areas?

Yeah, The four areas where we are seeing infrastructure related issues around Wilson basin Bakken, we are being proactive in lot of cases building our own infrastructure and the Barnett oil, where there was essentially no infrastructure for the rich gas project. We're building our own plants and infrastructure there. And then up in Canada in the Horn River Basin area where infrastructure is pretty limited and we think pragmatically that we'll have a third party install that infrastructure as opposed to EOG. But it's probably going to be a 11 before that happens. And then in the Marcellus; that’s highly, highly infrastructure challenged. We are not sure how we are going to be addressing that but really that you probably third party there. So as you find these resource plays, what really sorts out is that many of them are in areas where you never had higher significant hydrocarbon accumulations. And the resource plays in aggregate has turned out to be bigger than anyone expected. I think if you just take the Bakken for example, or the Barnett, what people thought it would be four, five years ago and what it is today. And I am talking about not only for EOG but for the rest of the industry, they've turned out to be considerably bigger. And hence we've got those issues, so what we have to do as a company is to put more efforts then we have in past years to infrastructure work. And on the people side, I would say that for 2008 we were probably operating at about 120% of capacity on the people side, if we go for $7 gas, 10% production growth maybe our people will only be working at 95% of capacity for next year. But it's a not, it's still a people short business in terms of engineers, geologist, land man etcetera. And we think we could flex easily with our staff between 10% to 14% volume growth.

So it's not like there is going to be freed up capacity to move them on the other things necessarily?

I would say, it's not, not obvious that we could say okay If we are going to grow 10%, we then reallocate people to something else, no I don't think that's anything we can do.

Okay. And I think, I know the answer to the second question. But, your interest in maybe taking an interest in some of these farm outs, potential farm outs, does that in anyways suggest that all of the or many of the important new resources plays have already been discovered in North America and that you need to go back and look at these farm out potentials or do you still see that there is a nice full undiscovered pool of resource potential?

Yes, you are right and you know what the answer to that question is. We still think there is considerable more resource potential attacking these plays with horizontal drilling. So we are focused heavily on that, the drill to earn things, the farm-ins, they will be niche things that come up. But, the way to view it is, we have a chance to capture acreage that a year ago, we would have never had a chance to capture or someone else's perhaps paid a high price for it or maybe they just attempted to drill it themselves and they can’t now. So, those are pretty good opportunities for us and what gets us into those opportunities are those well completion charts that I refer to and was posted on our website in our IR presentation. We can show people that for an acre of rock, we will make a better wells than our competitors. And we’ve proven that clearly in the Bakken, early in the Barnett and early time in the Horn River. And people are aware of this, and they say this if I’m going to farm out well then I think I'll do it with the one that going to generate the most production from that acre of rock. And certainly appears to be with EOG.

Okay, thanks a lot Mark.

Thanks.

We will take our next question from Leo Mariani with RBC.

Hi good morning here folks. Quick question on CapEx plans for next year. Could you guys kind of go ahead and sort of prioritize your key plays in terms of what you would drill. I am just curious as to how some of your gas plays prioritize next year?

Yes, the first priority is that we'll be looking at the oil side and we've said 40% of our CapEx, North American CapEx will go to oil. That's up from probably from 30% of our CapEx, North American CapEx this year that was devoted to oil. So we'll be shifting a significant movement there. In times of the gas side, the way we’ll prioritize things, the difference between 14% and the 10% volume growth is; one, we’ll look at areas that where we have no lease termination or lease life issues. And those were the areas that we would likely to throttle back most readily. And just a couple that come to mine are Uinta Basin area that we've got, our lease is secured and we could accelerate or decelerate drilling there not lose any acreage. Mississippi Chalk play is another one that pretty much is in the same state. So a large determinate will be, and really to some degree Barnett is now in pretty darn good positions where we don't have to drill a billion wells before the lease expires and you know, that is pretty locked down. So those were just some examples of where we... if we cut back drilling, it would be more on the basis of how do we hold together all of our acreage, as opposed to turning loose some of that and ranking some other forward.

Okay. Jumping your (inaudible) play, obviously you've had some wells on stream for a little while here could you just give us a sense of what type of decline rates you guys are seeing on those wells?

Yes, We've had wells on now for... we have got two categories, we have a couple wells that we mentioned in February that we're short laterals. We say short laterals, may be they were 1500 foot lateral length and those wells kind of gave us a tantalizing hope that if we could get lateral length of that twice that long, we would end up with pretty good wells and indeed that's what happened. We've now got wells, the best well there what we had on now for about 60 days. For the first 30 days it averaged over 10 million a day average rates for first 30 days. That's probably translates well, it's roughly 10 Bcf well. So if you go back to what we articulated in February at analyst conference, we gave a matrix and said the economics were the X and Y under cases of four and six Bcf per well. And from what we're seeing now, we think those reserves per well estimate probably going to be extremely conservative and we going to be able to beat those pretty readily. The other thing is that our experience in the Bakken, our experience in Barnett is it takes about 20 or maybe 30 wells to get the frack recipe right before you have something you can kind of rubber stamp. And we're getting these pretty good wells out there in Canada with just roughly our fifth or sixth well. So we think there is probably going to be a lot of improvement coming from that. So net net out of all that, I think it strongly reaffirms that, we said we thought we have minimum of six net Tcf on this acreage back in February and I think that what we've generated subsequently strongly reaffirms that.

Okay, given that backdrop what are your drilling plans there this winter?

Yes, it would be... Gary you want to address that?

We are going to go ahead and contract one... probably one and a half rigs. We'll drill 13, 14 rigs here in 2009.

13, 14 wells.

Wells, 2009.

Yes.

And the reason for that too is we are just watching our capacity. We've got a burn capacity, somewhere around 35 million a day. And there is 45 or maybe 50 million capacity available on the land. So we'll drill to complete fill available capacity.

Got it. Last question here on the Haynesville play. It sound likes you've got your first well and you are going to frack it pretty soon here. Can you give us a little bit color in terms of kind of where your acreage is located in the play, and maybe what your potential plans over there?

Let me... 115,000 acres. It's pretty relatively evenly spread, maybe a little more heavily weighted towards Texas. And probably about 40% of it, maybe 45% is HBP, and its spread throughout what others and we have mapped is the core area. It's a pretty good core area I'd say and we are pretty well represented in all parts.

Okay. And I guess any thoughts to the drill any follow-up wells or you want to analyze your first result first before you move forward?

We are drilling follow up wells as we speak; we have our second well drilling now.

Okay. Thanks a lot guys.

And we'll take our next question from David Heikkinen with Tudor, Pickering, Holt & Co. David Heikkinen - Tudor, Pickering, Holt & Co.: Good morning, just first a macro question. Thinking about LNG and Asian weakness what are your thoughts going into the next couple of months around LNG imports?

Well going into next couple of months David, I think the only way incremental LNG would come here is if there is just absolutly no capacity in Asia or Europe. We are programming, just guessing that LNG '09 versus '08 goes up by about four-tenths of Bcf a day and that's just on the assumption that (inaudible) come on and that turns out to be a little bit extra LNG. But, I still foresee that fortunately the lowest price net back for LNG all through 2009 is going to be North America. And so, we will only get whatever the other market absolutely cannot digest. David Heikkinen - Tudor, Pickering, Holt & Co.: Okay. Then onto the Bakken, your gas plant and gas line capacity is that 30 million a day or do I have my notes wrong?

he gas line that we're installing is going to have a capacity for 80 million a day. David Heikkinen - Tudor Pickering & Co.: Okay.

The one that we got installed now in that plant is good for 20 million a day. David Heikkinen - Tudor, Pickering, Holt & Co.: Okay, so you’ll have a cumulative of 100 million a day.

No, we'll go ahead and retire the 20 million a day for the plant and just bear with 80 million a day dense phase refrigeration in pipeline. David Heikkinen - Tudor Pickering & Co.: Okay.

And the reason for this dense stage again is, one of the issues we have is that this gas in the Bakken is extraordinarily rich in propane, butanes and heavier components. And right now we're striping it out basically on location there in North Dakota and that's just not a good place to sell that product. I mean again, you suffer location differentials and so the game plan there is to get that all those oil rich liquids to Chicago where you have a much more pleasant market price and you don't take a big ding on the differentials. So, again it's just a lead time issue there but that's as in the oil, you'll notice our NGL differentials are not as great as we had hoped. And the more NGLs we bring on in North Dakota the more we have to get this problem fixed and we expect we will by mid next year. David Heikkinen - Tudor, Pickering, Holt & Co.: And as you think about NGL a little bigger picture, both southern region and you've have in the Bakken and Mid-Continent, you've had this blow out and big drop off in NGL realizations. What do you think about going into fourth quarter and then next year as far as were NGL prices will be?

Well we penciled in that there are going be about 55% of crude oil when it comes to dollar per barrel basis. David Heikkinen - Tudor Pickering & Co.: So the 40% we are seeing now in Mid Continent, that's anomaly?

We think so... David Heikkinen - Tudor, Pickering, Holt & Co.: Okay.

But, we can't purport to be NGL market experts so far. We can’t even purport to be natural gas market exports. David Heikkinen - Tudor, Pickering, Holt & Co.: Neither can we, that's all right. Thanks, guys.

Thanks.

And our last question today will come from Ray Deacon with Pritchard Capital.

Yes, hey, Mark. I was wondering if you could talk about your plans for Bradford County next year and what kinds of wells would you be drilling, horizontal or vertical? And then maybe some thoughts about Horn River and what your CapEx might look like there?

Yes. On the Horn River, he said previously that we're going to average probably about 1, 1.5 rigs there next year. So we’ll have a modest level of activity and it's really more of a kind of a learning curve activity to fill up what gas pipeline takeaway space is. So it's definitely not going to be in a hyper ramp up face. In Marcellus, it will be fairly similar. We're probably have one rig running year round in the Marcellus. Most of the time it will be spent on that 40,000 acres and then rest it will be proven up. And then the rest that we'll be drilling on some of the other acreage well be trying to prove it up. But, in our 10% or 14% volume forecast neither, certainly not the Marcellus and to not much of a degree, the Horn River, are we really counting on the significant volumes in '09.

When you said it's not that volumes wouldn't be meaningful in Marcellus until 2012, did you mean for industry or for you specifically here?

Yes, what I meant was for the macro industry. It's clearly the most complex logistical area that we have to deal with anywhere. It makes British Columbia look simple in comparison. And some of the recent legislation or regulations that have been proposed in Pennsylvania are likely to slowdown things even more. So, we just can't be saying we are in a debt market. We're going have a ton of gas and macro coming from that...

One more real quick one I guess. I've been watching (inaudible) week prices drop over the last five or six weeks, is there anything you're doing specifically that protects you some of that basis issue and with your Barnett gas? And does the sort of demise of these midstream MLPs affect any projects that you would have liked to have seen going forward?

Yes the Barnett gas, we've got pretty well covered with firm transportation to get it out of the Ft. Worth area. We're not really prone to getting beaten up on the differentials there because we really get it moved out of the area. Where we are more at risk is in the Rockies. And in the Rockies we've got, I'm talking about now plus the next four or five years we've got firm transportation on about half of volumes there on CIG or Kinder Morgan lines. But, the other half, we are exposed on a differential and that's we are putting some Rockies basis hedges into place in 2009 and 2010.

Got it. Thanks very much.

Okay. All right any last questions.

And there are no further questions at this time.

All right, well, thank you very much for listening in and we'll look to you in another three months.

Thank you. That does conclude today's conference. We want to thank you for your participation today, and you are now free to disconnect. .