Mark G. Papa - Chairman and CEO Timothy K.

Driggers - VP and CFO Loren M. Leiker - Senior EVP, Exploration

Thomas Gardner - Simmons & Company Gil Yang - Citigroup Brian Singer - Goldman Sachs Brian Kuzma - JP Morgan Robert Morris - Banc of America Securities Unidentified Analyst - Bear Stearns John Herrlin - Merrill Lynch Adam O'Laughlin - BMO Capital Markets David Heikkinen - Pickering Energy Partners Joseph Allman - JP Morgan John Mansfield - SAC Capital Marshall Carver - Pickering Energy

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second quarter 2007 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 the comparable GAAP measure can be found on our website.

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 play, may include other categories of reserves.

We incorporate by reference the cautionary note to U.S. investors that appears to the bottom of the Investor Relations page of our website.

And updated Investor Relations presentation statistics were posted to our website this morning. With me this morning are Loren Leiker, Senior EVP, Exploration, Gary Thomas, Senior EVP, Operations, Bob Garrison, EVP, Exploration, Tim Driggers, Vice President and Chief Financial Officer, Maire Baldwin, Vice President, Investor Relations.

We filed an 8-K with third quarter and full year 2007 guidance yesterday. The increase on our estimates for 2007 production growth from 10% for 11.5% are organic which is unusual for the Company our size that isn’t issuing equity.

Increase from the previous target is emanating from higher domestic crude oil and NGO production. We anticipate strong oil production in the second half driven by continued success in the North Dakota Bakken horizontal oil play that we highlighted in the press release.

The increase in NGL is coming from Barnett Shale. We are processing richer gas from this area, and is driving up our NGL production.

Our production mix for 2007 includes both 17% organic North American gas growth and 17% total North American growth. Yesterday’s 8-K filing reflects a CapEx increase from $3.4 billion to $3.6 billion.

The extra $200 million is primarily devoted to the increase North Dakota drilling and infrastructure and Barnett infrastructure. In Appalachia, we made a decision to put up for sale a shallow gas asset in order to focus our CapEx in effort on larger potential plays.

We are trying to maintain an active exploration effort looking for shale gas in Appalachia. The shallow gas assets represent a small piece from our portfolio.

That counts for approximately 1% of total Company production and a little over 200 Bcf of proved reserves. These are very low decline rate reserves and this a time when a market is looking for these type of assets that put into MLP structures.

We should be received more these asset in the marketplace and has being reflected currently in our stock price. Our intention would be close on this sale in late 2007 or early 2008, given our increased CapEx in the probability of lower than expected second half 2007 gas prices.

The proceeds from this asset sale together with a modest increase in our debt will allows us to execute our capital program while maintaining by follow the lowest net debt ratio of any Company’s peer group as we move into 2008. As we stated in the press release, this asset sale and our higher 2007 gross target won't affect that previously disclosed 2008 production growth target of an average of 9%.

I will now review our second quarter net income available to common and discretionary cash flow and then I will give an operational review. Tim Driggers will then discuss capital structure and I will close with some gas macro comments and a summary.

As outlined in our press release, for the second quarter, EOG reported net income available to common of $306 million or $1.24 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common to eliminate mark-to-market impacts outlined in the press release, EOG's second quarter adjusted net income available to common was $219 million or $1.17 per share.

For investors who follow the practice of industry analysts and focus on non-GAAP discretionary cash flow, EOG’s DCF for the second quarter was $736 million or $2.98 per share versus $621 million or $2.53 per share a year ago. I will now address some of our operational highlights.

In the second quarter, we generated 13% organic year-over-year production growth, highlighted by 24% organic gas growth in the U.S., driven primarily by production in the Barnett. For the second quarter, domestic oil production was up 20% year-over-year.

Additionally our first half North American ex-Barnett growth averaged approximately 7% indicating that EOG is not just a Barnett story. You’ll recall that our full year goal for the ex-Barnett assets is 6%.

I will commence our operational review with our North Dakota Bakken Horizontal Oil Play then I will shift to the Barnett, then to other North American areas and then I will close with Trinidad. In North Dakota, the new news during the quarter is that by applying our Barnett Shale completion techniques to display, we’ve raised a relative play economics to a standard that now exceeds those of the Barnett Shale, and that puts it us in the top class of high return plays in North America.

Before these improvements our wells were coming out at an initial rates of 400 to 500 barrels of oil a day, and now we are routinely getting initial rates of 1,500 to 1,600 barrels of oil per day. Our typical well in North Dakota now costs $5.75 million, recovered 700,000 barrels of oil a day net and generates a 100% direct after tax rate of return.

For those who don’t have your calculators handy, that’s a $7.50 barrel net direct finding costs. We started the year running one rig in display.

We are currently running four rigs, and anticipate ramping up to eight rigs in early 2008. This play has a lot of characteristics of the Barnett Shale i.e.

a large amount of oil in place per section actually about 9 million barrels of oil in place per section. Only about 9% recovery even using horizontal drilling and production decline curves that mirrored the Barnett.

We expect this asset will increase EOG’s oil production throughout 2008 and 2009, and you will be hearing more about this play in future quarters. Now, I will switch to the Fort Worth Barnett, where results continue to outperform expectations and we expect to exceed our previously stated production target of $280 MMcfe per day for the year all organic.

As an overall statement, I’ll simply repeat what I said last quarter. The Barnett continues to overachieve regarding our expectations and we have met or exceeded every promise we have made to the investment community regarding this asset.

I will also add that the Barnett is likely the highest ROR large natural gas asset in North America and EOG has a higher proportion of this asset relative to our total size then any other large cap independent. We believe it’s the highest ROR large natural gas asset in North America because of the unique ratio of well cost reserves and decline characteristics.

As I stated on the last call, we continue to believe the intrinsic economics in all parts of the Barnett Shale including the Western extension counties are superior to the Fayetteville Shale and the Oklahoma Woodford Shale play. The key takeaways and our current stage of development in each area is as follows.

First, in Johnson County, using baseball parlance, we are in about the third inning of our development stage and we continue to see noticeable improvements in completion technology and wealth spacing that will potentially net us a higher recovery factor. We continue to generate a higher proportion of monster wells then we’d initially expected, several of which we articulated in our press release.

The bottom line is that Johnson County results continue to exceed our expectations. In the West, secondly, in the Western counties of Jack, Erath, Palo Pinto and Hood, and Hill County, which is to the South of Johnson County, we are in the first inning of development.

In Hill County, we drilled eight wells this year, completed four wells per sale and a reserve per well within our forecasted range. In the Western counties, we are underway with a 22 well development program in the U.S.

and a 50 well development program in Hood. We highlighted a few of these Western county wells in our press release, and although, they don’t have the eye popping initial production rates that the Johnson County has, they represent the bread and butter results that typify these areas.

The third and last point I will make is that we are currently running 23 rigs, 16 in Johnson County, 1 in Hill, and 6 in the Western counties. Of these 23 rigs, 11 are new automated rigs.

By early ’08, we expect to have 19 new automated rigs in our fleet. Importance of these new rigs is that they have been proven and to reduce the drilling days by approximately half the days of the conventional rig.

This is the first step in our cost optimization program. We will unveil the second step at our November Analyst Conference.

The other of EOG’s large scale play is our Utah Uinta Basin and Mesaverde asset. In the past, we have probably under publicized this play.

It’s been one of our main drivers of our ex-Barnett growth and is a consistent high ROR play. In my opinion, this was one the key assets involved in the recent Karmcgee [ph] transaction.

Ours is the same asset as the one that was involved in this Karmcgee transaction except ours just had lower cost base. We are currently running nine rigs in this play.

The key attribute of this asset is similar to the North Dakota and Bakken assets of very high reinvestment rate of return. Typically our Uinta Basin direct after tax rate of return… after tax rate of returned has been 30% to 40%.

Before I leave North America, let me mention midstream infrastructure. EOG has elected to build its own intrastate gas pipelines, and in some cases, gas process plants in part of its Barnett Shale development as well as its North Dakota oil play.

This is the new strategy for EOG as we have not previously been in the plant or pipeline business for gathering pipeline of this size. We have done it for two reasons.

First, it makes business plans to build and control infrastructure if it’s not already in place around new large assets and second the MLP market offers a possible arbitrage opportunity further down the road once these assets were established. Now, I will turn to Trinidad.

During the second quarter, we exceeded our contract takes in Trinidad and we have increased our full year production estimates in yesterday’s 8-K. Additionally, we finalized the gas contract for our Block 4(a) discovery few weeks ago, and we are in the final stages of platform design for this project.

Sales under this project will boost overall Trinidad production by about $60 million a day net commencing in early 2010. I will now turn it over to Tim Driggers to give you CapEx and capital structure.

Thanks Mark. For the second quarter total exploration and development expenditures including asset retirement obligations were $925 million with less than $1 million of acquisitions.

Capitalized interest for the quarter was $6.8 million. Year-to date, total exploration and development expenditures including asset retirement obligations were $1.827 billion to $1.5 million of acquisition.

At June 30, total debt outstanding was $884 million and the debt to total cap ratio was 12%. At quarter-end, we had $59 million of cash on the balance sheet.

The effective tax rate for the quarter was 34% and the deferred tax ratio was 80%. Yesterday, we filed a Form 10-Q for the second quarter and a Form 8-K with third quarter and updated full year 2007 guidance.

For full year 2007, the 8-K has an effective tax range of 34% to 36% and a deferral percentage of 70% to 90%. The CapEx budget for the full year is $3.6 billion.

Now, I will turn it back to Mark to discuss gas macro and concluding remarks.

Thanks Tim. Regarding the North American gas macro, it’s apparent that the second half 2007 gas prices will be disappointing as the higher than expected LNG imports, surprising domestic production growth.

Question now becomes what happens in ’08? It appears to me that in ’08 industry production will continue to decline in Canada and will likely have less LNG impacts than previously thought because of the Japan earthquake, and likely high oil prices will discourage fuel switching, so the ’08 wildcards will be winter weather and domestic supply growth.

Because of the power of the Barnett Shale of become less pessimistic regarding domestic supply growth and I would say 1.5% domestic growth is possible in ’08 of total Canadian supply will likely fall another 2.5%. For 2008, EOG will likely hedge gas more heavily than in 2007 market permitting.

That doesn’t indicate nervousness about the ’08 gas market, but it reflects the reality that our stock has apparently been punished more heavily than others this year because of our un-hedged position. In my opinion, I’ll say relatively un-hedged position.

In my opinion, our superior per share of production growth, low debt, low unit cost, high returns, and quality asset base have been subsumed by short-term concerns regarding natural gas prices, and perhaps the heavier hedge position in ’08 would diminish those concerns. Our financial hedge position was articulated in yesterday’s 10-Q filing, and for 2008, we already have about 12% of our North American gas production hedge at $8.79 Henry Hub price.

We would like to have about 30% to 35% of our 2008 gas production hedge before year-end. Regarding oil, we are much less likely to hedge forward any volumes as long as the market is in backwardation.

Now let me summarize. In my opinion, there were five important points to takeaway from this call.

First, the organic production growth machine is running better than ever and our incremental volume growth from 10% to 11.5% is comprised primarily of domestic oil and NGOs. Second, we have a burgeoning new domestic oil play in North Dakota is generating high rate wells and 100% direct reinvestment rate of return, and will drive increases in the EOG’s total oil production through at least 2009.

Third, even with the current low gas prices, EOG has device the capital plan to take advantage of the MLP arbitrage at high ’07 and ’08 production growth rates and still keep net debt by far the lowest for the peer group. Fourth, and I think most important, EOG has collected a stable of premier high reinvestment rate of return domestic assets that we believe are second-to-none.

These are characterized by two parameters, large size and much higher than typical upstream reinvestment rate of returns created by a unique mix of well cost to reserves and production rates generated. These are the Barnett Shale which is the premier gas assets in North America and North Dakota Bakken and Uinta Basin.

These assets give you G&A edge in generating superior returns as well as production growth, which leads to me to my fifth and final point. Fifth, even with low gas prices and a relatively un-hedged 2007 position, we again expect be a peer group leader in 2007 ROCE as we have been for the past eight years.

Before I turn it over to Q&A, I mentioned that our 2007 Analyst Conference is scheduled for November 13 in Houston. Additional details will be forthcoming.

Thanks for listening, and now I will turn it over to Q&A. Question and Answer

Good morning everyone.

Hi, Tom.

Hey, Mark. With the recent success you’ve had in increasing your Bakken oil production and the rig count there, that’s going up.

Is there any desire within your Company to create a more balance product mix, and can you give us views on the outlook for the oil versus gas?

Yes, we are pretty sanguine about the outlook for crude oils in terms of just looking at overall worldwide supply and demand, I guess, our outlook for the next five years is that we think that most predictions that are out there are genuinely… are generally where they maybe missing the boat is on the non-OpEx supply growth. I think most people that have predictions every year, they are overly optimistic on what’s going to happen with non-OpEx supply growth.

So, it’s our feeling that oil prices have a pretty fair chance to be pretty robust as we go forward. And so, yes, we’re optimistic on the oil side.

And so, we sent signals to all of our operating divisions to certainly see if we can shift the balance of our portfolio organically to a bit more oil mix. And I believe this North Dakota Bakken play is going to do that.

The question is how big is, this play is going to be, but obviously we’re started here with one rig. As we get into early next year, we’re going to be running eight rigs.

So, you’re going to see our oil production ramp up considerably, and the real movement of that is going to occur in ’08 and ’09. Now you are just seeing the beginning of that movement in the second half of the year so as of an oil production growth.

But I think it’s going to become more marketed when you see our forecast come out for ’08. We will put those forecasts out in our Analyst Conference, so as we typically do in November.

Okay. And I’d like to get a little more color on this completion technology that’s leading to higher rates and recovery in the Barnett?

Yes, it’s… again conceptually we don’t disclose a lot of information on our Barnett completion technology. And again, I guess the point I’ll make in the Barnett completion technology, for example, these monster wells, you don’t see a lot of our peer companies touting monster wells in Johnson County and that’s simply because they’re… they don’t have them.

And that’s because we believe we have a competitive edge on our completion technologies in Johnson County. They’re completing wells in identical lock to us, but they’re not getting the quality of wells that we have, wells that are, say north of 6 million or 7 million a day in initial production.

And so, it is our technical edge that we have that we believe other companies don’t have.

Is any of that proprietary or do you think that through the service companies that leaks out rather rapidly?

It’s… none of it is proprietary that we have some patent on or anything like that, but it’s just application of existing technology drilling. But what we’ve done is just taken some of those concepts to North Dakota, and some of them are… I’d say known by everybody.

I mean it’s stage fracing. It’s basically fracing multiple elements along the lateral in North Dakota, but it’s just how we do that really is… it’s happened, but basically we’ve just taken some of those conceptual elements and simply put it.

When we started the year, we thought we had a play in North Dakota that the average net recovery per well was going to be something like about 250,000 barrels of oil and the well would come on initially in… and at a rate of 400 or 500 barrels of oil a day. And at 250,000 barrels of oil reserves per well and roughly at $5 million or $5.25 million well cost, we had a play that was marginally economic, but not anything that you could do back flips over.

And so we knew that there was a whole bunch of oil in place, but we had to do something to get the recoveries up and we really didn’t have a play that was that great, and that’s why we started the year running only one rig. But after we had found some of these Barnett techniques and suddenly we got the wells up where… we’re recovering now at roughly 700,000 or so barrels net which is closer to about 900,000 barrels… 850,000 barrels gross which is what most other companies would quote you.

Now we have… we’ve taken a project that now has turned into a 100% rate of return projects.

I see. That’s great.

A quick question on the Appalachia sale, then I will let someone else hop on. Are you planning on planning on keeping the deep rights on that asset sale?

Yes.

Okay. Thank you.

Thanks, Tom.

Good morning, Mark. Can you comment on going to the Bakken for a second, what the well costs were the 400 or 500 barrel per day wells and was the decline rate Barnett like decline rate as well?

I’m not… the well cost were about the same for the wells earlier in the year as they are now roughly. So, that the issue is really we just improved the well quality quite a bit.

The decline curves are… I would say approximately similar to the Barnett. So, these high rates, the 1,600 barrels a day rates that we put in the press release, those are not consist rates.

I mean you have a very high decline I can’t quote you that they are specifically identical to Barnett decline rates, but they’re typified by high declines in the first couple years and then the wells will level out and have relatively low decline after the first year to relatively long lives, which is kind of typical of all horizontal wells.

When then 400 to 500 barrel per day wells were also horizontal, or are those just vertical?

They were horizontal also. All of the drilling we’ve done… this play is very identical to Johnson County.

The bottom line is in Johnson County vertical wells were totally uneconomic and the same thing is in Bakken play. Vertical wells were totally uneconomic and the only way to commercialize this play was horizontal drilling.

Okay. The horizontal wells have done a lot better than last year.

Absolutely. Yes.

Okay. And at what point do these wells need to be put up on kind of… some kind of pump?

I guess, [inaudible] more easily at low pressure, but oil won't because it’s lift itself up? At what point… how many years down do you need to start putting a list on these?

On some of the earlier horizontal wells, we put them on pump after about six months. We anticipate with the way these wells were flowing that it might be a year before they would be on pump, either wells.

Okay. How does that affect the operating column?

We’re bringing electricity in currently to this part of North Dakota, and till this be a slight increase on the operating expand. I think respective to costs.

And what’s the basis for versus WTI for oil in that region?

Yes, it’s not any big… huge differential whack on there. The oil winds up going through the refinery in Minnesota via pipeline.

So, it’s not… it’s not a $4 or $5 differential. I can’t quote you exactly what it, perhaps more we can look it up and get back to you, Gil.

But it’s not like Canadian Cruiser or some of that stuff.

Okay. With Trinidad, Block 4(a), I think, probably 210?

Yes

And what… can you comment on that pricing that you’re getting on that new contract?

It’ll be linked to a basket of commodities such as ammonia and methanol primarily. So, it’s linked to Caribbean FOB prices for some of the not indigenous items down there.

I think you hinted that the pricing is more favorable than the previous contract, could you quantify that a little bit?

Yes, I can’t… I don’t want to quantify it on there, but it’s more favorable than some of our previous contracts that we had there. But it’s kind of a basket of those kind of commodities.

Okay. But so your average once this contract comes online, your average shouldn’t that rush it, right?

Yes.

All right. Thank you.

Yes, I’m… I think you got all my questions now. Thanks.

Okay.

Thank you. Good morning.

In the Bakken, can you provide a little more color on over what portion of your acreage you tested? And any opportunity to lock up additional acreage surrounding what you already have?

Yes. Brian, we said at our Analyst Conference back in November of last year when we had only drilled about four wells that we thought this thing was 30 million to 70 million barrels of oil.

Currently we have about 13 wells drilled and we've also shot about 300 square miles of 3-D. So, we did have a little better feel for that size.

And we have increased that estimate from the 30 million to 70 million, to 50 million to 70 million. But we're really not ready to say much more about it than that.

We do feel very good about the well results we've had. Well-by-well, we are in that middle Bakken zone.

The same zone we had on the other side of the Basin. We are drilling a few step-out wells to primarily in the one area… in that partial area right now and getting these very good results, and the risk still remains for the overall play.

How will those sweet spots be distributed within the overall oil accumulation? There's something that we think we're understanding better from the structural and the stratographic point of view of both.

Both have impacts on where the sweet spots are, and we feel like we do have a competitive advantage in understanding that. But we're really not ready to say how much of our acreage, of that 130,000 acres that we talked about at the conference last year is going to be… is going to be really good.

I would say that we are optimistic about that and we are still accreting acres in the area.

And just to be clear that you did mention that most of the wells that you tested so far and won as specific part of the acreage or were there any wells that were tested over a wider?

I would say all the wells, the 13 wells are really in two specific areas. The vast majority of those are really in one specific area at this point.

Great. And do you see an opportunity here to expand that position?

Yes, we do.

Switching to Canada, any updates on Canadian Shale drilling over the last couple of quarters?

We mentioned again at the Analyst Conference last year, Brian, that we had about 8,000 acres in a Canadian Shale play, and at that time we attributed somewhere between 1.2 and 2.4 Tcf net reserves to that play, obviously, unproven. And at that point we said that we were completing a vertical well and had planned to drill a horizontal well in the first quarter of this year.

We do plan to update the community on what we're doing in that play at our upcoming Analyst Conference in November. But I mean you must realize it’s a very competitive play right now for acreage.

And so, we're just really not ready to talk about anything more than that until November.

Okay. Thanks.

Good morning guys.

Good morning, Brian.

What's the average of the lateral length you guys are running in the Bakken play?

At 4,000 feet.

And do you have any update on your conventional exploration program either in Trinidad, or… an update on the Cotton Valley play? Are you guys running any horizontal in the Cotton Valley play?

No. We don’t have any updates for you in Trinidad or any exploration.

And in the Cotton Valley play, we don’t have any active horizontals going on. We may drill one some time late this year or early next year, but nothing… that's not an active area for us as far as horizontal with at this particular time.

Okay. And then to clarify in Appalachia you're still going after the Marcellus Shale play, is that part of the deeper acreage?

Yes. That's correct.

In Pennsylvania New York, we have about 230,000 net acres including 7 or 8 net acres that are earnable within our Seneca National Fuels joint venture and we are still planning to have by the end of the year about 10 wells drilled. And most of those will be vertical, some horizontal, and we should know a lot more by the end of the year as to the efficacy of that play.

Okay. That's it for me.

Thanks guys.

Good morning, Mark.

Hi, Bob.

You mentioned taking advantage of the MLP arbitrage, on the midstream side don’t think you have a whole lot as far as assets right now. So, going forward this year, next year and beyond that, how much annually do you expect to spend capitalize as far as building that midstream infrastructure.

Yes. This year we're probably going to be spending in a range of $150 million or so probably on midstream assets, and what's getting us into midstream here is primarily… we have got… I would say brand new assets here in North Dakota and Barnett where there was no infrastructure.

And basically, the choice there is, so we have a third party to build the infrastructure or we build in our shales whether just flat brand new assets with no infrastructure existing. So, obviously, as we develop some of these assets in the Western Barnett and in Hill County we will be putting our own infrastructure as opposed to have an third party do it.

And depending on how big the North Dakota play get, we will see how much infrastructure we have putting there. So, how much we spend in ’08 and in ’09 will depend on how big some of these plays develop out to be.

And whether we would ultimately spin them off into an MLP and that one would probably be an in house MLP. Just to make a side comment on MLPs, we were in camp that as far as doing and E&P based MLP that is something we would definitely not do in house.

We will very strongly in that camp, but as far doing some sort of a pipeline plan MLP, if that arbitrage existed couple of years down the road, we would serious consider that.

Right. It will probably be a while before you got enough credit come out that… some of the insights to be able to do that.

Yes. Bottom line is exactly that, yes.

Okay. Second question.

You notice that Barnett Shale production is exceeding the expectation; you probably exceeded the $280 million in a day you had mentioned before. The midpoint of your full year natural gas production guidance dropped just slightly, so you are going to be higher now in the Barnett, where is the shortfall going to be overall there?

Yes, the shortfall is going to be in gas in the ex-Barnett, but for that’s going to be made up in the liquid in the ex-Barnett. So, net-net what we are doing is the ex-Barnett is still going to achieve its 6% growth but it’s going to come through NGO and crude oil instead of natural gas.

So, that’s how everything works out.

So, you got an arbitrage that didn't exist before for the liquid stripping, is that essentially what you are saying?

Yes, that’s part of it yes, that basically is. And what we have done is we have… I would say we have displaced some of our gas drilling in some of the ex-Barnett areas and we replace it by funding more money into Bakken play.

Okay.

That’s just basically our view with the second half gas prices versus drill prices.

Thanks. And just last question here.

You mentioned that part of your budget would be funded with the proceeds from selling Appalachia. And of course, are there any area we concern was is it a net gas average below seven in the quarter, which at this point it appears probably well if you might reduce spending.

Is that just not an option, now given the Appalachia sale or is that something you should keep an eye on and that might cause you to scale back spending?

Yes, we probably will not scale back spending. I mean, basically, we have supplanted that plan with the plan of the Appalachian way to do it.

And while our net debt at year-end will be a function of when we elect to close the sale and that’s what is dependent on kind of some of tax issues we have. It would be more beneficial to close the sale of the Appalachian property.

So, what I would say is we view our net debt as… where is out net debt going to stand at the end of the first quarter ’08 and because we may or may now close the before April 31. So, we are trying to target net debt ratio in a range of about 13%.

We think would be in the range of about 13%, if we close the sale by year-end.

What is your tax bases in those Appalachian asset you are selling?

Yes, it’s fairly low.

Okay.

Unfortunately.

Okay. Great.

Thanks Mark.

Okay.

Yes. Hi, good morning everybody.

Thanks for the call. This may sound a little surprising coming from a debt analyst but when I look at your debt-to-capital 12% which is rally strong, obviously and your stock price.

I guess the question comes from… would you guys think about taking other actions to help boost this stock price other than just implement your plan which is sort of what we are hearing on the call today?

Yes, getting to more conceptual of discussion here… we have got… long-term plan is not to keep our debt at these extremely under geared levels. It’s kind of an open secret that we are pursuing horizontal drilling opportunities in places like Appalachia and Canada that we have previously disclosed and other places also looking for big accumulations and we are keeping the debt low because if indeed we find some of these we are going to have to essentially startup funding to get those plays off the ground.

And that we will do that with internal funding we certainly would be issuing equity or anything so than that would likely raise the debt-to-cap into the low 20 range, perhaps until we get these plays running until they became self funding. The backup plan on that would be that if indeed we are not successful on finding any of these huge new shale gas plays and we conclude that they just don’t exists out there.

And it is certainly a strong consideration that we would use some of that balance sheet to just do share buyback.

All right. What sort of the timeframe again on… I mean you might have said again here on those big plays in terms of when you would know?

I think we will… we are probably within…. 2008 will be a critical year on that.

Okay.

Its not years away. And while we are on the subject of some of these bigger plays, I will make one comment I will make one comment, we I will just preempt the question that is almost certainly to be asked before I get off the Q&A here, someone is going to ask us about these big plays, about some of them like a West Texas play.

We always get a question about Culberson County and ever since after November analyst meeting last year, I purposely downplay Culberson County. I said that was one of our lowest ranked plays.

Then on our last earnings call, I also significantly down stated just so we don't get any questions on it, I will tell you that we have disposed on our acreage in Culberson County, simply because we felt that that one did not meet the criteria that had set up to be a successful play. So, hopefully that will preempt any future questions on that.

Okay. Thank you very much.

Thank you.

Yes. Three quick ones.

Loren, with the Bakken, do you have the dolomitic zone? And also from what Mark was saying, it sounds like you have similar organic and thermal maturity compared to say the Montana side.

So, this is really a completion difference for the results you are giving, or what are the sweet spots?

Yes, John that’s the big question in whole play. And that’s the competitive advantage that we currently hold is it by drilling these dozens plus wells that we drilled on that side and taking a lot of core work and doing a lot of work with 3-D.

We feel like we understand what those sweet spots are but we are going to keep that under our vest for today, certainly. I would say that they are structural aspects, there are stratigraphic aspects of that, that we feel like we understand.

We are in the middle zone, John and you got the shale above and a shale below that are fantastic oil source rocks, maybe 20, 30 feet thick each. And then you have got the middle Bakken between those two, which is where all that oil is going and that is the zone that we are targeting.

It has various lithologies and that’s part of the trick and that’s why we are going to keep it close to our chest right now.

Okay. That’s fine.

One for Mark. You said that traditionally as you pointed out, you have been kind of hard asset light, in terms of your development strategies for infill plays and now you are adding more GTPM assets.

Kind of on a going forward spend basis, how much do you think GTPM would be of the total budget?

What's the acronym?

Gathering Transmission Processing that you were talking about?

Yes. It will be probably something like… 5% or so… 5% to 10% John, something like that.

Okay. Last one from me is kind of the devil's advocate question.

You are delivering differential growth; you are spending your cash flow which isn’t giving you much incremental cash flow gain, especially, in a lower price environment. Are you safe with any sort of lease exploration issues to keep drilling so aggressively the prices are going to stay weak?

And also regarding hedging, how high would you hedge or what kind of volumes would you hedge in total?

Yes, on the hedging question, we said we target 30% to 35% but we would… for example, if we got some price spike or so, we would go up to maybe 45% or maybe up to 50% on natural gas. In terms of lease exploration question, the only area where we have a lease exploration issues that would… is in the Barnett, where we have roughly the 600,000 acres.

So, it’s a situation there where we could not just stop drilling into Barnett. There are lot of our acreage would indeed fall apart but in other areas if we chose to and for example places like our new Uinta Basin, we could easily slowdown there and not worry about leases going apart, if we didn’t like the gas price scenario, the way into ’09 or whatever.

So, we have flexibility in certain of our areas to ramp-up or slowdown.

What's the average term in the Barnett that’s in expiration susceptible near-term?

Yes, the typical least term there is between three and five years. So, we… this year, we plan on drilling roughly about 400 wells.

Next year we will plan on drilling about 500 wells. And that’s also the highest reinvestment rate of return gas asset we have in the Company.

So, that’s probably the last place we turn off for a couple of reasons.

Okay. Thank you.

Okay, John.

My question ahs been answered. Thank you.

Good morning. And Bakken sounds like you are finding fractures that are both generated by hydrocarbon generation and structural fractures.

Is that fair for the sweet spot that a fair characterization.

David, I would not dissuade you from that or confirm it. I think, as we said a minutes ago, the sweet spot gain is both structural and stratigraphic and it’s something we are not willing to comment on it.

But it’s an active play with active leasing going on.

We shouldn’t think of only structural needs but off the thing other reasons that fractures will be generated across your acreage?

It’s a complex problem. Its one that we put a lot of work into on both sides of the basis, a lot of core work and a lot of geochemistry.

And we feel like we have a better understating of that and maybe some others and we would like to keep it.

That’s fair enough. I am thinking about the strategy of EOG… sounds like you are wanting to get a little more oily.

Focusing operations in each region, a little more on oil. Would we expect over the next 12 to 18 months to see more oil projects coming up at analyst day, Mark, is that a fair way to think about things?

It’s really hard to find oil in North America. That’s the issue.

I think we may have… with this horizontal drilling we may have found a pretty sweet oil project in North Dakota. The question is how big it is.

We basically think right now its 60 million barrels net which basically what I believe is we got 60 million barrels net of 100% rate of return project in North Dakota. And I will stack that up on a net basis again to some of these deepwater discoveries that people are touting which probably will turn out to be 5% to 10% after tax rate of returns when clear away the smoke and mirrors.

Whether we can find more these with horizontal drilling in the onshore U.S we are looking for that’s all I can say. But I wouldn’t say that it’s going to be a radical shift away from our gas weighting but it will be more of an at the margin shift, really David.

Okay. And kind of thinking about if you could snap your fingers and obviously, you can’t change oil and gas weighting, so this is very rhetorical, and would want to be higher oil weighting today.

I mean your gas macro sounded more negative than I have heard in a while, just wanted to think about that a little bit.

I would… I am still bullish on the gas side. But when I look at things right, if I can find more of these 100% rate of return projects, that’s even better than the Barnett.

So, I will take some of those on the gas macro side, I think where we are looking at is that we have to face up. The Barnett, I think by itself is powering some of this supply growth in North America and the supply growth in North America has surprised.

And I didn’t think it would be as robust as we are seeing but I still think we have got a generally bullish story for North American gas albeit it’s probably in the less bullish than I would have said a year ago.

All right. I appreciate the comments.

Thanks.

Yes. Hi everybody.

In terms of the North Dakota Bakken, I know you don’t want to say a whole lot, but I missed some of your earlier comments. But the two main areas where you are finding success, I would both of those be east of the Nesson Anticline?

Yes, Joe they are both east.

Okay. And with the… it sounds like your completion technique that you have transferred within the Barnett is a big help here.

Do you… some of the stuff that’s west of the Nesson Anticline that doesn’t seem to have the natural fractures in where industry has not had success in North Dakota. Do you think you might be able to take the completion techniques and make that part work, or do you have any interest over there?

I would say not currently. We are looking at the entire basins again from an overall geochemical point of view and stratigraphic and structural point of view.

Just looking at the whole piece and we like where we are. We think the southwest side where the big Elm Coulee field was discovered a few years ago, obviously worked very well and we think the flank that we are on now will work very well, also.

Okay. And then again, your ability to and your desire to get more acreage, you think it becomes more acreage as they move forward?

Yes. I think we will be picking up additional acreage as we move forward.

Okay. And then the completed well costs.

In your presentation you are saying $5.25 million just I guess that’s a gross number, confirm that. And then have recent wells been better than that?

We… yes, we think that within six months we would probably be in a $5 million average maybe and maybe beat that but for right now these $5.25 million and you get that ridiculously low direct finding costs we quoted to you there… or was it 750 in all. And that’s pretty good number; of course, we will try to beat it.

But that’s a pretty awesome number there.

Sure. And I understand.

Can you give me your average working interest and net revenue interest over there?

I think overall in that whole play, it’s probably going to average maybe 75%, 80% working interest, net revenue interest. And net revenue interest will probably be 80%, 85% of that number.

Okay. That’s helpful.

And Mark you spoke fairly strongly about not doing MLP, can you just give the reasons for that?

Yes. We just feel that if you do an in house E&P, MLP you are just creating a potential conflict that may bring on subsequent litigation there is one thing and to try and apportion assets of supposedly with no upside and put them in one pot and then assets with upside in another pot.

And second thing is just the fact that the MLP, which is by nature a declining asset, and then having that tied to a commodity price which is very volatile. And then having the attempt to commit to the purchaser of the MLP that you are going to give that person an ever-increasing dividend stream, if you will.

That’s something we probably don't want to get involved with.

Okay. Are taxes and kind of potential changes in the laws an issue for you as well?

No, I mean, that’s something we have to look at, but we didn’t think it’s kind of inherently something we just… the other two items that quarter probably more critical in our minds as to why we wouldn't want to do.

Okay, it’s helpful. And then ex-Barnett from the gas side, do you have any disappointing results that cause a little shortfall there?

No, it’s just a more of a redirection of capital away from gas in the second half and towards the oil.

Okay. And what taxes… if anything after selling the Culberson County, do you have anything left over there?

And previously talked about going to have a sweet spot and also I guess there is… I thought may be a bit more time in fact, before we really knew the result over there?

Yes. Joe that’s true.

In our conference last year we did mentioned that we have two separate plays there, the other one in West Texas where we have 32,000 net acres at that point. And we thought that was may be about a 400 Bcf kind of opportunity.

And that one is still cooking off. We still do not have results to talk about there, but it is still an active play for us.

Okay. Can you talk for that either?

Sorry, we can’t.

Okay. And lastly… and maybe you did this earlier and I apologize.

But the horizontal Wolfcamp, can you give a little update there?

Yes, that just one of our active plays out there that was kind of our bread and butter plays in that area. Again, we are running couple of rigs out there but we have always says that’s… that is a play that is a steady play for us.

It’s working, but it’s not one that we are trying to bang the drum over it because it’s not one that’s going to make or a break company. But its kind of steady play, we are running two rigs and making decent money at.

Okay, very helpful. Thanks for your comment.

Yes. Good morning.

I wanted to ask about the Uinta. Have you drilled and tested in the Uinta at this point yes?

Yes, John we…

I mean the Manco Shale have you tested that?

We have drilled Manco Shale well or two and we are involving with another operator there testing the Mancos. I would say that we are not convinced at this point, it’s a nationwide kind of play, but certainly they are appears to be some sweet spots to Mancos and we will continue to try to evaluate that play.

All right. And can you give us any indication about the rate for those well?

Well, I think it’s a little early to do that. I mean, really most of our activity in the Mancos has been non-operated and we would preferred to be operated or handle it.

Okay. Thank you.

Yes, just one quick question. How many wells per rigs per year in the Bakken?

What should our expectation to be there?

Probably 10 wells per year per rig.

Okay. That’s it for me.

Thank you.

Okay.

Hi. I would just ask one question about Culberson to more of that broader question.

In your divestiture at Culberson, was that a decision based on the feeling that that would never work? Or it was a more of an issue that you didn’t have the time and manpower to spend on it?

And in another words you able to testing that you had other thing to do that were more promising?

It’s a latter Gil. Just on our priority list the shale plays we were working.

We just had others that look more promising.

Okay. Thank you.

Thank you.

Okay. We just want to thanks everyone for participating in the call.

And we will talk to everyone three months from now.