Mark Papa - Chairman of the Board and Chief Executive Officer Loren Leiker - Senior Executive Vice President of Exploration Timothy Driggers - Chief Financial Officer and Vice President Robert Garrison - Executive Vice President of San Antonio and General manager of San Antonio

Brian Singer - Goldman Sachs Group Inc. Biju Perincheril - Jefferies & Company, Inc.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

David Tameron - Wells Fargo Securities, LLC Scott Wilmoth - Simmons & Company International Leo Mariani - RBC Capital Markets Corporation Joseph Allman - JP Morgan Chase & Co

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing the third quarter of 2010 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.

Effective January 1, 2010, the SEC now permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves but also probable reserves as well as possible reserves. Some of the reserve disclosures on this conference call and webcast, including those for the South Texas, Eagle Ford, Barnett Combo and New Mexico Leonard Plays may include potential reserves or estimated reserves not necessarily calculated in accordance with or contemplated by the SEC’s latest reserve reporting guidelines.

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.

With me this morning are Loren Leiker, Senior EVP Exploration; Gary Thomas, Senior EVP, Operations; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President of Investor Relations. An updated Investor Relations presentation was posted to our website last night.

We included 2010 and revised preliminary volume estimates for 2011 and 2012. We've reduced our full year 2010 growth guidance from 13% to 9%.

About 70% of this reduction relates to North American natural gas volumes, where we're now projecting minus 2% growth versus the previous estimate of plus 2%. Obviously, in this price environment, we're not incented to grow gas volumes.

Our conversion from a natural gas to an oil company is still on track. And we expect total crude, condensate and natural gas liquids to comprise approximately 67% of our 2011 North American revenues.

However, because of lower cash flows from weak gas prices, higher frac costs, delays in frac equipment availability and the pattern drilling used to maximize resource plays, we've also reduced our 2011 and 2012 liquids growth targets to better reflect real-world conditions. Even with these reductions, we expect to grow crude and condensate 36%, 53% and 30% in 2010, '11 and '12.

We've also made progress regarding asset sales, and I'll report on that later in the call. I'll now review our third quarter net income and discretionary cash flows.

Then I'll provide some highlights and discuss our capital structure. Tim Driggers will provide some financial details.

And I'll close with comments regarding our macro hydrocarbon view in concluding remarks. As outlined in our press release, for the third quarter, EOG reported a net loss of $70.9 million or $0.28 per share.

For investors who follow the practice of industry analysts who focus on non-GAAP net income to eliminate mark-to-market impacts of certain onetime adjustments as outlined in the press release, EOG's third quarter adjusted net income was $46.6 million or $0.18 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $755.4 million.

I'll now address operational results, and I'll start with the South Texas Eagle Ford. The bottom line here is that our confidence in individual well results and the total 900 million barrels of oil equivalent net after royalty reserve estimate, have increased since our April analyst conference.

Because this is such a huge net oil accumulation, and I believe investors have undervalued this asset, I'm going to take several minutes and provide an update based on our results from the last six months. Our press release provided details on a number of good wells, most of which have only commenced sales in the last month.

Here's what we know right now about our asset after drilling 77 wells, 59 of which are either producing or shedding for off-site fracs or waiting on fracs. First, the Eagle Ford formation is not a typical shale.

But instead, it's a borderline conventional carbonate reservoir. Pressure and flow data from our wells indicate we're seeing a lot of matrix flow, i.e., a significant amount of flow from the rock fabric itself, which is a good sign.

Second, the Eagle Ford is a predictable play. We've not drilled a large enough population of wells and we're getting very repeatable results across a 120-mile extent of acreage block.

Third, we've had a 100% well success rate within the acreage and the horizons we originally defined to contain our estimated 0.9 billion barrels. For a startup play, this is outstanding.

Fourth, for our 0.9 billion barrels of estimated reserves, the mix is 77% black oil. The oil in our portion of the reservoir has some unique characteristics that enhance the recovery factor.

We've kept this information proprietary until now. But with our acreage tied up, we can now talk without losing a competitive advantage.

I'll apologize in advance for getting too technical. But this is a very important point, because some analysts have expressed concern regarding recovery factors from a pure oil reservoir.

Specifically, there is an extraordinarily high differential between the initial reservoir pressure and the pressure at which solution gas breaks out of the oil, technically called the bubble point pressure. Across our acreage, the original reservoir pressure averages 7,200 psi and the bubble point pressure averages 2,500 psi.

This unusually high spread provides for a larger-than-normal fluid expansion recovery factor. That's why we're so confident with our 0.9 billion barrel reserve estimate.

Fifth, the reservoir can be broken into two zones, East and West. In the East, we have two targets, the Upper and Lower Eagle Ford.

These zones are relatively thick and high-quality. A typical well here is the Harper #10H well, which IP-ed at 1,070 barrels of oil per day and 980 Mcf per day.

In this same area, the Cusack Clampit wells, which were highlighted in the press release, IP-ed at rates ranging from 860 to 1,800 barrels of oil per day, with 1 to 1.8 million cubic feet a day of rich gas each. We have 100% working interest in all these Eastern wells.

In this Eastern area, we typically drilling 4,000-foot laterals and expect the average reserves per well of 460 Mboe net after royalty. The Western area has only one target, the Lower Eagle Ford, and the rock is a bit thinner.

Typical wells here are the Haynes #1H and Hoff #6H wells, which IP-ed at 979 and 629 barrels of oil per day respectively. We have 100% working interest in these wells also.

To maximize our economics in the West, we'll drill 6,000-foot-long laterals and expect 430 Mboe per well net after royalty. These per well recoveries are considerably higher than we noted in April.

Sixth, the typical decline curve for both areas indicate we'll produce 40% of our wells' reserves in the first five years. We originally thought we'd need roughly 2,800 wells to capture the 0.9 billion barrels of oil equivalent.

But now it will take us a lot fewer wells to monetize this asset. Overall, we believe we can achieve a $12 to $15 per Boe direct finding costs across the entire play.

We plan to run 14 rigs, drill 231 net Eagle Ford wells in 2011. And seventh, the direct rates of returns that we expect to achieve from both East and Western wings of our sweet spot will return to the same return goals as we gave at our April analysts conference.

As we exit the science stage and enter the program drilling phase in 2011 and '12, we expect to achieve the 0.66 and 95% direct after-tax rates return. In order to decrease our average completed well costs back to the original range by the end of next year on a normalized lateral length places, we're implementing drilling enhancements and completion design modifications as well as contractual and self-sourced frac solutions.

Let me take a minute here to discuss our volume growth projections. This applies not only to the Eagle Ford but also to our other oil resource plays.

EOG is a company that has rarely missed its volume targets over the past 11 years. Yet now, we are revising our 2010-'12 numbers downward.

Part of this is very simple. At current and projected gas prices, we have no interest in growing gas volumes.

Regarding oil, our individual wells are performing as expected. But we underestimated the downtime for patent drilling and delays for frac equipment.

As we previously stated, optimizing shale oil or gas recovery requires drilling five or six side-by-side wells, frac-ing them simultaneously and only then turning all wells to production. Therefore, if frac equipment is delayed, it doesn't affect only one well but cascades to five or six wells and the associated production.

We believe our updated volume estimates now account for this methodology. To give you a little more color on these frac equipment delays, we're currently experiencing delays in almost every one of our divisions and have about 100 wells experiencing delays.

Since most of our budget is oil wells, this disproportionately affects oil volumes. These delays won't go away anytime soon.

And our new 2011 and 2012 growth forecasts assume the frac delays continue until at least mid-2011. Moving to an emerging oil play.

We're pleased to report success on additional acreage in our New Mexico Leonard Shale. Last quarter, we told you we'd proven up 31,000 of our 120,000 net acres.

And we can now report we've proven up an additional 18,000 acres. Our Elk Wallow 11 #1H and #2H wells are producing at 337 and 505 barrels of oil per day, with 3.1 million and 4.8 million cubic feet of rich natural gas, respectively from an upper and lower Leonard interval, indicating we have two separate targets in this area.

We have 100% working interest in these wells. We expect our Leonard reserves will likely increase from the original 65 million barrels of oil equivalent, in our estimate.

Because acreage explorations aren't as critical here, we'll develop this asset at a relatively slow pace in 2011. Our Barnett Combo results continue to be consistent, and we're in a steady manufacturing mode.

For the second quarter in a row, we've expanded the Core area. This time from 150,000 to 160,000 acres.

This play keeps getting bigger. Earlier this year, we highlighted our first very good horizontal well in the Eastern portion of our acreage, where we'd previously recorded only verticals.

Since then, we've completed many successful Eastern area wells in horizontals and verticals. Recent successful horizontals are Strickland A #2H, Settle C #3H and the Christian C #3H, with IP rates of 1,118, 731 and 954 barrels of oil per day.

It's 1.6 million to 2.1 million cubic feet a day of rich gas. EOG has working interest varying from 90% to 98% in these wells.

Two successful vertical wells in the East are the Strickland #1 and Slagle #1, which IP-ed at 865 and 539 barrels of oil per day. We have 96% and 100% working interest in these wells, respectively.

We've also achieved good results in the Western portion of Montague County, with a Posey C#3H testing at 536 barrels of oil per day. We're currently operating 16 rigs in the Combo and plan to run 16 rigs here in 2011.

One other interesting feature here, although the Combo increased about 1/3 oil, 1/3 NGLs and 1/3 residue gas, the current revenue split is over 90% liquids and less than 10% gas, consistent with our liquids shift. We plan to drill 258 Barnett Combo wells in 2011.

On our Barnett gas activity, essentially all of our Johnson County acreage is now held by production, till we plan to drill zero Barnett gas wells in 2011. Moving to the Bakken.

Per well results continue to be as expected, and we continue to prove up acreage outside our Core area. The newest area is Southwest of the Core, where we drilled several 640-acre space wells with good IPs.

The Mandaree 4-15, 2-9, 10-5 and 6-20 wells IP-ed at maximum growth rates of 1,490, 1,358, 840 and 1,175 barrels of oil per day, respectively. We have 63% to 90% working interest in these wells.

Our drilling within the partial Core area has also yielded the expected results, and we've seen no unusual declines here. Overall, we're happy with our North Dakota results.

And this asset is currently our single largest oil contributor, although that will change within a year or two as the Eagle Ford ramps up. We plan to run 10 Bakken and Three Forks rigs in 2011.

Also about 25% of our 2010 wells were 1,280-acre space laterals, and that 25% will grow to about 70% next year. The Manitoba Waskada oil volumes are finally drilling after one of the wettest summers in 60 years, which inhibited our activity.

Net production has increased 4,600 barrels of oil a day in January, and we expect a year-end exit rate of 7,700 barrels per day. The last oil play I'll mention is the Niobrara in Northeastern Colorado.

We're currently running three rigs here. Two recent wells, the Critter Creek #5-10H and #9-15H had IP rates of 690 and 748 barrels of oil per day on restricted chokes.

And we have 100% working interest in both of these wells. Even though natural gas isn't currently in vogue, we have some upbeat news from the Marcellus and continued good news from the Haynesville-Bossier, where we're drilling to hold acreage.

In the Marcellus, we've modified our frac program in our first four wells on the EOG/NSG joint venture acreage with these new style completions are very strong. The Clearfield County counts the 34H, 35H, 37H and 38H wells IP-ed at 9.2, 8.5, 7.1 and 8 million cubic feet a day respectively.

EOG has 50% working interest in these wells. In our Haynesville-Bossier area, we continue to make good wells such as AC LCO #1, Black Stone 4 #5 and Fremont Farms #1 wells, which IP-ed at 34, 23, and 26 million cubic feet a day, respectively.

We have 48%, 75% and 75% working interest in these wells. We've refined our mapping of the play's sweet spots.

Although we're not known as a major Haynesville player, we believe EOG has a Haynesville-Bossier sweet spot acreage position that's as good or better than any other operator in the play. Current Investor Relations presentation has a chart showing EOG with 67% of our total acreage position in the sweet spots of this play.

During 2011, we plan to drill the minimum number of wells here that is necessary to maintain our acreage position. In the Horn River Basin, we're in the process of completing several wells.

And early results from three wells completed in the EB section show IPs between 16 million and 22 million cubic feet a day. We won't be as active here in 2011, as we've been in 2010.

Outside North America, our Trinidad asset is currently in the production mode, and we will begin developments early on our Toucan discovery in the fourth quarter. This will provide deliverability to meet our 2011-13 gas contracts in China, we expect to frac another well, the third, by year end.

Outside of operations, part of our business plan involves selling some assets to partially cover our expected 2010 and 2011 operating cash flow shortfall. At our April analyst meeting, our goal was to sell assets this year and maintain a maximum 25% net-debt-to-capital ratio.

Since April, gas prices have obviously collapsed, so we've come up with a new capital plan. We expect to sell between 600 million and 1 billion of acreage and oil-producing assets this year, with almost all of that expected to close in the fourth quarter.

I want to stress most of these deals are not yet closed. For 2011, we plan to sell at least $1 billion of primarily gas acreage or producing properties.

And we've raised the conceptual upper limit on our net-debt-to-total-cap ratio from 25% to between 30% and 35%. Unlike others, we don't intend to sell or JV any of our horizontal oil plays.

We intend to emerge from this transformation retaining 100% of the oil and combo assets that we've captured. And we're willing to liquidate gas assets, gas acreage or assets to achieve that goal.

I'll now turn it over to Tim Driggers to discuss financial and capital structure.

For the quarter, capitalized interest was $19.5 million. For the third quarter 2010, total exploration and development expenditures were $1.5 billion, excluding asset retirement obligations.

Total acquisitions for the quarter were $3 million. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $107 million.

During the third quarter, we accepted bids to sell a portion of our Canadian shallow natural gas assets for net proceeds of $320 million. Additionally, these assets were considered to be held for sale, and we've recorded a pretax impairment of $280 million to write down these assets to fair value.

At quarter end, total long-term debt was $3.8 billion, and the debt-to-total-cap ratio was 27%. At September 30, we had $28 million of cash, giving us non-GAAP net debt of $3.7 billion and a net-debt-to-total-cap ratio of 27%.

Yesterday with earnings press release, we included a guidance table for the fourth quarter and the updated full year 2010. For the full year 2010, the effective tax range is 40% to 50%.

Note that this is on a GAAP basis. We have also provided an estimated range for the dollar amount of current assets that we expect to record during the fourth quarter and for the full year.

Now I'll turn it back to Mark.

I'll now provide a few macro comments. Regarding oil, we're still rationally bullish based on the fact that global oil demand is currently 86 million barrels a day, the same as in 2008.

And the demand has rebounded very nicely for last year. It's worth noting that 2010 global oil demand growth is the second greatest in the past 30 years.

We've increased our 2011 hedge position slightly and currently have 10,000 barrels of oil a day hedged at $90.39. Regarding North America natural gas, the question is, "Can it get much lower?"

And I guess time will tell. I expect the gas rig count to fall by about 200 rigs by mid-2011.

We currently have 150 million cubic feet hedged at 2011 at a $5.44 price and 200 million a day hedged for 2012 at a $5.57 price. Now let me summarize.

In my opinion, there are three points to take away from this call. First, beginning in 2011, we are now predominantly an oil company based on our anticipated revenue mix.

And there is no other company our size that's growing oil and NGL volumes similar to EOG's rate. Second, our oil assets are generating consistent and repeatable results.

I'm particularly pleased with the results this quarter from the Eagle Ford, Barnett Combo, Leonard and Bakken. Regarding the Eagle Ford, two recent industry transactions for acreage in the oil window have ratified our asset value, particularly when noting that we were the first mover and have a premier oil window acreage.

And third, although our capital plan has changed a bit since April, we're on track to sell significant natural gas properties in 2010 and have additional sales planned for 2011. Additionally, we've pared our 2011 dry gas CapEx to absolute minimum level to hold our Haynesville, Marcellus and Horn River acreage positions.

Our goal is to retain and develop 100% of our oil assets without incurring excessive debt, and if we lighten up on some natural gas assets in the process, so be it. Thanks for listening, and now we'll go to Q&A.

Mark, just a question on the gas assets. You mentioned that Horn River Basin activity will be less next year than this year.

Could you just talk about the development that you plan at the Horn River and given the obligations related to the LNG facility?

The status of the Trinidad LNG facility is, we're still teaming up with Apache and working on that. And we're making, I'd say, consistent progress.

But I believe it's going to be year-end 2011 before we truly know if we have a firm project or not. So over the last three months, we've clearly made some headway, but it's just going to be a slow progress.

I believe the project's got a pretty strong chance of actually happening. I think all the elements are in place for it, but we still got a ways to go.

So what we've adopted in light of these very dismal North American gas conditions is, we've done enough science wells now in the Horn River to have a pretty good feel for reserves, potential per well, drillability and so on. And we're just going to, for 2011, just take a minimalist approach in terms of our CapEx related to Horn River drilling in that particular area.

Regarding the asset sale in the second quarter conference call, you mentioned acreage amount you're going to sell in various places like the Marcellus, Eagle Ford and Haynesville. Have there been changes to those plans?

Yes, we don't really want to talk about anything specifically until we get some firmer situations. But generally, I'd say in either 2010 or 2011, it's likely that we'll be divesting ourselves of a portion of the Marcellus acreage and a portion of what we call kind of our non-core Eagle Ford acreage.

And what about the Haynesville and are you also going to sell some Niobrara?

Yes, the Haynesville, we've got a small amount of acreage there that we'll probably liquidate. That's not going to be a substantial amount.

And the Niobrara, we have divested a little bit of the 400,000 acres. But we'll definitely be keeping the majority of that 400,000 acres.

The best way to explain all of this, Joe, is on the natural gas front, we've got a huge gas inventory clearly in the Haynesville/Bossier and the sweet spot hitting probably between nine and 10 Tcf. We're quite encouraged now with the Marcellus on our combined EOG/NFG acreage.

We know we've got a ton of gas in the Horn River and certainly a bunch in the Uinta basin and some in Johnson County in the Barnett. And what we'd be looking at selling over the next 18 months are our properties that perhaps are long-life existing gas properties that may be time to pass down to another operator.

We're a company that over the last decade, we haven't sold much. We've been in accumulating mode that whole time, so we've got a pretty good inventory of existing properties to liquidate.

And there are buyers out there, even at these kind of gas price conditions. And so we'll be liquidating some of those and also on some acreage that either we have to invest in drilling-wise or the Ford expires or something along those lines.

So what we want to do is we want to emerge from this with the horsepower for gas of all those core plays I just mentioned to you. So if it turns out that the gas turns out to be a bullish commodity over the next five or eight years, we've got a kind of horsepower there.

And we want to emerge from this with essentially 100% of all of our oil and combo plays. We believe we can do that during the next year or two, even while we're liquidating some gas-producing assets and some portions of some acreage.

Could you talk about your Permian activity in the Southeastern region and if you're in related counties, please?

Yes, what we can say about that particularly in those areas, and it's no secret that there's a play that's active out there called the Wolfcamp play, a horizontal play. We're aware that at least two public companies have made press releases recently, and their press releases were basically predicated on an EOG well or wells in that area.

And what they're saying is based on EOG's well results, we, companies A and B, have a new oil play. As is typically our case, we'll talk about any new potential plays whenever we have sufficient data to provide an intelligent assessment to our Wall Street.

And at this point, it's just too early for us to comment. But we do have to recognize that our name's out there in public relating to this plays.

So that's kind of a circuitous answer. But this is what we've given on previous plays in the past.

Is the 40-14 well as good as the rumors have it?

I really can't comment on that at this time, Richard, except to say that at some point down the road when we really feel that we've got our acreage position locked in and we have sufficient data from sufficient wells, then we can provide you a comment.

Hey guys, you alluded to increasing your sales force, frac solutions, and I know you guys have sort of stayed in the Barnett. Are you thinking of continuing to do that in other basins?

Or are you considering buying into pressure pumping equipment?

Yes, kind of our current situation, Scott is, that we are indeed self-sourcing our fracs, if you will, in the Barnett, particularly in the Combo play. We're not going in the business of buying pressure pumping equipment.

But we very much recognize that the costs and the availability of equipment from major suppliers is just flat unacceptable to us really, and we're pursuing other avenues. And the other avenues, we'll just say that we expect to have those in place approximately mid-2011.

And at that time, we'll discuss exactly what those other avenues are. If I give you one primary reason why we've had to lower our volume estimates here, it's been lack of availability of frac equipment.

And as I mentioned earlier, we're literally just, in essentially every division, we're literally waiting months, not weeks, not days, months for availability of frac equipment. And the costs of that equipment, when it does show up, is I'd say have increased dramatically from our April analyst conference.

And that's just the situation. We have to come up with a plan to obliterate that.

And we have a plan, and we'll articulate it more clearly as we get to mid-year next year.

Just jumping over to Eagle Ford, you guys have had success with increasing the EURs. Have your down-spacing assumptions changed at all since your analysts day that you guys area 125- to 140-acre spacing?

Can you kind of talk to how that's progressed?

Yes, Scott, at the conference, we were talking about 125 acres spacing for the Northeastern portion of Eagle Ford, and I think it's 140 acres for the Southwestern portion. But we're still experimenting with that.

We have lengthened our laterals, because we now have really excellent quality 3D shot in both those areas, Northeast and Southwest. And we now know how we could drill a lateral before we get in trouble with faulting and that sort of thing.

So we have extended our lateral links probably for an average of I think 3,500 feet in both areas in the past to maybe 4,000 feet in the Northeast and as Mark said earlier, about 6,000 feet in the Southwest. And the uplift that we're showing on our EUR is just really, you can tie almost all of that uplift just for the longer laterals at this point.

But the bottom line is, we're not yet calling on increased recovery efficiency or down-spacing or anything like that to improve our EURs per well. We think that's still in the future for us.

Okay and then lastly just on the rig count in general heading into 2011, it seems like you're going to stay flat in the Combo and the Bakken, picking up in the Eagle Ford. Are there any other moving pieces, up or down, on the rig count that I'm missing there?

No, we're good. We're running 75 rigs.

And looks like 2011 will be in the 75 to 80 rigs as well.

First on the Canadian sale. If I've read what was in the Q correctly, it seems what you sold was about half of what I thought you were producing up there.

So is there more Canadian gas products to be sold? And #2, from what you said out there, are you know leaning towards monetizing more of your producing properties as opposed to growing acreage?

Yes, relating to the Canadian sale, yes, the answer is, it's likely that with the next 12 months that there will be additional Canadian shallow gas sold. We only sold a portion of that.

And basically, what's announced in the press release is only a portion of that gas. And in terms of monetizing some gas assets, yes, I would say that relative to our April analysts conference, we're now more likely, particularly in 2011, to monetize some producing gas assets more than we were previously.

If you look at our projected volume growth in North American gas for 2010, 2011 and 2012, it's negative in '11 And I think it's plus 1% for 2012. And those projected sales are reflecting in those volumes, so those volumes we provided are not pro forma.

We're assuming that we sell property x say the first quarter next year, property Y by mid-year. And so that's why you're seeing on the North American volume growth.

Our feeling is just on the macro view, I'd love to be more optimistic on gas. I hope I'm wrong.

But we are so long on gas assets in this company that we can liquidate some of these gas assets and still retain tremendous horsepower if we decide to grow gas assets in 2013, '14 or 2015.

And In the Eagle Ford, you talked about the lower and upper zones. Are you accessing both zones with one lateral?

Or are you looking at two separate wells down the road?

It's not a case where we're talking about a lateral that have one branch that goes to the upper and one to the lower. That's not what we're doing.

Those Cusack Clampit wells that we highlighted in the press release, those wells are alternating one well within lower. Then the next well beside it is in the upper.

Then the next well beside it is in the lower, next well is in the upper. That's kind of similar to what we've done in the Barnett.

So the way to look at it is that upper requires a separate well from lower.

And then, if you look at that trend, I mean some of your best wells are towards the Northeastern part of your acreage, any thoughts on the acreage extending what happens if you go farther northeast?

On last quarter's call, we mentioned that we'd gotten a 3D shot over that Northeast and 3D imaged a new fault block that could the extend 160-mile length of this play another 20 miles to the Northeast. So we had not yet drilled that fault block, but certainly we'll do so in the next multiple months.

If that fault block works, then we do have a 20-mile extension potentially of 160 miles.

If I can think about 2011 CapEx, you said a little bit of an out spend. Should we assume that the outspend is equivalent to the projected asset sales?

What's the right way to think about that?

Yes, we will furnish data the CapEx number on the next earnings call for 2011. But The way I'd suggest you think about it is so we'll be targeting this 30% to 35% debt range.

And for us, the 35% is kind of a red zone that's kind of a zone we don't want to go north of. So we'll be managing the asset sales.

We'll be looking at what the product prices for next year in China and try sort all that out. But the predominant deterrent there is going to be the debt level.

And If we have to, we'll sell more assets to keep it in that debt level or less assets, depending on kind of where we stand on product prices and CapEx.

Another question, If I had went and backread the transcript from the second quarter last night. You made a number of comments about you said infrastructure was tight.

It looked like there was some delays in the frac side. How has the market changed between August and November?

That's a good point. Let me correct one thing.

I misspoke a little bit earlier. I said 160 miles for the Eagle Ford.

That's really 120 miles with a possible 20-mile extension. In terms of the frac situation between April and today, it's really gotten worse, I mean, worse from a producer's viewpoint.

It's literally at a point now where if we want to frac a well, and we call up one of the major service companies, typically they'll say, "Well, we can get to you maybe right after the first of year. And the price, we'll tell you the first of year.

But it's going to be even higher than your worst case scenario to frac this well. And if you don't like that particular price availability, well, we've got a lot of other people had a needing fracs.

But I would say we certainly had a peak drilling activity several years ago, when gas was $9 or $10 and there was a frenzy of activity. But the frac situation was not as tight then as it is today, in my opinion.

We said that the second quarter is that the costs and stimulation was up 20% to 40%. Today, we would say it's 40%, maybe as high as 50% more.

If I think about the PV and the impact of pushing too much drilling back out here. Obviously the value's still there.

But it takes a couple of years to get it. Care to share what the next two years slowdown does to that model.

How should we think about value creation? And I assume you do.

Care to share what the next two years, the slowdown in production does that model? How we should think about value creation other than being pushed back couple years?

Predominantly in the CapEx, I mean it's costing more to drill?

We're not going to try and give you an PV for any of our assets or so. Let me point out also, there's nobody else in North America, other than maybe the heavy oil guys, who've captured essentially in one play close to 1 billion barrels.

And if this discovery were made in the Deepwater Gulf of Mexico, it would be highly heralded in newspaper headlines, so on and so forth. We can beat the bridges of our direct finding cost of whatever a Deepwater funding cost is.

And we beat the bridges off a heavy oil project. And so we haven't a dam of a project.

And maybe the PV has been pushed back potentially a year or six months. But when you look at it in the bigger picture scale, that's not all that meaningful in terms of the deferred PV, as far as we look at it.

That's as far as I'll go, David.

Previously on the debt cap side, you guys were 20% to 25%. Mark you talked about 35% sort of being your max red zone.

Does that factor in the effect of the asset sales? So I guess what I'm asking is, post asset sales next year, you're still going to be at 35%?

Our game plan is between now and 2012 to be no more than 35%. And that does factor in, that assumes we do have asset sales in 2011, yes.

Obviously, you guys cut your oil and liquids production guidance for '11 and '12, and so you've articulated about a lot of the reasons. Do you expect to also see a reduction on oil and liquids related to CapEx as well on the next couple of years?

We'll answer that when we provide CapEx guidance on the next earnings call, Leo.

Jumping over to Eagle Ford. What are you guys seeing now in terms of well costs over there?

They're currently higher than what we forecasted in our April analyst conference. And we're working to get those down.

I mean the primary reason is the frac costs there are in rough terms, maybe as much as $1 million higher than what we had estimated previously. And we hope by mid-2011 with some of this outsourcing that we're talking about, we can get those costs more in line.

But the costs have gone up, but also the reserves have gone up because we're drilling longer laterals. So in terms of the returns, this is likely to be an awesome project on the terms, unless oil prices collapse.

One comment you guys made is that it doesn't sound like you're selling much of your Niobrara acreage. I know you haven't declared victory on that.

But does that indicate that you've got some optimism about the play there?

What was promised is at year end, we'd give an update on the Niobrara, which would really translate into the next earnings call. The issues, we've articulated the same as our last call is a much more heavily fractured play, so the initial production rates are going to be quite good.

The question is, what will those production rates look like six months, 12 months after the initial rates? So we just need a bit more time to watch it before we really give you specifics on that.

I know that you guys reduced your international gas volumes for 2011. Is there still some slippage there at the startup of Toucan?

And when are you going to be selling some of the gas there?

No. It's really due to the projection of the internal markets.

What happens when we had this big recession, worldwide recession in 2009 are these anticipated growth of new methanol and ammonia plants that they assumed would be built on the country of Trinidad. But those all got put on hold.

And so we anticipate that there may be just some internal demand restrictions. We may not have as high contract takes next year as we've enjoyed this year.

So we've got a little bit of a cautionary factor built into our numbers there for Trinidad.

It sounds like you've sold a portion of the shallow Canadian gas. Could you let us know how much shale volumes were sold and what their reserves were, can you say that?

No. We just do not say that because we're in the process of working to sell the remainder of the gas, and we don't want to set any particular parameters out their, benchmarks.

But in your new production guidance for 2011, have you factored in this sale that you've already made there?

Yes, that's correct.

As you highlighted, one of the key drivers in the change of your oil guidance is the result of the greater completion, tie-in delays in the key resource plays. Can you provide more color on how long it takes to drill complete and tie-in wells in the Eagle Ford, Barnett Combo and Bakken today, what you assumed that, that could get to previously in 2011 and 2012 and what you're feeling today?

That's a pretty broad question there. As far as the time you start a well and you bring it on production, it could be anywhere from, depending on the play, anywhere from 60 to 90 days, probably on the higher end of that.

And as far as yes, going forward here, Mark had mentioned that we expect to maybe have some relief on available pump services mid-year 2011. And that may draw back from the 90 days to the 60 days, Brian.

That answer your question?

It partially does. So, I guess, what didn't change relative to where you were previously where you were assuming that, that could've gone from 60 to 30, and now you're assuming it go from 90 to 60?

Is that essentially the kind of key changes of how you're thinking about things here?

I guess I'll take a crack at that, Brian. We all knew that we want to complete these wells in bunches, four, five or six wells together.

But what we assumed back in April was, if we called up a service company and say, we need you to frac a well in three weeks, that they'd show up in three weeks and we'd then frac five or six wells simultaneously. Now what we're finding is you have to schedule this four our five months in advance.

And instead of three weeks, you're really looking at four to five months to get those things done. And what it does is it sets you back the whole, not one well but six wells.

Production comes online many, many months later than what you expected. And then what it does for you is, we assumed we'd have an exit rate in December of this year, we'll say X back in April.

Now we know that exit rate is going to be less than that and so that's why the gross volumes that were projected now and for 2012 are going to be less. We're sill going to have pretty dramatic year-over-year production, but we're compounding off a lower base than what we previously expected because we didn't achieve our this goal this year.

And then we built into it the fact that miraculously this frac equipment does not become instantly available on January 1 of '11. We don't see any real improvement there.

The biggest improvement we're going to see, we believe, in the frac equipment, sort of us outsourcing is, if the gas rig count drops by a couple of hundred rigs. And we believe by mid-next year, my guess is 200 rigs.

Gary Thomas is guessing 300 rigs, the drop in gas rig count. When that happens, if that happens, then all of a sudden, whatever frac equipment is tied up there becomes available for oil plays.

So we're kind of hoping that happens for multiple reasons, one is a great gas mark and two is just backup free up equipment. Hopefully, I gave you a little more color there, Brian.

And then when you look at the change in your gas production expectation, how do we think about the organic impact from a combination of reduced activity outside the Marcellus and Haynesville combined with the stronger result you've seen in the Marcellus and the Haynesville? Is it still kind of an organic decline?

Or do the two offset each other?

No. We'll be selling more gas, we believe, over the next 18 months than we're developing new gas.

I would say it's a sale-related decline more than anything else. In other words, the impact of the total volume of gas we're likely to sell in million cubic feet a day is going to overwhelm our organic growth.

And the net's going to be those slightly negative North American gross numbers.

Just a follow up on the earlier CapEx question, I know you don't have guidance this early for next year but is the way we should just back into what you would be assuming today to assume the 10% growth, assume $1 billion asset sales, 30% or 35% net debt to total cap, assume stripped commodity prices and then back in to what CapEx implies, is that essentially a good way of thinking about what you may be modeling internally?

I don't think we want to give that much clarity at this point in time because the asset sales we're looking at next year are probably a minimum of $1 billion, as we think about it today. But we'll give you more clarity by the next earnings call on that one.

Just trying to get a little more color on the new debt-to-cap target. What are the primary drivers again for the increase from 25% to the 30% range?

I'm just wondering if that's a price issue, a realization versus hedges? Or is that related to higher spending?

Or some other reasons?

I'd say that the two clear reasons are a collapse in gas prices relative to what we saw in April. And also in April, I believe if you looked at the oil price expectation or the NYMEX that existed in April versus what we've actually achieved so far this year, we've actually gotten a lower oil price than what the NYMEX would have indicated in April.

So part of it is clearly the hydrocarbon prices are providing less cash flow this year than we hoped for. And then, the other part of it is just I'd say cost escalation primarily in fracs.

It just cost us more to get done than what we anticipated. That's not new news to you.

I think most everybody who's reported earnings so far has indicated some cost pressure issue relating to fracs. So those are the two big components of it, Brian.

When you think about the Leonard Shale and the Eagle Ford, do you think directionally lateral lengths are getting longer, more stage fracs? Is that sort of Bakken concept going to be applied you think or being applied to some of these new oil shales?

Very definitely, yes. If you project that two or three years, when you look at the Bakken, when we started at the Bakken, you're looking at maybe 4,000-foot laterals, and now, we're kind of routinely talking about 5,000 to 10,000-foot laterals.

And the industry is doing the same thing up there. And when we started out in Eagle Ford, the data that we had back in April were really based on 2,900-foot laterals.

And today, we're talking about 4,000 to 6,000-foot laterals. So if you go out a couple of years for, say, the Eagle Ford, it wouldn't surprise me if we end up talking about routinely 8,000 to 10,000-foot laterals.

Because the reserves, one thing we found in pretty much all of these resort plays are the reserves are just a linear function of the lateral length. If you drill oil with twice the lateral length, you're likely to get twice the reserves.

And the same thing will hold true for any of the other plays, whether it be the Leonard Shale, the Combo play or some of these things. So in many cases, you've got some limitations there, if you've got a lot of fall patterns.

So the more highly focused an area is, you can't can go out and drill a 10,000 or 14,000-foot lateral. But the sense of the industry moving to longer laterals in all the play will very definitely occur.

Last question is on LOE and as you shift to a higher percentage of liquids, where do you think directionally the LOE trends in the company over 2011 or 2012?

We certainly can't deny the fact that if you take just a dry gas well versus an oil well, the LOE is going to be higher for an oil well. So we clearly have that, that we'll be working against.

But of course, obviously, the margin, profit margin on an oil well is much higher than a gas well. But I can't give you a percentage or a number other than again, to defer to the next earnings call, we'll give some LOE guidance for the full year of 2011, relating to that.

So that hopefully will give you a little bit of input there, Brian. I'd like to thank everyone for staying with the call.

And once again, it's a case where EOG has been one of the most accurate companies on hitting volume targets for 11 years, but we just had a confluence of events here. But even once you get through the sticker stock of the lower volume growth that we're projecting, I don't think there's a company out there who's going to match our liquid volume growth for the next several years.

And I also mentioned that the volume growth doesn't stop in 2012. It continues in '13, '14, '15, clearly on liquids side.

We just haven't forecasted far out. So thank you very much.