Gary L. Thomas - Chief Operating officer Timothy K.

Driggers - Chief Financial Officer and Vice President William R. Thomas - President Mark G.

Papa - Chairman of the Board and Chief Executive Officer

Irene O. Haas - Wunderlich Securities Inc., Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Andrew Coleman - Raymond James & Associates, Inc., Research Division Raymond J.

Deacon - Brean Murray, Carret & Co., LLC, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Rehan Rashid - FBR Capital Markets & Co., Research Division Bob Brackett - Sanford C.

Bernstein & Co., LLC., Research Division Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Scott M.

Wilmoth - Simmons & Company International, Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing third quarter 2011 earnings and operational results.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call.

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC permits 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 estimates on this conference call and webcast, including those for the Eagle Ford, may contain -- may include 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 in the Investor Relations page of our website.

With me this morning are Bill Thomas, President; Gary Thomas, Chief Operating Officer; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website last night, and we included fourth quarter and updated full year guidance in yesterday's press release.

I'll now review our third quarter net income and cash flow, followed by operational highlights. In addition to our typical play results, I'll also address several hot button topics, such as infrastructure-related downtime, facts and logistics and crude oil marketing.

Tim Driggers will provide some financial details, and then I'll provide macro and hedging comments, a conceptual view of our 2012 business plan and concluding remarks. As outlined in our press release, for the third quarter, EOG reported net income of $540.9 million or $2.01 per diluted share.

For investors who follow the practice of industry analysts who focus on non-GAAP net income to eliminate mark-to-market impacts and certain non-recurring items, as outlined in the press release, EOG's third quarter adjusted net income was $223.2 million or $0.83 per diluted 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 $1.17 billion.

I'll now discuss our 2011 business plan and third quarter operational results. Our business plan continues to be simple and consistent.

We've completed the organic conversion to a liquids-based company by exploiting our world-class domestic onshore, horizontal oil positions, while preserving all of our core North American natural gas resource play assets and maintaining a low net debt-to-cap ratio. This is manifested in very high year-over-year crude oil production growth rates, the best in the industry for a company our size.

We continue to have 0 interest in growing North American natural gas volumes in a $4 environment. We believe that debt adjusted production growth per share us a useless metric to evaluate E&P performance, considering the value discrepancy between crude oil and natural gas, which is currently trading at 22:1.

What counts is profitable liquids growth, particularly crude oil. Our investments in high rate of return domestic oil plays will flow through the income statement and generate disproportionately high growth in EPS, EBITDA per share and cash flow per share.

In the third quarter, we hit both our volume and unit cost targets. We exceed 54% year-over-year total company oil growth in the quarter and 51% year-over-year oil growth for the first 9 months.

Our total liquids growth was equally impressive: 49% year-over-year in the third quarter and 47% for the first 9 months. You'll note that we haven't changed our full year liquids growth target of 47% year-over-year or 154,000 barrels per day.

Unlike many companies striving to achieve liquids growth, a majority of our growth, almost 80%, is in higher value crude oil as opposed to NGLs. Also, there are no changes to our 2011 capital budget guidance.

I'll now discuss the major drivers of our oil growth, starting with Eagle Ford. This continues to be the hottest and highest rate of return play in the U.S., and EOG has the largest and best situated net position in the oil window.

We continue to be the largest oil producer in the play, with net after revenue -- net after royalty, excuse me, production of 53,000 barrels of oil equivalent per day at the end of the third quarter, 78% of which is crude oil and 11% is NGLs. All of our 561,000 net acres are productive, and we expect to be the largest net Eagle Ford oil producer for at least the next decade.

Our press release contains multiple well results, so rather than provide a well-by-well recitation, I'll provide some context regarding the overall play. There are 4 key points.

First, our well quality continues to improve and to exhibit consistency across the trends. Also, we continue to have a 100% success rate.

Our press release highlighted 3 wells with IP rates of about 3,000 barrels of oil per day, plus additional NGLs. These are the best wells we've completed to date.

The Meyer Unit #6H IP-ed at 2,918 barrels of oil per day, 500 barrels per NGL per day and 2 million cubic feet a day of residue gas. The Mitchell Unit #1H and #2H wells IP-ed at 2,821 and 3,090 barrels of oil per day with 450 and 500 barrels of NGL per day each and 2 million cubic feet a day of residue gas, respectively.

We have 100% working interest in these wells. We've noticed improved rates across our acreage.

We are consistently completing wells with IP rates of 1,500 to 2,000 barrels of oil per day, plus NGLs and residue gas. This is attributable to improvements in the placement of the lateral in the optimum portion of the Eagle Ford play interval and also improvements in frac design.

This is not surprising because we continually work the science to enhance our understanding of every play. Second, we continue to be encouraged by our downspacing results.

As a reminder, in the last quarter's call, we stated that our 900 million barrel of oil equivalent net after royalty reserve estimate was predicated on a 130-acre well spacing and that we were pleased with initial results from our first downspacing pattern, i.e., closer than 130 acres on the King Fehner Unit lease. We've now observed production from this downspaced unit for 150 days, and the results continue to be positive.

We are testing 6 additional multi-well pilots of varying increased densities, and early results from all of these pilots look positive. We're not yet ready to make a firm technical call regarding closer spacing, but it's fair to say we're optimistic.

I'll also note that there's an interrelationship between well spacing and per well reserves. Third, in addition to the good news regarding well performance and increased density, we are beginning to see some consistent well cost reduction.

As you know, the Eagle Ford is a high-activity area for the industry, and this year there's been continued upward service cost pressure. The third quarter is the first time we've noticed a consistent trend of lower total well costs, due primarily to 3 internal factors.

First, our drilling time for well is decreasing, which we'd expect as we become more familiar with the play. Our fastest well to date is the Cusack Ranch #5H, which we drilled and cased to 15,467 feet in 13 days.

These cost efficiencies are an important factor in reducing well costs. Second, we've optimized our frac designs, which has reduced costs.

And third, we've implemented contract pumping services for our fracs, cutting costs by $0.5 million per well. The next game changer will be utilizing self-sourced frac sand from our new mine, which will start up in December.

This should reduce per well cost by an additional $0.5 million per well. Overall, we expect our 2012 completed well cost to average about $5.5 million.

This will easily make us the lowest-cost Eagle Ford oil producer and will generate great economics. Fourth, the last overall point regarding the Eagle Ford relates to takeaway capacity.

We continue to dodge a lot of bullets here. We had only a minor amount of downtime caused by facility limitations in the third quarter.

As I've said before, we will be on the nice edge of oil takeaway and gas plant processing capacity until the Enterprise expansions are installed in mid-2012. In the interim, we're moving 15,000 barrels a day of crude-by-rail, much of which is capturing a portion of LLS pricing.

The Eagle Ford oil pricing structure relative to the WTI has recently improved, and we're now receiving a significant uplift over WTI for most of this production. To summarize the quarter's Eagle Ford results, it's good news, good news and good news on the well performance, spacing and well cost fronts.

I continue to believe EOG's Eagle Ford position is the highest rate of return, large-scale hydrocarbon play in all of North America, onshore or offshore. I also continue to believe this is the largest oil company -- oil discovery net to any one company in the last 40 years in the U.S.

Speaking of good news, I'll now discuss our 240,000 acres of Permian Basin Wolfcamp and Leonard assets, which will be increasing growth contributors in 2012. Other companies have reported mixed results to date in the horizontal Wolfcamp, but EOG's results have been great.

I don't know whether that's due to better acreage or better technology, but the results speak for themselves. Our press release listed several recent completions, and again, I won't give well-by-well recitations.

So far, our wells have IP-ed between 600 and 1,400 barrels of oil per day, with 0.3 million to 1.3 million cubic feet a day of rich gas per well. In terms of understanding the play and optimization maturity, this play is about a year behind the Eagle Ford, but we've come up the learning curve enough to identify this as a significant future growth driver for us.

We also feel good about our Leonard Shale play, but we restricted 2011 capital allocation here because the acreage is already held by production. In the Bakken, we continue to be one of the largest oil producers in North Dakota and are achieving consistent results in the Bakken and Three Forks.

We'll drill 84 gross wells here next year and expect to have a steady consistent program for many more years. Our production has recovered from the second quarter flooding, and thanks to our crude-by-rail infrastructure, we didn't incur any significant production downtime this past quarter.

In 2012, we'll be testing some Bakken downspacing ideas similar to the Eagle Ford. Our well results in the Barnett Combo play were quite good in the third quarter, with several typical wells noted in the press release.

Late in the third and early fourth quarters, we did encounter some gas processing plant capacity issues that restricted production. We expect these issues will be resolved soon and the downtime is integrated into our fourth quarter volume forecast.

In summary, both the Bakken and Combo plays continue to deliver the expected results. We previously mentioned contributory liquids plays, such as the Marmaton, Niobrara and Powder River Basin.

We continue to have a moderate degree of successful activity in all these areas, but at this juncture, we'd classify them as contributory and not game changers for EOG. Before I close out the oil play discussion, I'll mentioned timing regarding our Argentina Vaca Muerta shale play, where we have approximately 100,000 net acres.

We'll start our first well in the first quarter 2012, though we should have some results by late 2012, In the East Irish Sea, we're targeting startup in the fourth quarter 2012 for our Conwy oilfield, which we expect to peak at 20,000 net barrels of oil per day in early 2013, giving us an early boost for 2013 liquids growth. Also, I'll mention we continue to maintain an active exploration program and continue to search for new horizontal liquids plays, primarily in North America.

Turning to the dry gas side of the ledger. We're continuing to focus our efforts only in areas where we must drill to hold acreage, mainly the Marcellus and Haynesville.

In British Columbia, we're still excited about the Kitimat LNG export project, but it's not yet a done deal. The project is contingent upon a construction cost estimate and the ability to lock in oil index sales contracts.

We recently had a lot of questions regarding EOG-owned sand mines and our crude-by-rail connection to St. James, Louisiana.

Because of the industrywide frac sand shortages and the resulting steep price increases, we've attacked this cost side of the business by developing our own sand mines and processing plant to provide high-quality frac sand. We'll commence the new sand plant startup next month.

The first area to receive sand will be the Eagle Ford, followed later in 2012 by the Marcellus and Permian. As I noted when discussing the Eagle Ford, the dollar savings per well will be substantial.

And since the frac is roughly 50% of the total well cost, this will position EOG as a low-cost producer in multiple resource plays. Regarding our St.

James crude-by-rail terminal, we still expect it to be operational by April 2012. We'll have the capability to move either our Bakken or Eagle Ford oil to St.

James. Total EOG capacity will be 100,000 barrels of oil per day.

We'll likely start with 50,000 barrels of oil per day of deliveries to St. James in April, and increase over the course of 2012.

We plan to increase the amount of deliveries to St. James as our existing fleet of railcars increases between now and year end 2012.

Another portion of our 2011 business plan involve $1.6 billion of asset sales. To date, we've closed on $1.3 billion.

On the last call, I mentioned that the timing of a small portion of these sales may carry over into the first quarter of 2012, and that still appears likely. Between our 2010 and 2011 dispositions, we will have sold about 6,600 net wells, which leaves us with a more concentrated portfolio.

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

Good morning. Capitalized interest for the quarter was $13.9 million.

For the third quarter 2011, total cash exploration and development expenditures were $1.59 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $162 million.

At third quarter end 2011, total debt outstanding was $5.2 billion, and the debt-to-total capitalization ratio was 29%. At September 30, we had $1.4 billion of cash on hand, giving us non-GAAP net debt of $3.8 billion, or net debt-to-total cap ratio of 24%.

On a GAAP reporting basis, the effective tax rate for the third quarter was 40% and the deferred tax ratio was 82%. Yesterday, we included a guidance table with the earnings press release for the fourth quarter and updated full year 2011.

For the fourth quarter, the effective tax range is estimated to be between 40% and 50%. For the full year 2011, the effective tax range is 40% to 45%.

We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the fourth quarter and for the full year. Now I'll turn it back to Mark.

Thanks, Tim. Now I'll discuss our views regarding macro-hedging in our conceptual 2012 and 2013 business plan.

Regarding oil, we still think the global supply demand balances is tight, even after this summer's release of oil from U.S. and European strategic reserves.

Following a second global recession, we're optimistic regarding 2012 WTI prices in the $90 range. We're currently 23% hedged at a $97.02 price in the fourth quarter 2011.

And for 2012, we're approximately 7% hedged at a $106.37 price. As mentioned, beginning in April 2012, we have offloading capability at St.

James, Louisiana, giving us full LOS pricing for up to 100,000 barrels of oil per day. This represents a current uplift of $16 per barrel over WTI.

We also view this as a hedge. We continue to have a cautious view regarding 2012 North American gas prices and are hedged accordingly.

For North American natural gas, we're approximately 50% hedged for the fourth quarter at $4.90 price. Additionally, we've sold options at a $4.73 price that if exercised would mean we're 65% hedged through year end.

For 2012, we're approximately 40% hedged at a $5.44 price, with options that if exercised will increase approximately 75% hedged at a $5.44 price. As in past years, we'll provide more detail regarding our 2012 business plan, including CapEx plans and production growth targets on our February earnings call.

However, at this time, I can provide you some conceptual indicators regarding our 2012 plan. As with this year, the overwhelming majority of our 2012 CapEx will be devoted to high, greater return oil and liquids projects, with a minimum amount allocated to dry gas drilling primarily to hold acreage.

In 2011, the CapEx split was roughly 80% to liquids and 20% to dry gas. Next year, that split will likely be 90-10.

If 2012 WTI oil prices average $85 higher, we'll likely have a CapEx budget at least at this year's level and grow liquids in the range of 27% year-over-year, assuming no downstream facility curtailments. To cover the spending gap, we'll sell sufficient properties to maintain our 30% net debt-to-cap limit.

We don't plan to issue equity. If oil prices average less than $85 next year, we'll simply reduce CapEx and reduce the targeted 27% liquids growth target, we won't issue equity and we'll sell whatever properties we need to conform to the 30% max debt-to-cap limit.

In either case, we'll have 0 interest in growing gas volumes, unless gas prices surprise to the upside. If you look conceptually to 2013 and assume that decent oil price, combined with a continued weak gas price, our funding gap narrows considerably or if we desire shrinks altogether if we elect to decelerate CapEx and achieve only robust instead of outstanding 2013 liquids growth.

The point is, we have a plan to cover our 2012 funding gap, and with our powerful liquids asset base, we can conform our 2013 and later years CapEx budgets to generate whatever liquids growth rate is optimum. Now let me summarize.

In my opinion, there are 7 important points to take away from this call. First, the game plan we articulated several years ago is working.

We've captured world-class, low-risk oil positions that are driving the strongest organic liquid growth, primarily oil, of any large-cap independent. In parallel, our EPS, EBITDA and cash flow per share are growing at disproportionately high rates.

This will likely continue for many more years. Second, we're accomplishing this game plan with relatively low debt.

Third, our Eagle Ford position is turning out to be even better than when we initially unveiled it in early 2010. We have not only the largest but the best quality net acreage position in the play.

Fourth, in the Bakken and Eagle Ford, our 2 biggest oil plays, our well results are essentially the best in the industry based on sell-side research, shown in our website IR slides. Anyone who wishes to check state data can reach the same objective conclusion.

The same holds true for our Barnett Combo wells. Although still early in development, we also believe our Wolfcamp well results are the best in the industry.

Fifth, essentially all of our oil assets are located in E&P friendly states in the onshore U.S. Sixth, we have a business plan to deal with our 2012 funding gap.

And finally, we continue to look for new liquids plays and ways to improve low recovery factors in our existing plays. In 2012, we intend to focus on recovery factor improvements in our large captured oil positions.

Thanks for listening, and now we'll go to Q&A.

Obviously, it looks like your results in both the Eagle Ford play and Wolfcamp play showed kind of materially higher IPs here in the third quarter versus 2Q in terms of the ones you highlighted. Can you comment as to whether or not you think that there are some potential EUR changes coming to the upside here in these plays?

Yes, Leo. The situation relating to the EURs, particularly in the Eagle Ford, are -- if we were to keep the same 130-acre spacing, we might have some positive upward trends there.

There is an interrelationship, however, between spacing and EURs. And so what might come out of it ultimately here is if we end up drilling on tighter spacing, that may offset the tendency toward higher EURs.

So it will probably be some time in the first half of 2012 when we're able to give an assessment of the more dense spacing, and at that same time, we'll give an assessment of the reserves per well. But clearly, the directions are positive here on both spacing and well results.

In the Wolfcamp, it's just -- it's too soon to know -- I mean, we are doing some similar spacing test there, and we're still assessing the reserves. But that one will be a little bit slower to come to a technical conclusion on that one.

Yes, I would say, clearly, the results in the Eagle Ford particularly are better than I would have ever expected. Going back to when we first rolled this out in early 2010, I'm, I guess, ecstatic would be a good way to describe the results that I believe we're seeing in the Eagle Ford.

Okay. And I guess just sticking with the Wolfcamp.

Can you guys comment on kind of the where the well costs are now and where you think those might go into 2012?

Yes, our well costs are down about 40% from when we started. And like Mark was saying, yes, the first wells were taking about 20 days, and they're taking about 12 days now.

And also, yes, we'll be able to drive those down with additional efficiencies, and most especially with having EOG store sands for our frac jobs.

Okay. So I guess can you maybe just comment on the actual numbers for the current well costs then?

Our current well costs then are in the $5.5 million to $6 million range. And then that's why we're thinking, yes, we'll get them down there in the $5.5 million or less with us having our own sand.

I'll just go and say, yes, we'll just continue to work the science, as Mark was saying, and further reduce our cost and improve the efficiencies of our completions in both of the cost discourse and the completions.

Okay. And I guess, Mark, any sort of differences in the assets sale program in 2012 versus 2011?

Are you going to kind of take a similar approach with kind of a mix of acreage, infrastructure and producing assets? And maybe could you identify anything at this point?

Yes, I mean, at least it's the first pass, we probably don't have a lot of further infrastructure items that we're talking about selling in 2012. So it's going to be primarily gas-related assets or acreage that we're looking at disposing.

And that's why we want to wait until our February call. Then we'll -- the way to view the asset sales for 2012 is the plug number.

You can kind of work backwards and say, okay, what's our cash flow going to be for 2012 based on whatever we see the price looking like in February, assuming a 38% max debt cap and then the plug number that you fill in is what we need to sell in the way of assets.

Just thinking about the Eagle Ford and the consistency that you guys have shown there. Could you maybe put in -- could you compare the Wolfcamp, the Permian development to the Eagle Ford in terms of expectations, how long, what type of well control you need for that to be the real big next growth story for the company?

Yes, what -- the way I'd characterize the Permian, both the Wolfcamp and the Leonard, is number one, we don't have the overwhelming acreage position. We've only got roughly half the acreage, net acreage, in the Permian as we do in the Eagle Ford, so it's not going to be as big an impact on the company.

In terms of the individual well results, I'd say that the well results on an individual basis are not going to be quite as strong in the Wolfcamp as they are in the Eagle Ford. We're not expecting we can get wells in the Wolfcamp approaching 3,000 barrels of oil a day, plus NGLs.

That's probably too optimistic. So I would say the Eagle Ford continues to be grossly underestimated in valuations in our stock, and the Wolfcamp/Leonard will have an impact maybe kind of like of half an Eagle Ford just in qualitative terms.

Well, half an Eagle Ford is still pretty good. My other question was in the midstream side.

To what extent does time in the midstream impact the liquids targets for 2012? And I'm not now looking for exact, just as that plus or minus 5%, 2%, kind of ballpark it?

Yes. Well, I'd say either that 27% growth rate, if we really had some nasty stuff happen in the midstream, it might affect it 5%.

It might knock it down to 22%. But at this stage, I'd say I'm a lot more comfortable about the midstream than I was at the beginning of the year for both 2011 and 2012.

Short of the -- if we exclude the flooding we had up in Manitoba and North Dakota, we really haven't had any massive midstream bottlenecks this year. And we're far enough out in front in terms of our midstream planning that short of a gas processing plant having -- just going down because of an explosion or something and being down for a couple of months or some oil pipeline having some massive leak that caused it to be shut down for months.

I'm fairly comfortable for the 2012 logistics. And it's really only the first half of 2012 for the Eagle Ford.

Then we've got the relief in the system with the startups of the Enterprise plants and pipelines.

If we are in the $85-plus scenario for next year, what's the kind of the implied Eagle Ford drilling ramp or needs to meet the pipeline and your HBP activity?

Yes. This year, it looks like we'll be drilling about 270 wells in the Eagle Ford, and we would have some increase next year in terms of Eagle Ford drilling.

And we'll give you some details on that. I mean, we're still thinking through that, but we'll give you some details on that in the February call.

But in conceptual terms, the Eagle Ford will go up a bit on the number of wells. The Bakken will go down in number of wells or rigs.

And the Permian will go up relative to this year. And the Niobrara will go down 2012 versus 2011 in rigs-directed activity, if you will.

And the Combo will stay roughly the same.

Okay. And then on your HBP needs in the Eagle Ford over the next couple of years, could you just quantify that?

Yes, we're in decent shape on that. At this stage, we -- if oil went to $50 a barrel or so, then we'd be stressed.

But if oil pays $80, $85 or so and we keep on the drilling program we're planning, then we should be in good shape to retain the entire acreage position.

Okay. And then when I think about the Bakken rig count decrease next year, is that largely just a function of where that asset is in it's life cycle, more of a development mode, or is it a statement on economics relative to the Eagle Ford?

Yes, it's more a statement of where our leases are. We've been drilling in the Bakken for quite a few years, as you know, and we're in darn good shape on just holding the lease position together.

So we have the flexibility in 2012 to not be forced to drill in the Bakken because we have leasehold issues. And so what we're doing is we're basically saying, okay, we'll slowdown in the Bakken a bit and we're going to accelerate in the Permian, particularly in the Wolfcamp.

So the economics are not necessarily driving it as much as the leasehold situation is. I had noted that on a few other competitors' earnings calls, they were talking about well costs in the Bakken for long laterals that I believe the numbers that were quoted are somewhere between $10 million and $12 million a well.

Our well costs up there for a long lateral, 10,000 foot lateral, are more like $8.2 million to $8.3 million. So I can see where some people might have some pretty skinny economics if you're spending $10 million plus on these kind of wells.

I was wondering if you could give a little bit more -- few more thoughts on the Vaca Muerta and beyond this first well? What type of commitment do you have for drilling next year?

Yes, Let me have Bill Thomas address the thoughts on the Vaca Muerta.

Yes, Ray, we've got a well planned in the first part of next year. And the section we're targeting there, we've got data that shows that it's relatively thick, about 900 feet thick, and it's got about 150 million barrels per section of oil in place.

So it's certainly a world-class potential rock. And we're planning a horizontal well, and we will be conducting microseismic on it to monitor the frac and do all the science work to fully evaluate how the well fracs.

And certainly, we'll follow up that and see how the well produces. So our expectations are really high for it, but we'll just have to see how it goes when we get the well completed.

Great. And maybe one follow-up.

In terms of the Permian, I think last quarter, you talked about bottlenecks emerging there similar to what you've seen in the Eagle Ford. I guess, based on your comment, that your activities going to ramp up, it sounds like you can maybe resolve some of those issues.

Is that fair?

Yes, our feeling is as the Permian is going to continue to heat up, that the Wolfcamp success we have, I mean, other companies are likely to have similar success subsequently. And so what always happens, it happened in the Bakken, it happened in the Eagle Ford, is you have a lot of success by the industry, and the next thing that inevitably happens is bottlenecks.

And we would expect that a year or 2 from now, you'll see a bunch of bottlenecks out there in the Permian, and we're already working trying to -- as we were ahead in the game in both the Eagle Ford and the Bakken, to be ahead of the game to ameliorate those potential bottlenecks. But as far as 2012, at this stage, we don't anticipate any really ugly bottlenecks, at least on the stuff that we're going to develop.

I'm intrigued by some of those well results at Meyer and Mitchell. You said it was the placement of lateral.

Can you talk about whether that's as a mute [ph] fall? Or is that where in the Eagle Ford?

And also, the frac design. What are you doing differently?

On the frac design, Bob, we are doing something different, but we're sure not going to tell anybody about it just for competitive reasons. As far as locating the lateral in this section, I mean, typically, the Eagle Ford thickness is 150, maybe 200 feet at the thickest.

And we've done a lot of experimenting as to where in that interval should you lay the lateral. And we think we've got -- there are better spots than others there.

And we think we've now consistently put that lateral in the proper spot there. So it's probably been the case of the -- I'd say the frac enhancement, the frac design, maybe 50% of the credit, and the lateral location, the other 50% of the credit.

But it just shows that the Eagle Ford is, because the rock wall is a bit better, you get outside responses, disproportionately large responses to just some small tweaks. And that's what we've seen, particularly in the Eagle Ford there.

That asset is just going to get better and better and better. I know I sound like a broken record on that, but it's truly a sense of wonderment to me how impressive that is.

Well, I'll try again on the placement. Does that imply that you're getting contributions from either a shallower or a deeper zone or not?

No. No, Bob.

No, we don't -- this is -- we believe it's all 100% contribution from the Eagle Ford only.

Following up on the last question there. With the strong quarter-on-quarter increase we've seen in the Eagle Ford IPs, not just in Gonzales County, but even in Karnes and LaSalle.

Assuming that these better IPs translate to better EURs, do you feel like you're increasing recovery rates or just that you'll end up needing fewer wells to recover what you always thought was recoverable?

Yes, again, I'll put off a specific answer on that till early next year. But the chances of needing fewer wells is pretty low.

All this downspacing data tells us directionally that if we go any direction from where we are today, we'll end up drilling more wells in the Eagle Ford. And that the combination of the downspacing, plus these improvements in the frac and everything, that those 2 factors could drive a boost in the recovery factor, which is currently 4%.

But we don't want you to go off and say, based on these wells, that you can say, well, we may have downspacing potential, plus higher reserves per well. It's probably not going to work that way.

It may be downspacing plus equal reserve per well or something along those lines, when you put the 2 together.

I guess, though, that even before one considers downspacing, the conclusion is that there's upside to the 900 million barrels, just for the well results alone.

Well, we're directionally feeling pretty good, That's all I'm going to commit to at this point.

Okay, that's helpful. And then secondly, you remarked in your release that the transition to EOG being a liquids focus company is complete and you're now into harvest mode in terms of developing some of what you found.

Should we expect either less focus or more flexibility and exploration capital spending for new liquids plays going forward?

The answer to that is no. We continue to be working to turf up new liquids plays.

And I mean, if you're driving toward any energy catalysts, I think the catalysts are twofold. One is, can we turf up brand-new liquids plays?

The second catalyst is, on the existing ones that are already identified, can we increase recovery factors on those? And so -- but we're placing a large degree of emphasis on both those.

But I'd say looking for new plays is clearly on our short list of things that we're doing.

Are you as optimistic on the potential for finding meaningful new plays as maybe you were before yourselves and others have unlocked the number of new liquids plays that have been unlocked here in the last couple of years?

I'd answer that by saying they haven't all been found yet, that's for sure, and our job is to be the finder.

A couple of questions. Mark, did you mention the recovery factors, or do you only think you're recovering 4% right now in the Eagle Ford, is that correct?

Yes, generally, 4%. There's about 21 billion , 22 billion barrels of oil in place in the Eagle Ford, and recovering 0.9 billion, I think that comes out closer to 4% than 5%.

Okay. And what do you think that number should, based on whatever you look at or your, I mean, geologists looking at?

What number you think that should realistically get to? Let's say the next 3 to 4 years?

Not going to answer that. Good try, though, David.

All right. Let me go to a different route.

Just looking at your gas production, obviously, backed off midland [ph] capital. What's your -- what do you think your decline rate's at now?

It seems like it has started to slow in the last couple of quarters. It came off kind of hard and then slowed down.

How should we think about 10% CapEx for natural gas next year? I know it's dependent on the gas price.

But what's the best way to think what your underlying decline rate is right now?

Yes, it's fair to say, our North American gas volumes this year have held up better than I expected relative to our expectations at the beginning of the year, which means the decline's a little less steep than we thought. But I'll also say that we really don't care for 2012 where our gas volumes go because we think it's just, at best case, you're just cycling money.

So our interest in having gas volume growth next year or not is very, very low, unlike pretty much the whole rest of the industry. I can't quote you a specific decline rate, but in terms of management focus on North American gas volumes at a $4 price range, we're just indifferent as to the volumes, I guess, the best way to put it.

And I have one question, but it has multiple parts. So starting with the most recent dozens of wells that you've drilled, are you targeting the same horizontal interval within the 1,000 foot Wolfcamp?

And essentially, how many zones within the Wolfcamp does work? What I'm after is are you going for a double-decker or triple-decker play?

And if yes, how big is this play? Does it extend half to 2 counties we know of?

And then also, well costs, how much is it costing? And then, finally, you said that this play is one year behind the Eagle Ford, about half the size, so we imply that you have scored about $0.5 billion barrel discovery already in the Wolfcamp.

And with that, I will stop there.

Oh, that's about a 5-part question. I'll let Bill Thomas answer that, Irene.

Yes, Irene, on the targeting, the shale is really thick. It's about 900 feet thick.

And so we're focusing on 2 targets right now, one mainly in the middle target. And that's where we drilled pretty much all the wells that you've seen that we've release in the press releases.

And the far right, those have all been in the middle zone, We have recently drilled several wells in the upper target, and we are in the completion process on those, and we don't have the results on those yet. So we at least have 2 targets there, and if they're both successful, you're correct, we will develop that play like we've done other plays, we will alternate targets.

And we're currently working on the spacing. We've got multiple spacing tests going on.

And so it's going to take us some time to be able to give you any kind of numbers on the full reserve potential of the play because, again, we're just in the early stages of testing the upper target. And we're still in the early stages of figuring out what's the correct downspacing.

So both of those will have a tremendous effect on the number of wells. As for the cost, I think we talked about that before.

I think our target cost is about $5.4 million per well.

Yes, our costs are about the same as right now as what the Eagle Ford is. But the thing that's encouraging there, it's about 1,000 feet less TVD, Irene.

And we're just thrilled with the drilling results. As a matter of fact, we just recently drilled one well, and it was drilled in just around 7 days at 14,500 feet.

So it's an excellent area to be drilling in and very few problems associated with that part of the operations. And we are drilling slightly longer laterals there.

As far as the total size of the play, it's certainly a regional shale deposit over the Midland Basin, and so it has a large extent to it, and it's fairly consistent. And so both of those things are really positive for EOG.

And like Gary said, it's a play that we can consistently get good results and we can consistently drive down our costs and increase the recovery factor of the play. So this is really a strong play for us and it's got a lot of upside.

Okay. If I may have one follow-up question.

The more recent wells, the blockbuster that you've just have announced, can you tell us how many stages of fracs there are? Are they ultra-long laterals?

The Wolfcamp wells or the Eagle Ford?

The recent, the 3 Wolfcamp wells that you just have announced as really huge. Are they the longer laterals, say, 9,000-foot well?

I don't think you disclosed.

No, these are, they are longer, Irene, between in the 7,000 to 7,500 foot length as far as total treatable lateral.

Okay. And so the frac stages?

On the stages, they're in the 30 range, 30 to 34.

So they're pretty closely spaced?

They are as far as the stage lengths.

The Eagle Ford side that are getting premium to WTI even now, maybe a little bit thoughts there and then kind of what logistically is happening to get you there? And then second, past maybe some divestitures still left to do in '12, is there a sustainable growth rate of the Enterprise that you would be comfortable talking about, of course, assuming appropriate margins?

Yes, Rehan, on the Eagle Ford oil pricing kind of logistics, our view is, is what changed the kind of the calculus there in the Eagle Ford oil pricing is when we started up our crude-by-rail and started moving about 15,000 barrels a day to St. James, then we saw a change by the oil purchasers pretty much throughout the Eagle Ford.

And prior to that, we were typically getting WTI minus some increment for our crude. And now we're consistently getting WTI plus an increment for the crude.

So I think it's just a case of proving that we have alternates [ph], EOG has alternates [ph] other than just selling the crude in the local Eagle Ford market is what changed the dynamics. So our guess would be that we're probably in a situation where we have a decent chance to get WTI plus increments prospectively for the Eagle Ford crude, that it'll probably a long-term thing.

In terms of long term, you kind of said on what kind of grows long term for the company would we be happy with in terms of production growth rate. We'd really -- you kind of hit my hot button on that because I think that because the value of oil growth or NGL growth is so disparate from gas growth, the best way to say it is, as a management team, we view kind of total company production growth as a useless metric.

And we're a lot more focused on EPS growth, EBITDA growth per share, cash flow growth per share. So in other words, we're at 110% focused on our liquids growth, and we don't have a great interest in the gas growth side.

So it's hard for me to quote an aggregate number for you other than we feel pretty strongly, though, on the liquid size as long as we have supportive WTI and LLS prices that we're going to have long term a disproportionately high liquids growth rate relative to the large-cap independent peer group. And that's what we're really focusing on.

I'm asking, what are the physical terms in Argentina? Is that a concession, or is that a PSA?

They're basically farm-ins from people who hold it ahead that acreage. And generally, those are not PSAs.

They're under the kind of the regime that the previous entities, owners of that acreage had. It's a pretty convoluted, as you know, kind of tax and fiscal regime down there.

But our research of it says that under the terms we've assumed under the farm-in, if we can make good wells, we can make a decent rate of return there.

Okay. And does the farm-in that you have, I guess, takeaway options or are working those as you get closer to the well results?

Yes, there are plenty of takeaway options there because essentially, what we're doing is we're drilling in the middle of an old existing gas and oilfield. So there's plenty of takeaway options.

The issue is really -- what it's really going to boil down to, I believe, with that shale play is, what is going to be the average well cost on a program basis. That's the risk you run on these international shale gas or shale oil projects are, can you drive the well costs down to make sure you have good economics.

And so that's the thing that we're looking at. I mean, our growing in very, very rough estimate is we think that the first well or 2 may cost us $15 million a well and then we completed the well cost and then ultimately we can drive that down to maybe $10 million a well.

But that's very, very rough. And we'll just have to see as we go forward.

The reason I said we'll probably won't be able to report any results until late 2012 is whatever result we get on the first well, we're going to want to test another well or 2 before we go spouting off that this is a big success or a big non-success. It's probably going to take us till late next year before we really can opine pro or con on Argentina stuff.

Okay. And there is enough access to services down there so you wouldn't have to bring any of your own, I guess, technical guys down there, I guess, have North American kind of a frac guys go down there to help you get the well completed?

Yes, we're pretty comfortable with the level of services. The 2 biggest issues there were directional drilling services and the frac services.

And there appears to be enough in country, at least for us, to get a couple of wells done. There's probably not enough in the whole country if the whole play takes off and turns into a monster play.

But right now, for testing purposes, yes, there's enough in country.

Okay, great. Then the last question I had is just more on, I guess, the strategic side of things.

Given the ambivalence toward gas, I mean, would you guys think about, I guess, larger, more holistic changes to the portfolio vis-a-vis, maybe an MLP of some of those assets or a larger asset sale of some of the more gassy piece of the portfolio?

Yes, as far as an MLP or a VPP, very, very unlikely. We just like to keep our whole accounting and the company very simple.

So pretty much 0 chance of that happening. Bigger gas asset sale, yes, it's possible.

We just have to see as we go through, but we're so long on gas assets in the company that it wouldn't break our heart if we parted with some significant gas assets. Okay.

I appreciate everybody staying with us here through the hour. And we'll talk to you again in 3 months.