Good day, everyone, and welcome to the EOG Resources Second Quarter 2011 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing second 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. 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 estimates on this conference call and webcast, including those for the Eagle Ford, 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 and Investor Relations page of our website. With me this morning are Bill Thomas, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; 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 third quarter and updated full year guidance in yesterday's press release. I'll now review our second quarter net income and cash flow, followed by operational highlights. In addition to our typical play results, I'm going to also address several hot-button topics, such as weather-related downtime, logistical issues and our plan to deal with the wide differential in crude oil prices between benchmark WTI and LLS. Tim Driggers will provide some financial details, and then I'll provide macro and hedging comments along…

Good morning. Capitalized interest for the quarter was $14.8 million. For the second quarter 2011, total cash exploration and development expenditures were $1.64 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $180 million. At second quarter end 2011, total debt outstanding was $5.2 billion, and the debt-to-total-capitalization ratio was 30%. At June 30, we have $1.6 billion of cash on hand, giving us non-GAAP net debt of $3.6 billion or net-debt-to-total-capital ratio of 23%. On a GAAP reporting basis, the effective tax rate for the second quarter was 46%, and the deferred tax ratio was 71%. Yesterday, we included a guidance table with the earnings press release for the third quarter and updated full year 2011. For the third quarter, the effective tax range is 35% to 50%. For the full year 2011, the effective tax range is 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the third quarter and for the full year. For each $1 per barrel change in wellhead crude oil and condensate price, combined with the related change in NGL price, the sensitivity is approximately $24 million for net income and $36 million for operating cash flow. EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas prices is approximately $15 million for net income and $23 million for operating cash flow, excluding the impact of swaptions. Now I'll turn it back to Mark to discuss hedging and provide his concluding remarks.

Thanks, Tim. Now I'll discuss our views regarding macro and hedging. Regarding crude oil, we still like both the short- and long-term supply demand fundamentals, although guessing which way short-term prices will move is obviously a speculative call. We currently are 26% hedged August through December of this year, at a $97.02 price. And for 2012, we're approximately 7% hedged at a $106.37 price. We continued to have a 1- to 3-year cautionary view regarding North American gas prices, but believe 2014 and later markets will balance as gas-powered electricity demand increases. For this reason, we have no interest in growing 2011 North American gas volumes at current price levels. Our hedges are consistent with our macro view. The North American natural gas, we're approximately 50% hedged at a $4.90 price for September through December of this year. Additionally, we've sold options at a $4.73 price net of exercise. It would mean we're 88% hedged through year-end. For 2012, we're approximately 39% hedged at a $5.44 price. With options net of exercise, it will increase to a 70% hedged level at a $5.44 price. Now let me summarize. In my opinion, there are 6 important points to take away from this call. First, our reinvestment RORs are very strong. I think they're the best in the industry, led by the Eagle Ford. This is driving our EPS, EBITDA and cash flow per share growth. Second, we believe our unit cost containment this year is excellent, considering the inflationary environment. Third, we're the leading oil producer in the 2 hottest and highest ROR domestic oil plays, the Bakken and Eagle Ford. No one our size is growing domestic oil volumes comparably to EOG. All of our plays are onshore, and all of the oil is sweet and high quality. This quality crude is in demand by refineries, and we'll be able to access LLS prices early in 2012. Fourth, we're not interested in growing North American gas volumes at current prices, unlike most other companies. Fifth, we're accomplishing all this while maintaining low debt. And sixth, I'll be 65 years old next month, and it's appropriate that investors may want to know my plans. I plan to be in the current job for at least the next 18 months, and when I do retire, my successor will be a long-tenured EOG employee, who has the EOG DNA. Across our 10 operating divisions in North America, the average tenure of our general managers is 17 years. Here in Houston, Bill Thomas and Gary Thomas, Senior Executive Vice Presidents of Exploration and Operations have a combined 65 years at EOG. As with any public company, we have succession planning discussions with our board, and when appropriate, we'll announce when decisions have been made. Thanks for listening. And now, we'll go to Q&A.

[Operator Instructions] Our first question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Just in the Niobrara, can you provide us with the resource estimate update on the 160,000 net acres that you think are de-risk at this point?

Yes. We haven't really come out with the resource estimate yet on there. I mean, it's no secret that the Niobrara has proven to be, I'd say, one of the more complex horizontal oil plays that both we and the industry have dealt with. I'm sure you're aware there's been mixed results from various companies in the Niobrara. I'm pleased to say EOG probably has the best results in Niobrara than any company. But we're still in kind of an understanding and evaluation phase of it as opposed to -- so we really don't want to give a number at this point in time because there's pretty wide range. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Well, maybe just on the Hereford Ranch area, even if the not total resource, what are you seeing sort of at the average EUR per well? Or just some context on that.

Yes, Brian, I'd say the averages is probably in the 200, 225 barrels of oil equivalent range. The good thing we're seeing on these wells is that many of them -- they don't come in at really extremely high IPs. They'll come in at, say, 300 or 400 barrels per day. But after a year or so, they're still making 200 barrels a day. So the decline rates are really low, and that's very encouraging to us. We also had a lot of encouragement on our step-out drilling, as Mark's indicated in his comments and in our press release. And so, just overall, we're real positive in what's going on, and I really think it's going to be a significant play for EOG. But again, we want to have a little bit more time to drill some more wells and to evaluate the production before we come out with a reserve potential number.

Our next question comes from the line of Brian Singer with Goldman Sachs.

First on the Bakken and the Eagle Ford, can you talk to the costs associated with railing that to Louisiana, i.e. how should we think about the combination of quality and transport differential? And then can you also maybe add some color on where your current rates are relative to the second quarter average, whether we see a step up?

Yes. In terms of when you say current rates, you talk about oil production rates or...

Oil production rates, that's right, yes.

Yes. What we're programming this year for the Bakken is not a particularly strong step-up in oil production rates in the second half of the year compared to the first half. Where the growth is going to come in oil production rates is primarily from the Eagle Ford and secondarily from 3 different areas, really. The biggest secondary area will be the Combo play, and then also some contributions from the plays in the Permian Basin, and Mid-Continent. In terms of the rail cost, we haven't disclosed the cost or incremental cost to rail it from Cushing to St. James, Louisiana, and because it's possible we may be conducting third-party business there. And I don't want to give any proprietary information away, but what I can say is, relative to the current price value differential between LLS and WTI, it's totally obvious that we would, if those differentials exist next year, we'll be rail coloring every possible barrel we can to St. James as opposed to Cushing.

And then as a follow-up, going back to the Niobrara, can you talk a little bit as to why you think you're seeing the flatter declines and flatter IPs there? And in the past, I think you've highlighted that unique frac technique, though I think you mentioned in your comments that you needed to optimize fracs further, and if you'd add some color there.

Brian, I guess, early on, with some of the wells that came on with high IPs, we were thinking this was really more of an open fracture play. But as time goes along and we see more production from the wells, we're realizing that we're getting some contribution from the kind of system profitability, which would be a kind of a combination of maybe some new, some micro fracture system and the matrix firm. The wells wouldn't be so low decline. So that's what gives us encouragement, and it does pay. As you don't have open fracture systems, you really need to stimulate a lot more, and so it's really important for us to continue to learn and to refine our completion techniques to make this successful. And we don't have to get a low cost down on the play because the IPs are not that high. So we've got some work to do, but we certainly see a really good encouragement from the results so far.

And Brian, let me just give a little more color, which may be helpful to people on the call. If you look at what's going on with the Niobrara, I'd say the play is kind of a liquids-rich play that most similar to it in one respect was the Barnett Combo and that the reason we basically own the Barnett Combo play in that overwhelmingly dominant acreage over there is because that play was very technically tough to turn into good economics. And so hence, everybody else shied away from it. And it took us several years to turn that into the kind of play we wanted to, and right now, we're really accruing the benefits from the Combo play, which is giving us extremely strong economics. The Niobrara is kind of like that in that it's not a slamdunk. The Eagle Ford and the Bakken were slamdunks. We came out of there in the first inning and hit homeruns, and those were just easier rocks to deal with. So some of these plays are ones that, because the rock quality is superior, you can knock the ball out of the park right in the first inning, and some of them takes you 'til the fifth inning or so before you knock the ball out of the park. And right now, with the Niobrara, we're probably in the third inning or so on that one.

Our next question comes from the line of Leo Mariani with RBC Capital Markets.

Just wondered if you could kind of comment on what you're seeing on the Eagle Ford in terms of recovery factors. I think you mentioned 4%, Mark, I think you had previously had a range of maybe somewhere around 3% to 4% roughly a year ago. I just wanted to get a sense of what you thought was responsible for some of the uplift and maybe sort of any guess as to kind of where you think this number might migrate to over time if you think there's going to be some upside there.

Yes, I'd say our view is that there will be upward pressure on our $900 million of net after royalty reserve estimate there. Generally, we have been -- that estimate was based on a 130-acre spacing, which in rough terms translates to maybe a 1,200-foot to 1,500-foot between lateral wells. And we're now in the process that we have 2 to 3 months production history from wells spaced more closely, and we're drilling a lot of the wells that are currently being drilled or on this more closed spacing. And the initial reservoir simulation results, actual production results are encouraging, but as usual, we're pretty cautious in giving out estimates. So we could come out with some flashy number right now, but we just wanted to get more well results than the 3 wells that we have at down-spaced conditions and watch production for a while before we give you any additional numbers on the Eagle Ford reserves.

Got you, okay. I guess just jumping over to the Wolfcamp play. I think you guys are seeing favorably higher production rates rather than sort of your last round of updates in the well that, I guess, did just over 1,000 BOE per day when you throw in the gas. Just wanted to get a sense to what's happening there, if you guys are continuing to experiment with different frac techniques. I know you mentioned longer laterals on that particular well. What do you think's driving sort of the better production there?

Leo, there's kind of several things going on. I think, certainly the longer laterals is making a big contribution to the better wells. We've also recently continued to tweak our completion techniques, and we now have, I think, in the last call, we had 1 well. We now have 7 wells that we completed with the new frac technique. And these 7 wells are averaging over the first 30 to 60 days about 15% to 20% better production than the old kind of completion techniques. So we don't, haven't upgraded our EURs yet. We are watching more a little bit longer. But that's also very, very, very encouraging. We've also drilled a number of step-up wells to prove up additional acreage. And so, we're very encouraged about this, looking at plays. It's moving along very nicely. We're getting our costs down. We're proven up additional acreage, and then we're improving those results from the wells that we're drilling. So it's all doing really well.

And our next question comes from the line of Scott Wilmoth with Simmons & Company. Scott Wilmoth - Simmons & Company International: Guy, you mentioned the Wisconsin sand mine coming online in 4Q, could provide an upstand for most of your resource plays. You guys quantified the impact in the Eagle Ford. What could that mean to cost savings across your portfolio or maybe in terms of total CapEx for next year?

If we use this sand, and we have our dedicated frac fleets on maybe [indiscernible] most of our wells there in the Eagle Ford. We already have that going in the Barnett. We're going to use this sand also in Pittsburgh, some also in West Texas. We could probably look in its savings around $400 million, just on the sand part. Then we have the benefit of the dedicated frac fleets, and that improved efficiency there. We have these contracted to similar to what we have, drilling rates contracted to us, just a day work basis. Scott Wilmoth - Simmons & Company International: And then when I think about rig activity in the Eagle Ford currently at 22 rigs, can you talk about initial plans you are running into 2012 and what your future activity level needs to be to hold your acreage in the future?

Yes. We, right now, we're planning on ramping up our activity in the Eagle Ford. And that's obviously going to be function to some degree of oil prices. So we're going to drill 250 wells this year in the Eagle Ford, and as a minimum, we'll drill 250 wells next year there. And in terms of some of the other areas there, we'll just being deciding what is the cash flow that we're going to generate next year and then try to balance it here. And obviously, this is -- we made -- depending on what oil prices do is a big function there.

And our next question comes from the line of David Tameron with Wells Fargo.

Mark, can you -- I think you might have mentioned, but I missed it. Can you talk about what the recovery rates are right now in Eagle Ford or what do you think the recovery rates are?

Yes, about 4%, David.

Okay, 4%, and it does -- you said the additional downspacing, what do you think that would take you to adjust that, if that would work for tighter spacing?

We haven't said. Yes, all we're saying is there, if the downspacing works, the recovery factor will likely be higher than 4%, but no quantification on how much higher.

Okay, okay. And then on the M&A, on the divestiture front, the $1.6 billion, additional $600 million you've said are in core plays. Did you characterize gas versus oil or kind of what's the midstream? Is it EMP appropriate? Can you give us a little more color there?

As far as the producing properties that we're selling, all of that is gas properties. Most of it is properties that we've had for some time, like East Texas, and we're selling scattered properties in the Mid-Continent, Gulf of Mexico properties offshore. And that's approximately half of our overall dispositions, and the balance of that is leasehold facilities.

Our next question comes from the line of Irene Hass with Wunderlich Securities.

This is my question. It seems like you guys have got these resource plays down to a sign, specifically in Midland basin, the horizontal Wolfcamp play. What do you think is the optimal link? I noticed that you still have some EUR up there on your presentation. Could there be upside to it? I'm just kind of wondering how much it's cost to drill and complete this play particular? Are you going for multiple benches? Are you focused on bench a, b or c? And that's all I have for you today.

Yes, Irene, we've been drilling laterals anywhere from 6,000 to 9,000 feet. And a link to a lateral depends on a larger percentage of geology and the lease parameters, and things like that. Of course, we're drilling as long as we can to make better wells generally to get higher rates of return on that. We are testing multiple spacing patterns. We're drilling some wells on 990-foot spacing between laterals and some on 660-foot spacing, and we are, we primarily only tested the middle Wolfcamp. It's got 3 different pays over about 1,000 feet of gross intervals, so there's a lot of oil and gas in place. And there's 3 potential pay zones. We've primarily been testing the middle pay. Well, we do have plans to test the upper pay. And so there's a lot of work to be done. There's enormous amount of potential, and it's going really well. The well costs are running right now, about $5.4 million a well, and they're steadily going down. Our group in West Texas are doing a great job of getting the cost down.

Our next question comes from the line of John Herrlin with Societe Generale.

2 quick ones. With Argentina, you said 2012 drillings. What are you going to do for things like frac equipment? It's not a country that's well known for having large fleets.

Yes, I mean, there is a small amount of frac equipment in-country right now, and then the major service companies are in the process of shifting additional frac equipment down there. And for the first couple of wells, it's going to be kind of one-off deals that we'll have to schedule months and months in advance to get the fracs done. But our logic is, if this shale turns out to be something that is commercial and productive, that you'll see them, particularly the major service companies, just move equipment in there in the 2013 through 2015 timeframe. So it's -- we're pretty optimistic about the quality of that shale. We charge our people with -- the only way we go outside North America is if we could find the shale, an oil shale that we thought looked superior to Eagle Ford, and we believe we found one there. So time will tell.

So it wasn't the beef?

No, it wasn't the beef, John.

Okay. With the Wolfcamp, how optimistic should we be? It's pretty thick interval, shale interval. How excited are you about it? Or can you put it in context of you other plays?

Yes. In relative terms, we're pretty excited about the Wolfcamp. That one, we think that we have a very good chance of making consistently good wells there. So on a scale whereby we kind of said in this call that the Mid-Continent Marmaton was going to be a contributory play, and we said the Niobrara was a contributory play and maybe we could get it someday to be more than a contributory play, I would say that Wolfcamp's got a chance to be a kind of a game-breaking play for us in the Permian basin as opposed to just a contributory play.

Our next question comes from the line of Bob Brackett with Sanford Bernstein. Bob Brackett - Sanford C. Bernstein & Co., Inc.: If we think about crude by rail, do you worry that some of your competitors will follow what you've done and get to a point where the rail system can no longer support that export capacity? And what do you think that limit of export capacity could be?

Yes, we're not -- I mean, the limitation right now, Bob, is not the rail system. It's tanker cars. That's where the real shortage is, it's tanker cars and external link capacity in Louisiana. Right now, we investigated, for example, a greenfield rail car terminal in Louisiana. The problem is the time to get the permits, the time to construct the greenfield plant. You're looking at minimum of 12 months from start time, probably more like 18 months. So what we've done is we've teamed up with a company whose got an existing terminal system there, a company called NuStar, and all we're going to do is augment that with building a rail car facility. The issue is everyone would like to get their crude there, but right now, the issues are weaker rail car crude there and there are some rail terminals in Louisiana except that they will capture those along the terminals, capture all the economic rent of that high LLS-WTI differential. So there's no benefit to producers to go through those terminals. So that's why we're going essentially through our own system there where we can capture that economic rent. I'll also say that we're quoting the nameplate capacity at 70,000 barrels a day, but we can very readily upscale that to 140,000 barrels a day without a whole lot of incremental investment. So the issue there is we don't think there's going to be a lot of people who are able to move this stuff by rail car just because the barrier to entry is 12 to 18 months of greenfield facility. So we think we will be advantaged in 2012 and the first half of 2013 relative to pretty much any other producer in ability to move crude to get the LLS price. So and on a timing issue, I mean, you're aware, as is most people, that the real question is, when will there will be an additional pipeline system out of Cushing to the Gulf Coast? And every time I look, it looks like that's been delayed or slowed down a bit more. And so it looks like to me that, at least through 2012 and by the early 2013, there's going to be some kind of a differential, pretty high differential between Cushing and LLS.

Our next question comes from the line of Robert Morris with Citi.

In the Eagle Ford, what are your well costs running currently?

They're running at about $6 million, 8 drill wells.

Okay. Things last quarter. So with the sand mine or sand source in the quarter reducing well cost by $1 million. You've also noted your budget increase is still pretty persistent service cost inflation. So to what extent will that bathing on the sand be offset by inflation and other components here? And what do you expect the average well cost in Eagle Ford to be next year?

We would say that the average well cost next year would probably be less than somewhere in the $5 million to $5.5 million next year. We are seeing cost creep there that just because it's such an active area, both there and the Bakken, that's where we've seen the increased cost to maybe somewhere 8% and 10% for 2011 above 2010. But there's more equipment that's being brought into the Eagle Ford, so I think yes, we'll see that subside.

Okay, Bob, one way to look at it is we kind of quoted some economics and quoted a well cost to $6 million. We are seeing upward pressure on that currently, and we quoted about $1 million of savings for all this frac stuff when we get in place in the Eagle Ford. But probably now, there'll be $1 million savings, but that'll be offset by maybe $0.25 million price increase just for this cost pressure. So $5.25 million next year may be a reasonable cost estimate. You'll remember we quoted knockout economics, it's $6 million cost. So we'll have these reduced costs but, I believe, will be absolute best reinvestment rate of returns of any play in North America. So we feel pretty good about that.

Good. On the service cost side, obviously everybody is pretty have pretty good margins of returns in these oil plays. When do you think some of this service cost inflation will begin to level out here?

We're seeing it level out. Last year, we were seeing, for instance, stimulation costs were up 30% to 50%. And this year, we've got areas where it's flat, and in areas like the Rockies, I mentioned again, it's up 15% to 20%. But Mid-Continent's up only about 5%. So we're seeing some of that flattening with the additional equipment that's being constructed and put in place.

Our next question comes from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co.: Along the same lines, when -- how long are your typical drilling or completion contracts for? What I'm trying to get to is oil -- before oil prices contract or stay lower, how long before you kind of get some of those inflation numbers back to you before you deal?

Yes, I mean, that's a good question. If you take our overall drilling rigs, we're running roughly 70, 72 rigs. We've currently got about half of them contracted long-term. Long-term means generally 1 year or 2 years, maybe 3 years at the most. And half are just on contracted just well by well. And the same on kind of our frac commitments. We've got these dedicated pumping fleets, and for our total frac requirements across the company, about 50% of those requirements are covered by these kind of long-term agreements. So in the scenario where you just had an utter collapse in both oil and gas prices, and everybody had to pull in their horns and slow down activity. In that frac theory, we could reduce our activity by 50% without incurring any contracts that we really would have to negotiate around. Rehan Rashid - FBR Capital Markets & Co.: Okay, and the completion contract terms are the same, 1 to 3 years, right?

Yes. Rehan Rashid - FBR Capital Markets & Co.: Okay, okay. A quick follow-up on maybe a little bit on the geology on the Eagle Ford. I don't -- joined late so I apologize if you've mentioned this already. The Eagle Ford well performance holding better than modeled, any kind of color around kind of why that could be happening?

Well, I'm not sure I'd say it's better than modeled. It's the same kind of we would describe as similar reserves that we've been talking about for the last 6 months in the Eagle Ford, which is nominally 430 to 460 Mboe net after royalty per well, but the consistency just is what continues to amaze me. The press release, we quoted 16 wells. That's -- we could've listed a whole lot more than 16 wells. So I'm just amazed that we haven't frankly drilled any real stinkers. We've got all these rigs around and drilling all these wells, and a bad well is the one that starts out at 700 barrels of oil a day, which is really a good well. So the point to make is we haven't seen any inconsistency in the Eagle Ford, and the downspacing is -- what we're really focusing on now is how densely can or should we drill these wells to maximize the NPV of this asset, given that right now, we're just slating 4% overall oil recovery. What you're going to see in all these source and our oil plays, whether it's the Bakken, the Wolfcamp so on and so forth, is Phase 2 of development of all of these plays is going to focus on improving the recovery factor. And if you go back to the natural gas side, a lot of you will remember that we quoted it initially in the Barnett Shale in Johnson County, a recovery factor that was turned out to be much lower than what we're currently achieving. We're, right now, we're achieving recovery factors in the Barnett Shale of roughly about 40% or so, I think, is our number. Now we never get to 40% oil recovery factor in these plays, but we really think what you people, as analysts, should be focusing on is who's the industry leader in improving recovery factors after these oil shales have been found and initial development has started? And just the EOG was the industry leader in finding most of these oil shale plays in North America. We believe we'll be the industry leader in attacking the improved recovery portion of it.

And ladies and gentlemen, this does conclude today's question-and-answer session. At this time, I'd like to turn the conference back over to Mr. Papa for any additional or closing remarks.

Yes, thanks for listening. I've just got 2 additional comments. If you kind of listened to the drift of this call, what you can take away from it is, essentially, every one of our horizontal oil plays, we have upbeat news that we shared with you this quarter. And that's pretty rare. And then the second point, I'll reiterate it again because I'm really just befuddled why anybody in the industry pays the slightest attention to natural gas growth in North America is beyond me. And I continue to see particularly sell-side writeups that say, "This company is growing at this rate." In my mind, it doesn't matter if you're growing at that rate if your primary driver of your growth is natural gas, which is barely profitable at best. So I'd sure like people to focus more on the parameters we quoted, which are the EPS, EBITDA, cash flow growth and rates of growth of those. And I think you'll view EOG as the standout company in those parameters. Thank you very much, and that concludes my comments.

Ladies and gentlemen, this does conclude today's conference. We thank you for your participation.