Good day, everyone and welcome to the EOG Resources First 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 first 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 that reference as a cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page at our website. With me this morning are Loren Leiker, Senior EVP Exploration; Gary Thomas, Senior EVP Operations; Bill Thomas, Senior EVP Exploitation; 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 second quarter and full year guidance in yesterday's press release. I'll now review our first quarter net income and cash flow, followed by our operational highlights. Tim Driggers will then provide some financial details, then I'll provide some macro and hedging comments, along with concluding remarks. As outlined in our press release, for the first quarter, EOG reported net income of $134 million or $0.52 per share. For investors who follow the practice of industry…

Good morning. Capitalized interest for the quarter was $15.6 million. For the first quarter 2011, total cash exploration and development expenditures were $1.58 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment expenditures were $160 million. At first quarter end 2011, total debt outstanding was $5.2 billion and the debt to total capitalization ratio was 31%. At March 31, we had $1.7 billion of cash on hand, giving us non-GAAP net debt of $3.5 billion or net debt to total cap ratio of 23%. On a GAAP reporting basis, the effective tax rate for the first quarter was 41% and the deferred tax ratio was 34%. Yesterday, we included a guidance table with the earnings press release for second quarter and updated full year of 2011. For the second quarter, the effective tax range is 35% to 50%. For the full year of 2011, the effective tax range is 35% to 45%. We've also provided an estimated range of a dollar amount of current taxes that we expect to record during the second 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 $25 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 $16 million for net income and $23 million for operating cash flow, excluding any impacts from 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 oil prices will move is a speculative call. We're currently 27% hedged June through December of this year at a $97 price. And for 2012, we're approximately 6% hedged at a $107 price. We continue to have a 1:3 cautionary view regarding North American natural gas prices but believe in the 2014-plus time period, natural gas markets will balance as gas power generation demand increases. Our hedges are consistent with our macro view. We're approximately 48% hedged at a $4.90 price for June through December this year. Additionally, we sold options at a $4.73 price that if exercised, would mean we're 86% hedged through year end. For 2012, we're approximately 38% hedged at a $5.44 price, with options that if exercised, would increase to a 69% hedge 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 shift from a natural gas to a liquids company is essentially complete. At current prices, we'd expect approximately 70% of our North American revenue to emanate from crude oil, condensate and natural gas liquids as opposed to 30% from natural gas. A large majority of the liquids are oil and not NGLs. Second, all of our oil plays are onshore North America, with the vast majority in the U.S. All of this oil is sweet, good quality and highly desired by refineries. Third, our reinvestment rates of return are very strong. I think they're the best in the industry, led by the Eagle Ford. Fourth, during my visits with shareholders, I'm often asked about industry capital allocation. We recently tabulated 2010 actual and 2011 projected North American gas production for all mid and large cap public independent E&Ps. EOG is practically the only company who's not growing North American gas volumes in this oversupplied market. This is truly amazing to me. Investors who focus on the efficacy of capital allocation, this should be a positive discriminator in EOG's favor. Fifth, for the first time, we've introduced our Powder River Basin acreage position, where we've already drilled 8 consecutive successful wells. And sixth, we are on track to execute our 2011 capital expenditure program, while maintaining low net debt. Thanks for listening. And now, we'll go to Q&A.

[Operator Instructions] Our first question today comes from Scott Wilmoth, Simmons & Company. Scott Wilmoth - Simmons & Company International: Hey, guys, looking at your Eagle Ford rail facility, is that crude coming to the Gulf Coast and how did the transportation costs compare to trucking your crude?

Yes, the crude-by-rail that we're moving from the Eagle Ford is either -- it's currently either going into the Belmont area or into the Louisiana area. So it is currently getting a price that is a hybrid between WTI and LLS. And compared to the trucking opportunities, where you're not going to end up at those end markets, there's a very significant difference right now. The crude takeaway continues to be a very, very large problem in the Eagle Ford and as Eagle Ford production grows, it's going to just get worse, I believe, in terms of crude takeaway. And so this rail system that we hastily put in is probably going to turn out to be a very profitable item for us, similar to what we've done in the Bakken. Scott Wilmoth - Simmons & Company International: Okay, great. Then next on the Eagle Ford well spacing, I know at the Analyst Day, you guys were saying anywhere from 125 to 140. Can you give us an update on that? And then what percentage of your acreage have you tested on that spacing yet?

I guess, overall question, Scott, what percentage of our acreage have we tested? We'd say we've tested 100% of our acreage with wells. In terms of the spacing, we're still doing some work to determine what the optimum spacing is. The range of wells we'll need to drill is, we're still somewhere between 2,100 and maybe 2,800 wells, depending on how the spacing plays out. But that's probably going to be another couple of quarters before we can definitely say the spacing is X.

Our next question today will come from Leo Mariani, RBC.

Just a quick question on asset sales. Just trying to get a sense of a little bit more color on what these $387 million in asset sales were for the quarter, if there's any production associated with that? And then just any thoughts you guys might have on the $400 million in pending asset sales? What are those and what's sort of targeted here?

Yes, the $380 million of asset sales that we announced basically year-to-date in the second quarter were all long-live gas-producing properties, fairly mature producing properties. The biggest portion of that was some Cotton Valley production, Cotton Valley/Travis Peak production in the East Texas area. And we also sold some production in the New Mexico area. And if you kind of take a look at what we've produced in terms of gas production -- in U.S. gas production in the first quarter, I believe, it was 1,134 million cubic feet a day, and I think our midpoint for the second quarter is 1,096. Don't hold me to that number. I don't have it in front of me. But that kind of shows an approximate amount of what we've sold that we would expect in the second quarter. As to the remaining sales for the rest of the year, it's going to be a combination of some midstream assets, some just raw acreage and some additional producing properties. Good enough?

Yes, that was very good color there.

And, Leo, this is Maire. The year-to-date asset sales are $647 million, the $387 million was subsequent to the first quarter.

Right, got you. Okay. Just looking at your CapEx for the quarter, I guess, if I sort of add in kind of your total spending on some of the infrastructure as well, you guys are at about $1.72 billion. Just kind of on a run rate basis, if I were sort of to multiply that by 4, I think that gets you kind of between $6.8 billion and $6.9 billion for the year. Just curious as to whether or not you had disproportionately high infrastructure expenses in the first quarter? And any comments on cost creep that may have hit you and then kind of how you think CapEx plays out for the year?

Yes, we still believe the CapEx number midrange is roughly $6.5 billion for the full year. Part of what we'll see in the second half, particularly in the fourth quarter, is the impact to some of our self-sourced sand, particularly in the Eagle Ford division on our fracs. So we'd expect the well cost to go down. So the first quarter run rate isn't -- you can't really multiply that by 4 to get there. In terms of cost creep, we're seeing cost creep clearly in the service sector. And you've heard that from frankly everybody who's done earnings call. The biggest proportion of cost creep is the frac jobs as it was last year. So it's incumbent upon us to move to a self-sourced fracs, where I think we'll have a differential advantage relative to others in the industry and we are moving that way.

Next is Joe Allman with JPMorgan. Joseph Allman - JP Morgan Chase & Co: Mark, just a -- first question is, in terms of the new PRB play and also on the horizontal Niobrara Play, what are your current costs per well and where do you expect them to be when you get into development mode? And then, what's your best guess in terms of EURs per well now?

As far as the cost on the Powder River, the Turner, we started out there, it was right at $6 million per well. We're getting those now down to $5.5 million. So, yes, we would expect maybe to trim a little bit more off of those costs in a program mode. And in the Niobrara, we've got a couple of plays there within the Niobrara and more in the fracture play, our cost is around the $3.6 million per well. And then we get into the matrix play, it's in the $6 million. We would expect to be able to bring that down in the $5 million to $5.5 million range. Joseph Allman - JP Morgan Chase & Co: And then the EURs per well?

Yes, on the Turner itself, it's a little too soon to tell, we've given you a pie chart I think in the IR slide that went out last night that shows that it's about 45% liquids, 55% gas. But that's for the full reserve life of the well. And obviously, we've had to do an internal model to come up with those numbers. It's a higher liquids yield in the first couple of years, as in all these retrograde condensate type plays that you will come down over time. We're modeling a variety of EURs per well, but something in the 350 to 400 Mboe per well gross is our sort of walking around number right now.

Yes, and on the Niobrara, we just -- it's a bit too soon to give you an estimate on per well reserves on -- the Niobrara's clearly a more complicated play. And I'd say our degree of understanding is not yet sufficiently strong, where we feel comfortable giving either an overall reserve estimate on our captured acreage or a per well basis. That's probably going to have to wait until the end of the year.

And next, we'll hear from Brian Singer with Goldman Sachs.

Mark, as you highlighted in your comments, you are implying a big ramp up of oil production in the third and fourth quarters. That can certainly make sense if there's a weather impacted well of oil offline waiting to come back when those weather issues subside. Can you try to quantify the impacts that the weather issues in the Bakken and Waskada are having on your current production in terms of what maybe shut-in or the extent of the potential that would be in backlog by the end of the quarter?

Yes, a well of oil, that's a good way to characterize it there. Specifically, I'll give you a little color as to what's happened to us, particularly in the second quarter. The second quarter, we had flooding that affected us both in Waskada and in the Bakken, and this was just simply high water, where we couldn't have our pumpers access wells to physically maintain them. And then last weekend, we had in North Dakota a very severe late-season ice and high windstorm that snapped, literally, hundreds of thousands of power lines in the area of Williston, as well as our field area. And so we're pretty much without electricity. The power companies are trying to restore it, but obviously, they're giving first priority to things like the City of Williston, the hospitals, the schools, the residential. And then, we were kind of one of the later priorities to get it out into the field operations. And we don't really know how long the power outages are going to last. What's loaded into our estimate for the second quarter for oil estimate is we're assuming that we're going to get hit for the entire month of May, with some pretty significant power outages that are going to affect our North Dakota production. And I know if you just look at the ramp up that we'll need in the third and fourth quarter to get us to our full year target, it looks like a pretty steep ramp up. I don't want to give you specific quantifications but what I can tell you is that the third and fourth quarter, the ramp ups in terms of where they're going to come from, in the Bakken, you'll clearly going to have a snapback of production in the third and fourth quarter relative…

That's helpful. That's very helpful. And then secondly, you spoke last quarter regarding proprietary completion methods in the Niobrara. This quarter, you mentioned the new completion in the Marcellus. Are any of these related? Are you doing things differently in terms of completion techniques across plays that's having a material impact on economics, and can you put that into context in terms of what that could mean both for the 2 plays and for the ability to unlock any additional plays?

Yes, Brian, what we can say about it is, yes, you're right. We're using different completion techniques specifically designed for each play. And they vary widely from area to area. In the Marcellus, we've done one thing that's made tremendous differences in our wells and we're experimenting with new techniques in the Niobrara. And we had multiple play types in the Niobrara. And so each play type has a specific completion technique that's proprietary to EOG and we can't really talk much about the details but we work really hard gathering the data, analyzing the data and continue to refine our completion techniques for each play. And so they're very specific and it's working out really good for the company.

Brian, just to give a little more color on that. Obviously, there's been mixed results from the Niobrara as from various companies in the industry, whereas you heard fairly consistent results on EOG's results in the Niobrara. And then in the Wolfcamp, as I kind of read some of the earnings data that's come out here from other companies, you're getting kind of mixed results from other companies in the Wolfcamp. Whereas EOG, we're pretty well nailing it in the Wolfcamp. Every well is good and we think getting better. And I really think this goes back to EOG being first mover in these plays. I continue to believe that we are number one in technology in horizontal oil plays. That means finding them before everybody else and it means figuring out how to complete the wells and frac them most efficiently. And I just think the Wolfcamp example is just the latest in a long string of cases, where EOG wells are better than results from other companies.

Irene Haas, Wunderlich Securities has a question.

I just kind of wanted to drill down a little bit on the Niobrara. I mean, from what I hear is that there's a sorting out process and even you mentioned there are various sub-plays, and the cost for drilling a fracture well versus matrix well is quite a bit different. So just trying to get a sense as to number one, Mark, why do you feel optimistic as there's definitely different usage of adjective from before? And how can we look at this play? Is it going to be a core area, non-core? Is it going to be sort of patchy depending on a specific geology?

Well, I think it's too early to say, really, about the full extent of Niobrara. We're in the process of drilling multiple wells on -- step-out wells on our acreage. Then the Hereford Ranch, we've had very encouraging results, both in the fractured type play and in the matrix type play. And so that's what gives us the encouragement. And we see those characteristics really in much of our acreage. So we're in the process of gathering data. We have some very proprietary techniques to evaluate the particular play types and we've got some techniques that we're trying on the completion side that at least at this point in the development of the play, they're getting really positive results. So that's what gives us the encouragement as we go forward.

And would you -- it seems like the matrix plays are more expensive than the sort of fracture play. Is that correct? And if that's the case, would you favor the more fractured zones or is it too early to tell?

Well, the plays are different in that the matrix plays will have a higher resource recovery. And so you're able to drill more wells per acre, per section. But the economics really on both play types, we think, are going to be very strong. So we want to pursue, our acreage and our techniques, match all that together to maximize the reserve recovery of our acreage. So we feel positive and very encouraged about both types as we go forward.

Okay, great.

Biju Perincheril with Jefferies has our next question. Biju Perincheril - Jefferies & Company, Inc.: Going back to the Powder River Basin, can you talk about, if you have tested Niobrara there? Do you see potential for Niobrara?

Yes, Biju. We said we had 138,000 net acres in the Powder. And we're really mapping and working at 6 independent targets, 4 of those are sandstones including this Turner that we're doing most of our drilling on so far. The other 3 are in this upper Cretaceous, so-called halo plays that others have talked about, which we do think are prospective on a portion of our acreage. A couple of shale plays and one of those is in fact the Niobrara. We are intending to test the Niobrara either late this year, early next year, waiting on permits in a couple of areas. We certainly see prospect activity in the Niobrara, in that basin. Biju Perincheril - Jefferies & Company, Inc.: Okay, that's helpful. And then, the CapEx, the $1.58 billion, is that all-inclusive or just E&D excluding facilities?

That's inclusive. They're in that number. Actually, it's not inclusive. The facilities number there was 100 -- there was an additional $160 million per facility. Biju Perincheril - Jefferies & Company, Inc.: I'm sorry, that $160 million is additional?

Yes. Biju Perincheril - Jefferies & Company, Inc.: Okay, and so can you talk about once you bring in the self-sourced frac-ing solution, how much you expect to save and the timing of that?

On the self-sourced frac plays, we have quite a number of the frac fleet in place now. What we're doing is sourcing our own profit and generally, we're doing that through contract. We've got one sand mine in place and we're working to bring another online. And that will be near first of year 2012. Biju Perincheril - Jefferies & Company, Inc.: Okay. So if I sort of take this first quarter CapEx, it looks like the run rate is a little higher than the annual budget. Are you factoring in some savings or I mean, I would imagine the second half completion pace would have to pick up to meet the production numbers.

Just depends on which play. For example, in the Combo, we're really going to be running less rigs in the second half of the year than in the first half of the year. So all I can say on the CapEx is, we expect to achieve the number that we're showing in the guidance last night. Biju Perincheril - Jefferies & Company, Inc.: Okay. Then just one last question on the rail line in the Eagle Ford. Is 20,000 the max capacity or is there a plan to build that out further and is there a CapEx number there?

Yes, what we did in this rail line in Eagle Ford, it's a -- I don't want to use the word makeshift, but it's one we put together in a 30-day period. It's realizing the criticalness of the takeaway for crude oil in the Eagle Ford. We knew we couldn't basically take an 8- or 9-month period to get the rail line, crude-by-rail constructed as we did in North Dakota. So we just took our learnings from North Dakota and said what can we get together on a temporary basis that's going to cover us? And so it's not obvious to me that we'll end up with north of 20,000 barrels a day capacity by year end. And whether we decide to permanently run that rail line or not is something we'll have to sort out. As you remember, what we're trying to do is bridge the gap between today and mid-2012. Mid-2012 is when Enterprise is supposed to have that big-inch oil pipeline going down pretty much the heart of our acreage position. So we were just -- in other words, if we were to invest the capital right now and say, let's build a real true absolutely permanent crude-by-rail facility there, it's not certain that we'd be needing it post mid-2012. So the amount of capital we spent on this rail system is pretty de minimis, less than $10 million. So it's not a big capital consuming item. And it's really -- it should be viewed at least right now as an alternative to the trucking that gets us to a higher priced end user market, refinery market, if you will. Biju Perincheril - Jefferies & Company, Inc.: Got it. That's helpful. Appreciate it.

And hearing no response, we'll take our next question, Eric Hagen, Lazard Capital Markets.

Joe, got my questions. Sorry, I didn't get off the queue.

Next, we have John Herrlin, Societe Generale.

I got a couple of unrelated ones. Mark, in terms of your total well count right now or rig count rather, how much is horizontal in total that you're going to spud this year versus vertical?

We got currently 72 rigs since we've mentioned the last quarter. We'll be running probably at the average, 75 to 78 rigs. And of that, I would say 80% of that is going to be horizontal.

I might even say, 85% or 90%. It's pretty rare when we drill a vertical well, John.

Okay. That what I thought. I was just confirming. What about lateral lengths? Are you going longer or your frac stage is increasing? Have you changed your well designs?

We are going with longer laterals. For instance, in the Bakken, probably 75% or 80% of those wells are going to be the 1,280s or 10,000 foot laterals. We've drilled as long as 14,000-foot laterals there. And that's just kind of in the trend in most of our areas. And yes, when you go with the longer laterals, you have larger completions, additional stages and additional profit requirement.

Are your drilling time efficiencies offsetting some of the completion costs?

Yes, that's how we are in addition to us doing the self sourcing. And also us sourcing our own profit, et cetera, for our stimulation jobs. But for instance in the Haynesville, we reduced our days by about 20% and we've also continued to alter our stimulations there. So we've reduced our well costs there from the start of the year by somewhere between 15% and 18%.

Last one for me, you had some of your competitors talk about being more integrated. You just mentioned that you're mining your own sand as proppant. Does that work for you or it just as a business model doesn't make sense to you to be more integrated on the services side?

John, we're certainly not going to integrate ourselves to the tune of buying drilling rigs. That's not at all what we're considering. On the frac side, what we've been doing in the Barnett, both in the Barnett gas and the Combo areas for the last 3 or 4 years is we've been using our own mined sand and using what the third-party contract pumping companies, not necessarily the majors, and going that route as opposed to building our own frac pumps and manning our own frac pumps. So we have a business model that seems to work for us. It's worked in the Barnett for the past 4 years. And that's what we're really looking at doing most everywhere is not having the frac pumps owned by EOG but having a third party operate those, kind of contracting them, kind of like we contract drilling rigs. And have us provide the proppant to those particular pumps.

Well, I remember when you help start some of the companies, you talked about that a few years back. I was just wondering if you're going to increase the scale just given how you're operating?

Yes. Well, the scale in terms of the fracs, I mean -- the frac generally is roughly 50% of any of these resource play total well costs, 50%. And that's the piece we're really attacking to say we have to get control of our frac costs and not be dependent on other traditional service companies, if we're going to be the cost leader in this resource play business. And I think we're quite a bit ahead of most everybody else on where we're moving on that piece of the business.

Next is Joe Magner with Macquarie.

With the successful test of the northeastern fault block in the Eagle Ford, can you just remind us how that's captured in your 900 million barrel resource estimate?

Yes, Joe. As I kind of stated in my editorial comment there, I don't believe the 900 million barrels is even remotely captured in our current stock price. And so, if we were to say, wow, we have a new fault block and it increased our barrels from 900 to x, I'll consider doing that if and when I see the 900 million barrels that we already have reflected in the stock price. So don't look for us to make any adjustments to the 900 million barrels based on one well, one fault block or anything like that. But obviously, it's an area that we hadn't given any credit to and we found it on the 3D seismic and drilled it. And right now, this Eagle Ford's turning out to be one of those things that you almost have to pinch yourself and say this is too good to be true. 100% success rate across 120 miles is just phenomenal. So that's a good nonanswer to your question but that's the explanation I'll give you, Joe.

All right, I'll that for now. And then just over on the Niobrara, I wonder if you'd be willing to comment. There have been some challenges discussed by industry participants between completing wells in the fracs area and the matrix area. Just wondering if you'd be willing to comment on any progress you've made overcoming some of those challenges or coming up with solutions to address those?

I think we're just not quite sure of how much the 2 completion techniques are integrated and how they're competing. So we're just really gathering data on all of that. We're doing micro seismic and other techniques to determine and figure out how those plays work. So I'd say, we're just really too early to say much about that.

Joe, I mean, one thing we will offer up there is that there seem to be a couple of different play types, fracture versus matrix and it's really leading us to 2 distinctly different completion types depending on where we are in the Niobrara. So that's what made it a little bit harder and slower for us to really kind of get a handle on what kind of an oilfield we've really have captured here because it's -- we kind of have night and day completion techniques depending on which particular type of rock we're attacking with that particular well.

And are you able to understand the type of rock you're going to be completing based on seismic or some sort of mapping? How do you determine going in which completion technique you're going to be able to use on that oil?

Yes. I would just say right now, we think we have a proprietary edge on our understanding of the Niobrara, and we really don't want to give any more of it away on this call.

Okay, fair enough.

Hearing no response, we'll move to David Tameron, Wells Fargo.

A couple of questions. If I just look at the acreage positions, it looks like you sold down your Niobrara, you're at, I guess, 220 net now. Is that the right number? Then similar in the -- you sold-out 70,000 or so in the Eagle Ford, is that accurate?

No. In the Eagle Ford, that's not accurate. When we talk about the 520,000, that's how much is in the oil window. And then we've got roughly another 70,000 that's in either the wet gas or the dry gas window. So there's been no change in our aggregate Eagle Ford acreage position. In the Niobrara, yes, we have sold a bit of acreage there and that's really didn't want to but this is part of what we need to do to raise the $1 billion in property sales for this year.

Okay, fair enough. And then, if you think about the Wolfcamp, can you talk about, from our perspective, modeling, et cetera, what decline rates should we be thinking about? I know it's early, but what have you seen from these wells? Can you just give us some color there?

Yes, what we have so far in Wolfcamp were 6 wells with completions and 5 of those we have online long enough that we can do good 30-day averages with some confidence. And out of those 5, we actually talked about 4 of them on the IR slide, I believe, they averaged about 350 barrels of oil per day. One that didn't make the slide was an earlier shorter lateral that averaged about 190 barrels of oil per day in its first 30 days. Decline rates are kind of similar to what we're seeing in a lot of these oil plays. They're fairly steep in the first few months and then they tend to flatten out. We've given you in the past, I think, 270 Mboe or 1,000 barrels of oil equivalent, net after royalty per well is the number that we're working with right now. I'd say that based on these first 4 wells, we're pretty confident we can hit at least that. And in fact, they're a little bit above the curve at present. And we've also given you a breakdown that shows about 55% oil and 23% NGLs for a total of 78% liquids over the life of that and only 22% gas. So I would say in terms of decline curves, they're not dissimilar to our other oil plays.

David, I'll give a little more color in addition to what Loren said on the Wolfcamp. We're particularly enthused about the Wolfcamp. Our 120,000 acres and if you look back, I believe, it was a previous quarter's IR presentation. We quoted at kind of a direct IRR on that after-tax of roughly 25%, I believe. And if you just look at the numbers, you'd say, well, Wolfcamp is lower return play than the rest of our oil plays. What that 25% kind of represents is kind of stage one of optimization on the Wolfcamp. We think that we can easily beat down the cost on the Wolfcamp play, particularly with self-sourced sand in that particular play. And probably, get higher reserves. So, I guess, what we'd say, is we're in the first half inning of the Wolfcamp. If we're in the first inning of the Eagle Ford game, we're in the first half inning on the Wolfcamp and the data we see today tells us that we can turn this into a rate of return play that's probably similar to the Bakken or the Combo once we get into some kind of optimization mode on it. But for the rest of this year, what we're going to be doing in the Wolfcamp is exploring on -- so that we've got at least one well down and pretty much all the portions of our 120,000 acres. Right now, we're only kind of concentrating on, I believe, it's 47,000 of those acres. And so, we're going to be working on that and then working on what can we do with both well costs, length of laterals, optimization, the fracs. For example, the well I mentioned on the earnings call, the last well I mentioned there, we tried a completely different frac style than we've done in the first several fracs. And it looks we have a better result based on early, early times. So I would say we rank Wolfcamp pretty high on our priority list. But it's really, as far as a contributor to EOG volume growth and really getting into a drilling mode, that's going to be a 2012 event for us.

All right. A lot of good color. I appreciate it.

And our next question comes Ray Deacon from Pritchard Capital Partners.

All my questions have already been answered.

And next is David Wheeler, AllianceBernstein.

On the return to the Eagle Ford, you mentioned the returns are 95% to 140% at the strip but at a $6 million well cost. If well costs come down to $5 million, what does that do to the returns.

They're almost sinful to repeat. They are consistently north of 100% is what we can say. It makes a big difference to knock it from $6 million to $5 million. So that's why I'm so excited about the play, David, is we're looking at a play that at least on a direct basis is going to yield us north of 100% rate of return for $10 billion to $15 billion of investment. And if you think across every other single E&P company in the world, I can't think of one who's got this sort of investment opportunity, particularly in a, let's say, a relatively benign climate like Texas and the United States as opposed to some foreign country. And I really think that it's just -- people just haven't realized exactly what EOG has captured here. And again, I'm sorry, I'm blowing off on the editorial comment. But you led me into it there, when you said what happens when the well cost gets knocked down $1 million a well.

Sounds like it could be its own company there. You're self-sourcing and you mentioned the Wolfcamp. How much could well costs come down in your other plays, self-sourcing frac and you've talked a lot about how you're going to do it in the Eagle Ford. How many different plays can you self-source and how much could costs come down in those plays?

We're looking at all of our large resource plays where we've got pattern drilling in completion. Right now, we've got about 50% of our frac fleets that are self-sourced, they're dedicated or day work sort of fleet. And we'd probably rather not say right now. We're still putting our interim sand in place and then we've got the large mine that will be coming on late this year, first of the year. But it makes a significant impression on our cost. And when Mark mentions going from $6 million to $5 million, a big part of that is associated with the dedicated fleets in our own process.

I think the same range of numbers, roughly $1 million reduction is what we're envisioning for the Wolfcamp, for example. And right now, our priorities for the self-sourced sands are, first, the Eagle Ford level. First of all, all of our Barnett stuff is currently self-sourced. But then in terms of new fields, Eagle Ford is first priority, Wolfcamp is probably second priority and Marcellus probably third priority, as we would see it today. And these will get noted in beginning late this year and then hopefully, by mid-2012, we've got them all 3 of those areas working with the self-sourcing.

That's great. And can you remind us, it sounded like you didn't want to compare the trucking costs out of Eagle Ford versus of the new rail costs. But as we go from trucking/rail to ultimately pipeline, what's the approximate improvement in the costs per barrel?

Well, on the first part of that, we'll give you a general number. The rail versus the trucking current conditions will probably, in the Eagle Ford, we're probably gaining $4 to $5 a barrel versus trucking on there.

And that's cost and realizations combined?

Yes, that's costs and realizations combined because we're not getting full LLS price right now. We're having to share of that with some terminal operators, with the terminus of the line over there. Ultimately, the pipeline cost is going to be, I guess, a very pleasant relative to either the current rail or certainly the current trucking costs. And right now, the pipeline terminus is basically the Houston area. So we'll be getting in to the Houston ship channel, which oil prices today delivered at Houston ship channel are about midway between LLS and WTI on there. So at this juncture, the rail is, it's not obvious, the rail is going to be the long-term answer once that pipeline gets in. It looks like the pipeline will be the cheapest, David.

Okay, that's great.

And that does conclude our question-and-answer session. I will now turn the conference over to our host for any closing or additional remarks.

I have no further closing remarks. Thank you very much and we'll talk again next quarter.

Thank you very much. And that does conclude today's conference call. Thank you for your participation.