Good day, everyone, and welcome to the EOG Resources 2012 First Quarter Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I'd 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 2012 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 also 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 and Bakken, may include potential reserves or other 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 Investor Relations page of our website. With me this morning are Bill Thomas, President; Gary Thomas, COO; 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 2012 guidance in yesterday's press release. This morning, I'll discuss topics in the following order: I'll initially review our first quarter 2012 net income and discretionary cash flow, then I'll provide operational results and our 2012 business plan. Tim Driggers will then discuss financials and capital structure and I'll follow with our macro view and hedge position, and finish with concluding remarks. As outlined in the press release, for the first quarter 2012, EOG reported net income of…

Good morning. Capitalized interest for the quarter was $11.9 million. For the first quarter 2012, total cash, exploration and development expenditures were $1.9 billion excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $171 million. Total acquisitions for the quarter were $327,000. As mentioned, through May 1, proceeds from asset sales were $565 million. At the end of March 2012, total debt outstanding was $5.0 billion and the debt to total capitalization ratio was 28%. At March 31, we had $294 million of cash on hand, giving us non-GAAP net debt of $4.7 billion or net debt to total cap ratio of 27%. The effective tax rate for the first quarter was 38% and the deferred tax ratio was 56%. Yesterday, we included a guidance table with earnings press release for the second quarter and full year 2012. For the second quarter and full year, the effective tax rate is estimated to be 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. Regarding price sensitivities, with our current hedged position in 2012, for each $1 moved in crude oil prices, net income is impacted by $29 million and cash flow is impacted by $43 million. For each $0.10 move in natural gas prices, net income is impacted by $10 million and cash flow is impacted by $14 million. Now I'll turn it back to Mark.

Thanks, Tim. Now I'll provide some views regarding macro hedging and concluding remarks. Regarding oil, we still think the global supply-demand balance is tight and the fundamentals dictate an average $105 WTI price in 2012. The upside pressures are mainly geopolitical. The downside risk is a second global recession. And for that contingency, we've recently increased our crude oil hedge position. We don't subscribe to the theory that North American oil growth will create a global surplus. We think a lot of the advertised but untested new North American liquids plays are even more show than subsequence or our NGL plays. For the second half of 2012, we're approximately 24% hedged at $106.74 price. We continue to have a very cautious outlook regarding 2012 natural gas prices. And fortunately, as a percent of North American gas, we're 45% hedged at $5.44 for the second half of the year. We think the current rise in gas prices is a head fake but the storage overhang is just too massive. As you know, we've been a big North American gas bear the last several years, and we adjusted our gas investments accordingly in 2010, '11 and '12. Last year, our North American natural gas production declined 7%, and this year we project a 10% decline. This is likely the largest 2-year gas production decline of the peer group, so we're doing our part to balance the market. Please see the table that was included in our earnings press release for the details of our hedging contracts. Now let me summarize. In my opinion, there are 6 points to take away from this call. First, the game plan we articulated several years ago is working. In the first quarter, our year-over-year GAAP EPS increased 131%, non-GAAP EPS increased 72%, adjusted EBITDAX was up…

[Operator Instructions] We'll take our first question from Leo Mariani with RBC.

Just a quick question on CapEx. Looked like it is kind of trending a little bit higher in the first quarter on a run-rate basis, if I sort of multiply it by 4 for the year. Can you just talk through how CapEx may change sequentially in the following quarters to kind of keep you guys within your guidance?

Yes, that's been a focus for us. And as is mentioned earlier by Mark, yes, we started off the year. We've got to a peak of 76 rigs, and we did that because we had dropped back to 65 end of 2011, and we wanted to go ahead and get quite a number of these patterns drilled to bring on our production. We're reducing that to 65 rigs total. That's dropping rigs even out of the Eagle Ford as well as some of our gas well drilling. And with that running 65 rigs, we believe we'll be able to stay within our CapEx guidance.

Okay, great. And I guess in the Bakken, clearly you guys seem pretty excited about it. Just trying to get a sense of how much additional acreage has kind of come in to your development program. And additionally, how much acreage you think left to be tested in the Bakken in sort of the Lite area that's kind of yet to be determined?

Yes, Leo. It's not so much additional acreage. Pretty much all of the acreage we have, we think is acreage that's going to turn out to be productive. Out of all the things we described, and we kind of described 4 things there, the core area downspacing, the light area downspacing, actually it's 5 things. And then the Antelope area and the stuff out there in the state line area and then the Waterflood. I'd say that there's a -- 3 of those things are definitely working, core area downspacing, state line area, Antelope. The Bakken Lite area downspacing, we don't know for sure whether that's going to work, and then the Waterflood. But probably the biggest things that could make a difference there are the core area downspacing, which we already checked the box on that, and then the Waterflood. Those are the ones that are going to be the big difference. It's not so much are we going to be trying to prove up incremental acreage somewhere. It's really, really now, how best -- how dense a spacing can we drill on the acreage that we have, and then can we make a secondary recovery project work on that. So that's the way I'd look at it, but there's -- if we can get the -- particularly the Waterflood to work, then we've got, I think, a significant upgrade in the likely reserves that we’ve got captured and the likely production we'll be generating out of the Bakken for the next decade, really.

We'll take night our next question from Brian Singer with Goldman Sachs.

In the Eagle Ford, can you talk to, by year end, what areal extent you're planning to test at 40 acres versus what you've already tested at 65 to 90? And then beyond the downspacing, where do you think you are in optimizing completions in the Eagle Ford and whether you see room for further efficiencies?

Yes, I'll give it to Bill Thomas.

Brian, that's a good question. We have several patterns that we're currently drilling and frac-ing and just starting to test that are on the lower spacing, below 65 acres per well. So we're going to take that kind of flow because that's pushing it pretty hard, and we really would like to get a couple of those patterns fully tested and developed before we expand that to -- over large, large areas. So that'll just take a little bit of time and we'll just kind of see how that goes as we progress. On the frac side, as you know, industry-wide, we are very aggressive on trying new techniques and new styles of frac technology and using microseismic and trying to increase the amount of rock that we are connecting each one of these horizontal wells. And so we're making very, very substantial and steady progress in the Eagle Ford. As Mark mentioned earlier, we are being more aggressive in some of the areas on our frac styles. In terms of sand, we're using different kinds of frac fluids and even different kinds of sand sizes in alternating the pump rates, as well as alternating the way we distribute the frac along the laterals and we're making really good progress. I would say much of the increases in the IPs that you see on the wells are due to just better frac technology than we had a year ago. So we're just very pleased. We're also, as Mark mentioned, the rock quality in the Eagle Ford, it looks like we definitely captured the sweet spot. And so the quality of rock that we have to deal with and work with in the Eagle Ford is very, very, very good.

Great, great. And then as a follow up, is the takeaway from your comments on CapEx going forward that your call on development opportunities in your Big Four fields is now leading you to pursue more outside partner funding for opportunity for exploration outside those Big Four fields? And then can just remind us how you're thinking about balancing growth with CapEx and cash flow beyond 2012?

Yes. It's fair to say that if you looked at our Big Four fields, and this is our internal assessment in terms of the size of them relative to a year ago, and you know this, a year ago we were looking at Eagle Ford at 900 million barrels, now we're looking at it 1.6 billion. A year ago, we were looking at the Bakken. And based on this call, we're certainly more excited about the Bakken Three Forks than we were a year ago. And as we also said on the call, we continue to expand in the combo play, although nothing that's discernibly exciting, but just gradual expansion and the same in the Wolfcamp Leonard area. So they've all gotten bigger, some of them -- considerably bigger, some of them just a bit bigger. And then we continue to have an increasing list of greenfield new play ideas. And so we just decided that this 30% net debt to cap is a hard line for us. And we will just avail ourselves of some external financing on at least one selected oil play. And so I think on a go-forward basis, 2 things come out of -- that you ought to conclude. One is the 30% net debt to cap is not a number we take lightly. And the second thing is that the comment about not using external funding in the Big Four plays is just totally inflexible. We're not going to change that at all. But on some of our greenfield ideas for new plays, we may elect from time to time to consider using outside financing

We'll take our next question from Pearce Hammond with Simmons & Company International. Pearce W. Hammond - Simmons & Company International, Research Division: Mark, impressive liquids growth during the quarter. And as we ramp up the earnings season, a number of the producers have delivered some pretty stunning liquids growth. I was wondering if you can elaborate a little bit more on your comments at the end of your prepared remarks that you're not worried about there being a glut of oil developing here in the U.S. given this impressive oil growth in this tight oil [ph] revolution?

Yes. I mean, I'm not sure, as the quarter ends that I've seen that impressive of liquids growth for most of the companies. So I might disagree a little bit from your first comment there. I think there's a lot of intent to have impressive liquids growth, but I haven't seen the numbers put on the board. But there are some theories out there by some sell siders that there ultimately will be a huge plethora of liquids growth. But I just -- and there are a lot of liquids plays that are being talked about, but they're yet unproven liquids plays. And I would just say that our analysis is that we just don't think that there's going to be the growth out there that some people are projecting. And if you look at our analysis in what we put out there on our website last night, we're projecting, by 2015, about 1.5 million barrels a day of increase in total U.S. oil production due to this horizontal revolution, which is quite substantial. But we don't think that's going to be enough to change the global supply-demand picture. Pearce W. Hammond - Simmons & Company International, Research Division: And then as a follow-up to Leo's question on the CapEx and how we stay with the guidance for the full year, can you provide us with that roadmap? You say you're going down to 65 rigs from year end and that was starting at where? And then is the majority of that going to be gas rigs?

The ones we dropped were -- we dropped 4 there in the Eagle Ford, but the rest of them are principally gas or liquids-rich gas well drilling. Pearce W. Hammond - Simmons & Company International, Research Division: And then what was the starting point on that? Going from how many rigs down to 65.

We peaked at 76 and we're now dropping to 65.

We'll take our next question from Joseph Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Mark, how much of the 9% decline in North American natural gas year-over-year that you experienced in the first quarter, how much of that is natural declines and how much of that is asset sales?

We haven't worked that out exactly. I mean, it's probably fair to make an assumption, maybe half. Half is due to asset sales and half is just natural declines, Joe. It probably won't be too far off if you make that as an assumption. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. That's helpful, Mark. And then in the Parshall field, what were your previous assumptions about the recoveries you were getting, and then where can those recoveries go with the infill drilling?

Well, I mean, in the Parshall field, the latest model we've done, we keep on updating it. Previously, I'd quoted that our Bakken recovery factors in that area we're about 10%. But now the latest model we've done shows that the recovery factor is about 8%. And then it shows, with the downspacing, hopefully we can take that up to -- from 8% to in the range of about 12% or so, and then further boost it farther than that, if we're lucky enough to have the Waterflood work. I'm not going to quote you a number on the Waterflood. We'll give you that one if it actually works.

We'll take our next question from David Tameron with Wells Fargo.

Back to the gas comments. What do you think is going on in the Barnett as far as why those wells are holding up better? Is it just didn't have the -- can you just give us some color there?

Yes. I mean, what I meant to convey there is they're holding up just a little bit better than what we had projected on our decline curves. So there had been some talk out there that all these resource plays were going to fall on their face once you quit drilling. And the intent of my comment was to say this is the first time where we've had kind of 2 years without a lot of interruptions from a lot of new drilling wells. And the data basically shows that we have 2 years, that with no precipitous declines other than what we had projected, and actually, a little stronger well performance than what we've projected. So there were some profits of doom out there that said always all these resource plays we're going to -- overstated reserves, et cetera. And I just thought it'd be useful to you folks to hear some real work data.

All right. But, yes, obviously a lot of plays are seeing that so a lot of guys report more gas than they thought.

Yes, sad for the gas market.

Yes it’s not good. As a follow up, back to Eagle Ford, you said you're going to 21 rigs from 23 at year end…

Actually, 27 going to 23.

Okay. 27 going to 23. Is that just simply CapEx or is there -- I mean, why not, if the play's working as well you think and you're trying to test some new concepts, why not just keep running at that 27 given the return you're probably seeing there right now.

Yes. We just had a target to drill up 300 net wells this year. And what we're finding out is with our drilling efficiencies, we're -- it's taking us less time per well to drill. And so we’re able to drill the 300 net wells for the rest of the year just with 23 rigs. So that's kind of what drove us to release rigs.

We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

I wanted to jump back to the Eagle Ford. The well results that you discussed are obviously pretty impressive. And looking at your presentation on the website this morning, it looks like those wells are fairly consistently -- fairly close to the transition window, I guess, into the white gas area. I guess my question is how repeatable do you think those results are going to be across your acreage? And are you prepared to not chop your type curve or your expectation for the play generally in terms of near-term production outlook?

Yes, you're right, in that what we found is the wells that are nearer to the transition, closer to the rich gas area, generally have the better quality. And so when you blend them all together, the wells that are farther back from that you end up with that 450 Mboe per well. A lot of these wells that we’re quoting, of course, are our best wells. And so many of them are 800, 900 Mboe per well, kind of wells on there. So again, we're -- overall, it's kind of the average well it turns out to be. The surprising thing to me is that other people, all of which I'm sure are quoting their best wells to you. Have yet to quote 2,000, 3,000, 4,000 barrel a day wells. So there appears to be a big differential between the wells we're making and what other companies are making, which is still kind of surprising to me on there.

As a follow up, Mark, if I can use my follow up. So as you lower your rig count for this year in the Eagle Ford, are you -- how are you -- are you kind of high grading where you're focusing the near-term drilling program towards that sort of transition region. In other words, should we be looking at higher early production results, maybe transitioning to lower production over a longer period of time? In other words, your 2012 production guidance could actually have some upside risk? I'm just trying to understand how you're allocating the rigs in that play? And I'll leave it at that.

No, what's really driving us is more the acreage exploration than trying to high grade it there. We can cover all the acreage exploration with 300 wells this year, but that's what's driving us, so we're not in a perfect world for NPV optimization, you drill all your best wells in the early years. But it's not a case where we're targeting our best wells in the early years, and then saving all the weaker well later. It's really just -- we drilled some of the better wells and some of the less good wells driven by the acreage side. So you can't really project that the well quality will go down in later years because we cherry-pick the best wells.

I think about -- more about front end loading the better wells so that we actually end up with much shaft [ph]. As you say, faster NPV realization. Okay, that's very clear, Mark. I'll leave it there.

We'll take our next question from Arun Jayaram with Crédit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: Mark, last quarter you commented or gave some data on the Henkhaus unit where you're testing down the 65 acres in the Eagle Ford. And obviously, the results from the 4H well were very, very strong. I just wanted to see if you could give us a sense for the 5H and the 12H wells. How tightly spaced were those laterals relative to that unit?

Yes, they were basically all in the same spacing. The 5H and the 12H are a little bit shorter than the other wells, but their IPs and the way that they're responding for total lateral are very comparable to the other wells. And the surprising thing on that is, is that we have significant production from the other wells on the unit before we completed these wells. And so that's very, very, very encouraging to us. The matrix contribution on the Eagle Ford, I think, has been remarkable, and it's been a very big pleasant surprise for us. So things are going well. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. But in general, those are all in that 65 acre spacing in terms of width? Is that a fair comment?

Yes, that's correct. Yes. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. And my follow-up question. Mark, you talked about the offset wells in Bakken increasing in the core part of the field as you've gone down from 640 to 320s. What exactly is going on there? And can you comment, was that a positive surprise for you?

It was a surprise, yes. We didn't expect that. Our theory is that when we frac those wells originally, which would've been the 640-acre wells 4, 5 years ago that looking back, we probably didn't get as efficient of a stimulation as we might have liked and that we now are going to bigger fracs today than what we did back then, and that in the downspaced well, we gave a bigger frac and we probably stimulated some of that area even around the 640-acre original well. So that's kind of -- that's one theory that seems to make the most sense to me, that we would frac new rock around even the older well. So it's kind of an extra bonus, really, on there, which kind of cinches the case for the downspacing there, really. And the other thing it tells us is that clearly the 640-acre original spacing was too wide. So it makes it kind of a slam dunk case for the 320-acre spacing, and then it just opens the question about well is 320 still too wide? And should we investigate 160? So that'll be the next step we're look at too. On the spacing on both the Eagle Ford and the Bakken, clearly, what we did in retrospect is we started out with too wide of spacing and in both of them now, we're densifying the spacing, and we’ll densify it until we conclude okay, this is too dense of a spacing. And maybe in the Eagle Ford example maybe 65 acres is as dense as we want to go, maybe 40 acres is, we don't know. But I guess you live and you learn. The other way we could've done it is we could have gone to ultra-dense spacing to start, and then said this is too dense and then work the way to wider spacing, but we're doing it the other way. So we'll just see how it plays out, but we're concluded that the initial spacing was too wide, and we'll just work inwards until we conclude that now okay this is too close in terms of spacing.

And we'll take our next question from Ray Deacon with BBMC Capital. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: I was wondering, so I think is -- I think previously you were saying Bakken production will be in decline in 2012. Is that still the case or not?

I think previously what we said is Bakken production would be flat in 2012. And it's probably fair to say that in 2012, Bakken production will be flat or maybe we'd say maybe just very slightly up. But based on what we're seeing, I'd say that 2013 and forward, there's a pretty decent chance Bakken production will have a good chance to be on the incline. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. And would that be based on results of downspacing in Bakken Lite and Waterflooding or based on what you see today?

Probably just on what we see today, not even counting the Waterflooding results. The Waterflooding, all we're doing right now is a pilot. And we'll know something about that by the end of the year and then we'd have to go to a full-scale Waterflood. And so frankly, it would be 2014 before we really see production results from a full-scale waterflood. So that's still a couple years away.

We'll take our next question from Irene Haas with Wunderlich Securities.

Mark I just want to catch back up with one of your beginning comments. You said that a lot of your growth is really coming from oil and condensate. And so I want to ask, how do you feel about the natural gas liquid markets, specifically ethane? Are we kind of hitting a bottleneck or simply we have unusual amount of downtime during first quarter. In multiple basins, I wanted to get your take on the ethane market.

Yes. I mean, we've put some guidance in our 8-K there. For the first time, more of a gas than guidance as to -- as a function of crude, what our total NGL price expectations are. We don't guarantee the accuracy, but we decided we'd put some guidance in there anyway. Our read on the NGL market is that the second quarter will -- and specifically ethane. Second quarter will continue to be relatively weak. But the second -- and the reason first and second quarters were weak, are weak is that there were a lot of plant turnarounds, ethylene plant turnarounds. But beginning in the second half of the year, we expect those prices to strengthen in a relative sense, and that we're a little more bullish than a lot of people that ethane prices will remain decent, probably in the 40% to 50% range of crude oil long term. So right now, we're not writing off those prices and saying they're going to just degrade to nothingness. And that's based on the long term that the ethylene -- the cheapest place to make ethylene is probably going to be in the United States as opposed to anywhere else in the world. But second quarter, our expectations are pretty bearish. Check with me in 6 months and I might have a different story.

We'll take our next question from Monroe Helm with Barrow, Hanley. H. Monroe Helm - Barrow, Hanley, Mewhinney & Strauss, Inc.: Actually, my question had to do with the response that you were getting on the downspacing and you already answered that. So I'll leave it at that.

We'll take our next question from Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: A follow-up on that Bakken rejuvenation. Are you recovering frac fluid from the new wells in those old mature offset wells?

Yes, we're recovering frac fluid from the offset as well as the new well. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. So you've connected it up and you've kind of done a mini waterflood test inadvertent, Mike.

That's correct, yes. And the good thing about this is you're always seeing substantial increase in the offsets. And there were about 7 of those wells, and this production is holding up extremely well in those.

Some of our technical people that are optimistic about the Waterflood have a theory that the reason we've doubled the production in the older wells is that we've in fact done a mini Waterflood with the frac. So that's one theory anyway.

And at this time, due to time constraints, we're going to conclude the question-and-answer session. I'd like to turn the conference back over to Mr. Papa for any additional closing remarks.

No, I have no further remarks. We'll talk to you next quarter. Thank you for listening.

And that does conclude today's conference. Again, thank you for your participation today.