Good day, everyone, and welcome to the EOG Resources Second Quarter 2012 Earnings 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 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 2012 earnings and operational results. This conference call includes forward-looking statements. The risk 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 includes 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 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, Chief Operating Officer; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website last night, and we include third 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 second quarter 2012 net income and discretionary cash flow, then Bill, Thomas and I will provide operational results and our second half 2012 and preliminary 2013 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 our press release, for the second quarter 2012, EOG reported…

Thanks, Mark. Last quarter, we advised you that we were more optimistic about the Bakken and Three Forks as growth vehicles than in the past several years for 3 different reasons. I'll give you some updates regarding these reasons. First, 320-acre infill drilling in the Bakken Core continues to generate positive results. The press release shows several new infill wells. The reason we're so excited about EOG's core area down-spacing is that our 90,000 net acre core is the sweetest spot in the entire Bakken, and it's where 22 of the 30 best Bakken wells in the entire play have been drilled. So this is a rich hunting ground for down-spacing. With our Bakken acreage now held by production, we are shifting our focus to increasing the recovery factor with down-spacing and improved frac technology. Second, we continue to have great results in our Antelope Extension area, which is 25 miles southwest of the core area. Typical recent wells here are the Riverview 100-3031H and 04-3031H, which tested at rates of 1,834 barrels of oil per day and 1,863 barrels of oil per day plus rich gas from the Three Forks and Bakken, respectively. Third, the third growth area is our Stateline area, where we recently completed the Stateline 08-3328H in Eastern Montana at 1,260 barrels of oil per day. With confirmed success, we estimate 200 potential locations in this area. As you can see, we have plenty of room to run in the Bakken and Three Forks. Additionally, we continue our Bakken Core waterflood pilot project, and we expect to have preliminary results by year end. Shifting to our Permian Basin, Wolfcamp and Leonard horizontal plays, our results continue to be consistent with previous quarters. The recent Wolfcamp completions are the Munson #1001H, #1002H and #1003H and the University…

Thanks, Bill. Outside North America, we still expect our 100% working interest in East Irish Sea Conwy crude oil development project to start up in the second half of 2013. We recently installed the platform and expect to commence drilling in the first quarter 2013. In Argentina, our first horizontal Vaca Muerta oil well has been completed and is under evaluation. We hope to have some definitive results on next quarter's call. In Trinidad, recent gas takes have been higher than expected due to higher indigenous gas demand. We expect some methanol and ammonia plant maintenance downtime in the second half, and our full year guidance projects only slightly higher full year 2012 Trinidad gas production compared to 2011. There's nothing new to report on the Kitimat LNG project. I'll now address 2 other key EOG differentiators, crude-by-rail and sand plants. Our St. James, Louisiana crude-by-rail facility has been operational since mid-April, and the impact showed up in our overall second quarter U.S. crude oil realizations versus WTI. The terminal construction cost is already paid out. Now that the Eagle Ford oil pipeline is operational, we've moved a number of rail cars to the Bakken, and we're primarily using the crude-by-rail system to move our Bakken crude to Louisiana, capturing the current $20 differential between Clear Brook, Minnesota and St. James, Louisiana. During July, we're selling about 20 -- excuse me, about 50,000 barrels gross at St. James, and we expect this volume to increase to approximately 80,000 barrels of oil a day by year end as more tank cars become available. Our Wisconsin frac sand system is also working as planned. The first sand shipments began late last year and, in combination with our Fort Worth plant, is currently providing our frac sand needs for more than 700 wells…

Thanks, Mark. Capitalized interest for the quarter was $12.1 million. For the second 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 $145 million. Year-to-date, total cash exploration and development expenditures were $3.8 billion, excluding asset retirement obligations. Expenditures for gathering systems, processing plants and other property, plant and equipment were $316 million. Total acquisitions for the quarter were $108,000 and $435,000 for the first half. Through June 30, proceeds from asset sales were $1.1 billion and, as Mark mentioned, through the end of July proceeds were $1.2 billion. At the end of June 2012, total debt outstanding was $5.0 billion and the debt-to-total capitalization ratio was 27%. At June 30, we had $280 million of cash on hand, giving us non-GAAP net debt of $4.7 billion or net debt-to-total cap ratio of 26%. The effective tax rate for the second quarter was 39%, and the deferred tax ratio was 67%. Yesterday, we included a guidance table with our earnings press release for the third quarter and the full year 2012. For the third 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 third quarter and for the full year. Regarding price sensitivities, with our current hedge position for the second half of 2012, for each $1 move in crude oil prices, net income will be impacted by $14 million and cash flow will be impacted by $20.5 million. For each $0.10 move in natural gas prices, net income will be impacted by $4.3 million and cash flow will be impacted by $6.4 million. Now I'll turn it back to Mark.

Thanks, Tim. Now I'll provide our views regarding macro hedging and the concluding remarks. Regarding oil, we still think the global supply-demand balance is tight, and we expect prices to strengthen throughout the remainder of the year. Two recent concerns I've heard from oil bears involve horizontal shale oil. One concern is will the U.S. create enough shale oil to affect global supply. EOG's forecast is an increase in the U.S. of 2 million barrels of oil per day by 2015, which, we believe, will not impact a 90 million barrel of oil a day global market. We think there are only 3 consequential horizontal oil plays in North America: the Eagle Ford, Bakken and Permian, and that all other alleged oil plays are either inconsequential on a national scale or really NGL plays. A picture is worth a thousand words, and Slide 7 -- if you take a look at Slide 7 on our website, it makes this blindingly obvious that there's only 3 plays that are meaningful in terms of U.S. oil impact. The second concern relates to possible international horizontal oil shale plays and their potential impact on supply. My answer there is maybe it will happen, but it's not likely for another 10 years at least. Remember, it's been 10 years since horizontal drilling unlocked shale gas in the Barnett, and no one yet has found commercial shale gas outside North America. Also, the key to commercial shale oil or gas is the ability to drill thousands of wells at low per-well cost, and whether this can be done internationally is likely problematic. For August to December 2012, we're approximately 22% hedged at $106.69 price. We've recently begun to layer in 2013 hedges and currently have 16,000 barrels a day hedged at $98.12 for the first…

[Operator Instructions] We'll take our first question from Brian Lively from Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Mark, on your commentary about potentially doing a JV in one of the other non-4 big plays, I'm just thinking about it strategically in 2013. Are you saying that basically that, in combination with just no – essentially, no gas drilling is going to kind of fund that gap for next year and allow you to continue with the high liquids growth?

Well, we're just -- our 2013 plan is obviously not specific yet, and we'll furnish a much more detailed plan, as we do every year, on our year-end earnings call in February that'll have specific growth targets for both the liquids and gas. But the predicates of the plan are clearly that the amount of dry gas drilling we're going to do next year is going to be pretty close to nothing, only one rig, really, which is just going to be holding acreage primarily in Bradford County, in the Marcellus. And basically, we're going to attempt to hold to the 30% net debt. We'll consider selling some additional properties, and we're going to heavily fund the oil plays, and the NGL plays will be more -- we'll just see what happens to NGL prices. But the oil plays are going to get the vast majority of the funding. And the big plays there that are going to get the funding will be one, Eagle Ford and two, the Bakken because they're primarily oil. The Permian Basin, even though people think of it as an oil play, it's really a combo play, as, of course, is our Barnett Combo. So both the Wolfcamp and the Leonard have -- about 40% of that production is oil, and the rest of it is NGL. So what you can look for are those 2 plays, the Eagle Ford, first, Bakken, second, are going to get the lion's share of the money. And then we'll look at some plays other than our big 4 plays. And if it makes sense, we may bring in a JV partner depending on what our cash flow, what our property sales balance is. So all we wanted to do, really, Brian, is just signal to you that at this stage, the plan is clearly, there will be a further ramp down of dry gas drilling and there'll be a definite shift of capital even more heavily likely toward the Eagle Ford and toward the Bakken and at some additional plays which -- we may look at the oil or combo plays other than the big 4. We may look at bringing in some outside capital. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Mark, that's helpful. Just my follow-up question, and it sort of fits in that context, we saw a pretty attractive, at least in my view, valuation done on a JV in the Pearsall. It looked like that acreage overlapped on your position probably more so than anyone. Could you provide a little bit of an update in terms of what you're seeing in the Pearsall and what you're testing there?

Yes. We really -- I would just say that in relationship to the Eagle Ford acreage, we realize there are multiple zones that are potentially pay zones above and below the Eagle Ford, and it's not particularly likely that we would be splitting horizons, vertically splitting horizons in that area. That's not our first choice. So that particular area is not one that directionally, we're looking at carving out some other interval other than the Eagle Ford and a JV there. That's kind of a little bit messy in our opinion.

Moving on, we'll take our next question from Leo Mariani from RBC.

Obviously, you've detailed some very strong results here in the Eagle Ford. I realize that, that kind of represents your sort of best results in terms of what you guys have discussed. Just wanted to get some color on how the overall average results in the Eagle Ford, if you take into account all of the wells, has changed from earlier this year.

Yes. I mean, Leo, we haven't changed at this juncture from the average reserves per well, which we provided to people earlier, which is the 450 Mboe per well, net after royalty. Now obviously, some of these or most of these wells that start out at north of 2,500 barrels of oil per day are considerably better reserves than 450. But over the entire acreage position, we're still sticking to that number. Now obviously, we've made some improvements, and it's possible that, that number could go up with time. But as you know, we're pretty conservative. And as we've done with volume growth projections this year, we'd rather be on the conservative side. So all I can tell you is the numbers we provided you earlier that come out to the 1.6 billion barrels and the average reserves, 450 are still the numbers we prefer that you use. But hopefully, some of the comments we provided on the call would convey our enthusiasm that the Eagle Ford is a very unique rock in that the more time we spend with it, the more enthused we are about the recovery factors and the ultimate potential of that rock. But it's just going to take some time, some time for us, technically, to get our arms about that. But we are very enthusiastic about that asset, and that's why we have 0 interest in JV-ing that asset.

That's great color. That makes a lot of sense. I guess obviously, it's a little too early to discuss 2013, per your prepared comments here. But just hypothetically, if we're at kind of a $90-plus WTI environment next year and with gas drilling coming down and cash flow going up, I mean, there should be materially more cash available to fund the oil play. So should we certainly at least expect in that environment to have significantly more oil-directed drilling activity next year?

Yes. I really don't want to get into 2013. Yes, I mean, as a percentage of our total CapEx, more -- a higher percentage will be oil-directed. But beyond that, I don't want to get into any specifics until we really get to our February earnings call.

Moving on, we'll take our next question from Brian Singer with Goldman Sachs.

Following up on that last question, last couple questions there, when you look at the techniques on the frac-ing side that have really driven some of the improved well results that you're seeing in the East, what's the applicability that you may have or may not have as you move and shift activity more to the West? And is getting more wells completed in the West the main impediment or the main catalyst needed to take up that EUR, or are you seeing underperformance elsewhere?

I mean, the reason we're shifting a bit more of the rigs to the West is mainly just an acreage earning issue. We've got all this acreage to hold, and so we just have to -- we're driven a bit where we locate the rigs by our acreage earning calendar, and that's why we're -- and some of the well -- a higher percentage of the wells we drilled in the second half will be at a lower working interest than, generally, most the wells we drilled in the first half year are 100% working interest, and we won't have that benefit in the second half of the year. So that's why our overall production growth is going to be tempered. Total company oil production growth will be tempered a bit, as well as just a slowdown in our overall CapEx. In terms of the West, the wells in the West, as a rule, will not be quite as good as the wells in the East. They'll still be wildly economic. But it's -- on average, you're not going to be getting 4,000-barrel-a-day IP wells typically in the West as you're going to get in the East. So we're just -- we're not expecting those kind of well profiles out there, but we expect quite good wells, for sure. So we're just going to have to see. With our recent frac improvements, we expect to see better wells this pass in the West, and we've got a year or 2 going to West, so we'll see. And we've done some drilling in the West all this year, and we found some quite good wells out there. So all this is ground into the plan, Brian. So what we're trying to do is not let you guys on the sell side take our first half results and extrapolate them to the second half and say, "EOG's sandbagging, and their oil growth in the second half is going to be off the charts again." So that's my advertisement I hope I can get across to you guys.

Yes, I guess on the topic of quarter-on-quarter kind of noise, we can look and see the Eagle Ford number that you reported for June, up 26,000 Boe a day versus what you had in April. Now I guess we don't technically know or maybe you could help us with what the real average was during the quarter. But that type of growth should look like you're well on your way in Q3, but I know you always like to say there may be other factors that may be more one-off. But can you talk a little bit about the quarterly trajectory and whether you see any temporary -- beyond shifting your wells West, any other temporary hiccups to the pace of the Eagle Ford growth?

Yes. I'd just say the number of monster wells that we got in the second quarter that I bragged about, that was an extraordinarily high number of monster wells. We don't expect that we're going to see that in the third quarter. So to that degree, second quarter was maybe a little bit anomalous on there. So we're -- I'd say that there definitely is going to be a slowdown in the Eagle Ford growth, third quarter versus second quarter, because of the working interest issues and also because of the number of completions. I quoted the number of completions in the second half versus the – on there and number of rigs we're running. So as you noticed, our burn rate in the first half on CapEx was at $4.1 billion, and we're trying to limit ourselves, just from capital discipline, to spending $7.5 billion or $7.6 billion for the full year. So we are consciously slowing down our CapEx. And our biggest CapEx consumer is the Eagle Ford. And the analogy I would give you is right now, EOG is like a coin-operated machine. You put in a lot of coins, and we are an oil-producing behemoth with 100% efficiency. You put in less coins, we don't produce as much oil. But we have 0 inefficiencies, no exploration inefficiencies or anything like that. And we're going to be putting in less coins in the second half than we put in, in the first half, and so the rate of oil growth is going to slow down a bit. So it's just that simple.

Moving on, we'll take our next question from Joe Magner from Macquarie Capital.

I appreciate that you're not necessarily getting into details on 2013 spending yet. Can we expect that you will, and I apologize if I missed this earlier, maintain the commitment to keeping your net debt-to-cap below 30%? Is that still a goal for next year?

Yes. That's our target, Joe.

Okay. And I guess as we think about some of the spending that's taking place this year, you've mentioned that $750 million of dry gas spending is taking place to hold leases and whatnot. How much of that might occur again next year, or will you be mostly through a lot of that activity by the end of 2012?

That'll probably go from $750 million to maybe like $100 million or $150 million, so it's going to drastically drop.

Just getting into one of the plays, there's just some differences in terms of how companies are referring to the Wolfcamp Shale, horizons that are being targeted. Can you, I guess, maybe remind us how you think about the upper, lower and middle Wolfcamp and how that might compare to some of the other industry norms that are being discussed?

Yes, Joe. Ours might be a little bit simpler nomenclature. We divide the 3 -- the Wolfcamp, it's about a 1,000-feet dig, so we divide it into 3 zones: the upper zone, the middle zone and the lower zone. And those are defined stratigraphically, there's shalier, more, really, clay, intervals that separate the 3 zones. So they're kind of distinct zones that we can map around the basin. And we're not real sure and we know some have broken them up into 4 different zones and things like that, and so I'm not sure exactly what the difference is between us in EOG. But ours is a pretty simple thing. And our focus right now, of course, has been on the middle zone. It's been really -- it's got really good consistent pay quality, and we're consistently making really good wells in that. And then we are currently completing a couple of upper wells now, and we'll have some results on those later down the road. But that's how we're doing it.

Moving on, we'll take our next question from Pearce Hammond from Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: Could you give an overview of how you see service cost trending right now in your 4 core areas?

Yes. We've seen the drilling rig rates drop. They've been negotiated, probably only 10% lower. The tubulars, they're dropping also. They're probably down about 10%. But as you'll recall, most of EOG's services are pretty well contracted. We've got about 40% of our rigs, drilling rigs under long-term, and then about 2/3 of our frac fleets are contracted. And then yes, EOG provides our own sand. We buy our mud wholesale. We provide our own sources of acid gel, that sort of thing. So our costs are pretty well locked in. So we wouldn't see much additional change other than, yes, we'll continue to drive efficiencies into our operations. And that's how we've reduced our costs, both on the number of stages per day and then dropping the number of days per well. Pearce W. Hammond - Simmons & Company International, Research Division: And then of the Bakken and the Eagle Ford and the Permian, which 1 of those 3 would be the tightest right now on services in general?

Probably the Permian, the tightest right now. But we're not really having any problems there. That's probably our lowest activity area. Of course, we're busiest in the Eagle Ford and then next, in the Bakken.

Moving on, we'll take our next question from Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I had a question on the impact on production on the various disposals of the non-operated properties. What sort of scale is that, and when will that hit? Did that close in the quarter, or will it come later?

Yes, Bob. In terms of when it'll hit, it closed late in the second quarter, so when it will really hit is in terms of third quarter. So that's another reason that the growth of second half oil production will be a little bit tempered because of that impact. In terms of the scale of it, we typically, on the assets we sell, which is $1.2 billion this year so far, we haven't released who's been the buyer and we haven't released what volume we've sold, and it's because we don't really want to get into all this stuff about as adjusted volumes or pro forma or anything like that. We're not an as adjusted company. So we'd just say it was the biggest single sale of our $1.2 billion that we sold, but that's as far as we want to go on any disclosure on it. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then do you have much in the way of non-op production left in the Eagle Ford or Bakken?

In the Bakken, no. I don't think we have any. It'd be just a tiny, miniscule amount, really. In the Eagle Ford, we do have some -- we are partners with PXP on some, where we operate some and they operate some on a 50-50 basis. So it's not a big amount relative to our Eagle Ford position. As just a guess, Bob, wow, 95%, maybe a little bit more than that of our Eagle Ford we operate, maybe 97%, something like that, we operate. But there is a little bit that is joint outside operated.

And moving on, we'll take our next question from Biju Perincheril from Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Going back to the Pearsall question earlier, have you drilled any wells to test the Pearsall? And drilling Eagle Ford, does that hold your Pearsall rights?

Second question first. Yes, drilling an Eagle Ford well generally does not hold the Pearsall rights because the Pearsall is deeper than the Eagle Ford. And generally, most of the leases, you only earn to the depths drilled. In terms of -- we have done a little bit of testing of the Pearsall and really haven't disclosed any results yet on it. So you can take that as either a positive or negative. What we will say again are there are 3 or 4 zones both above and below the Eagle Ford that have the potential maybe to be productive, and we're kind of testing them in time. But they're really so secondary or almost tertiary to the potential of the Eagle Ford that they're -- not given it a very high priority relative to optimizing the Eagle Ford. In other words, if we can figure a way to improve our recovery factor by 2% or 3% in the Eagle Ford, it dwarfs whatever we might find in some of the other intervals in terms of magnitude. So that's kind of what's driving our priorities. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then in the Eagle Ford, it looks like you've recently jumped over to, I guess, further Northeast in Madison County. Are you looking at the Eagle Ford, or is that a different play like the Woodbine there? Can you share any color on that?

Yes, we have drilled a well. It's called the Eaglebine play, generally, by the industry. And so we're testing some concepts over there. But we've really not thought much about that, and are not really prepared to talk much about that kind of play at this point.

And moving on, we'll take our next question from Bob Morris from Citigroup.

When you mentioned potentially doing a JV in another oil play, I assume that's separate from the JV you did with Mitsubishi in the Tuscaloosa Marine Shale and is a play that you've not disclosed or talked about yet.

Yes. Don't try and pin us down too much. We're really -- what you ought to take directionally out of that is our inventory in -- out of our big 4 plays is -- and our success rate there is so high that we could easily push essentially all of our cash flow into those plays next year. And so in any of our other oil plays, horizontal oil plays, we may elect to push our capital away from those and use JVs and allow us to funnel more money, particularly into the high rate of return Eagle Ford. So that's kind of the thinking behind what we're talking about.

Okay. And then on the joint venture with Mitsubishi in the Tuscaloosa Marine Shale, what has been your activity under that joint venture to date?

Yes. Well, currently, we've commenced drilling, and probably, by year end, we'll have first wells results on there. So I guess on the February earnings call, we'll know something from the first well.

Moving on, we'll take our next question from Irene Haas from Wunderlich Securities.

I have actually 2 questions for you. Firstly, I wanted to find out, second half, looking into the Bakken and also the Eagle Ford, how should we think about the differential versus WTI or LLX, however you want to express that, and then also within your U.S. portfolio, percent of Bakken crude and Eagle Ford? So that's my first question. My second question is in light of the recent activity in Midland Basin, specifically to the Wolfcamp and Cline Shale play, are you still thinking with your 430,000 barrels per day EUR? Because one of your competitors have sort of raised that bar.

Yes. Okay. Thanks, Irene. I'll fill the question about the differentials, and then I'll ask Bill Thomas to fill the question about the reserves in the Wolfcamp there. Our plan -- in the Eagle Ford, we're selling essentially all our oil now in the Houston market. And currently, in the Houston market, we're getting the same price essentially as if we were selling that oil in St. James, Louisiana. So we're getting pretty much St. James price. And then the Bakken, we continue to move a little bit of the Bakken oil on pipeline and selling it at Clear Brook just to keep some pipeline access, and that little bit of oil is getting -- suffering a severe discount, like the Bakken oil does up there. But the majority of our Bakken oil is getting moved by rail and sold as St. James. So essentially, the majority of both those areas, Bakken and Eagle Ford, is being sold at St. James prices. As to the question on the Wolfcamp reserves, Bill?

Yes, Irene, there's a couple things, comments on that. Yes, we're sticking -- I mean, right now, we're holding to our 430 Mboe per well on the Wolfcamp. And then it's the same, really, on the Wolfcamp or the Eagle Ford. When we're in the early stages on these wells, we're doing 2 things. We're trying to make better wells but we're also downspacing. So as we drill wells closer and closer together, we're trying to measure what the EUR per well is going to be. And so we're very cautious on increasing the EUR until we really get the proper spacing. And that goes for, really, any of these plays. And the other thing I would say about the Wolfcamp is it's not -- it's clearly in third place as far as rock quality. And it's cleared us -- we've completed, I think, 72 wells so far to date. And it's going to be more difficult in the Wolfcamp play to get the recovery factor up. It's not certainly as easy as the Eagle Ford play or the Bakken play to get really high recovery factor. So we're being very prudent. We're doing everything we can, technically, to make the play better. And it's a really good play, and we're very, very satisfied with our results there. But I would just be somewhat cautious on trying to extrapolate that we're going to get 6% or some really high number recovery factor out of the Wolfcamp as we've done in the Eagle Ford and some of these other plays just because the rock quality and the difficulty there has got a higher degree of difficulty.

Moving on, we'll take our next question from Doug Leggate.

Regarding the guidance, if I could go back again to the north of 100,00 barrels a day in the Eagle Ford, I got to tell you I'm struggling to get to your guidance for the year, Mark. Could you just walk us through -- I know you've already gone through it, but how many of the 145 completions are planned to be in the lower working interest areas? And if you could help us with the delta between your 100% working interest to what the actual difference is, order of magnitude, basically. And I have a follow-up, please.

I don't know if we have that data right at hand here, Doug. Maybe Maire can get some of that information to you later on. I'd say again, the best way to look at it is probably the -- we've got more rigs moving to the West. We have less monster wells that are going to be completed in the third quarter versus the second, and some of them are lower -- clearly, some wells are going to be lower working interest, and there's just less capital going to be spent in the second half of the year. And then you've got the effect of, in the first half, we sold $1.2 billion worth of assets, and the effect of the liquids that we sold are going to bite in the second half of the year. So that's kind of the way to get to it, and that's the best explanation I can give you.

Maybe I can try the same question slightly differently. You would still expect Eagle Ford to grow from June levels in the second half? Is that a fair assertion?

Yes.

Okay. My second question's also on guidance. It's on the operating cost this time because it seems you had a pretty phenomenal second quarter on costs. But your guidance again has it moving right back up again in the second half of the year. Can you just walk us through why that would be the case? And I'll leave it at that.

Yes. One piece of that guidance relates to Trinidad. If you notice, Trinidad, we had very high volumes in the second quarter, and then we're toning down those volumes for the second half. Trinidad has quite low operating costs. And so to the degree that those volumes are going to come down in the second half, that's going to skew the average operating cost back up a bit. So that's one piece of it. And a lot of it is, again, the growth in the -- the volume growth in the second half is going to just average -- the rate is going to be a bit lower across the whole company. So that's why we're expecting it to go up a little bit more. So we hope we can beat on the operating cost for the second half, but we'll just see.

And at this time, that will conclude our question-and-answer session. I'd like to turn the conference back over to Mr. Papa for any additional or closing remarks.

No additional remarks. Thank you very much for listening.

And thank you. That will conclude today's conference. We thank everyone for their participation.