Good day, everyone, and welcome to this EOG Resources Third Quarter 2012 Earnings Results Conference Call. As a reminder, this call is being recorded. And at this time for opening remarks and introductions, I would 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 taking the time to join us on election day. We hope everyone has seen the press release announcing third 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 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 included fourth quarter and updated full year 2012 guidance in yesterday's press release. This morning, I'll discuss topics in the following order: I'll initially review our third quarter 2012 net income and discretionary cash flow. Then Bill, Thomas and I will provide operational results. Tim Driggers will discuss financials and capital structure. I'll then follow with our macro view, our preliminary 2013 business plan and concluding remarks. As outlined in our press release for the third quarter 2012, EOG reported net income of…

Thanks, Mark. We continue to be particularly upbeat about the Bakken and Three Forks potential on our acreage in the Williston Basin. In the Bakken Core area, the 320-acre downspacing has proven to be successful, and 2 recent wells further confirmed the strength. The Fertile 46-1608H tested at 1,732 barrels of oil per day, with 90 barrels per day of NGLs and 363 Mcf per day of natural gas. The Fertile 47-712H (sic) [Fertile 47-0712H] tested at 1,258 barrels of oil per day, an 83 barrels per day of NGLs and 332 Mcf of gas. We have 92% and 78% working interest in these wells, respectively. We'll be testing 160-acre downspacing in the Core late this year, and we hope to have some results from our pilot waterflood project by February. In the Antelope area, we're applying improved frac technology to our current well completions. We recently completed an outstanding Antelope Three Forks well, the Hawkeye 100-2501H, for 3,196 barrels of oil per day with 5.5 million cubic feet per day of rich natural gas. EOG has a 73% working interest of this well. Other recent Antelope wells are listed in the press release. In 2003 to 2015, we plan to spend most of our North Dakota capital in these same 2 areas, primarily downspacing in the Bakken Core and further development of both the Bakken and Three Forks targets in the Antelope Extension area. We plan to develop our Bakken lot and Stateline areas in subsequent years. Shifting our focus to the Permian Basin Wolfcamp and Leonard horizontal plays. We're seeing Wolfcamp results similar to previous quarters. But in the Southeast New Mexico Leonard, we're seeing improved results. We previously said the returns on these 2 plays were equal, but we now rate the Leonard above the Wolfcamp. The…

Thanks, Bill. Outside North America, we expect our 100% working interest East Irish Sea Conwy crude oil development project to start up in the second half of 2013. In Argentina, our horizontal Vaca Muerta oil well yielded lower-than-expected results. The production results were similar to a nearby vertical well we had completed, indicating no multiplier effect for the horizontal versus the vertical. We're still evaluating results and plan to proceed cautiously during 2013. In Trinidad, our third quarter gas takes were higher than expected due to incremental short-term market demands. There's nothing new to report on the Kitimat LNG project. I'll now address 2 other EOG differentiators, oil margins and sand plants. You'll notice that for the third quarter, our U.S. crude oil price realization was $5.45 over WTI. Considering where our crude is produced, this is likely the most advantageous realization of any similarly situated company. Our 2 biggest production areas are the Eagle Ford and Bakken. As I previously mentioned, our Eagle Ford crude is currently priced off on LLS index. In the Bakken, almost all of our crude plus some third-party crude is being railed to our St. James, Louisiana terminal and receiving LLS prices. Additionally, we're railing a portion of our Wolfcamp crude to Louisiana. On the well cost side, our sand plants continue to function smoothly and provide the frac cost savings we've described in previous quarters. EOG's success is based on a simple equation: higher crude oil volumes and higher crude oil price realizations combined with lower well and unit costs and less money-losing North American natural gas volumes equals more net income. I'll now turn it over to Tim to discuss financials and capital structure.

Thanks, Mark. Capitalized interest for the quarter was $12.7 million. For the third quarter 2012, total cash, exploration and development expenditures were $1.6 billion excluding asset retirement obligations. In addition, cash expenditures for gathering systems, processing plants and other property plant and equipment were $161 million. Year-to-date total cash, exploration and development expenditures were $5.5 billion excluding asset retirement obligations. Cash expenditures for gathering systems, processing plants and other property plant and equipment were $477 million. Acquisitions cost year-to-date totaled $435,000. Through September 30, proceeds from asset sales were $1.2 billion. Our goal is to close on an additional $100 million prior to yearend for a total of $1.3 billion of asset sales for the year. At September 30, 2012, total debt outstanding was $6.3 billion and the debt to total capitalization ratio was 31%. At September 30, we had $1.1 billion of cash on hand, giving us non-GAAP net debt of $5.2 billion for a net debt to total cap ratio of 27%. The effective tax rate for the third quarter was 37%, and the deferred tax ratio was 52%. Yesterday, we included a guidance table with the earnings press release for the fourth quarter and full year 2012. Our updated 2012 total CapEx guidance is approximately $7.6 billion excluding noncash items. For the fourth quarter and full year, the effective tax rate is estimated to be 35% to 40%. We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the fourth quarter and for the full year. Now I'll turn it back to Mark.

I'll now provide our views regarding macro hedging and concluding remarks. Regarding oil, we think the current NYMEX plus $2 to $3 per barrel reasonably reflects likely 2013 prices. We continue to believe that U.S. shale oil won't flood the global market for the reasons I articulated on our previous earnings call. Likewise, we think any meaningful supply effect from shale oil outside North America is many years away and will be very slow to develop. For the first half of 2013, we have 98,000 barrels of oil per day hedged at $99.39 per barrel. And for the second half, we have 68,000 barrels per day hedged at $99.45 per barrel. We also have some options next year that may be exercised and would increase our hedge position by an average of 42,000 barrels of oil per day at an average price of $102.16. Regarding gas, we expect 2013 prices will be better than 2012, but not good enough to provide a cost of capital full cycle return on North American gas well drilling. Our current 2013 hedge position is 150,000 mmbtu per day at $4.79 per mmbtu excluding unexercised options. Please see the table that was included in our earnings press release for the details of our hedging contracts. Now let me provide a brief outline of our 2013 business plan. As usual, we'll provide our specific 2013 plan with volumes, CapEx, et cetera, in our February call. But today, we can provide 4 directional guidelines. First, we expect our overall 2013 CapEx to decline below 2012 levels, primarily because we've accomplished our goal of converting our dry gas resource play acreage to held by production status. This year, we spent roughly $700 million, primarily in the Haynesville, Marcellus and Horn River converting leases to held by production, and…

[Operator Instructions] We'll hear first from Pearce Hammond with Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: In the Eagle Ford and the Bakken, what inning do you think we are in regarding drilling efficiency improvements? Essentially, are there more substantial leads ahead in drilling efficiency?

Yes, there are. To give you an idea, last quarter, we said that our average drilling comp is 14 days; this quarter, it's 13 days. And we're now -- some of our fastest wells, we're drilling in 8 days. So we have room to beat the 13-day average timeframe. If you would have asked me 18 months ago whether we'd be able to drill our fastest wells in 8 days, I would have frankly told you, no way. So I would expect that we're going to see further improvements over the next 12 months in the average time to drill the wells, which is going to give us a good chance to drive the average well cost down even further. I mean, right now, the direction we're seeing is the rig comps are trending down, some of the service costs are trending down. So I think that the average well cost of $5.5 million for 2013 is eminently achievable for our wells in the Eagle Ford. And that probably beats the industry average in the Eagle Ford by $2 million a well. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then a follow-up, in the Eagle Ford and the Bakken, do you think we're getting to a point of diminishing returns on the number of frac stages? Or do you think we will see the average number of frac stages per well gradually increase?

We're getting close. We've continued to increase the number of stages. We may do it slightly more here in 2013.

Yes, I don't see us going doubling the number of frac stages over the next 2 or 3 years from where we are today, if that's the direction of your question, Pearce.

Next question will come from Leo Mariani with RBC.

I want to see if I can get a little bit more color on the rig drop that you talk about. You talk about going from 70 to 52 rigs here. Like in your slide deck, you mentioned going from 5 to 4 in the Wolfcamp and from 7 to 5 in the Bakken. But just a little bit more color on other areas that you've sort of dropped rigs. If you'd give us any kind of numbers around that, that'd be great.

Yes. And let me kind of segue that into kind of the production targets that we've given you for the fourth quarter, specifically the oil production numbers. The simple way I'd explain it is, we've -- we spend about $6 billion through the first 3 quarters of the year, and we gave you an estimate that basically says we intend to spend about $1.6 billion in the fourth quarter. So we have very roughly a $2 billion a quarter run rate, and now we're telling you we're going to spend $1.6 billion in the fourth quarter roughly. And the growth rate of the company, the oil growth rate, I'd say, is very similar to a coin-operated machine. EOG right now is very similar to a coin-operated machine. You put dollars in, and you have 100% efficiency. There is no inefficiency due to exploration, and there is essentially no operational inefficiency. So our growth rate for the fourth quarter and -- is essentially going to be a function of how many dollars we spend. And that's why our growth rate in the fourth quarter is going to be less than it was in the first 3 quarters. And we basically are just curbing our spending to stay within our capital budget, and we're just slowing down pretty severely, really, in all of our plays. But the most severity is going to be in the Eagle Ford where we are cutting completion units, cutting rigs and just slowing the process down. So -- and I've also seen a couple early comments there on our -- where people are saying, "Well, you're probably sandbagging on your oil volumes in the fourth quarter." I know we've beaten the volumes in the first 3 quarters on the guidance, but don't assume that we're sandbagging in the fourth quarter because we are putting the brakes on it quite hard on the CapEx spending. And frankly, I expect it will hit about the midpoint of our 8-K target for the fourth quarter on our oil volumes and not overachieve. It's not due to lack of prospectivity. It's not due to well quality. It's just flat due to a coin-operated machine that we're putting less coins in there in the fourth quarter.

That's very helpful. I guess, can you maybe just kind of address how that might ramp up in the Eagle Ford? I mean, I guess, obviously, you're pulling back to stay within your budget this year. But if you do spend slightly less, and you're spending quite a bit less on gas, might you start ramping the Eagle Ford back up kind of next year? Just any color on sort of directionality and how to think about that?

Yes, the directionality is, what we intend to do, specifically in Eagle Ford is, the last 2 weeks in December, we are going to start dropping coins back in the machine at a pretty heavy rate. And it's not going to show up in any December volumes, but it's going to give us a headstart in January. It will start showing up in early January volumes. And we've got this ground into our numbers. So our intention is, is to get a pretty fast start out of the gate in early January. So I wouldn't -- don't assume that because we're losing momentum in the fourth quarter, that loss of momentum is necessarily going to carry over into the first quarter of 2013. We are adjusting for that, and we'll be reversing that momentum in December. And it should show up in the January volume numbers.

All right. That's really helpful. And I guess in terms of the Eagle Ford, it looks like your step-out wells away from Gonzales County were really strong in this quarter. I know that you had kind of said that the overall average in the play may be lower. We've had a lot of wells that are 700,000, 800,000 Boe in around Gonzales, but it looks like they're pretty strong. Is this kind of maybe biased, the EUR is up a little bit in Eagle Ford?

Yes, are you talking about the wells in the West there, Leo, that we highlighted on that map?

Yes. The LaSalle and McMullen stuff that you guys have announced.

Yes, yes, yes, the -- I would still say that the direction that we hope to be heading with the downspacing, if the downspacing's successful, is more likely to be that we end up with more locations at the 450 Mboe net reserve average as opposed to increasing the 450 Mboe average. So although certainly in certain areas, the wells are greater than 450 Mboe. But what we would hope the downspacing does for us is give us more locations with an overall aggregate average of 450 Mboe as opposed to raising that average across the entire acreage block. And that's what we hope the outcome is sometime in the first half of next year. And where we stand on the downspacing is we've got multiples, tighter spacing pilots than the 65 to 90 acres already drilled. We have initial tests on those tighter spacing pilots. They look good. And what they need now is time. We just need some time to observe the performance of those tighter spacing pilots to just see how they do and then cross check them against our computer models. And that's the phase where in now, it's just the -- some time to watch the production history on these tighter pilots.

We'll now hear from Brian Lively with Tudor, Pickering. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Mark, the operating results this quarter were substantially better than the expectations you laid out in Q2. Just curious on the LOE side, could you kind of bucket some of the categories where you're seeing the biggest improvements?

Yes, Gary?

Yes. We're seeing improvement in our SWD, salt water disposal, disposal because we've spent some money and facilities installing additional SWD takeaway. And also, yes, we've made some improvements on chemicals. And it's just kind of across the board, just working all of our efficiencies on lease operating expenses. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So there's really no reason to not think that those cost improvements will continue to get better and at least stay the same through 2013?

Yes, we should see that. We're -- if you check the 8-K, we're forecasting them to go up a bit in the fourth quarter, that's weather-related, particularly for the North Dakota side where you get this snow issues and things like that. But directionally, particularly on the oil side, as you look at the full year 2013, we expect to have another year of robust oil growth. I think you're going to see the unit cost trending in a good direction. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just for my follow-up question, Mark, you made a comment about in 2014 hoping to return more cash to shareholders. Implication there is you expect to be free cash flow positive. I just wonder if you could put some more color around your expectations. I know we're not even at 2013 yet, but in terms of the free cash flow generation as you get into 2014.

Yes. The overall point I wanted to make is, I consider 2013 to be kind of an important year because really for the previous 3 years, we have clearly been fighting a large kind of a chronic organic free cash flow deficit each year. And it has been a shareholder concern issue. And 2013, I think, as long as oil prices are in the low 90s for WTI, I think we are finally going to free ourselves from that burden. And then as you project 2014, 2015, 2016, we're still going to have, I believe, peer-leading large cap group oil growth during those timeframes. And it's going to put us in a position where we're going to have flexibility to do some things that we haven't been able to do in the past, such as consider more significant dividend increases, consider accelerating our oil growth by additional CapEx increases if we wanted to. It certainly would put us in a position where we don't have to sell properties or possibly even buying in shares. So what I just wanted to note is that the one shareholder concern that people have had the last 3 years about us, in my opinion, is going to go away starting next year, and it's going to turn into a positive starting in 2014.

Our next question will come from Arun Jayaram with Credit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: I just wanted to talk to you maybe bigger picture. Obviously, you have a giant resource here in the Eagle Ford. You've talked about 1.6 billion, 1.7 billion barrels of reserves. I just wanted to see if you could provide us on longer term thoughts on how you milk the cow, so to speak, or to develop this resource to maximize value. You've been running this year a little bit more than 300 well completions. Do you plan to accelerate that, Mark? Or how do you think that it's -- that's fit to develop this in terms of a well count?

Yes, and it kind of gets into our 2013 kind of capital allocation situation. The first thing we have to do is get a handle on what is the true resource here. Is it 1.6 billion barrels as it currently stands, which is our 65 and 90 acre spacing? Or is it some other number depending on what our spacing tests show. So that's kind of job 1, and we think we'll have that answer, as I mentioned earlier, within 6 months. And then based on that, then we decide how -- what's the most intelligent way to develop this thing. But I will say the direction for 2013 is to -- we are more likely to attempt to accelerate development above the 320 well level as opposed to decelerate the development below the 320 well level in 2013, assuming oil prices stay at current levels. Arun Jayaram - Crédit Suisse AG, Research Division: Right. Interesting. And then the reduction in year-over-year CapEx, is that just from rig efficiencies or completion efficiencies, plus a little bit less spending on gas, plus maybe less infrastructure spending? Is that fair?

Yes. I mean, the direction I could give you is, and without trying to give you the exact numbers, but we're -- it's kind of like filling the pieces, we're telling you we're spending $7.6 billion this year. And if you say we spent $700 million on dry gas this year and we're going to spend $100 million next year, that ought to give you a pretty good direction on what we are thinking at this point in time our CapEx is going to be for next year. That's all I'll say about it at this point. But you can kind of fill-in the blanks there. Arun Jayaram - Crédit Suisse AG, Research Division: That's very helpful. And last question, Mark, obviously, the returns have gone down as you frontloaded spending in your oil plays. And obviously, given the high reinvestment opportunities in the Eagle Ford, high return opportunities, your returns should rise over time. I guess, as you think about the longer term focus on growing your returns, do you -- where does EOG stand in terms of adding 1 or 2 more unconventional plays? Where are you in that process?

Yes, well, again, our position is different than most peer companies. Most peer companies, when they -- it seems like, to me, when they acquire acreage on a potential new play, they make a big announcement about it often before they even drilled the well. And our position is just the opposite. Whenever we have a play that we have confirmed through multiple wells that works and whenever we've tied up whatever acreage level we want, that's the first time you'll hear about our greenfield play. And so, we're working on multiple ones, and the first time you hear about it is when we have everything tied up as closely -- as tightly as we can. So we're not going to give you an indication of any timeframe or anything related to them, other than to let you know we're working on some.

Now we'll take a question from Brian Singer of Goldman Sachs.

There's a glass half-empty and a glass half-full way of looking at your guidance here. The glass half-full way is you're disciplined in spending, building a backlog of uncompleted wells, particularly in the Eagle Ford where we should see a sharp step-up as you reengage completions in the first half. And the glass-half empty way, maybe, okay, $1.6 billion to $1.7 billion in CapEx per quarter would drive lower oil productions, so therefore, your maintenance costs to just have flat production would be higher than $1.6 billion a quarter. Can you just address these, how you think about that backlog shift and what you think is closer to reality?

Well, in general terms, I'd say that you'd be a pessimist to say a glass half-empty view of EOG's earnings report. I'd say that the previous quarter and this quarter, we've pretty much blown the doors off the earnings, particularly relative to most peer companies. So I'd -- in a polite way, I say I reject the glass half-empty view. So we have the advantage of having a -- the poker hand and looking at our cards for 2013. And what I can tell you, Brian, is I like the hand we have that we're playing for 2013. I wouldn't change it with anybody else's hand. I feel pretty comfortable. I would tell you, frankly, that the only thing that can sink the EOG's ship in 2013 is a disastrous decline in crude oil prices, and that's why we've hedged reasonably aggressively for 2013. So absent the major collapse in crude oil prices, what I would predict is that if you like what you saw of EOG in 2012, you're going to like 2013 from EOG. So that isn't a direct answer to your question, but I hope it gives you a feeling of the confidence that I have in our 2013 story.

That's great. And then separately, can you give us any additional color on some new venture areas, maybe your thoughts on the Pearsall Tuscaloosa Marine Shale and whether we should expect you to consummate any new joint ventures as you've kind of talked to a little bit before, either in some of these new venture areas or in less Core plays?

Yes. I would say, in the Tuscaloosa Marine Shale, the only reason we even came public on that was that a trade magazine had basically tracked our acreage position there and published it in a trade magazine. And so, the current status of that is, probably on the next earnings call, we will have a report from our first well. We have drilled a horizontal well and we'll be frac-ing it soon. And so we'll have some data on it, and of course, we're in a joint venture on that. And we'll just see what the results are. And in the Pearsall, we are aware that the Pearsall zone exists below the Eagle Ford on portions on our acreage. Frankly, we are not as enthusiastic regarding the Pearsall as some other companies are. And so, you don't see any advertisements in any of our books trumpeting the Pearsall. And so at this stage, we're not thinking that the Pearsall is going to be the next big huge stealth play for EOG.

Now moving on to Biju Perincheril with Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Just a couple of questions. In the Eagle Ford, if you are targeting something more than 320 wells next year, does that mean rig count going back up to sort of high-20s? Or are we looking at something lower because of the efficiency gains you've already achieved there? And also, can you give us some color on the completion increase, how many earning you are running earlier and what the current number is?

Yes. On the first question there on how many rigs we might run next year in the Eagle Ford again, I don't want to get too specific on there. But, I mean, we'd -- based on the efficiencies we're seeing in the days per well and the reduction in days per well, I mean, we might be in the range of 25 rigs next year or something like that. It doesn't look like it's going to be in the high-20s or anything like that for the Eagle Ford in there. And the completion crews, I think we're running 4 right now completion crews. And I don't have right now what number we would be running to for next year in terms of it. But like I say, in our next quarter, we'll be giving you a specific well count as to how many wells we would intend to drill in the Eagle Ford, and we can give you specifics on the completion crews and exactly how many rigs we would intend to run, as well as the Bakken, Three Forks, well count in the Wolfcamp and so on and so forth. So we're not trying to be evasive, but February is the time when we provide those level of specifics, and we'll give it to you at that time. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay, no, that's very helpful. And then, if I look at your current Eagle Ford production, it looks like roughly cash flow neutral if I look at the activities this year. First of all, is that a fair assessment? And when I think about longer term development in the Eagle Ford, is it fair to think that you will keep activities up, sort of more or less match cash flows there?

Yes. Your first part of that statement is correct that in rough terms, we're roughly cash flow neutral currently in the Eagle Ford. As far as on a go-forward basis, we don't look at just the Eagle Ford in terms of, did our -- our plan would be to run the Eagle Ford 2013 or 2014 on a cash flow neutral basis. We -- our decision on what we do with the Eagle Ford on a go-forward basis is going to be more a function of what we think the true total reserves are in the Eagle Ford and what are our alternative investment opportunities and what's the reinvestment rate of return in the Eagle Ford versus other areas. So it's -- we don't look at it just on Eagle Ford alone, really, Biju. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: And one more question, if I could. Some of your peers have talked about a restricted choke program in the Eagle Ford, and maybe that's yielding higher EURs. If that's something you've tested, any plans to test that? And does the efficacy of a program like that depends on the gas-oil ratio?

Yes. The -- all this stuff about -- the stuff about what size choke and people producing in a link to the EURs, we probably have more knowledge, I mean, than any company, certainly on the Eagle Ford oil production than anybody. And what we have found is that the higher the gas-oil ratio, the more sensitivity the choke management -- the more important the choke management is. For example, in the Haynesville and in our Barnett Combo, we actively pursue choke management, and we are looking at, right now, choke management for our Wolfcamp areas. In the Eagle Ford, in the position where our acreage is, which is the black oil area or the area where we fortunately have very high oil portions of the mix, the choke management is not very important. Where other companies have acreage, where they have higher gas-oil ratios, the choke management may be important to ultimate recoveries. But we can't speak about their positions and whether choke management works or doesn't work on their acreage. What we can say is that on our acreage, choke management, in our opinion, is not that critical to EURs. And that's because we have the preferred acreage, frankly. It's just more oily. So that would be our response to that issue.

Next question will come from Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: I wanted to go back to those Baker-DeForest wells in the Eagle Ford that you announced this morning. Could you tell us where on that 65- to 90-acre spacing range those wells are? And more generally, when you have those monster wells, are they more likely to be on tighter spacing, reflecting more oil in place? Or are they more likely to be on a wider spacing, reflecting more conductivity and better fracs?

Yes. Those probably -- the Baker-DeForest wells, I don't have the exact numbers, but they would be on the tighter spacing areas. I can't tell you whether they're on 65 or 90, but I would say they're probably closer to the 65- than the 90-acre spacing in terms of that. So what -- all -- essentially, all the 12 well -- monster wells that we would have related to you here in this particular quarter will be on pretty tight spacing on there. So it's -- what's happening is, it's -- the quality of acreage plus we're giving these wells larger fracs in terms of pounds of sand and number of stages relative to the fracs we would have given these identical wells, say, 12 or 18 months ago, and some other tweaks that are proprietary tweaks to the fracs. So those are the 2 things that are the keys to these monster wells. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Great, that's great detail. And it sounds like there's just more oil in place, and so there's just more to come out there.

Yes. And it's just a more effective stimulation than we would have given to these high oil-in-place areas even a year ago or 18 months ago. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And then one quick follow-up. Going -- on the Bakken, going back to your comments, I think they were on the -- your last earnings call when you talked about the response of the original offset wells to the downspacing, the subsequent downspacing, that when you put a frac in, you saw that sustained response in the original well. Is there any update that you can offer on that, whether you've seen that -- whether you've seen that sustain in wells or whether you've seen that replicated in new areas as you've downspaced?

Yes, Charles. We do continue to see that in our downspacing, like in the Fertile wells that are on -- that are in the press release. When we do the aggressive fracs, and we've been working on our frac technology in the Bakken, as well as we have in the Eagle Ford, and we're making really good progress there. So when we do the more aggressive fracs in the downspacing, we do see response from the offset -- the older offset wells. So they -- generally, they come up and they kind of double in production. And then they go on a decline and, eventually, they'll get back on the original curve that they were on, but there is some -- certainly some additional reserves in oil that we're contacting with these more aggressive fracs. So we're really pleased that our Bakken results are certainly improving because of the frac technology in the downspacing.

It looks like we have time for one final question, that will come from Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Quick question, what assets are relying on salt water disposal that you'd mentioned earlier on the LOE comments?

That's principally the Bakken. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then the other, crude-by-rail, what role do you think that ultimately plays? Is that something that simply is run until pipelines come into place? Or is that something that's going to be ongoing as part of the mix forever? And what's the payout period on those crude-by-rail facilities?

Yes, Bob, I really think that crude-by-rail is going to be around for a long time in EOG's system. I think the lag time on getting pipelines built is really something like 5 to maybe 8 years. So it's -- the crude-by-rail is not just to stop gap measure, in my opinion. In other words -- and I see the crude-by-rail destinations perhaps changing 3 years, 5 years from now, such that perhaps Louisiana is not the optimum destination to deliver the crude to depending on what market conditions are at that point in time there. So but I would guess that 5 years from now, 10 years from now, crude-by-rail is still a significant kind of a market uplift for EOG's crude marketing. And did you have a second part to the question there? Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Yes. What's the sort of payback period on a loading terminal?

There, at least in EOG's experience so far, it's in months rather than years.

And that's all the time we have for questions. I'll turn the call back over to Mark Papa for any further remarks.

Okay. Thanks, everyone, for listening. And remember, if you haven't voted yet, get out and vote.

Ladies and gentlemen, that will conclude your conference for today. We do thank you for your participation.