Good day, everyone, and welcome to the EOG Resources 2016 second quarter results conference call. At this time for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir. Timothy K. Driggers - Chief Financial Officer & Vice President: Thank you and good morning, thanks for joining us. We hope everyone has seen the press release announcing second quarter 2016 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the press 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 reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. Participating on the call this morning are: Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, VP, Marketing Operations; and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, and we included guidance for the third quarter and full year 2016 in yesterday's press release.…

Thank you. And we will take our first question today from Evan Calio with Morgan Stanley. Please go ahead. Evan Calio - Morgan Stanley & Co. LLC: Hey, guys. Good morning, everybody, and good results to close out earnings here. William R. Thomas - Chairman & Chief Executive Officer: Thanks, Evan. Evan Calio - Morgan Stanley & Co. LLC: My first question, Bill, is how quickly can you get into the 10% annual growth rate, the bottom of your new growth at $50? It looks a little bit back-end loaded on slide 14. And I guess my question is, do DUCs allow for fast return? And what signals do you need to add rigs to move towards these targets? William R. Thomas - Chairman & Chief Executive Officer: Yes, of course, Evan. The driver is oil price. And as oil prices improve above the $50 level, the more capital we'll add and the faster we'll ramp up our activity. We're not limited on beginning out very significantly. We have ongoing operations and enough rigs and equipment going now, and the DUCs really help us get off to a good start. But it is, as you can tell from the chart on slide 14, it's not 10% every year. So 2017 will start off incrementally at a lower rate, and then we'll build from there as we go forward. And of course, as volumes grow, cash flow grows too, so the process multiplies itself as we go forward. Evan Calio - Morgan Stanley & Co. LLC: What drives the higher growth in the back end of the decade? Does that reflect the EUR base decline management, or is that all an effect from premium locations? William R. Thomas - Chairman & Chief Executive Officer: The whole driver for us being able to grow at these kinds of rates at these low oil prices is really the switch to premium and the lowering of the well cost at the same time. The productivity of the wells is just a tremendous uptick from where we were in 2014, and so the capital efficiency I believe has more than doubled since that time. We did not put in the outlook, we did not put any EOR investments in there or production response, so that's really not a part of the outlook that we did. Of course, the EOR has great capital efficiency. It's just as good as premium, and we're working it in over time as is appropriate. Evan Calio - Morgan Stanley & Co. LLC: Great, I'll leave there for somebody else. Thanks.

And we'll go to Doug Leggate with Bank of America Merrill Lynch. Please go ahead. Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Thanks, good morning, everybody. Bill, this is pretty exciting. Obviously, we see this as the formal change I guess. I guess the question I have is you could pretty much, assuming you're right on the macro, you could pretty much assume to grow at whatever pace you want as it relates to inventory. I'm guessing a 10% hurdle is not, for your track record, that difficult to achieve. So what are the constraints that you see to EOG's growth aspirations as relates to people, infrastructure, and maybe even a switch in capital towards EOR or back to shareholders? William R. Thomas - Chairman & Chief Executive Officer: Doug, the constraints would be – I think the biggest one would be we don't want to lose the capital efficiency gains that we have built in right now, and so we don't want to go so fast that we're bringing in equipment and people and spending money and drilling wells and really lose these efficiency gains that we've got right now. So if oil, say, went to $70 or $60 or $70 really quick, we could ramp up appropriately, but we wouldn't do it overnight. We couldn't do it overnight. We would have to build up the service quality, and we would certainly want to maintain our efficiencies that we've already built in. That's the one thing we don't want to do. Of course, we want to focus on our balance sheet and to get that net debt-to-cap back down to below 30% also. So I believe I'll let Gary Thomas chime in on that. He can give some color on that.

Yes, Doug. As Bill was saying, the premium drilling is what helps us with the growth forward because it just requires fewer wells, and we'll not be having to ramp up to the number of rigs that we had, for instance, in 2014. And another reason is because of the productivity by rig. If you could, look at Exhibit 20 showing that. But we've got a plan in place to be able to ramp up to maintain our efficiencies and more than likely continue to reduce our costs. Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.: I appreciate the answer. Go on... William R. Thomas - Chairman & Chief Executive Officer: To answer your question on would we buy back shares, that's really not in our plans at this time. We're not opportunity limited. That's an important part of the process. And so geologically, we don't have an opportunity limit there. So we would ramp up appropriately to maintain the discipline and to reduce the debt at the same time. Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Bill, I appreciate the detailed answer. Hopefully my quick follow-up is just on the balance sheet. Clearly, there are going be some assets that maybe don't make it into the premium inventory. So as you've now made this permanent shift, rather than get specific, could you quantify for us? What impact on your base production do you think disposals could ultimately represent? Because obviously that would amplify the implied growth rate going forward. And I'll leave it there, thanks. William R. Thomas - Chairman & Chief Executive Officer: Doug, on the oil growth rate, I don't believe it's going impact it significantly at all. The things that we've targeted this year are mostly gassy properties to sell. And as we go forward, they would either be kind of combo-ish or gas properties going forward. So on the oil growth, property sales shouldn't be a factor much at all. Doug Leggate - Merrill Lynch, Pierce, Fenner & Smith, Inc.: I appreciate that. Thanks, guys.

Next is Pearce Hammond with Simmons.

Good morning and thanks for the helpful long-term plan. My first question is given the rise in completion activity, do you believe you have enough access to enough Texas-based finer sands, or will you need to use more of the white sands, potentially requiring you to reactivate your Wisconsin mines? Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Pearce, we have both available to us. We've been working on our own Texas mines and plant and expanding there as far as our capability, as well as working on our Wisconsin plant, being able to reduce costs and put in place improved transportation. So we believe that we have adequate sand, and we believe we've been able to lower our sand cost as well, and we're seeing that helping our cost here in 2016. So we've got plenty of sand available. We feel like we've got most all of our resources available to us as well. The thing that's really helped us during this downturn is we've been able to just continue increasing our efficiencies. And before, I probably mentioned that we thought that as far as our cost reductions, maybe two-thirds were sustainable. With what we've seen here from 2015 going to 2016, we've lowered our well cost in all of our areas somewhere 11% to 13%, and that's just through increased efficiencies. So those will go forward with us.

Thank you, Billy, very helpful. And then my follow-up. Bill, as you look at the non-premium inventory, big picture thought, does it make sense to divest more of it, or do you need to hold on to some of it and let technology catch up to that so you can move the acreage into the premium category? So I just want to get your big picture thoughts on how you view that non-premium inventory. William R. Thomas - Chairman & Chief Executive Officer: Yes, Pearce, I'll let Billy address that, Billy Helms. Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Yes, Pearce. So in our inventory, as we continue to demonstrate, we can add more and more to our premium inventory. There's some of the inventory that may never make it to that. So we're looking at what options are best to bring that value forward, whether it's monetize that property or produce it out for a period of time or whatever the optionality is. We have a tremendous amount of flexibility. We haven't designated certain properties yet to be put on the market, but we'll just be opportunistic in that approach and evaluate each one independently. We haven't really considered any of those volumes, as Bill said, in our four-year or five-year plan. And so as he mentioned, they'll be mostly gas or gas combo-type plays, so that really won't affect oil production guidance any.

Thank you.

And we'll now go to Subash Chandra with Guggenheim.

Good morning. So the question was, in creating these premium locations, do you find the best rock gets better, or are you equally successful in converting Tier 1/Tier 2 rock to premium? Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: I think the rock quality is a very big driver on the premium, and the higher the quality of the rock, the better it responds to the technical advances we make in the completions. There's no question about that. So I think one of the things that's not clearly understood in the horizontal shale industry is that these sweet spots in these plays, especially in the oil plays, are not very large. So capturing the very highest quality rock is extremely important and certainly something that EOG has excelled in and focused on over the years, and it really is the biggest driver of productivity.

Okay. My follow-up is, how many completion crews do you have active in your basins, and is there a rig count-to-completion crew ratio that we should think about?

This is Gary Thomas. We have now eight completion units running and we've got anywhere from 11 to 12 rigs, and that's a pretty good ratio as far as an average.

Could you scale up the rig count without adding completion units materially?

We could, yes. It depends on where you add the rigs. If we added in the Eagle Ford, we would have to add fewer completion units, for instance, there. They're just so efficient after having operated there for the last seven or eight years.

All right, thank you. Great quarter, thanks.

Ryan Todd with Deutsche Bank is next.

Thanks. Good morning, guys, maybe a couple points of clarity. Can you talk about – the incremental 50 wells drilled in 2016 and the 80 completions, does that involve any rig additions, or are you completing that with the existing rigs and crews that you have on hand?

This is Gary Thomas. What we've been able to do is just the tremendous efficiency improvements have allowed us to go ahead and do this with the same number of drilling rigs. We will be adding one or two completion units here through the second half to go ahead and take care of the 350 completions in this round. It's all being done within existing capital, planned capital.

That's great, thanks. And then maybe as we look out over the next couple years, can you talk about the allocation of capital between the Eagle Ford and the Permian? As you look into 2017 and 2018, what's the expected split between capital going to each basin, and how will that change as you look forward over the next two or three years? And is that reflective of the relative rates of return between the two assets? William R. Thomas - Chairman & Chief Executive Officer: As we look into 2017 and forward, the capital will be – about 45% will be in the Eagle Ford, about 45% in the Delaware, and then about 10% in the Rockies. That's a rough balance between each one of those areas. Of course, the one we've increased capital most this year is in the Delaware Basin, and that will be increased again going forward. The rates of return that we're getting in the Delaware are just outstanding as the well results we've talked about today.

So is it purely a rate of return driven exercise? The Delaware wells, have they risen to the top, or is it also a reflection of depth of inventory, infrastructure, things like that? Or is it just returns driven? William R. Thomas - Chairman & Chief Executive Officer: It's certainly returns driven, but I would say of those three areas, if we look at our current scorecard, the returns on all three of those areas are about equal. So it has to do with inventory and returns and of course, operational efficiency.

Okay, thank you very much.

We'll go to Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: Good morning, Bill, and to the rest of your team there. William R. Thomas - Chairman & Chief Executive Officer: Good morning. Charles A. Meade - Johnson Rice & Co. LLC: I'd like to pick up on the theme that you mentioned a couple times in your remarks about improved capital efficiency. And certainly we're seeing that in spades today with you increasing your completed well count – or your completions by 30% and your wells drilled by 25% with the same CapEx. But I think I get the theme that this is really driven by your shift to premium drilling, and I'm looking at that left half of the slide five you have where you lay out your plans for the next few years. Is that ongoing shift to premium a fair weather vane to look at for how capital efficiency will continue to improve in 2017 and 2018, or is it the kind of thing that you think you've seen the beginnings and we shouldn't expect a whole lot more from this point forward? William R. Thomas - Chairman & Chief Executive Officer: Yes, that chart is very indicative of the way that capital efficiency goes. So I believe this year it's about 60% premium. Next year it's 81% premium. And then I think from 2018 forward it's 98%. So as we complete more premium wells each year, the capital efficiency will increase. Charles A. Meade - Johnson Rice & Co. LLC: Got it, that's helpful. Thank you. And then if I could pick up on one of the big themes from last quarter, your Austin Chalk activity, I think I heard you mention that you're still excited about that play. Can you give us a sense? Are any of those locations in your premium count right now, perhaps under the overall Eagle Ford heading, or is this still in the exploration bucket waiting to be promoted somewhere down the road? David W. Trice - Executive Vice President-Exploration & Production: Charles, this is David. As far as the Austin Chalk goes, like we mentioned last quarter, we're still delineating that play. So we're still intending to drill nine wells throughout our whole acreage position there. And currently, we don't have any Austin Chalk within our premium count, but that's clearly a potential for some upside there. Just like Bill had mentioned, one of the ways that we're going to add premium in the future is through exploration. So the wells that we've brought on, as we talked about last quarter, are clearly premium. So we're still excited about that play, but we need a little bit more data on it. Charles A. Meade - Johnson Rice & Co. LLC: That's helpful insight, thank you.

We'll go to Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Thank you, good morning. William R. Thomas - Chairman & Chief Executive Officer: Hey, Brian. Brian Singer - Goldman Sachs & Co.: Bill, you've recently spoken a bit less on the topic of recovery rate. But given that you are increasing your premium inventory in part because of productivity gains and longer laterals, I wonder if you could provide an update on where you see recovery rates, particularly in the Delaware and Eagle Ford, and then the opportunity from here for further technology and productivity gains to increase resource in premium inventory and overall recoveries. Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Brian, this is Billy Helms. On the recovery rates, we've gotten away from quoting what we think the overall recovery rate is by zone. But needless to say, it's improving. I think a large part of that, a very significant part of that is what Bill talked about earlier. It's understanding the rock, our shift to better define what targeting is, and then deploying our high-density completion process. It's really made a huge difference on the recovery rates. We really don't focus on what that recovery rate percentage is. It really doesn't help us understand our go-forward models on how these wells will perform. So it really hasn't been a focus for us, but that's the color I would give to you is that they're definitely improving with time. Brian Singer - Goldman Sachs & Co.: Thanks. Maybe I'll ask it in a slightly different way then, since you talked about the targeting and the enhanced completions specifically. What inning do you think we're in, in terms of the impact that those technological improvements are having on your productivity?…

We'll go to Irene Haas with Wunderlich. Please go ahead.

Following up on the Delaware Basin, your inventory count of about 2,130 wells, I'm curious as to – for the Wolfcamp. I think mostly in Wolfcamp A, and you're doing work on the deeper horizons. Are there more headroom to add locations without really adding more acreage? David W. Trice - Executive Vice President-Exploration & Production: Irene, this is David. In the Wolfcamp, really what we've targeted mostly there, we've got several targets in the upper Wolfcamp, so there are quite a few premium targets. Like Bill mentioned earlier, we're still early in the Wolfcamp, so we still see quite a bit of upside there. But clearly from the data that we show, like on the chart seven in our investor book, we've made some big progress there. These are clearly premium wells. As we go forward, we're going to have the ability to drill more and more of them with longer laterals.

A follow-up question, I was wondering. How far are you along with your database, how many wells you have inputted in your position targeting model? Do you use existing vertical wells, horizontal wells, and core samples? I'm just trying to get a feeling as to how much more data you might need to really nail it perfectly. David W. Trice - Executive Vice President-Exploration & Production: There's a lot of industry data out there, legacy log data and everything that's helped us with that. But really what's going to drive it more than anything is, as we drill the wells and complete them and gather the data over time, you'll continue to see some improvement there. Just like you've seen, we never stop learning. We've continued to test the limits, and so I still think there's plenty of upside on the Wolfcamp.

Great, thank you.

We'll now go to Bob Brackett with Bernstein Research. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: I had a high-level question and then a follow-up. The high-level question is, it looks like you've added, say, 34% to your net locations, to premium, but the average EUR went up 75%. What's driving that? William R. Thomas - Chairman & Chief Executive Officer: Really, Bob, it's just the combination of better rock and better completions, and now we're going to add longer laterals to that too. So the well results, the productivity of the well increase is just very, very large and incredible. I think once there's enough of this data out in the big databases where people can analyze it and compare EOG wells versus the industry or really any other operator drilling horizontal oil wells now, they're going be very, very surprised and very, very impressed. We do have one chart in the slide deck that compares our Wolfcamp results to other operators. I believe it's slide number eight. So you might want to look at that, but the wells are just fantastic wells. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. The follow-up is, could you talk a little about the process by which a location moves or gets blessed as premium? Is that done by the asset? Is it blessed by headquarters? Is it statistical, or is it sticks on a map? William R. Thomas - Chairman & Chief Executive Officer: It's a process that really is done in our division offices. So our decentralized culture that's focused on the details right there, they're evaluating the rock, driving the costs down at the same time, and executing on the wells. They know their properties the best, and they are constantly working. And they are so focused on improving returns and improving productivity and driving down cost. So they're really driving this whole thing, and it is an amazing performance that's going on. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: And there's sticks on a map there. Those locations are known lat/longs [latitude/longitude]? William R. Thomas - Chairman & Chief Executive Officer: Absolutely, yes. The well count are absolute sticks on a map. They all have a well name. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: Yes. William R. Thomas - Chairman & Chief Executive Officer: So they're not like a spreadsheet. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: Great, thank you.

We'll go to Mike Scialla with Stifel. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Hi, good morning. Bill, you said in your prepared remarks that the minimum 30% IRR for premium wells translates to a healthy corporate rate of return. Is there a minimum ROE you can equate that to, or does that necessarily translate to positive earnings? William R. Thomas - Chairman & Chief Executive Officer: We picked the 30% because when you pull in our full-cost of capital, which would be infrastructure, land, G&G (53:22) and things like that, it usually draws the return down to maybe 15%. So we would like to have a minimum full-cost all-in call it capital cost rate of return of about 15%. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Okay, thanks. And then, Billy, you mentioned in your prepared remarks you're seeing no degradation in productivity per foot with these longer lateral lengths. I guess is there anything specific there without giving away the trade secrets that you can talk about, maybe bigger casing size or something like that that's preventing that degradation in recoveries per foot with the long laterals? And I was wondering too, you mentioned the Eagle Ford and the Delaware, where you're going with the longer laterals. On the Eagle Ford side, is that really confined to the western portion of the play, or does it have any application in the east as well? Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Mike, this is Billy Helms. So on the Eagle Ford, first of all, for both the Eagle Ford and the Delaware Basin, when we drill a longer lateral, we definitely want to make sure that we are maximizing the recovery. We're not losing efficiencies as we just drill longer laterals. So…

Okay. Our final question today will come from Paul Sankey with Wolfe Research. Please go ahead.

Hello, guys. Sorry, guys, just a quick one I'll add after all you said. I was asked this morning what would happen at $40 flat to all your assumptions? Thanks. William R. Thomas - Chairman & Chief Executive Officer: Paul, at $40, we would adjust our capital appropriately, and we would be able to generate what we believe would be the best rates of return in the industry. That's certainly a big separator for EOG. But we would adjust our spending to cash flow and stay balanced and stay disciplined and hunker down and continue to improve. We are optimistic and we have hope, and we're not there yet, but at one day, we would be able to get our capital efficiency to a point where we could actually grow oil at $40, and we're working towards that goal. We're not there quite at the moment, but we're going to continue to focus on that. But our focus, of course, first, has always been on returns and capital discipline and keeping the company healthy in that regard.

I've got the feeling it's just a couple of minutes and it's a long question, but could I just follow up? Could you walk us through the progression from the field level returns that you talked about after tax to the corporate level returns? I don't think anyone has asked that one, which is always a conundrum as it regards to U.S. E&P. William R. Thomas - Chairman & Chief Executive Officer: Yes, I did talk about that a little bit earlier. But we did put the benchmark of 30% rate of return on the direct side, which is the well cost only. We set that at that mark so that we would have room that when we put in full cost, that would be land and seismic and infrastructure, our capital rate of return, not ROCE or ROE, but our capital investment rates of return would be about 15%. Now that walks down – it's a long process, but that walks down to ROE and ROCE. But the ROE and ROCE are trailing metrics. And it takes years to get your base production to the point where it reflects the returns that you're currently drilling. So it's a long process; it takes several years to get there.

It's the top of the hour, I'll leave it there. Thank you.

And at this time, I'd like to turn the conference back to Mr. Bill Thomas for any additional or closing remarks. William R. Thomas - Chairman & Chief Executive Officer: Yes, I'm going to ask Gary Thomas to add some remarks on our progress on cost reduction and where we see that headed.

It goes along with the last question there, and also, yes, us being competitive on the world market as it requires that we really be disciplined in spending and that we just continue to work our costs down. And that is, yes, through just all the primary efficiencies we've mentioned earlier with us having the top rigs. And you'll note too that we had quite a number of our rigs in 2016 under contracts placed a couple years ago, higher rates, $26,000 and $27,000 a rig. Now those are rolling off, and we're going to be able to replace those, about half those rigs with rates that are in the $13,000 to $15,000 per day rate. So that allows drilling costs to be down about 20% – 25%. Our tubulars, we depleted their inventory here early 2017. And with the arrangements we have in place, that will allow those costs to go down in the 20% to 25%. With our sand, as I mentioned earlier, we've reduced our production costs, optimized the transportation, just all of those sorts of things that allow us to reduce sand cost by about 15%. Same with rigs, we had many of our frac fleets under long-term contract. Half those are going away, which will allow us then to bring in the lower frac rates. We've continued to improve completion efficiency with faster completions, wireline run times, just our stage arrangements. The water infrastructure has continued to be enhanced, and it allows us to reduce our water costs. Our wellhead inventory, it's somewhat depleted, and that will allow us to reduce those costs in the 25% range. So all of this, and that probably accounts to 50% to 60% of our well cost, allows us to further reduce well cost here going into 2017. Yes,…

Thank you very much. That does conclude our conference for today. I'd like to thank everyone for your participation.