Good day, everyone, and welcome to the EOG Resources first quarter 2018 earnings conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you, good morning. Thanks for joining us. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release in EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliations for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. Some of the reserve estimates on this conference call may include estimated potential reserves, not necessarily calculated in accordance with the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings press release issued yesterday. Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, President; Billy Helms, Chief Operating Officer; David Trice, EVP Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; and David Streit, VP, Investor and Public Relations. This morning we'll discuss topics in the following order. Bill Thomas will review our corporate strategy and cash flow priorities. I'll cover our capital structure and dividend outlook. Billy Helms will cover first quarter operating and financial highlights, and Ezra Yacob, Lance Terveen and David Trice, will review asset levels results and marketing developments across our most active plays. Then Bill will provide concluding remarks. Here's Bill Thomas.

Thanks, Tim. Good morning, everyone. EOG is a disciplined, high-return, organic growth company. Delivering high returns and strong growth is a rare combination not often found in any industry. With our low-cost organic exploration expertise, the company is currently developing nine premium geologic plays across six basins in North America. The power of our premium-only drilling strategy is reflected in our first quarter performance. We earned a company record direct after-tax rate of return of 150% on $1.5 billion of total invested capital. The ability of EOG to generate 150% direct after-tax rate of return on that much capital in one quarter is remarkable compared to any standard. Strong execution delivered volumes on the high end of our forecast, and most of our operating costs came in below targeted ranges. We are well on our way to executing our 2018 plan that will deliver 18% oil growth and generate over $1.5 billion of free cash flow at $60 oil. We believe disciplined reinvestment of cash flow and high rate of return drilling is fundamental to creating significant long-term value. We've been very consistent and clear about this priority for our cash flow. We believe it is by far the most shareholder-friendly decision we can make. Disciplined investment in premium oil, defined as having strong returns at $40 oil, allows EOG to deliver strong oil growth with free cash flow at $50 oil and substantial free cash flow at $60 oil. Along with reinvesting in high return wells, we've outlined the following priorities for utilization of free cash flow. First, an impeccable balance sheet is fundamental to a commodity-exposed business. Having low debt strengthens the sustainability of our dividend and maintains our investment flexibility through the volatility of the commodity price cycle. Concerning flexibility, let me be clear on one point.…

Thanks, Bill. Over the last three years, we have reset the company to thrive at much lower oil and gas prices. As a result, we are uniquely positioned to generate a meaningful amount of free cash flow. EOG now has the opportunity to take the next steps to further strengthen the balance sheet and increase the rate of dividend growth. Currently, our balance sheet is strong at 28% leverage and $6.4 billion of total debt. Our target is to further reduce total debt by $3 billion. The $3 billion of debt reduction is a prudent target in a cyclical capital-intensive business. We expect to achieve that target over the next several years by repaying bonds as they mature, using cash generated from operations. This measured pace of debt reduction provides room to fund strong dividend growth. We were pleased to make it through the last downturn without cutting the dividend and without a dilutive equity offering to shore up the balance sheet. Whatever future commitments EOG makes must be sustainable for the long term. This means we must consider the strength of our balance sheet and the sustainability of the dividend through low commodity price scenarios, not just against the rising level of oil prices that exists today. The dividend is an important element of EOG's financial strategy. We've increased the dividend at a compounded annual rate of 19% since 1999. With a lower breakeven cost structure and a strong balance sheet, we're now targeting a dividend growth rate that exceeds the 19% historical rate. Our dividend growth strategy signals our confidence in the future profitability of the company, provides shareholders with a tangible form of return on their investment, and imparts a measure of discipline on the organization. EOG creates shareholder value through operations and not financial engineering. A strong financial position is a competitive advantage as we seek to sustain our performance through the volatility of the commodity price cycle. The company can do this with a straightforward financial structure and an impeccable balance sheet. This will leave EOG positioned to keep its financial commitments in future downturns, including sustaining a more ambitious dividend. Up next to provide details on our operational performance is Billy Helms.

Thanks, Tim. 2018 is all about maintaining our disciplined capital growth program. In the first quarter, we delivered at or above our production targets and have laid the groundwork to deliver our forecasted well cost targets. We are maintaining our full-year capital guidance of $5.4 billion to $5.8 billion, growing oil production 18%, growing total production 16%, reducing well cost 5%, reducing debt, producing free cash flow, and most importantly, delivering double-digit return on capital employed. There are a number of operational accomplishments from the first quarter I'd like to highlight. We increased activity earlier in the year and are now operating about 40 rigs across six basins. We still expect to average about 39 rigs for the year. Our operating teams in each area are quickly moving the new rigs in our fleet up the learning curve to deliver sustainable efficiency improvements that will yield benefits the rest of the year. In our larger development programs, we moved to larger packages of wells with longer laterals, completing more than 150 net wells with over 30 of those brought to sales in the last week of the quarter. About two-thirds of the wells in the Delaware Basin were in packages of six wells or more. In Eagle Ford, over half the wells were in packages of five wells or more. In the coming quarters, we will be competing several 6 to 10 well packages in both plays, which will improve our operational efficiency and maximize the net present value of our acreage. Initiating this development from larger multi-well packages results in a production profile that is more weighted to the second half of the year as can be seen in our full year production guidance. As a result, we anticipate that our growth will be more heavily weighted to the…

Thanks, Billy. The Eagle Ford continues to prove itself quarter-after-quarter as a world-class oil play and EOG's premier asset. In the first quarter, we brought 72 wells online with average spacing of about 300 feet and average payout of seven months. We believe this operational and financial performance in the Eagle Ford is unmatched in the industry. We increased our rig count to 11 in the first quarter and realized a 5% increase in footage drilled per day, accompanied by a 5% decrease in cost per foot. Not to be outdone, our completions team also increased operational efficiencies and is forecasting further cost savings with the addition of local sand sources. Wells on the eastern Eagle Ford acreage position averaged 1,810 barrels of oil equivalent per day for the first 30 days online and wells on our western acreage averaged 1,375 barrels of oil equivalent per day for the first 30 days. While the wells in our western acreage position have lower initial rates, the combination of less faulting and our contiguous acreage position allows for consistently longer laterals than in the East, which drives operational efficiencies. Therefore, the wells across our entire 520,000 net acres in the oil window are all equally competitive on a rate of return basis. The Eagle Ford is a key contributor to flexibility of our diverse portfolio of assets providing the company many options. We modeled several growth forecasts assuming no productivity improvements or cost reductions. If we chose to pursue more growth in Eagle Ford, our current inventory of well locations and large acreage position would support more than 10 years of development. No North American basin compares with the Eagle Ford for low transportation cost and access to Gulf Coast pricing. Currently, 85% of our oil production in this basin flows through…

Thank you, Ezra. I'd like to bring everyone up to speed since our last call on EOG's pricing mix for our crude oil and natural gas sales in the Permian, infrastructure buildout and takeaway positioning. Our 2018 Delaware Basin oil and natural gas production will have minimal exposure to in-basin pricing. Only 25% of our in-basin crude production is exposed to Midland pricing. This translates to less than 10% exposure for EOG's total U.S. oil production. Furthermore, we supplemented physical capacity with additional price protection with Mid-Cush basis swaps. On the natural gas side, less than 20% of in-basin production is exposed to Waha Hub pricing, which translates to about 5% exposure when viewed on a total U.S. production basis. We are in similar shape for our Delaware Basin production next year. Only 20% of crude production is exposed to Midland pricing and about 20% of natural gas production is exposed to Waha, which is manageable risk when viewed on a total U.S. production basis. So we're in great shape, and historically we have always been able to consistently anticipate the infrastructure needed to support growth. Similar to our past experiences in the Barnett, Bakken, and Eagle Ford, an early-mover strategy in the Delaware Basin is paying off. We've successfully diversified our marketing options with physical firm takeaway to protect flow assurance and benefit from higher price realizations for both crude and natural gas sales. Please see slide 18 of our investor presentation for a history of our industry-leading oil price realizations. On our last earnings call, we referenced the new Conan Oil Gathering system and terminal. This system has been in the works since 2016 and was placed into service on schedule during the first quarter of this year. Between the gathering system and short-haul dedicated truck offloads, we…

Thanks, Lance. Well costs continue to drop for our Rockies plays. The efficiency gains we are making in both the Powder River Basin and DJ Basin are astounding, particularly considering they are in addition to the incredible progress made last year. In just one quarter, we have reached and beat well cost targets in some of our Rockies plays. Tremendous progress has been made in both drilling and completions to reduce days on location that translate directly to cost savings. Overall, drilling days are down 70% since the beginning of the downturn in 2014 for the DJ, Powder River Basin, and Williston Basin. This is a powerful testament to the great sustainable efficiency gains our teams have made during the last several years. Recently, normalized spud-to-TD drilling days in the Powder River Basin are down from 9 days on average in 2017 to about 7.5 days for the first quarter of 2018. During that time, completion efficiencies have more than kept pace with drilling. Stages per day and footage per day are up a whopping 50% in the first quarter versus the 2017 average. This includes a record day in the DJ Basin of 26 stages pumped on a four-well pad in a single 24-hour period. That record-breaking pad averaged 21 stages a day for the entire job. Our cost performance in the DJ Basin Codell has set the bar for the rest of the company. Some notable wells that we highlighted in last night's press release are the three-well Flatbow package that IP-ed at over 1,300 barrels of oil equivalent per day from 3,900 foot laterals, and averaged just $2.9 million per well. We also turned on a four-well 9,500-foot Big Sandy package that averaged over 1,300 barrels a day equivalent per well, with a well cost of $3.5…

Thanks, David. I have a few closing thoughts. Number one, our first quarter results have positioned EOG to have record-breaking direct rates of return on capital investments in 2018. We are going to remain disciplined and stay focused on improving returns going forward. Number two, we're on track to continue reducing both operating cost and well costs. Number three, with our diversified assets, forward-looking marketing arrangements, and advanced infrastructure planning, we are in excellent position to avoid any significant takeaway issues or negative product price differentials in the Permian or in any of our other active plays. Number four, with two decades of horizontal experience and technology advancements behind us, we are developing sweet-spot acreage positions with our latest precision targeting techniques and determining optimal spacing patterns to produce industry-leading well results and per acre net present value. And finally, EOG has never been in a better position to deliver long-term shareholder value. We have the largest and highest quality drilling inventory in the U.S., and it continues to grow much faster than we drill it. We are a low-cost leader today and we will continue to lower costs as we go forward. We are delivering record-setting returns on capital invested, improving corporate ROCE, along with strong production growth and substantial free cash flow. EOG is a high return organic growth company delivering sustainable long-term shareholder value. Thanks for listening and now we'll go to Q&A.

Thank you. And our first question, we'll hear it from Arun Jayaram with JPMorgan.

Good morning. Bill, no one's going to fault you for wanting to reduce your debt or increase your dividends over time, but I did want to ask you one question. As you execute your premium drilling strategy, your returns on capital employed are now moving into the double-digits, and I was wondering if you could talk about weighing a buyback above your cost of capital versus reducing debt what looks to be in the 6% to 7% range?

Arun, we're committed to doing what's right for the shareholders. Our senior management team and our board are significant EOG shareholders and we're aligned with investors. And we're constantly evaluating what's best to create long-term shareholder value. Currently, with the improving commodity prices, we believe investing in high returns and reducing our debt and strong sustainable dividend growth are the best ways to create long-term shareholder value. So at the moment, we're very confident in that plan and we believe that will be the best avenue to create shareholder value.

Great, great. And just reduction in debt, does that suggest maybe keeping some dry powder for as you execute your exploration drilling program or to look at potentially other opportunities like you did with the Yates package?

Arun, we don't plan any corporate M&As. That's just not one of our game plans. As you know, we're a very organic company. We've got a lot of confidence in our organic exploration effort, and corporate M&As or just something that would be really not in our game plan at this time.

Great, thanks a lot. Thanks a lot.

And next we'll move to Bob Morris with Citi.

Thank you. A bit of a follow-up here, Billy, you've always said that you would spend 100% of your cash flow unless you saw some sharp degradation in efficiencies, and obviously $1.5 billion of excess cash flow is quite a significant amount. You starting out the year what you plan to average for the full year on the rig count, so what precludes you from stepping up activity or adding some rigs in some of these key areas given the sort of returns you're seeing here as we move through the year?

Bob, this is Billy Helms. First of all, we remain committed to stay within our capital guidance. We're very much on track with our plan as we laid it out. Actually, our rate of capital spend is directly in line with what we laid out at the start of the year. And we've already talked about the benefits of moving to these larger packages of wells. And as a result, the front end of the year is more loaded towards capital spend with the production more weighted towards the back half of the year. So, at this moment, yeah, we're very pleased with where we are headed and we don't really anticipate increasing activity above where we currently are. We're still guiding towards that average rig count of 39 and staying within our capital guidance.

Okay, great. Thank you.

And we'll hear from Irene Haas with Imperial Capital.

Yes, good morning. So I have a question for the Eagle Ford trend which you guys definitely was the first mover, and it's been going on nine years, I was wondering what is the organic growth rate for this trend in 2018. And also regarding the Austin Chalk, I want to understand what are the key gating factors that would lead you to fully develop this concept, and when would the Chalk be a meaningful contributor to your Eagle Ford trend growth.

Irene, this is Ezra Yacob. And I don't think we're going to spend any time today guiding to the direct growth on that asset right now. But what I will say about the Eagle Ford is the upside we see there just involves our continued progression of integrating the data that we've collected over the development cycle that we've had there. We continue to integrate both high-graded geologic mapping completions data back into of our geologic model, and it helps kind of drive our precision targeting as we develop even finer scale and high graded targets. And then also with respect to the Austin Chalk, we've gone a little bit slow making announcements on that because, geologically, it is a bit more complex than the Eagle Ford. I would say that it already is contributing in a pretty good way to not only our returns but also in 2017, both the Eagle Ford and Austin Chalk actually showed just a little bit of growth year-over-year. And so we're happy with our pace of development there in the Austin Chalk and when we have more information on that, we're a little more comfortable with it, we'll provide greater detail.

Okay. May I ask one more question? So are you generating organic growth out of the Eagle Ford and Austin Chalk trend in 2018?

Irene, without getting into specific details, we do plan to grow that asset this year.

Thank you.

We'll be doing that at a pace...

Sorry?

I was just going to finish up and say, we'll be doing that at a pace commensurate with where we can go ahead and continue to integrate our learnings, and do that really with a focus on returns first.

Understood, thank you so much.

And next we move on to Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co. LLC: Thank you, good morning.

Good morning. Brian Singer - Goldman Sachs & Co. LLC: I wanted to start on the well cost front. How can we define the more secular versus timing impact of your ability to use your scale to gain preferred services pricing exposure? Specifically, if you're not seeing the inflation in cost in 2018 because you locked in services cost early, what level of inflation would we see in 2019 when you need to recontract, or is there a quantifiable secular advantage?

Yes, Brian. This is Billy Helms. What we can give you is – it's a little bit early to talk about guiding for 2019. So let me give you a little bit of color on where we are for 2018. First of all, as you're aware, we locked in about 60% of our well cost with the services we have locked in so far, with drilling really preferred providers on the drilling side and the completion side. And we self-sourced quite a bit of that too, about 25% of well cost is self-sourced. So the progress we're making and I guess the confidence we would have in lowering our well cost in 2018 – we talked a little bit about how we're lowering cost in each one of the plays, I think for Permian, we added quite a few rigs and so we're starting to see the operational performance on those rigs get to the metrics that we like to see in our rig fleet. Completions are already down about 2.3% for the first part of the year. On the Eagle Ford, of our drilling cost is already down about 5% and the completions are expected to follow. And then we've made tremendous progress in the Rockies, both on the drilling and completion side, in lowering our well cost anywhere between 4% and 5%. So I think overall, we're very pleased with where we're headed. And we have a long history – just speaking of 2019 again, we have a long history, each year as we go into the year, we anticipate what the trends are going to be and we get ahead of them and try to work with our preferred providers to lock up some services for the coming year. And I expect 2019 will be done the same way. It's a little bit early to really guide on where we'll be, but we're very confident that we'll be able to maintain our cost advantages as we go into the next year. Brian Singer - Goldman Sachs & Co. LLC: Great, thank you. And my follow-up goes back to the earlier discussion on the Eagle Ford, and I'm going to be trying to tie Bob and Irene's questions together. What would you need to see either in capital availability, rate of return or confidence in that precision targeting to allocate more capital to Eagle Ford? And do you need to exhaust your financial goals of reducing debt by $3 billion and delivering on that above 19% dividend growth before you would do that?

Brian, this is Ezra again. Like I reiterated, I think we're happy with our plan and we're happy with where we're at, kind of executing on it and we're on track with it. As far as adding additional capital or redirecting capital to the Eagle Ford, I think – without guiding into future years, we have definitely run through a number of different forecast growth models, like I talked about in the opening statements, where if we choose to actually grow more aggressively there, we can certainly do that and we have the inventory and acreage position to do that for over 10 years at high returns. But as far as doing it within the year, I think it's safe to say that we're pretty happy with where we're at with our balanced approach across multiple basins to achieve our CapEx and volume growth goals for this year. Brian Singer - Goldman Sachs & Co. LLC: Thank you.

And we'll move on to Doug Leggate with Bank of America.

Well, thanks and good morning, everybody.

Good morning.

Bill, I wonder if I could go back to dividend policy, capital discipline, share buyback discussion or – not so much of last part. But I'm just – looking at the dividend policy going forward, what do you see is the competitive metrics, what's kind of the end game you're trying to get to there? And I just want to be clear on the $50 to $60 range you gave, I guess, a year or so ago, is $60 as a budget a kind of hard stop, so you should think of anything beyond that as going towards the balance sheet? And if that's the case, what happens longer term as it relates to incremental, let's call it, windfall cash flows?

Doug, I don't think we have some hurdle rate on the oil price. We've really reset the company to be very successful even in moderate prices going forward. And so the company is in a fantastic position now to make, I think, a strong statement to say that we're in a position to more aggressively grow our dividend than we ever have in the past. And we believe that our dividend is sustainable through the commodity cycles. And so the company is just in a fantastic position to both systematically reduce our debt and to grow our dividend very aggressively and sustainably in most commodity price situations.

No question on the reset, I appreciate you tolerating another question on that issue. My follow-up is really on inventory. And I'm not challenging the discipline of the $40 hurdle for premium locations, but obviously some of the market may have a different view as to what the sustainable oil price is. And the question is really about inventory relative to your growth pace. If we had to run at $45 or a $50 number as the threshold for premium inventory, how would it change over the disclosure you've given so far? Does it go up 10% or does it double? And I'll leave it there, thanks.

So I think first of all, we don't have any plans on changing our criteria. We're going to stick with $40 oil and $2.50 flat. That needs to be really clear going forward. That is a fundamental thing with EOG. If you looked at our entire inventory, which is quite substantial, I would say pretty much all of it would be 30% or better rate of return at $50. So it's a very high-quality total inventory. The inventory that we have in the company that's non-premium at $40 would be, I would say, equal to or better than the average inventory of the whole industry. So it's a very high-quality inventory set. And we have a lot of confidence that we'll continue to make improvements on the non-premium inventory and bring it to a level to where it will classify as premium at $40 oil. So we've got, again, a very sustainable cost reduction. It's not just a one-year thing. It's a very consistent cultural attribute of the company. And then we have a tremendous ability to continue to improve well productivity at the same time. So our goal is to convert a lot of that non-premium inventory into premium inventory as we go forward.

Thank you, Bill, very clear.

And we'll move on to Scott Hanold with RBC Capital Markets.

Thanks, good morning. Could I ask another question on your increasing the dividend rate versus the long-term rate? Is there a particular yield that when you guys step back would like to be at? It looks like you guys are running somewhere sub-1% right now, and some of the large peers are in that 1.5% range. Is there a target rate you'd like to see EOG at?

No, Scott. We don't have a specific target other than just to say that on a percent increase on a yearly basis, we want to be above our historical average of 19% CAGR. So that's where we want to guide as we go forward. And we certainly, as I said before, we've got the ability to do that at relatively moderate oil prices and sustain that going forward.

Okay, I appreciate that. And a little bit more on – it seems like you're definitely more front-end CapEx weighted, as you said, and in the back half ceasing that production. Can you talk about the cycle times that some of these larger Permian pads have? It looks like you averaged about four in the first quarter moving to five, but can you discuss maybe what those cycle times look like as you move from two to four to five?

Scott, this is Billy Helms. The cycle times, of course, vary by play. So in the Eagle Ford, it's a much shorter cycle time than, say, the Delaware Basin, just strictly because drilling times are much longer. And it also depends on the size of the pads. So certainly a 10-well pad might be a lot longer to cycle time than a 6-well package. And then it also depends on how many rigs and frac fleets we put on each package. So it's hard to give you, directionally, a certain number other than to say it takes several months to start drilling a pad – or a package of wells and bring that whole package to production. And as a result, it results in some lumpy nature of both capital spend and production. And that's why you see the production growth vary by quarter. And it's also why as we entered the year, we obviously had to build some inventory to be able to execute this plan, so the capital guidance is more weighted towards the front of the year than the second part of the year. And that's just the lumpy nature of this development.

Is that smoothed out in 2019 as you catch up with that inventory?

Yes, I think you'll still see a lumpiness to the overall production growth. But you won't see, I'd say, the delay we exhibited in the first quarter on a go-forward basis. You'll see it more just growth quarter-over-quarter as we move through the future.

I appreciate that. Thanks.

And next we'll move to Leo Marinari (sic) [Mariani] with NatAlliance Securities.

Hey, guys. I was hoping you could address the Austin Chalk a little bit more. I know that you said that you're not trying to make extensive comments. I'm just trying to get a sense of the inventory there. It sounds like this is one of the best returning plays you guys have. Just curious, is this a couple years inventory, or is there a similar 10 years like the Eagle Ford?

Leo, this is Ezra Yacob again. It's just really still pretty early in in the Austin Chalk. We are still doing a lot of testing on our well spacing, trying to determine the optimal spacing, how many precision targets we have in there. We've talked about in the past that it is different than the historical Austin Chalk play. It is a matrix – contributing kind of a matrix drive play. And so it's not quite as straightforward to use a lot of those historical learnings. The way we're developing it is different and it's unique. I'd say the initial productions look good. I know it seems like we put a lot of wells on but we'd like to be confident before we really come out with any detailed numbers on that. And like I said, when we have a little more detail on that, we'll certainly talk about it.

Okay, that's helpful. And I guess I just wanted to follow up on the Eagle Ford. You guys talked about some of the differing production rates you saw in the first quarter on the eastern wells versus the western wells, but then cited that returns are pretty similar. Just curious, does that kind of imply that maybe your well cost in West are lower than the East, what can you say sort of say about that?

Leo, it's Ezra again. I think you hit the nail on the head there. The cost per foot – I tried to highlight in those opening remarks the contiguous nature of the western Eagle Ford acreage and a little bit less faulting out there, allows us the opportunity to drill longer wells and larger packages. It's a little bit less pressured and less shallow too. So in general, the costs are a little bit cheaper there. In the eastern Eagle Ford side of our acreage position though, we usually have wells with a little bit more robust rates, a little bit bigger wells, but it is a little bit more challenging drilling over there. It's a little bit deeper, a little bit extra pressure. And then in general, the well lengths tend to be just a little bit shorter due to both the layout of specific leases over there, but then also there's an increase in the faulting off to that eastern side.

Okay, that's helpful. And I guess just quick question on your dividend here. You talked about increases in the future. Should we expect to see a increase here in 2018? Are you more talking about evaluate that for 2019 and beyond?

Leo, we don't have any specifics on timing. Our board evaluates the business environment every quarter concerning the dividend. And I think what we're saying is we believe EOG is in the best shape we've ever been for sustainable, more aggressive dividend growth. So our board is eager to return cash to shareholders with a strong dividend growth.

Thank you very much.

And next we'll move to Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: Yes. Good morning, Bill, to you and your whole team there. You've covered this a little bit already in your comments in the Q&A, but I just want to go back to the comments you made in your opening when you said you had no interest in corporate M&A. And that's certainly been the pattern for you guys, with the one prominent exception of the Yates deal. And that was really a brilliant deal for you guys but I'm trying to understand a little bit more, is the Yates deal the exception that's not likely to come along again or should we be interpreting that you see the market or the opportunities differently from the way you did at that time?

I think, Charles, what we are saying is that we've got extreme confidence in our ability to organically add new high potential at very low cost through our exploration efforts. In general, I think this year, we have a very robust exploration effort ongoing. And we've acquired a significant amount of low cost acreage in multiple plays, and we're testing numerous new plays with exploration or step up drilling this year. And so our organic machine is really in high gear and we have a lot of confidence in it. And we believe we can acquire significant, hopefully, even better drilling potential than we currently have through that process at very low cost. Charles A. Meade - Johnson Rice & Co. LLC: Got it. That's helpful, Bill. That's all for me. Thanks a lot.

And we'll move on to David Heikkinen with Heikkinen Energy Advisors.

Good morning, guys, and thanks for taking my question. We appreciated the details that you put on slide 21 around your diversified marketing options. Can you talk more specifically about firm sales, firm transportation, financial hedges and then balance of avoiding those long-term contracts that I know EOG doesn't want?

David, this is Lance Terveen, and thanks for your question. Let me start and answer your last question there, when you talk about commitments. I'll tell you all of us in this room, we've seen the Barnett, the Haynesville, the Uinta. And so when we think about long-term commitments, it's really twofold. It's we want to have near-term flow assurance; and two, we just want to be very disciplined about any kind of long-term commitments. And what we think that does when we can kind of have that first mover and we can identify it, where we need to identify transportation and access to get to markets, at that point, we really make good business decisions, because a lot of folks are going to be waiting for new pipelines that are going to be starting out in late 2019 and probably into 2020. And what happens when there's a lot of hype and especially very active area like the Permian, with 453 rigs running, it's just – it's not a panic that comes in but people are looking for capacity. So we want to get out in front of that like we've done and like what we've shown. So for us on the commitments, it's really – it's just being very disciplined, have a balanced approach, get in front of it. And the second thing with that, it allows you to have more discretionary volumes and it allows you to look at other projects, and other things that can come available at even lower rates. So getting in front of that and having some of that near-term assurances really sets us up in the future to lock in other markets or also look at lower transportation costs.

Any specific kind of split

Go ahead, David.

Any specifics of splits as far as you think about that flow assurance of marketing agreements, either firm sales, firm transportation? Because you might have done these contracts or terms two years ago, three years ago, I'm just trying to get an idea of how you think about splitting marketing agreements, pipeline agreements, hedges, just in that kind of forward-looking process (55:07).

Sure, sure. Again, it goes back to our experiences and what we've seen in other basins and as we've looked at making commitments and transportation commitments. So again, when we look at that and we look at the forward forecast and where we think each of the basins might be growing, especially like a new emerging basin. So typically, we want to lock up anywhere from maybe 70% to 80% of that near term and leave kind of more available in the outer years. So really with the crystal ball, when we're looking at making the commitments, we try to protect more of a, call it, the first three years. And then if we need to make medium-term commitments, then those commitment volumes are a little smaller in the outer years. So that's strategically how we think about the commitments, David.

Yeah, so cut a three-year and roll. Okay, that's helpful. Thanks, guys.

And we'll move on to Jeffery Campell with Tuohy Brothers.

Good morning. I just wanted to ask for a little bit color on the Woodford oil. I noticed that you've added a rig and you drilled quite a long lateral there, which is usually a sign that you're more into development than into delineation. And it seems like this play has really accelerated in a reasonably short amount of time. So I just wanted to just check in on that.

Jeff, this is David Trice. On the Woodford, yes, we have picked up additional rigs there. We are running four rigs currently there. And what we're doing this year is, one, we're securing operatorship on all these units, and then also we're doing several spacing tests there. So what we want to really focus on in the Woodford this year is we want to – like in our other plays, we want to really confirm the correct spacing so that we can be sure to maximize the NPV per section there.

And if I could just follow up on what you just said, what's your – if you look at your position as a whole, what percentage of it can you operate now and what are you trying to get to?

Really most of the 50,000 acres net that we show we would be able to operate that. We have quite a few trades going on where we may not have a majority interest. And so we think at the end of the day, we'll be able to operate the entire position.

Okay, great. Thanks for the color.

And next we'll move to Bob Brackett with Bernstein Research. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Thanks for taking my question. I'll follow up a bit on the Austin Chalk. If I divide the Austin Chalk into the Karnes Trough into Louisiana and into everything else, where's your sense of how mature your understanding of those plays are right now? And where is the upside on each of those?

Bob, this is Ezra Yacob. Let me start with the Karnes Trough area down in the South Texas trend. Now like I said, we brought to sale last year a number of wells and we're very happy with the initial rates on there. And again, it's a new concept on the play that we have been working over the last couple of years where we're basically applying our precision targeting, our petro-physical model in combination with our seismic attributes to upscale and model these precision targets that actually have matrix contribution. And then we're applying some of our high density frac designs, things that we've developed in these different basins -or different unconventional plays, basically to the Austin Chalk. And so we're really happy with it. I would say where the upside resides down in South Texas is continuing to delineate targets, high grading those targets and again, kind of the continued evolution of our frac designs. It is the Chalk, so it does – each of these plays that we're in, whether it's a carbonate, siltstones, mudrocks, as you know, little tweaks on your completion design can make a big difference. And so the biggest upside I see with the Austin Chalk is just that, advances – continued evolution and advances on our completions, delineating additional targets. And then in Louisiana, it's very early on that prospect. I think everyone knows that we've drilled a very successful Eagles Ranch well out there. We're very pleased with the initial results on there and we'll provide further details on that on future calls. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: And elsewhere, is the Austin Chalk trend, should we think of it working along the entire trend or do you need sort of local structures to help you out?

This is Ezra again, Bob. Yeah, the way I'd follow up with that is I'd say there are definitely going to be sweet spots. That's obviously a widespread play from Mexico all the way up around Gulf Coast there. Just like any big regional unconventional play, there are going to be sweet spots in different parts of that area. There are different attributes geologically and geophysically, including structure is one of them, that we're looking at to high grade those areas. But any additional color than that, I'm not sure if we want to provide today. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Great. Appreciate it.

And that will conclude today's question-and-answer session. At this time, I would like to turn the call back over to Mr. Bill Thomas for any additional or closing remarks.

In closing, I want to say thank you to every EOG employee for all of your great work. Our execution in the first quarter was outstanding. We are well on our way to the delivering the best investment returns in company history. EOG is never been in a better shape to deliver sustainable, long-term shareholder value. Thanks for listening and thank you for your support.

And that will conclude today's call. We thank you for your participation.