Good day everyone and welcome to the EOG Resources 2017 First Quarter Results Conference Call. As a reminder, today's call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to Chief Financial Officer EOG Resources, Mr. Tim Driggers. Please go ahead.

Thank you and good morning. Thanks for joining us. We hope everyone has seen the press release announcing first quarter 2017 earnings and operational results. This conference call includes forward-looking statements. The risk associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. This conference call also 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, Senior VP, Marketing Operations; Sandeep Bhakhri, Senior VP and Chief Information and Technology Officer; 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 second quarter and full year 2017 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review first quarter highlights followed by a few remarks from Sandeep Bhakhri on EOG's technology driven culture. Gary Thomas, Billy Helms and David Trice will then discuss operational results. I'll discuss EOG's financials and capital structure and Bill will provide concluding remarks. Here's Bill Thomas.

Thanks Tim. Our first quarter performance was a great start to the year. We beat our production targets and are on track to grow oil production 18% this year. As you may recall, last year we made a permanent shift to premium drilling which means that new wells must earn a minimum total weighted 30% return on direct drilling and completion capital at $40 oil and $2.50 natural gas. Our shift to premium drilling is the reason we can deliver high return double digit oil growth this year within cash flow including the dividend. Last quarter we talked about delivering this year's growth at $50 oil. We now believe we can deliver 18% oil growth within cash flow at $47 oil, a record for the company. Our premium strategy clearly sets EOG apart as one of the most capital efficient and lowest cost U.S. horizontal drillers. Our focus on growing low cost premium production will continue to drive down breakeven costs and strengthen our bottom line over time. Highlights from the first quarter include, one, both U.S. and total oil production beat the high end of our forecasts. Two, we increased our premium resource potential by 1.4 billion barrels of oil equivalent by converting 1,200 locations to premium for new total of 6.5 billion barrels of oil equivalent and 7,200 locations. That's a 27% increase in premium resource potential and 15 years of premium drilling at our current pace. Three, our Delaware Basin Whirling Wind wells set an industry all-time horizontal production record for the Permian Basin. Four, we continued to lower well costs in all our major plays and we are lowering full year operating cost guidance. And number five, the first quarter drilling program generated more than 70% direct after-tax rate of return. Generating high returns in today's…

Thanks, Bill. Good morning, everybody. We've received a lot of questions recently on our in-house information technology, our proprietary data marts and apps, and especially our use of big data and data science. I'd like to walk you through our evolution and explain how our approach is different than most and why we have three key competitive advantages that cannot be easily replicated. The first competitive advantages is data. Data is king and one of our most valuable resources, and there are two pieces to it. One, you need comprehensive, integrated and easily accessible data sets, and two, you have to own the data. You cannot outsource its collection, analysis or delivery. EOG probably has the largest, most comprehensive and integrated data sets of any unconventional operator, having collected detailed data from more than 5,000 horizontal oil wells that we have drilled in almost every major unconventional play in the United States. The second advantage is data delivery. Data delivery is key to effective decision making. Data needs to be available 24/7, anytime, anywhere in easy to use software tools. Over the past 25 years, we have built successive generations of fit for purpose software tools such that today, EOG has a suite of best in class data delivery systems consisting of 65-plus software applications covering virtually every functional area of the business. These tools power our decision making, delivering raw, analyzed and learned data 24/7, anytime, anywhere. And our most important advantage, we have been doing this a very long time, almost three decades. It's simply part of our culture. Without a culture of innovation and continual learning, technology cannot thrive. And without world class technology, innovation and learning cannot happen. It's a virtuous cycle. Culture and technology aren't built overnight. If you haven't been doing both for a…

Thank you, Sandeep. Last quarter, I talked about our cost reduction targets for 2017 and sources of savings we expected would offset tightening in the oil field services market and potential inflation. I'm pleased to report that we are on course to reach our cost reduction goals for the year, and in some basins, we've already achieved the targets set at the start of the year. During the first quarter, EOG continued to reduce costs throughout our operations. Delaware Basin completed well costs averaged $7.8 million during the first quarter, an 8% reduction from 2016. $7.8 million was our original 2017 cost target for this play, so we've set a new lower target of $7.6 million. Eagle Ford well cost in the first quarter declined 4% from the 2016 average of $4.5 million, which is already half way to our target of $4.3 million. In the Bakken, we reduced well costs 6% to $4.8 million, which is more than half way to our $4.8 million target. We updated our cash operating costs guidance for the year and in total, we expect it to be lower than initially forecast. On the production side, we beat the high end of our forecast in almost every category. Our teams working each play are executing according to schedule and plan, and the production beats are being driven by well results that continued to exceed expectations. Another notable item regarding our updated 2017 guidance, we now expect to average 26 rigs in 2017, which is three more than our initial plan for the same amount of capital. That's further testament to how ongoing cost reductions and well productivity improvement continue to drive record capital efficiency. Even with additional rigs, we are not yet changing our target to complete 480 net wells this early in the year. Additional rigs provide flexibility to our operations and allow us to reduce production lumpiness that results from developing larger multi-well pads. Several of our rigs are on well-to-well contracts, so we have the flexibility to increase or decrease wells as we monitor the macro environment and respond accordingly. I'll turn the call over to Billy Helms, who will provide you an update on our Eagle Ford and Delaware Basin plays.

Thanks, Gary. The Eagle Ford continues to deliver solid results. This world class play is increasingly being developed with larger multi-well pads, where we continue to achieve efficiency improvements that are helping to drive down costs. Our acreage is currently 97% held by production and by the end of the year we expect it to be 99%. As a result, we have even more flexibility to optimize operations using multi-well pads. We are also ringing out additional drilling efficiencies through innovative operations such as offline cementing. Improvements to drilling and completions that speed our time to first production not only lowers costs but also minimizes the impact to volumes due to downtime from nearby well shut-ins. Through a combination of cost reductions, longer laterals and advancements in precision targeting, we converted 500 net wells in our Eagle Ford inventory to premium status this quarter. That's more than two times the number of Eagle Ford wells we are completing in 2017. The total premium net count, net location count is now 2,425, representing more than 10 years of high return inventory. In addition, our G&G team continues to refine our targeting model to identify the optimal lateral placement and development spacing. With over 0.5 million acres, we have much left to understand and explore. The play changes significantly throughout our acreage, and we are working hard to delineate where the Lower Eagle Ford may have two distinct targets, and where the quality of the Upper Eagle Ford is high enough to produce premium wells. Delaware Basin is arguably the most prolific tight well play in North America, and EOG continues to deliver the best well results in the industry. See slides 13 through 15 in our investor presentation for an update. We produced a number of competing headlines with our first…

Thanks, Billy. We completed five more wells in the Austin Chalk during the first quarter, producing excellent results consistent with the well performance we achieved last June. Our Austin Chalk completed well costs are already averaging a low $5.2 million per well, delivering premium economics. These five wells produced an average per well 30-day initial rate of over 2,600 barrels of oil equivalent per day from an average lateral of 5,700 feet. The 19 Austin Chalk wells we've drilled to date along with additional core taken during the first quarter has provided tremendous insight into the Austin Chalk depositional model and reservoir characteristics on our acreage. We are still learning about the Austin Chalk and its potential. For this reason, we are not yet ready to give a resource estimate for this prolific target. In the Bakken, we continued to draw down our inventory of uncompleted wells in the first quarter. Even when loaded with higher historical drilling cost, these wells have a low average completed well cost of $4.8 million for 8,400 feet of treated lateral. During the first quarter, we completed three new wells in our Bakken Lite area using high-density completions for the first time, two of these wells targeted the Bakken interval and one targeted the Three Forks. The Ross 42, 43 and 106 came online with an average per well 30-day rate of almost 1,000 barrels of oil equivalent per day with a completed well cost of only $4.6 million for an average lateral of 7,700 feet. These wells are premium. With continued success in the Bakken Lite area, we could add to our Bakken premium inventory over time. While most of the completion activity was in the Bakken during the first quarter, we continued to make premium wells in the Wyoming DJ and Powder…

Thanks, David. We're on track for the first quarter, investing approximately one quarter of our 2017 forecasted capital expenditures. Total exploration and development expenditures for the first quarter were $966 million, including facilities of $148 million and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $34 million. Capitalized interest for the first quarter 2017 was $7 million. At quarter end, total debt outstanding was $7 billion for a debt to total capitalization ratio of 33%. Considering $1.5 billion of cash on hand at March 31, net debt to total capital was 28%. In the first quarter of 2017, total impairments were $193 million. Impairments to proved properties of $138 million were primarily the result of a write-down to fair value of legacy natural gas assets. The effective tax rate for the first quarter was 28% and the deferred tax ratio was 6%. Yesterday we included a guidance table with the earnings press release for the second quarter and full year 2017. Our 2017 CapEx estimate remains unchanged at $3.7 billion to $4.1 billion excluding acquisitions. The exploration and development portion, excluding facilities, will account for about 81% of the total CapEx budget. The budget for exploration and development facilities and gathering, processing and other accounts for approximately 19% of the total CapEx budget for 2017. We plan to concentrate our infrastructure spending in the Eagle Ford, Delaware Basin and Rockies to support our drilling programs in those areas and enhance operating efficiencies. Now I'll turn it back over to Bill.

Thanks, Tim. In closing, I'll leave you with a few important points. First, EOG's Delaware Basin acreage position and results are proving to be the best in the industry. Our record setting wells and ongoing cost reduction are generating the best capital returns and delivering the highest capital efficiency in the Permian Basin. Second, we're not just a Permian company. We are achieving premium returns and oil growth in five core plays. Every core play continues to get better and provides EOG with the largest and highest quality horizontal asset base in North America, with decades of high return growth potential. Third, as we discussed today, EOG continues to be the leader in horizontal technology. Our culture thrives on innovation, and we develop new ideas time and time again. With our extensive proprietary databases and sophisticated analytics, we are turning out new innovative ideas rapidly. We believe we are extending our leading technology faster than ever before. EOG's culture and technology advancement are a sustainable competitive advantage. Fourth, we're on track to deliver high return oil growth within cash flow. We said last quarter that we could deliver 18% oil growth within cash flow at $50 oil. With our increased confidence in cost reduction, we now believe we can deliver that 18% growth within cash flow including the dividend with $47 oil. As more and more of the low cost premium wells are brought online, our bottom line breakeven will continue to improve over time. And finally, EOG is on target to achieve our 2020 vision and to accomplish the following four goals: first, to be the U.S. leader in return on capital employed; second, to be the U.S. oil growth leader; third, to be among the lowest cost producers in the global oil market; and fourth, commitment to safety and the environment. Thanks for listening. Now we'll go to Q&A. Kim?

Thank you. Our first question today will come from Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning

Good morning, Brian. Brian Singer - Goldman Sachs & Co.: I wanted to get a bit more color on the Eagle Ford. Slide 40 shows the productivity both in both the east and the west, and you talked in your prepared comments to a number of returns-enhancing initiatives via cost reductions. If we look at, from a well productivity perspective when you take into account the benefits of targeting and data analytics that you discussed, what are your expectations for how 2017 and perhaps 2018 wells could look like in the context of slide 40? How much additional room do you see for further well productivity gains, specifically in the Eagle Ford?

So yes, Brian. This is Billy Helms. Yes, in 2017, we don't have it on the chart, as you mentioned, but what we're seeing is we're delivering consistently better and better wells in every one of our areas. On the chart we show producing days of 360 days. We don't yet, being this early in the year, we don't yet have that many days of production on our 2017 wells. That's why the slide is not updated. But generally, what we're seeing is improving well performance even though in some areas, we're offsetting some depletion in some of the patterns that we're drilling. But overall, the targeting and the high density completions are continuing to improve our well performance. In addition, we are moving, as you noted, we're moving to more and longer laterals in our patterns, and that in addition is generating overall higher EURs per well. So I think we're pretty pleased. It's still early yet to say where that's heading, but we're excited about what we're seeing to date. Brian Singer - Goldman Sachs & Co.: Great. Thanks. And my follow-up is with regards to the CapEx budget and guidance for the year. As you mentioned, you added three rigs but no additional completion activity. Can you add a bit more color on what seems like is a build-up by the end of the year in uncompleted inventory and what you would want to see or need to see to begin to complete those wells?

Brian, this is Gary. And as you said, yes, we continue to reduce our costs. So we'll drill more wells with the same CapEx guidance. We depleted our uncompleted inventory last year, and now we're just building that premium inventory. And previously, we would drill two to three-well pads. Now we're drilling five to six-well pads. With more wells per pad, that just means that we have fewer overall pads and fewer options or locations for our frac fleets. And this could be a problem if we can't find a pad to move on for some reason. So we just needed the additional pads, which means more wells for each frac fleet. Thankfully our well costs are really low, so that's just a low cost insurance for flexibility and optionality. And it's still too early in the year and oil prices are too volatile to make adjustments to our guidance. But if we can adjust readily and we can lay down rigs, we can add inventory or we can add more completions. But just our primary focus is to invest within cash flow and the highest return premium wells.

Moving on, we'll hear from Doug Leggate from Bank of America Merrill Lynch.

Thank you and good morning everybody. Bill, I wonder if I could take a follow-up to that. I guess it's kind of a philosophical question given oil is back at $46 or something like that today. You're clearly the most efficient operator in the industry. There's no question about that. But my question is what's your appetite for a 15% to 25% growth rate in this environment? Because you're giving up some of the best wells in the industry and for one of the lowest oil price environments. And I guess what's behind my question is, while you're obviously best of the best I guess within the sector, your return on capital employed last year was still in negative territory. So I guess my question is, what's the rush in a $46 world despite the quality of the inventory. And I've got a follow-up specifically to Whirling Wind, please.

Doug, the returns we're getting on these premium wells at $50 in, at $45 is very, very strong. It's in the $40 to $50, $60-plus in the first quarter, we were at 70% rate of return. So we feel like the economics of the wells even at low oil prices is extremely strong and the right call for the shareholders to continue to reinvest in those. We also have a very strong confidence. You heard us talk about this over the years that we can replace that inventory much, much faster than we're drilling it, so we don't believe we're spending our best wells in the lowest oil price. We believe that our wells actually will continue to improve over time as we continue to find better rock and apply new technologies. So our commitment is to grow within cash flow and to grow at very, very high return capital reinvestment rates and we believe that's the way to build shareholder value.

Our next question comes from Jeffrey Campbell from Tuohy Brothers.

Good morning. I was wondering at first, could you provide some color on which intervals were contained in the 700 premium locations that were added in the Delaware Basin? I mean it seems like you had good results in several different intervals, so I'm just wondering if we could get a little color there.

Yes. Jeff, this is Billy Helms. On the increase there in the Delaware Basin, the majority of those are in the Wolfcamp. Of the 700 we added in the Delaware Basin, 425 were in the Wolfcamp and the remainder there in the Bone Springs and the Leonard. So the majority of it was driven by the Wolfcamp.

Great. Thank you. And as a follow-up, in the Powder River Basin, the lateral lengths were fairly short this quarter relative to most of the other intervals developed during first quarter 2017. I'm just wondering if there is any color on that. Was it determined by lease geometry? Are you working towards increasing lateral length over the rest of the year?

Yes, this is David. In the Powder River as we noted, three of the five that we brought online were legacy Yates wells and they were short laterals. And then we do on occasion drill some of the shorter laterals due to lease issues but really on a go-forward basis, we're planning in the Powder to be drilling all two-mile laterals. So that's what you'll see in the majority of the laterals in the future.

Okay. Great. Thank you.

And we'll go next to Subash Chandra from Guggenheim.

Yes. Hi. So this quarter, a lot of Delaware operators are talking about what pads might look like in development. Could you discuss where you are in that transition, if the wells we're seeing right now are pretty representative of what they might look like in future years? Or will there be a dramatic change in how you go about developing the stack in Delaware?

Yes, Subash. This is Billy Helms. So in the Delaware Basin, I'd say we're still in the early innings of trying to develop our multi-well pads. We're testing largely, as you know, the Wolfcamp interval to start with and we've still got a lot of horizons to test, both most of which are above the Wolfcamp. And so we're looking at what is the optimal way to increase our well count in this area and ultimately end up with a greater number of wells in each section or spacing unit that we drill. But recently I think right now we're probably drilling on average three or four wells per pad initially, and we're coming back in behind that with additional development.

And I think in your intro comments you talked about EOG's experience in understanding density and well interference in prior plays, so is your gut feel that in development that you'll need to pull back on completion intensity, avoid pressure sinks and that sort of thing when you look at your prior experience elsewhere?

Yes, Subash. This is Billy Helms again. I'd say we haven't seen that occur yet. We're continuing to optimize the spacing and completion design for every interval. Each interval is uniquely designed with the data that we collect that we've talked about and all of our tools that we use to analyze what is the best and most optimal way to develop each zone. So we haven't yet seen a limitation on how we space the wells or how we design our frac treatments. I'd say they're more customized. There's not a one size fits all I guess is the way I'd think about that. They're all optimized. I'd say we're still testing downspacing in several areas. Our resource assessment is based on our most recent analysis, but we're testing those and pushing the limits as we speak.

Our next question comes from Scott Hanold from RBC Capital Markets.

Thanks. Good morning.

Good morning.

Good morning. The point on longer lateral lengths, obviously you're extending them in the Eagle Ford as well as the Permian. Can you discuss, specifically with the Permian where there seems to be a pretty big opportunity as you look forward, how much blocking and tackling is there yet to do on bolting on acreage? And where do you ultimately think that could end up?

The Permian, we have been historically in the years past 4,500 to 5,000 foot. I think the average lateral length this year is about 7,000 foot, and we continue to put acreage positions or bolt on acreage positions. We're trading acreage with other operators and consolidating positions to help us to continue to extend those laterals even further. So I think it will grow incrementally over time. It may not be the 10,000-plus lateral lengths like we've done in some of the other plays, but it will continue to improve and get better over time. The uplift on the economics is pretty dramatic on the longer laterals because they don't cost near as much, and so you get a big uplift on the economics and the returns on the longer laterals. And we've been able to, I think the most important thing, with our precision targeting technology and identifying the best rock and our ability to keep that bit in the best rock the entire lateral length, has allowed us to continue to have the same productivity per foot on the longer laterals as we do on the shorter ones. So if a long lateral is twice as long, we actually get twice as much oil. So that's a big technology gain that we've made just recently.

We'll go next to Irene Haas from Wunderlich.

Yes. Hey. Good morning. Congratulation on the Whirling Wind wells. They're truly impressive. Just wondering if they are from the Upper Wolfcamp. And then what is driving the performance? Is it the completion techniques, geosteering of better rocks? And can this be replicated over a large area?

Yes, Irene. This is Billy Helms. So those Whirling Wind wells are drilled in the Upper Wolfcamp, and what really led to the high production rates that we've seen is a combination of several things that we've talked about. And I see it leads off with understanding the geology and understanding where the best rock is and then being able to keep the target in that best rock throughout the length of the lateral, and these are over 7,000 foot laterals. And then combining that with the high density completion technology that we continue to advance, those, the combination of things is what led to that production increase, and we don't think we've reached the peak of that knowledge yet. We think we still have advancements that will continue to drive productivity increases throughout the play. Every play, the geology changes across the basin, so every location won't be exactly like the Whirling Wind wells, but there's still a lot of potential for improvement across the play.

So should we expect sort of a more spectacular flow rate as such in the future, maybe from slightly different geographic area? Can this be replicated?

Yes, Irene, I wouldn't say that we'll continue to set record after record after record every well we drill, but I'd say the uplift on the overall program will continue to increase and I think, one thing that I think I would add some color to is that as we have stepped out with the inclusion of the Yates acreage, as we've stepped out across the play, we've seen uplift in the productivity more than so than we expected when we acquired that position. And so we've been pleasantly surprised by the application of the EOG technology to the acreage that we acquired in the Yates position to improve productivity across the basin.

Our next question comes from Bob Morris from Citi.

Thanks. My question actually was along the line of what Irene's was, and congratulations on the great well results, and Sandeep did a great job outlining the big data and analytics that you're using to improve these well results. But in the increase in performance and in premium inventory theme, so (51:43) you've outlined it's more to do with targeting within the horizontal lateral of the wells more so than longer lateral length and lower well costs. But in understanding that lithology, what is the difference in the rock that you're targeting? And is there that much variability across the zone? In other words, is that rock that you're targeting a lot more fracture prone? Is it just more oil saturated? Or what is the characteristic of that zone that you're able to target, and how variable is the rock across the formation when you target that zone?

Bob, this is Bill Thomas. You're asking some information that's proprietary. But I'll give you some general guidelines. Certainly, the rock is variable in the Permian, particularly in the Delaware Basin. There is a lot of variability in a vertical sense and then laterally it does vary some too. So you need a lot of data to identify it, and we start with cores. We do an extensive amount of core work, full cores and analyze that rock. We integrate that into a petrophysical model and then we integrate all that data into 3-D seismic, and we create very detailed maps, structure maps and stratographic thickness maps before we even start to drill the well. So it does take a lot of very sophisticated geology to identify these targets and it takes a lot of data and a lot of really good G&G and engineering work to locate that lateral. And then importantly, we developed the in-house software as Sandeep and David described to keep the bit in that really good rock, 95% to 100% of the lateral. And when we do that and we do the sophisticated high-density completions, that's why the wells are so good. And so the goal is just continue to identify better zones, to have better execution and to continue to improve the frac technology over time. So we think there's a lot of upside left and we're very encouraged directionally, technically where we're headed.

So you think – I know you said you won't set record after record after record – but you feel that you're still moving up the learning curve and everything you just described that so that we should see better well results across the board if you continue to be better able to target those better zones, I would assume, here.

Certainly. That's the goal, Bob, and that's our hope. We consistently improve performance over time and we are continuing to develop new tools and new ideas, and so we're hopeful that will continue in a very strong direction in the future.

Great. Well, we'll look forward to that. Thank you.

Thank you.

Next, we'll go to Charles Meade from Johnson Rice. Charles A. Meade - Johnson Rice & Company L.L.C.: Good morning, Bill, and to you and the rest of your team there.

Hello, Charles. Charles A. Meade - Johnson Rice & Company L.L.C.: I wanted to ask, and Bill, this might be for you or perhaps for Sandeep, but I wonder if you could give us, without giving too much away, can you give us a sense of the kind of data types and streams you're capturing now versus perhaps what you were doing a year or two years ago? And what new sorts of data, or opportunities for data capture you might be looking at a couple years down the road?

Yes, Charles. This is Sandeep. I'll take that question. I would say the biggest change for us versus a couple of years ago is the real-time data that's streaming in. And as the data comes in with higher resolution with some of the black boxes that they're putting out on the rigs and our frac fleets, we're able to get a lot more insight into the data, and we're able to turn that into new learnings and translate that into the high productivity wells. The best example of that is just the data that we're getting real-time in now to help us geosteer, and I think that's the biggest delta change from the past, where the data wasn't as real-time. And then, on the frac side of the business, it's the same thing. We're getting real-time data coming in from every frac fleet, and so we're able to change our completion designs and accommodate real-time, understanding what the rock is telling us. So those would be two concepts that are different, say, from two or three years ago. Charles A. Meade - Johnson Rice & Company L.L.C.: Got it. Thanks, Sandeep, and that really fits well with, I was going to ask the same question about those Whirling Wind wells, but I think you guys have explained it's an intersection of the targeting, fracking, everything well. If I could ask just question perhaps for David Trice about the Austin Chalk. I recognize you guys are not ready to put a resource number on that, but I'm curious if you could elaborate a bit on how you see that evolving. Is this kind of a, maybe a kind of a polka dots across the map of different hotspots? Or is this kind of all concentrated in one area? And what's a timeline for, your best guess as to timeline for when you will kind of mature that?

Yes, Charles. I'd say on the Austin Chalk, we've certainly learned a lot about it over the last several quarters, and you know we just wanted to continued to do step-out wells, the targeting test and spacing test as well. We've got several spacing tests over the last several months. We've done some at 400 feet and some at 600 feet, and the results are good on all of those. But we're still trying to dial in the exact spacing. But just keep in mind, I mean it's a lot different than what the traditional chalk was like. If you think about the traditional fractured chalk, you had really wide spacing, and this is going to be much more of a resource-type play. So nobody's ever really kind of chased the chalk in this way. So we just want to have a little bit more time and collect some more data. We've collected a couple cores and quite a few logs, and we're really, most of our testing has been across a 10 to 20 mile stretch on our acreage, but in the coming quarters, we'll have some updates. Charles A. Meade - Johnson Rice & Company L.L.C.: That's helpful color. Thank you.

Okay. I think we can close the call.

And we do have one more question. Would you like to take that?

Sure. Go ahead.

It comes from Marshall Carver from Heikkinen Energy Advisors.

All right. Thank you for squeezing me in. You highlight individual wells in the presentation. We tend to think of premium wells as the median result. What are your thoughts around standard deviation around your IPs and EURs as you're heading forward?

Marshall, I think there's a slide in the IR deck. I think it's slide 10 that gives the metrics on our premium wells that we completed last year versus the non-premium wells, and they are remarkably better. I think this is one of the things in the Street that may be a little bit misunderstood. The premium wells are roughly, the returns on them are roughly a fivefold increase in returns. The finding costs are less than half. The capital efficiency is more than twice as good and the first year oil production on the premium versus non-premium is actually double. So the premium wells are remarkably better than the wells that EOG has historically drilled in the past, and EOG's in the past has drilled the best wells, we believe in the industry. So the premium wells are certainly a game changer for the company. And as we go forward and we add these low cost reserves to our reserve base, they will continue to drive down our DD&A rate, and that will filter to the bottom line. Our breakevens will be better and certainly help us on ROCE. So they're remarkably better wells, and I think that's maybe not quite understood by the Street. Thank you, Marshall.

In closing, the company is getting off to a great start in 2017. Each division in the company is focused on delivering industry leading premium wells, and we're tremendously excited about the future of the company. Over time, those low cost reserves will improve our bottom line and continue to create long-term shareholder value. So thank you for listening and thank you for your support.

And that concludes our conference today. Thank you all for your participation. You may now disconnect.