EOG Resources Inc (EOG) — Q1 2017 Earnings Call Transcript

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 risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release, and the 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; 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 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.

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 a 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 price environment is a testament to the power of premium. It's also a testament, or rather the result of EOG's rate of return-driven culture. When your entire team, from entry-level professionals to executive management, are incentivized by returns, as they are at EOG, it drives innovation. Innovative thinking is why EOG is consistently a first mover into brand new plays, delivering the best performing wells in the industry for the lowest cost in the industry. EOG was one of the first to both horizontally drill and hydraulically fracture the Barnett and the Bakken; the first to figure out that we can coax oil from extremely tight shale rock, leading to our second to none acreage position in the Eagle Ford; the first to understand the benefits of complex near-wellbore fractures versus biwing fractures; and the first to deploy high-density completions and precision targeting that enables EOG to consistently deliver premium well performance. EOG's innovative culture incorporates rigorous geoscience, petrophysics, and cutting-edge engineering in order to achieve return-focused technical advancements. Science and engineering, of course, requires data. Ten years ago, that data was analyzed using over-engineered spreadsheets. Today, we employ sophisticated analytics using our vast collection of data and technology tools that have been developed in-house at EOG. Now I'd like to introduce Sandeep Bhakhri, our Chief Information and Technology Officer. Sandeep has been with EOG for 25 years on the front lines of EOG's information technology evolution. He will go into more detail on how EOG is using data science tools and mobile technology to enable faster innovation throughout the company.

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 from most and why we have three key competitive advantages that cannot be easily replicated. The first competitive advantage 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 is that we have been doing this for 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 long time, you will have no source of sustainable competitive advantage. Let me give you a little history. When I say we've been doing this for a long time, I mean since the early 1990s. The cost-saving trend at that time was to outsource information technology. EOG initially followed suit, but soon thereafter recognized the strategic mission-critical importance of IT and we decided to bring it back in-house. Rather than implement one size fits all behemoth back-office systems in vogue at that time, we instead opted to customize and maintain our own accounting system. Then in 2000, the dot-com boom was in full swing and investments in technology allowed us to tackle our first major IT-enabled transformation, namely, to reduce organizational friction for data access. We call this answering the what question. For example, what is the current production of this well? What is the cost of this well? Etc., etc. We built 10 web-based self-service applications, eliminating the need for employees to ask each other what questions and to instead focus on why and how questions. Using IT to help answer the why and how questions became even more important in 2010. The catalyst was the explosion of data and data analysis that was the Eagle Ford. EOG's development of the Eagle Ford generated orders of magnitude more data than at any other time in EOG's past, creating an ever-increasing need to have access to this data and analyze it as soon as possible. Our completion engineers were experimenting with completion designs for every well and sometimes every stage while our production engineers were analyzing high-frequency production and pressure data from all our wells over our increasingly vast wireless field communications footprint. Third-party data collection tools were not keeping up with our demand. This was the start of our data collection and data storage initiatives that led to our eight huge proprietary integrated data marts that now house data across virtually every functional area of our business. We believe they are the most comprehensive collection of integrated unconventional oil and gas data sets in the industry. Simultaneously, we began data delivery initiatives that resulted in over 45 desktop applications that were fit for purpose custom tools accessing our ever-growing proprietary data marts. The very first in 2008 was a reservoir analysis tool with custom algorithms that allowed our reservoir engineers to analyze well performance in a significantly shorter time than standard decline curve analysis. Since then, EOG has built a comprehensive suite of world-class commercial-grade apps that address every functional area of our business. Combined, our eight proprietary data marts and our 45-plus desktop applications help EOG engineers answer the why and how questions more quickly than ever before, which in turn shows up as superior well performance, lower costs, and innovative exploration ideas. Our latest technology evolution began two years ago with our move to real-time data collection and mobile data delivery systems. While we were already getting production data in real-time, we built custom black boxes to retrieve real-time data from every rig and every completion spread. This, in turn, spurred the need for mobile versions of our existing apps. In two short years, we have developed what we believe to be 20 of the most sophisticated mobile applications in the oil and gas business. We did it quickly by leveraging our existing proprietary data marts as well as our wireless communication footprint. Real-time data and our mobile apps are a major productivity game changer. People at EOG are connected 24/7, anytime, anywhere, to the same data. We call it having a control room in your pocket. Add to this our culture of bottom-up decision-making that doesn't require multiple layers of approvals and you have an environment of accelerated analysis, innovation, and change at the speed of thought. In a moment, David Trice will share a new drilling record reached in the first quarter using one of the toolkits we built in-house for precision targeting using mobile access to real-time data.

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 halfway to our target of $4.3 million. In the Bakken, we reduced well costs 6% to $4.8 million, which is more than halfway 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.

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 wringing 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.

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 costs, 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 River Basin. In the DJ Basin, we brought online nine Codell wells in the first quarter. While the 30-day IPs on these wells are not flashy, averaging 710 barrels of oil equivalent per day each on 8,600-foot laterals, the production is flat and the well cost continues to rapidly fall. Normalized to 9,000 feet, DJ Basin well costs are just $4.5 million. In addition, we set some new drilling records in the Codell. The Pole Creek 531-2536H was drilled to a total measured depth of almost 18,000 feet in only three days. With a drilled lateral of nearly 9,000 feet, the average rate of penetration in the lateral was over 7,800 feet per day and was drilled 100% in zone, even though the target window was only 10 feet. This accomplishment was the direct result of EOG's performance-driven culture and integration of drilling technology, real-time data delivery, and in-house software applications. Our geosteering and drilling software serves our needs better than any third-party applications available on the market today. Our geosteering team can receive a real-time feed of EOG data directly into our software to interpret and integrate with offset well control and seismic data. All this information can be viewed and interpreted on a desktop or mobile application, so everyone associated with the well are in constant communication and can collaborate regardless of where they're located. It's essentially a distributed control room. The benefits are immediately visible as lower costs and better well performance.

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.

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. 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.

Thank you. Good morning.

Good morning, Brian.

I wanted to get a bit more color on the Eagle Ford. Slide 40 shows the productivity both in the east and the west, and you talked in your prepared comments about a number of returns-enhancing initiatives via cost reductions. If we look 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. 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.

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. 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 the best of the best 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, 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.

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.

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.

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.

Thanks. 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.

Yes. Hey. Good morning. Congratulations 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. 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. 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.

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 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 stratigraphic 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. The goal is just to continue to identify better zones, have better execution, and continue to improve the fracking 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, 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.

Good morning, Bill, and to you and the rest of your team there.

Hello, Charles.

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 kinds 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 of years down the road?

Yes, Charles. This is Sandeep. I'd say the biggest change for us versus a couple of years ago is the real-time data that's streaming in. 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 high productivity wells. The best example of that is just the data that we're getting real-time 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. 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 of what the rock is telling us. So those would be two concepts that are different, say, from two or three years ago.

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 continue 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. Just keep in mind, 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. We just want to have a little bit more time and collect some more data. We've collected a couple of 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.

Okay. I think we can close the call.

Sure. Go ahead.

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 that may be a little 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. 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. 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. Thank you for listening and thank you for your support.