EOG Resources, Inc. (EOG) Q2 2016 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the EOG Resources 2016 second quarter results conference call. At this time for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir. Timothy K. Driggers - Chief Financial Officer & Vice President: Thank you and good morning, thanks for joining us. We hope everyone has seen the press release announcing second quarter 2016 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the press release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. Participating on the call this morning are: Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, VP, Marketing Operations; and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, and we included guidance for the third quarter and full year 2016 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review our shift to premium drilling and the long-term growth outlook we introduced in yesterday's press release. Billy Helms and David Trice will review notable achievements in select plays. I will then discuss EOG's financials and capital structure, and Bill will provide concluding remarks. Here's Bill Thomas. William R. Thomas - Chairman & Chief Executive Officer: Thanks, Tim. Good morning, everyone. EOG's goal during this downturn has been squarely focused on resetting the company to be successful in a low commodity price environment. We are focused on lowering operational costs and achieving a strong return on capital invested in a $40 oil environment. Our goal is to continue to be the U.S. leader in investment returns and be competitive with the lowest cost producers in the global oil market. On this call this morning we have important updates that highlight significant progress towards reaching our goals. First, per unit lease operating costs decreased by 27% in the first half of 2016 versus 2015, and per unit cash operating costs in the first half are down 15% compared to full-year 2015 and 30% below 2014 levels. Second, with outstanding capital efficiency gains, we exceeded the high end of our second quarter U.S. oil production target, and we are increasing our full-year U.S. oil forecast by 2% without increasing CapEx guidance. Third, we have increased our premium inventory by 34% and increased our premium reserve potential by a whopping 75%. And fourth, we closed on $425 million of non-core property sales this year. Along with maintaining our strong balance sheet, we are updating our portfolio by investing in high-return premium assets. As a reminder, a premium well is defined by an after-tax direct rate of return of at least 40% at $40 oil. We believe this metric makes EOG unique in the U.S. when it comes to quality of inventory and investment returns. There are a few additional points regarding this definition of premium that I want to be sure are very clear. Number one, 30% is a minimum return. This means the average return for our premium drilling inventory is clearly higher. Number two, 30% was selected as a minimum so that the fully-loaded investment, including all indirect costs, generates a healthy all-in corporate rate of return. Number three, 30% at $40 oil is the premium benchmark regardless of what the prevailing market price for oil is, meaning if oil goes to $50 or $60, the returns quickly move into the triple-digit range. Finally, premium inventory is a return-based metric. It can be achieved by cost reductions or productivity increases or a combination of both. Because our technical and efficiency gains are sustainable, we are confident that a large majority of our remaining inventory will be converted to premium over time. EOG's shift to premium is a new chapter for the company. Premium drilling establishes a higher permanent standard for capital allocation, and therefore will significantly increase capital productivity over time. This shift enables EOG to deliver high-return robust growth using far less capital at a far lower oil price. Which leads me to another highlight from yesterday's press release, the 2020 growth outlook we provided. Due to the sustainable gains in well productivity and cost, we can grow oil production at a 10% compound annual growth rate at $50 oil. At $60 oil, our compound annual growth rate jumps to 20%. And most importantly, we can deliver that oil production growth while covering our capital expenditures and our dividend with cash flow, enabling us to meet our goal of maintaining a strong balance sheet. As prices improve, we expect to incrementally reduce the net debt-to-capital ratio to our historical norm of 30% or less by generating free cash flow and, to a lesser extent, through non-core property sales. While the shift to premium drilling has tremendous impact on EOG's returns, growth, and capital productivity, the question remains. Is this shift really permanent? In other words, can EOG continue to replace its premium inventory? And the answer is yes. The three ways we add premium inventory are conversion, exploration, and acquisition. The first and most immediate way is through conversion. Converting well locations that were on the edge of the 30% hurdle rate is a source of the 1,100 new premium locations we announced yesterday. Furthermore, we have much more inventory on the verge of conversion. By improving well productivity or lowering cost, in most cases both, we expect much of our current non-premium inventory in the top basins to be converted to premium over time. Improvements to well productivity and cost savings are ongoing and never ending. In a moment, Billy Helms and David Trice will talk more about how productivity improvements, cost reductions, and longer laterals will add to premium inventory. The second way we add premium inventory is through exploration. EOG is a leader in organic exploration growth because at our core we are an exploration-driven company. In this lower commodity price environment, we have not stopped looking. With EOG's decentralized structure, we have six experienced exploration teams in the U.S. generating new ideas, acquiring leases, and developing new plays. EOG is a prospect generating machine, and our shift to premium has not slowed that effort down. In fact, it has enhanced the return hurdle by which new plays are evaluated. The third way we expect to add premium inventory is through targeted bolt-on acquisitions. Due to the current low commodity cost environment, we are actively pursuing opportunities to capture top-tier acreage. We were successful on four such transactions in the Delaware Basin last year, and are optimistic we can execute on more through this down cycle. I am confident that we can replace premium-level drilling every year through conversions, exploration, and acquisitions. And as I said last quarter, this shift to premium drilling is permanent and it's a game-changing event for EOG. Now I'll turn it over to Billy Helms to discuss the Eagle Ford. Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Thanks, Bill. As highlighted in the press release yesterday, we added 390 net locations to our Eagle Ford premium inventory. That's a 25% increase to our original estimate six months ago, and takes the total premium well count in the Eagle Ford to almost 2,000 locations. Two thousand locations represents 10 years of premium high-return drilling. What's more, there are at least 2,000 more Eagle Ford locations that are on the verge of premium designation. To convert these locations, we will need to reduce current well cost by 10% or improve EURs by 10%. Slide 11 of our investor presentation illustrates this. By making small, very attainable improvements, we can add another 10 years of premium high-return Eagle Ford inventory from our existing acreage. I am confident we will make this conversion over time. One of the ways we convert locations to premium is by drilling longer laterals. Our success in the western Eagle Ford, as illustrated on slide nine, is a good example. The trick with longer laterals is to maintain, or preferably enhance, productivity per foot of lateral. Due to engineering breakthroughs in EOG's completion design, we have gone out as far as two miles with no degradation in productivity per foot. While longer laterals will be one source of future premium inventory, two more significant sources will be EOG's focus on performance improvement through advancing our technical understanding and lowering cost. On the technical side, geological and geophysical advancements enable us to refine our precision targeting efforts. For example, we are determining where there may be multiple lower Eagle Ford targets to support drilling a W pattern. We are also working to understand where the upper Eagle Ford is prospective. While the prospective area for the upper Eagle Ford is geographically limited, there are some sweet spots that may contribute premium well locations. Finally, as we discussed last quarter, we will be completing seven additional Austin Chalk wells and continue to delineate the play and understand its full potential. On the cost side, we are finding creative ways to drive costs down further. We are drilling more wells per pad with more efficient rigs designed for pad drilling. The rig design allows for simultaneous operations such as conducting drilling and cementing operations on multiple wells at the same time, reducing both time and cost. On the completion side, we continue to optimize proppant schedules and stage lengths, reduce cost for items like sand and chemicals, while maintaining the EOG high-density completion process. Our continuing focus on every facet of our operations has allowed us to drop Eagle Ford total well cost another 11% year to date to $5.1 million. Also, we continue to be encouraged with our enhanced oil recovery or EOR projects. As a reminder, the process is highly economic and provides another way to create premium inventory. It not only increases the recovery, but also provides a means to flatten the field production decline. Finally, I'll draw your attention to slide 23. We added another line to the chart representing 2016 year-to-date cumulative production. Year after year, we improve our well productivity in the Eagle Ford. Much of this year's increase can be attributed to our shift to premium drilling. However, as slide five illustrates, just 60% of our 2016 drilling program is premium, so we expect to see this chart show improvement for many years to come. Now here's David Trice. David W. Trice - Executive Vice President-Exploration & Production: Thanks, Billy. Like the Eagle Ford, the Delaware Basin also added to its premium drilling inventory. Five hundred twenty net locations were added across all three plays, the Wolfcamp, Second Bone Spring, and Leonard. The new premium total now stands at more than 1,700 locations. That's almost 20 years of premium high-return drilling. In the Delaware Basin, the main driver of premium additions was improvement in well productivity through better targeting and completions. For example, slide seven of the investor presentation shows EOG's 2016 Wolfcamp oil wells produced more than 200,000 barrels equivalent on average in the first 180 days. That's a 17% increase in the 180-day cumulative oil production over wells in our 2015 program. More importantly, it shows a 45% uplift over a typical 750 MBOE well, which is the gross per well EUR given in our last Wolfcamp update. Finally, it's worth noting that the data in this chart is normalized to 4,500-foot laterals, meaning EOG's 4,500-foot laterals in the Delaware Basin are as good or better than the 10,000-foot laterals in the Midland Basin. In addition to productivity gains, longer laterals in the Delaware Basin are another way we've added premium locations to the Wolfcamp as well as the other two plays. Innovations made to wellbore design in the last six months allow us to drill longer while still applying high-density completions so that we do not sacrifice long-term reserves. The new design will allow us to maintain high recovery rates on the longer laterals while lowering costs and increasing returns. Sixteen gross Wolfcamp oil and combo wells were brought online in the second quarter, with an average 30-day rate of more than 2,400 barrels of oil equivalent per day and an average lateral length of 6,500 feet. These are industry-leading Wolfcamp results regardless of operator or basin, as shown on slide eight of our investor presentation. EOG expects to complete 70 Wolfcamp wells in 2016. While the effort in the last couple years has clearly been focused on the Wolfcamp, we have been able to collect a tremendous amount of data on all of the shallower targets such as the Second Bone Spring and the Leonard Shale. Despite limited drilling this year, results in the Second Bone Spring have also been impressive. Ninety-day cumulative production has increased 27% over 2015 wells and 60% better than a typical 500 MBOE well. The Second Bone Spring tends to be more stratigraphically complex, so additional data we collect from drilling Wolfcamp wells has aided in much better targeting, longer laterals, and more premium wells. We expect similar or better uplifts to our Leonard Shale results on a go-forward basis. In the Rockies, we've had great success in the Powder River Basin and Wyoming DJ Basin. As announced in our press release yesterday, we drilled three Turner wells last quarter that averaged almost 2,000 barrels of oil equivalent per day. Completed well costs, which include drilling, completion, and on-lease facilities averaged $5.4 million for a 6,500-foot lateral, down from $6.5 million in 2015. These Turner wells are incredibly economic at $40 oil. We plan to drill a total of 20 net wells in the Turner this year. When we conducted our first count of premium inventory in December of last year, the DJ Basin Codell in Wyoming was slightly below the premium threshold. Due to sustainable cost reductions and better targeting, we added 200 premium locations in this play. Currently, Codell wells cost $5.9 million for a 9,400-foot lateral. As noted in press release yesterday, our latest Codell well produced approximately 1,400 barrels of oil equivalent in the first 30 days. We expect costs and well improvements to continue and are working to expand gas takeaway options in Wyoming. The DJ Basin Codell will become a larger part of our premium drilling program in the near future. In the East Irish Sea, I'm happy to report that Conwy is currently producing approximately 10,000 barrels of oil per day. During the second quarter, Conwy was down due to issues on the Douglas production platform. While Conwy wells were initially tested at a daily rate over more than 20,000 barrels of oil, results from recent production testing indicate that the optimal level of production is 10,000 barrels of oil per day. For the remainder of the year, we expect to average about 4,000 to 8,000 barrels of oil per day to accommodate further tests and potential downtime. Here's Tim Driggers. Timothy K. Driggers - Chief Financial Officer & Vice President: Thanks, David. Capitalized interest for the second quarter of 2016 was $9 million. Exploration and development expenditures were $624 million excluding property acquisitions, which is 49% less as compared to second quarter 2015, while our total production volumes decreased by just 2%. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $20 million. We have maintained our full-year capital expenditure guidance of $2.4 billion to $2.6 billion. At the end of June 2016, total debt outstanding was $7 billion and the debt-to-total capitalization ratio was 37%. At June 30, we had $780 million of cash on hand, giving us non-GAAP net debt of $6.2 billion, for a net debt-to-total cap ratio of 34%. Year to date, we have sold $425 million of assets with associated production of 45 million cubic feet per day of natural gas, 3,300 barrels of oil per day, and 3,700 barrels per day of NGLs. Assets sold include Midland Basin and Colorado DJ Basin properties. The effective tax rate for the second quarter was 23%, and the deferred tax ratio was 214%. Now I'll turn it back over to Bill. William R. Thomas - Chairman & Chief Executive Officer: Thanks, Tim; now a brief word on our macro view and how it relates to our 2016 plans. Even though oil prices have been volatile, our view of supply/demand fundamentals has not changed. We believe $40 oil will not provide enough cash flow or investment return to overcome the combined effect of production decline and demand growth worldwide. While EOG can deliver healthy growth in cash flow at $50 oil, we continue to believe the U.S. horizontal oil industry as a whole needs a sustained $60 oil price and extended lead time to deliver a moderate level of growth. As we discussed last quarter, the substantial reduction in capital investments by the industry since 2014 is causing oil supply to decline in many producing regions worldwide. As production continues to decline, the inventory overhang will slowly work off. The consensus view is the market will balance during 2017. For 2016, given the uncertainty of the current commodity environment, we are maintaining our CapEx guidance at $2.4 billion to $2.6 billion. However, as a result of cost savings, we are increasing our well count to 250 drilled wells and 350 completed wells. This is an additional 50 wells drilled and 80 completions above our original plan for the same CapEx. In summary, I would like to leave you with the following important takeaways from this call. Number one, we continue to reduce operating costs. We believe these reductions are sustainable, and we have additional efforts underway to reduce future operational costs. Number two, our shift to premium is achieving what we believe are the strongest investment returns at $40 oil in the U.S. Number three, our shift to premium is permanent. We are confident we can grow premium quality inventory much faster than we drill it. Number four, we continue to exceed our U.S. production targets by increasing capital efficiency. We believe these efficiency gains are sustainable and give EOG a significant advantage as we enter the next recovery. And number five, we are maintaining our strong balance sheet through disciplined spending. I'll close this call with our view of EOG's future through 2020. There are four goals we plan to achieve. The first goal is to be the U.S. leader in rate of return on capital investments. The second goal is to be the low-cost U.S. producer and therefore competitive in the global oil market. Our third goal is to be the leader in Lower 48 absolute oil growth through 2020. And our fourth goal is to maintain a strong balance sheet through disciplined spending. By achieving these four goals, we will accomplish our ultimate goal of creating long-term shareholder value. Producing growth by consistently outspending and drilling uneconomic wells is not in EOG's vocabulary. We firmly believe that growth should be the result of strong returns and disciplined spending. EOG's unwavering commitment to our long-term shareholders is to focus on returns first. The company is uniquely positioned to produce strong returns and resume high-return growth as commodity prices improve. Thanks for listening, and now we'll go to Q&A.

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

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

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

Next is Pearce Hammond with Simmons.

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

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

Thank you.

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

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

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

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

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

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

All right, thank you. Great quarter, thanks.

Ryan Todd with Deutsche Bank is next.

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

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

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

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

Okay, thank you very much.

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

We'll go to Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Thank you, good morning. William R. Thomas - Chairman & Chief Executive Officer: Hey, Brian. Brian Singer - Goldman Sachs & Co.: Bill, you've recently spoken a bit less on the topic of recovery rate. But given that you are increasing your premium inventory in part because of productivity gains and longer laterals, I wonder if you could provide an update on where you see recovery rates, particularly in the Delaware and Eagle Ford, and then the opportunity from here for further technology and productivity gains to increase resource in premium inventory and overall recoveries. Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Brian, this is Billy Helms. On the recovery rates, we've gotten away from quoting what we think the overall recovery rate is by zone. But needless to say, it's improving. I think a large part of that, a very significant part of that is what Bill talked about earlier. It's understanding the rock, our shift to better define what targeting is, and then deploying our high-density completion process. It's really made a huge difference on the recovery rates. We really don't focus on what that recovery rate percentage is. It really doesn't help us understand our go-forward models on how these wells will perform. So it really hasn't been a focus for us, but that's the color I would give to you is that they're definitely improving with time. Brian Singer - Goldman Sachs & Co.: Thanks. Maybe I'll ask it in a slightly different way then, since you talked about the targeting and the enhanced completions specifically. What inning do you think we're in, in terms of the impact that those technological improvements are having on your productivity? Is there still a big gap? Even if you're not specific on the recovery rates, is there still a big gap where there's the opportunity for further use of these technologies to increase recovery? And are the benefits from targeting and enhanced completions fully baked into your premium resource and premium locations? William R. Thomas - Chairman & Chief Executive Officer: Brian, this is Bill. The targeting, we started that I believe in the latter part of 2014, and it's really in different stages and different basins. In the Eagle Ford, it's more mature there. We're probably still in the sixth inning. I've been saying this for years, but we're probably still in the sixth inning there of understanding what is the best target and working it into our W patterns and our spacing patterns. So as we get more data, even in a very mature area like the Eagle Ford, we get more data. We continue to find out more about the rock and the section, and we're able to discriminate and pick better rock all the time. So it's an ongoing process even there. In the Delaware Basin, we're probably in the second or third inning there. There's so much potential pay there, and we're still learning and we've got a lot of data to gather. As we drill the Delaware wells, we're focused on the Wolfcamp, particularly using those fantastic wells. But number two, you get to see all the Bone Spring sands and all the pays above you. And so you're gathering data as you drill these wells, and that helps with delineating targets and working the stratigraphy out in mapping. So each one of the plays is at a different position on improvements, but we think there's really a long way to go. We're not anywhere close to the end of being able to make additional improvements on that side of the business or on the cost side too. So it's an ongoing process and it's a very sustainable process. Brian Singer - Goldman Sachs & Co.: Great, thank you.

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

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

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

Great, thank you.

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

We'll go to Mike Scialla with Stifel. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Hi, good morning. Bill, you said in your prepared remarks that the minimum 30% IRR for premium wells translates to a healthy corporate rate of return. Is there a minimum ROE you can equate that to, or does that necessarily translate to positive earnings? William R. Thomas - Chairman & Chief Executive Officer: We picked the 30% because when you pull in our full-cost of capital, which would be infrastructure, land, G&G (53:22) and things like that, it usually draws the return down to maybe 15%. So we would like to have a minimum full-cost all-in call it capital cost rate of return of about 15%. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Okay, thanks. And then, Billy, you mentioned in your prepared remarks you're seeing no degradation in productivity per foot with these longer lateral lengths. I guess is there anything specific there without giving away the trade secrets that you can talk about, maybe bigger casing size or something like that that's preventing that degradation in recoveries per foot with the long laterals? And I was wondering too, you mentioned the Eagle Ford and the Delaware, where you're going with the longer laterals. On the Eagle Ford side, is that really confined to the western portion of the play, or does it have any application in the east as well? Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Mike, this is Billy Helms. So on the Eagle Ford, first of all, for both the Eagle Ford and the Delaware Basin, when we drill a longer lateral, we definitely want to make sure that we are maximizing the recovery. We're not losing efficiencies as we just drill longer laterals. So we've spent a lot of time – our operational groups have spent a tremendous amount of time trying to understand how to accomplish that. And the results we've seen so far have shown they've been very successful at maintaining that productivity per foot, especially when it results in – we're talking about EUR per foot mainly. Certainly, the initial production can somewhat be diluted a little bit just due to the longer laterals and flowing larger volumes up, restrictions on chokes and surface things, surface facilities. But the EUR per foot has been maintaining a pretty steady pace. So that's really encouraging. Now, I won't get into exactly how we're doing that. We do feel like that that is an advancement we've made internally, and we want to keep that a little bit proprietary at this time. But on the Eagle Ford and the Delaware Basin, both of those are benefiting from that and will continue to benefit from that. Michael Scialla - Stifel, Nicolaus & Co., Inc.: And in the Eagle Ford, is it really on the western side of the play, or does the east have any application? Lloyd W. Helms, Jr. - Executive Vice President, Exploration & Production: Yes, probably more so on the western, but certainly the east side also has opportunities for that. But the east side also has a little bit more geological complexity that hampers that a little bit. But certainly, there are opportunities, and we'll find that where we can. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Great, thank you. William R. Thomas - Chairman & Chief Executive Officer: I think we've got time for one more question.

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

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

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

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

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

It goes along with the last question there, and also, yes, us being competitive on the world market as it requires that we really be disciplined in spending and that we just continue to work our costs down. And that is, yes, through just all the primary efficiencies we've mentioned earlier with us having the top rigs. And you'll note too that we had quite a number of our rigs in 2016 under contracts placed a couple years ago, higher rates, $26,000 and $27,000 a rig. Now those are rolling off, and we're going to be able to replace those, about half those rigs with rates that are in the $13,000 to $15,000 per day rate. So that allows drilling costs to be down about 20% – 25%. Our tubulars, we depleted their inventory here early 2017. And with the arrangements we have in place, that will allow those costs to go down in the 20% to 25%. With our sand, as I mentioned earlier, we've reduced our production costs, optimized the transportation, just all of those sorts of things that allow us to reduce sand cost by about 15%. Same with rigs, we had many of our frac fleets under long-term contract. Half those are going away, which will allow us then to bring in the lower frac rates. We've continued to improve completion efficiency with faster completions, wireline run times, just our stage arrangements. The water infrastructure has continued to be enhanced, and it allows us to reduce our water costs. Our wellhead inventory, it's somewhat depleted, and that will allow us to reduce those costs in the 25% range. So all of this, and that probably accounts to 50% to 60% of our well cost, allows us to further reduce well cost here going into 2017. Yes, we are s pleased with the vendor help, service providers. We've got the top rigs, the top frac equipment. It's a fast-changing technology, so we're glad not to have ownership but just to work and partner with these service providers to have outstanding service at competitive prices. They're not always the same providers, but they're the best and the most cost effective in our arena. And the other thing is that our rig efficiency has improved such that, yes, we will not have to have the number of rigs we had back in 2013 and 2015. As a matter of fact, when we look at our 10% growth and our 20% growth, we think we'll be able to provide this sort of growth running somewhere between 25 rigs to 35 rigs. The number of frac plates we'll then require with the efficiency we're seeing are going to be in the 15 to 20 frac plates running for us, and that's on a compound average growth or increased rates. By the time we get to 2020, we're talking, yes, that's the 35 rigs on the 20% growth. So yes, the downturn has allowed EOG just to enhance our overall operations. Our divisions are performing especially well, continuing to lower our costs. And during the ramp up we would expect the same because if we look back and see what has been done by EOG in the period that we were growing volumes, the 30% to 40%, we will continue lowering our well cost, improving our efficiencies. And we expect our divisions to continue to do the same, especially with all the ideas we have now for further reduction. Thank you, Bill. William R. Thomas - Chairman & Chief Executive Officer: I'd like to end this conference by saying thank you to all of the EOG team. The EOG employees are focused on returns and they're performing at an extremely high level, and we could not be more proud of each one of them. So we look forward to the days ahead. So thank you for listening and thank you for your support.

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