Good day, everyone, and welcome to EOG Resources Second Quarter 2017 Earnings Conference Call. At this time, for opening remarks and introductions, I would like to turn the call over to Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you. Good morning, and thanks for joining us. We hope everyone has seen the press release announcing second 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 in EOG’s SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The 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 in 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 David Streit, VP Investors and Public Relations. An update of our presentation was posted to our website yesterday evening, and we included guidance for the third quarter and full year 2017 in yesterday’s press release. This morning, we’ll discuss topics in the following order: Bill Thomas will review second quarter highlights followed by operational results from Gary Thomas, Sandeep Bhakhri, Billy Helms, Lance Terveen and David Streit. I will discuss EOG’s financials and capital structure, and Bill will provide concluding remarks. Here’s Bill Thomas.

Thanks, Tim, and good morning, everyone. Over this last quarter, the question we received most often from the investment community was, how does EOG plan to respond to lower oil prices. Obviously, that question isn’t unique to ask as the entire industry is being asked to demonstrate capital discipline in the face of extended lower commodity prices. EOG is a return incentivized company and it has been since its founding. So our commitment to capital discipline is our core value and the fundamental driver of EOG’s history of peer-leading returns. From the beginning of the downturn in 2014, we have consistently executed a disciplined plan to return to industry-leading ROCE and industry-leading U.S. oil growth. This morning, we’re pleased to report that EOG’s second quarter results are right on target to achieve those goals. Our premium drilling strategy is the key. We continue to add low-cost premium reserves, driving down our DD&A rate and improving our ability to earn net income over time. Premium well results are the reason we returned the strong U.S. oil growth in 2017. Furthermore, during the second quarter, we exceeded all U.S. production targets. As a result, we increased 2017 U.S. oil production growth guidance from 18% to 20%. Our goal remains delivering cash flow, covering capital and the dividend. As outlined on Slide 7 of our investor presentation, premium drilling is already having a substantial impact on our production, finding costs and DD&A. Compared to 2016, oil production is forecast to grow 20%, while our DD&A rate is forecast to decrease 9%. In addition to strong growth this year, we continue to execute our robust exploration program to capture low cost acreage in plays that we believe could contain premium quality rock that would add to our growing 10 year inventory of premium drilling…

Thank you, Bill. The second quarter of 2017 marks EOG’s fourth consecutive quarter of domestic oil production growth. We delivered this high return oil growth, balancing CapEx with cash flow at an oil price roughly half of the peak in 2014. That accomplishment is a direct result of our permanent shift to premium drilling. Furthermore, second quarter production exceeded expectations, with 243 of our planned 280 net wells completed during the first half. We produced more than the high end of our U.S. production forecast for all commodities due to the outperformance from premium wells drilled throughout the first half of the year. On the capital side, we continue to see fantastic cost reduction in all our active basins. At the start of the year, we expected well costs in 2017 to at least remain flat as we were confident we could offset any exposure to inflation. However, we were also optimistic we could further reduce costs, so we establish stretch targets. Year-to-date, we’re on track to reach those targets in every major basin. During the first quarter, we met and reset our 2017 Delaware Basin well cost target, which we now met again during the second quarter. We’ve also met our Powder River Basin well cost target. And we exceeded our DJ Basin cost target by 10-plus percent. These cost savings are not a result of any one thing; they are a combination of everything. With our pleased but not-satisfied culture, EOG records are broken regularly. We all -- we are also keeping tight control of our operating expenses. We’ve offset any exposure to service cost inflation as well as increased costs associated with higher levels of activity. Ongoing cost reductions driven by the scale of our operations and other efficiencies have kept lease operating expenses flat quarter-to-quarter and down on a per-unit basis as we have successfully controlled LOE while increasing production. For the remainder of the year, we expect per-unit LOE will decline reflecting the sustainable nature of the cost savings and efficiency gains EOG realized over the last 2 years. As a result of well outperformance, we are increasing our forecast for 2017 U.S. oil production growth to 20% without increasing the number of wells completed or our capital expenditure forecast. Our performance year-to-date truly reflects the power of our premium drilling strategy. I’ll now turn the call over to Sandeep Bhakhri for a technology update.

Thanks, Gary. In our last earnings call, we highlighted how real-time data from our proprietary black boxes and our custom-developed mobile applications are a major productivity game changer. Last quarter, we showcased our proprietary real-time geosteering app, iSteer. This morning, [indiscernible] two new recentric [ph] apps we recently rolled out to our team in the Delaware Basin, and how they’re already making an impact. These tools were designed and customized with input from the entire drilling team, from the engineers in the office to the rig personnel on site. The entire team has access to more than 80 real-time data streams from advanced downhole instruments alongside instant access to data from previously drilled offset [indiscernible]. Drilling engineers and on-site rig personnel can analyze performance of bits and motors, as well as results from real-time predictive algorithms that project bit location and orientation to make real-time decisions. The whole team can look at real-time drilling projects in terms of days versus depth, depth versus cost, et cetera. It’s like having a real-time report card. The bottom line is that our drilling engineers and rig personnel are in lock step evaluating drilling performance versus their best offset wells. And all this analysis then goes into making the next well even better. Furthermore, the apps allow access to all these features anytime and anywhere. As an example on the New Mexico Wolfcamp [row] we recently drilled last month. Our company man on location called the well’s drilling engineer requesting to pull a drill bit. The drilling engineering who was out of the office at that time used his mobile app to quickly analyze their plan and determine that [tripping] for a new bit wasn’t needed in that particular interval of rock and would only add extra cost. With both the company man and…

Thanks, Sandeep. In the Eagle Ford, the average 30-day initial oil production rate from the 51 wells completed during the second quarter was about 1,500 barrels per day. This well performance marks a return to the productivity levels from last year before we began completing the older drilled but uncompleted wells or DUCs remaining in our working inventory. Many of the DUCs completed during the fourth quarter of 2016 and the first quarter of this year were drilled in 2015 prior to our more recent advancements in targeting. These latest Eagle Ford wells really demonstrate the impact that precision targeting makes on well performance. Successfully steering the lateral into the 10 or 20 feet of the highest quality pay of any given target can significantly enhance the well’s ability to achieve EOG’s premium drilling hurdle. From an operations perspective, this was a quarter of solid execution. We maintained and in some cases continued to lower completed well costs averaging just $4.5 million for a 5,300-foot lateral during the first half of this year. We are well on our way to reaching our year-end target of $4.3 million per well. The Delaware Basin continues to deliver outstanding well performance in multiple target horizons. In the second quarter, we completed 25 wells in the Wolfcamp and 19 wells in the Bone Springs. In the Wolfcamp, we are delineating in three different areas, two in the oil window and one in the combo area and testing various spacing distances between wells. Our first highlight, a four-well package drilled in Southern Lea County. The Rattlesnake wells are 660 feet apart and average 30-day IPs over 2,500 barrels of oil per day each from laterals that averaged about 6,700 feet. These wells complete a full section developed with eight wells per section in this Upper…

Thanks, Billy, and good morning, everyone. The industry has been focused on Delaware Basin takeaway for crude oil, plant processing and residue gas. Securing access to multiple markets and capacity options in 2018, 2019 and 2020 has been a key focus for our team. We’ve been successful diversifying our transportation options and sales points, so that marketing our Delaware Basin production will be as flexible as the optionality we built for our Bakken and our Eagle Ford production. Starting with crude. EOG capacity on a new third party Delaware Basin oil gathering system and terminal is on schedule for start-up in early 2018. This new system will deliver substantial cost savings and more importantly will give us three direct connections to takeaway pipelines with access to Cushing, Corpus and Houston markets along with the option to export our crude oil. Between our oil transportation agreements in place and our recent Mid-Cush Basis Swap positions, we’ve created security to market and minimized Mid-Cush Basis exposure. For natural gas, our Midland team has done a tremendous job, building out EOG-owned gas gathering and compression infrastructure. Our systems tie directly into multiple plants throughout the entire Delaware Basin. As we added to our plant processing capacity, we also ensure we have multiple options for residue gas take away from the Permian Basin. Through our existing agreements and soon-to-be-executed transactions with our strong midstream counterparties, EOG will be well insulated and protected during the most at-risk years of capacity concerns and volatility. Now here’s David Trice.

Thanks, Lance. We continue to drill very prolific highly economic wells in the South Texas Austin Chalk. In the second quarter, we completed nine wells with a 30 day average IP rate of over 2,600 barrels of oil equivalent per day each from an average treated lateral of less than 4,000 feet. The average well cost for these short laterals was just $4.6 million. Spacing varies but, in general, the recent wells average about 600 feet between laterals. We continue to test tighter spacing and lateral placement within the various Austin Chalk targets we are testing. More to come on this in the future. In our Bakken and Three Forks asset, well performance during the second quarter improved significantly. Much like the Eagle Ford towards the end of 2016 and into the first half of this year, we completed the remaining well inventory from 2014 and 2015. Those pre 2016 DUCs did not benefit from the more recent advancements in precision targeting used on our current working inventory of wells. Going forward, we have essentially depleted our Bakken DUC inventory, but the newly drilled Bakken wells will have the benefit of the latest precision targeting. Our 30 day average oil IP in the Bakken this quarter was almost 1,500 barrels of oil equivalent per day. The Clark’s Creek package and the Antelope Extension Area is particularly notable. The top-performing Bakken well in this package posted almost 3,200 barrels of oil equivalent per day for the first 30 days. Also included in the Clark’s Creek package was the Three Forks well. Its 30-day IP averaged over 3,000 barrels of oil equivalent per day. In the Powder River Basin, we completed 8 Turner wells during the second quarter. These wells came online with 30 day rates of over 1,700 barrels of oil equivalent per day each from an average treated lateral of 8,700 feet. We continue to see upside in our large 400,000 acre provision on the Powder River Basin and are pursuing block up trades throughout the basin. In Trinidad, we’re happy to announce we finalized an agreement with the National Gas Company of Trinidad and Tobago. The NGC and EOG agreed to a multiyear gas supply contract that will support a substantial drilling program and EOG’s ongoing exploration efforts. As mentioned last quarter, we recently completed a newly joint venture seismic survey and are planning to acquire another proprietary seismic survey next year. Both of these surveys are state-of-the-art and will greatly enhance our exploration and development activities in offshore Trinidad. In the second quarter, we drilled one new well in Trinidad and anticipate drilling at least three more wells in the second half of the year. With the new gas supply contract and new seismic data, we expect future EOG Trinidad projects to be economically competitive with our best onshore U.S. assets. I’ll now turn it over to Tim Driggers to discuss financials and capital structure.

Thanks, Randy. We are maintaining a full year 2017 capital expenditure guidance at $3.7 billion to $4.1 billion. During the second quarter, we are on track, investing approximately one half of that amount. Total exploration and development expenditures in the second quarter were $1 billion including facilities of $161 million and excluding acquisitions, non-cash property exchanges and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $56 million. Capitalized interest for the second quarter was $7 million. At quarter end, total debt outstanding was $7 billion for a debt-to-total capitalization ratio of 33%. Considering $1.6 billion in cash at hand, June 30, net-debt-to-total capital was 28%. In the second quarter of 2017, total impairments were $79 million. The effective tax rate for the second quarter was 63%. And the deferred tax ratio was 87%. Now I’ll turn it back over to Bill.

Thanks, Tim. In closing, I will leave you with a few important points. First, our premium drilling strategy is delivering better than expected well results. In the Permian, Eagle Ford and Rockies, EOG’s wells are some of the best in the industry allowing the company to exceed production targets with record capital efficiency. Second, we continue to lower well costs and operating costs. EOG’s cost-reduction culture leveraging sustainable technology and efficiency gains coupled with self-sourced materials and services continues to offset upward industry service costs. Third, EOG remains committed to capital discipline. We are on track to deliver cash flow at or above CapEx and the dividend into 2017. Fourth, we are engaged in a robust exploration effort using our extensive historical database and experience. We are focused on capturing high-quality rock and the sweet spot of new premium plays with strong leasing efforts underway this year. And finally, we believe we’re generating the highest investment returns in the U.S. and adding the lowest cost reserves. Our number one goal is getting ROCE back to our historical average of 13% or better, and creating sustainable long-term shareholder value. Thanks for listening, and now we’ll go to Q&A.

[Operator Instructions] And we’ll go to Evan Calio of Morgan Stanley.

Maybe I’ll start off with the incremental update in the Bakken and the Eagle Ford where you witnessed a normalized IP, 30 IPs, up by 30% in the Eagle Ford, and you doubled them in the Bakken. Can you provide color on what drove the change? Is it the shift away from DUCs, I think, you alluded to in the Bakken and into premium inventory or completion design specifics?

Yes. Evan, this is Billy Helms. I’ll start and maybe David Trice can add some color also. For the Eagle Ford, in particular, it was driven largely by our moving towards new drilled wells, getting away from the DUCs and taking advantage of our new steering technology that we kind of developed to identify the best rock and then steer the well in the best 10 or 20 feet of that rock. As we mentioned in all these plays, the rock quality makes a huge difference in the productivity of each play. And we’re taking the advantage of that this year. In the previous quarters -- the previous two quarters were driven largely by drilling or completing wells that did not take advantage of this new steering technology. So moving away from those and moving into a more -- a program more focused on the new advances in steering is what led to the improvements in the Eagle Ford. David?

Yes. This is David Trice. The Bakken is a very similar story. So we -- like I mentioned, we did, in the first half of this year, finish off pretty much all the DUCs in the Bakken. And a lot of these DUCs were drilled going back as far as 2014. So we’ve come a long, long way in the last 2 or 3 years on both targeting in the Bakken and in completions. And just understanding the interaction between the geology and the completion in the Bakken, because it is a -- you do see variations across the Bakken in the geology. And so you have to be able to match your completion and the timing of your completions to the geology. So that’s the biggest thing that we’ve seen as we’ve finished off those DUCs and starting completing some of the new drill, like the package that we announced that had such prolific results of -- in the Clark’s Creeks. So those are some new drill wells and so that shows the potential [indiscernible] return in the Bakken.

My second, if I stay on the Eagle Ford, on a normalized basis here, Austin Chalk wells are performing -- outperforming Eagle Ford wells by over two times in the last three quarters, it sounds like that outperformance is representative of development spacing. Just given what you’ve seen, what’s the consideration to progressing the Austin Chalk to full development mode? Or can you talk about kind of considerations there?

On the Austin Chalk, the main driver for the outperformance there is the reservoir quality. The reservoir quality of the Austin Chalk is superior to that of the Eagle Ford. And -- but a lot of the information we’ve collected over the years in the Eagle Ford that’s been applied to the Austin Chalk. So we’ve been able to basically take better rock and apply more advanced completions to better rock. As far as any updates on resource potential or anything like that, we’re still testing spacing patterns and various targets. We do see multiple targets in the Austin Chalk, similar to what we see in the Eagle Ford. But the geology is a little bit more complex. These aren’t -- the Austin Chalk is not exactly the same as a shale-type resourcing play. So we need to continue to collect more [indiscernible] data and get some additional target tests and as well as spacing tests before we can come up with any sort of resource update.

And we’ll next go to Brian Singer of Goldman Sachs.

With your recount higher -- with the recount higher across shale, not just for EOG but for industry, expectations from many are that we’re seeing -- or we’re going to see industry cost inflation. But as you highlighted, you’re still expecting well costs to fall in areas like the Eagle Ford. Are you not seeing the inflation? Or are you seeing it and more than offsetting it? And in a place like the Eagle Ford, can you talk to what represents the $0.2 million in well cost reduction you expect? And if there’s any offsetting impact in terms of what that well and its productivity look like?

Yes, we’re seeing some inflation on costs and not different than maybe we mentioned last quarter. It’s in that 10% to 15% range. A large part of our costs are pretty well fixed. We’ve got our drilling rigs probably 60% locked in. We’ve got our frac fleets about close to the same. We’re very fortunate to have these state-of-art rigs. And we are just offsetting the cost inflation with improved technology and the design of bits, design of motors. We have our engineers doing both of those. We’ve got our own mud systems and mud engineers. So we’re working those as well. So that along with [indiscernible] just these proprietary systems that Sandeep’s highlighted, that’s just given us greater confidence in further reducing our costs. We reduced our costs last year in that 15% to 30%, maybe an average of 20%. We think we’ll get to that 10% reduction again this year.

Great, great. And then my follow up is with regards to well performance. As you see wells outperform, and the improvement in 30 day rates in the Bakken and Eagle Ford was already noted, to what degree should we expect higher EURs from these wells, i.e., if we see that, hey, you’ve got almost double your 30 day oil IP in the Bakken, what type of EUR improvement should that lead to based on the knowledge in your reservoir modeling?

Yes, Brian, this is Billy Helms. Yes, we’re seeing that -- really the shift to premium has made a huge difference on not only initial production rate but the ultimate recovery we expect from each one of these plays. So you’re right, in general, as time goes on, we’re pleasantly surprised at the uplift we’re seeing in both production and EUR from the plays. And it all gets back to, as Bill and Dave described earlier, the quality of the rock. And of course, all that is driving our finding costs lower, which will ultimately lead to driving our DD&A rate down over time, which is the focus, as Bill mentioned, the focus of the company is getting back to our double-digit ROCEs. So that’s the focus. And it really ties back to focusing on the quality of the rock. That makes all the difference in the world.

I guess, is there a portion of the increase in 30-day well performance that represents greater depletion as opposed or quicker depletion as a result to it’s all EUR? Or should we assume the same percentage improvement in EUR as we see improvement in 30 day well performance?

Yes, Brian. This is Billy Helms, again. Yes, I think it’s not always directly proportional, the IP and the EUR. What we’re seeing is longer laterals oftentimes have a little bit suppressed IP relative to shorter laterals just on a length basis. But ultimately the EUR is increasing proportionately to lateral length, and that was a big focus for the company earlier in the year as we tried to go to longer laterals to make sure that our EUR per foot stayed pretty much the same as our previous wells. What we are seeing is just to take that to a next step further, I think by focusing on the quality of the rock and the steering and keeping it in that best rock, in general, the EUR is improving with time relative to the previous non-steered wells. So you’ve got multiple factors there that are working together to give us better results. It’s hard to give you an exact percentage of uplift on IP to EUR, because each plays is a little bit different. But in general, they are going up.

And we’ll next go to Doug Leggate of Bank of America.

Bill, I wonder if I could just start off, actually, with something of a macro question. You’ve kept Slide 26 in your deck, which talks about the new marginal cost of oil at $65 to $75. And I think, obviously, there’s probably some question marks around that right now. What I’m really getting at is your $50 to $60 range for your 15% to 25% growth rate in oil, how are you thinking about that longer term given that, I’m guessing, you’re probably thinking about resetting that Slide 26 deck as well as everybody else? And I’ve got a follow up, please.

Yes, at this moment, Doug, we’re not ready to change that guidance. We want to get more well -- well results and see how we line up here. But in general, we feel like our capital efficiency is going up, so we’re able to add more oil with lower cost all the time. And certainly, our breakeven costs are continuing to go down. On that chart you mentioned we’re at 10% -- to get a 10% return, it would take a $30 oil price. And over time, we’ll reevaluate that as we get better.

So I guess, it was probably a little bit obtuse question because I guess, what I was really hoping to get out of it was it seems to us that because your well results continue to get better, particularly in Eagle Ford, that 15% to 25% range, the $50 to $60 number has probably come down some. I guess what I’m really trying to get at is are you ready to give us the new deck where you can still achieve that 15% to 25% at $5 lower, for example?

Doug, Yes. No, we’re not ready yet to do that. We want to get more data and more time and really make sure that we’re not jumping the gun on that. And -- but certainly, our exploration effort is a big focus for the company. And we’re continuing to look for better and better rock all the time. And as that plays out, as we continue to increase productivity in the existing plays, et cetera, et cetera, we’ll take all that in consideration and update when we feel the right time is.

So hopefully that was my first mission. My follow up is, hopefully, a bit quicker. I’m going to take advantage of the fact that you were talking a little bit about the big data again on the call this morning. And really it relates to your exploration efforts. And my question is really about, can you kind of characterize for us, just at a fairly high level, when you’re entering a new play, to what extent is your data set and your data analytics allowing you to almost explore in a play before you drill the well? In other words, high grade the assessment before you actually go in and spend some real money. And I’m just -- in the context of business development because you mentioned that on the call again this morning, I know it’s pretty high level, but I’ll leave there.

Yes, that’s certainly an important point. We have multi decades of trial and error and multi decades of core data. And of course, we’ve developed our own proprietary petrophysical models to go along with that core data and multi decades of experimentation with the different types of completion technology. So we have all that data. We incorporate that into each kind of rock type that we’ve tested. And we have learned probably more about how horizontal technology affects tight rocks, particularly in plays of rocks that are non shale, in the last couple of years than we’ve learned in the last 10 years. So it’s been a very steep learning curve in the last few years. And that preparatory knowledge we were taking this year in a very robust manner to look for new plays. And we believe we have a lead on the industry. And we have a unique opportunity window, particularly this year, to add additional acreage in those kinds of plays. And so we’re -- we have increased exploration spending this year to do that. And so the whole process of gathering that data, collecting that data and analyzing that data has been a huge part of that, and we’re taking that advantage and using it this year.

We’ll next go to Paul Sankey of Wolfe Research.

You’ve got loads of good charts there showing how you’ve got great production growth and cost gains and all the rest of it, but I do notice that your return on capital employed graphic doesn’t have a scale. And further to that I was wondering, and I think my preference is, if I could give you one, would be that you had a rapidly rising return above, perhaps, a little bit less growth, So just a couple of things. First, I’m a bit bewildered by the sheer number of premium locations you’re adding because the inventory is now getting so long, I’m not sure why you would keep adding them unless you’re going to tighten the definition of premium location. And secondly, could we get to a point where you actually begin to aggressively pursue returns growth at $50 a barrel?

Yes, Paul. The Slide 7 that I referred to in the script is, I think, an attempt to kind of address some of the questions that you’ve brought up. The premium finding cost is roughly half of what the non-premium is. And so as we continue to focus on premium, we’re about -- last year, we were 50%, this year, we’re 80%. Next year, we’re projecting that 90% of our wells will be premium. And adding that premium finding cost as quickly as possible is very, very important to changing the cost basis of the company. And so higher growth with premium wells will drive the DD&A rate down quicker and help us to generate ROCE numbers more quickly over time. And so that’s what we’re focused on, and we’re focused on doing that with a disciplined cash flow -- spending within cash flow. So we’re adding the premium well reserves as fast as possible within cash flow and that -- and we’re also, of course, focused on cash operating costs. Those are a big part of earnings, too. So -- but again, adding those premium and adding that to the cost basis as quickly as possible within cash flow is the focus, and that’s the way we’re going to get there.

I guess, my question is, what is there? So are we looking at a double-digit return on capital employed by 2020 at $50 oil? Can you be more specific?

Well, we believe that you can get to double digits at $50, but it will take a bit of time. And we’re a bit hesitant to project the amount of time. It will do that but certainly, directionally, that’s possible, and that’s where we’re headed.

Yes, I just think it would be very differentiated if you could achieve that because we haven’t had a history in this industry of returns priority at the same time as the kind of growth that you’re offering. And I think for a company of your scale, once you get to 15% and 20% compound growth in volumes, I’m not sure why you would want to go faster than that. Is that fair?

Well, I think the important part of growth now within cash flow as fast as possible is adding those low cost reserves as fast as possible -- so within cash flow. And so that’s what we’re really focused on. I think it’s very important to note that these finding costs for these premium wells that we’re drilling are quite substantially much, much better than the rest of the industry. So if we’re growing faster than the industry, and these are the best wells, the lowest finding costs in the industry, then our ROCE should recover much quickly than the industry.

If you don’t mind, there’s a tremendous amount of controversy. If we could look back a little bit at the performance of your wells and the decline rate. Today, there’s a lot of controversy and a new buzz phrase is bubble point. Are you seeing more gas and anything in the decline rates that you’re getting that give rise to any kind of concern about the base that you’re dealing with? And I’ll leave it there.

Yes, Paul, this is Billy Helms. Yes, let me first start off by reminding everybody that we drilled over 5,000 horizontal oil wells in multiple basins, different plays, different target intervals and, more importantly, different rock types. As we’ve mentioned, the quality of the rock is extremely important, not only in their recovery but also in how the gas breaks out of solution. So there’s a lot of things that go into determining the GOR -- lifetime GOR for the play, and we take a particular note of that. And with our history and all the data we’ve collected, we have a lot of insight into what drives that. Of course, in particular, in the Delaware Basin, it’s highly over-pressured. And -- is one point, but also the type of rock we drill in and the core size that each rock type has also drives the GOR. So those are important points to make. Having said all that, what we are seeing is that the performance of our wells is adhering very well to the type curves that we use to build our forecasts on. And we’re not seeing a degradation in reserves or break out of gas over and above what we’ve already forecast. So I’d say, our wells are performing as we built our type curves, either performing or exceeding our type curves in most cases.

And we’ll next go to Charles Meade of Johnson Rice.

I wondered if I could go back to some of Gary’s prepared comments and make sure I heard them correctly and interpreted them well. Gary, did I hear properly that, for the first half of ‘17, you completed 243 wells versus the plan of 280? And if that is right, I guess it would make your first half performance even more impressive. And is there a catch up that you have planned in the back half of ‘17?

No, Charles. Sorry, but I didn’t speak clearly. We’ve completed 243 net wells of the planned 480 net for 2017. So we’re about halfway there.

And then a second thing, if I could ask about the Neptune wells that Billy Helms spoke about. And I guess, the question is, are those the same Neptune wells that made the appearance on your list of the top 16 of the 20 wells by peak oil month. And if they are, those are Bone Springs wells, does that indicate a possible step change in what you’re seeing in the Bone Springs?

Yes, Charles. This is Billy Helms. Those Neptune wells are the Bone Springs wells. And we are seeing some really outstanding performance in Bone Springs. And as you know, generally, we’ve typically been drilling the Wolfcamp intervals first, mainly because it’s deeper. It’s also highly productive but deeper. And it gives us a lot of the insight into geologically what’s happening in the Bone Springs. And these wells are drilled using that knowledge, but also the targeting technology that we’ve gained. So we’re getting some outstanding results from those wells.

Does that change? I mean, I think everything else on that list of those top wells is all -- I think most impressive is Wolfcamp. Is this a step-change that Bone Springs could maybe be half [indiscernible]?

Yes, I think the Bone Springs is meeting or exceeding our expectations. I don’t know if it’s a step-change in what we thought. We’ve always recognized the Bone Springs as a highly prolific zone. I think what you’re seeing is, this year, we are completing more than we had in previous years. And it does get down to the rock quality and how you select your targets, and those improvements that we made in that. So I don’t think it’s anything that we didn’t expect to have happen. I think the Bone Springs is highly prolific. But having said that, I think the Bone Springs -- important to also say, the Bone Springs is a highly stratigraphic play. And it’s not going to be the same everywhere. So you can’t extrapolate the results across the entire basin. And I think I made that point in the opening comments is every one of these play intervals are unique to a certain area. And you can’t expect results across the entire basin similar to these wells.

We’ll next go Bob Morris of Citi. With no response, we’ll move on to Paul Grigel of Macquarie.

Focusing in on the takeaway comments you made, specific on the Delaware Basin, starting with natural gas there. Can you provide more detail on what some of those key takeaway points are that you’re looking at outside of the basin once you’ve gathered the gas on your system?

Paul, its Lance. To us, the most important thing is diversification. So we hold some legacy transport that goes to the Southern California and Arizona markets. We’ve also [indiscernible] in capacity to the Gulf Coast. So as you think about the capacity, and we talked about the plant capacity, we’ll have transportation that goes all the way kind of into the Waha Hub. And then from there, we have takeaway that can go into either one of those the markets, whether it’s in the Sou Cal, Phoenix markets and also into the Gulf Coast.

And that’s firm capacity that you guys actually either have ownership or have control over?

Yes, sir.

Okay. And then, I guess, turning onto oil on the takeaway capacity from the Permian as well. A two part one, just one, as you guys look at new options coming on? Do you see it happening in, you mentioned early ‘18? Is there a continued growth through ‘18 that you see you can get on? And then second, with the addition of the mid Cush differentials that you guys examined there, how does that fit into both the broader takeaway strategy, but then also into a broader hedging strategy, given 2018 doesn’t have any oil hedges at this point in time, what would you guys need to see there?

Yes, I mean, the President mentioned in the prepared comments, we’re going to have the optionality to go to all the markets on the Gulf. Whether -- we have transportation and we’re going to hum going through Corpus, going through Cushing and also into the Houston markets. But what you’re seeing with the Mid Cush Basis Swaps, that’s really just complementing our transportation capacity that we have. So the way we think about that, we’ve got a certain amount of production that we sell at the lease. We also sell to local refiners that are in that area. They’re very good customers. So we’re going to always continue to have sales in Midland kind of based off the Mid-Cush index. So we just felt that the Mid Cush Basis Swaps were just very complementary to our transportation. And really, when you think about it, I mean, a dollar back of WTI, what you’re starting to even see today, even when you look at September, it’s trading more than $1.50 back. So -- which is [Indiscernible] as being very prudent to have some protection on a portion of the volumes that we’re going to have left in the Midland market.

Okay, and how does that -- and maybe this is for Tim, but how does that fit into the broader hedging strategy just on crude overall for you guys? Or how do you think about that at this point in time?

Yes, Paul. We always just look at that on a going forward opportunistic basis, and we’re -- fundamentally, what we see in the numbers is the market is still too bearish and the forward curve is flattish at best. So we’ll just continue to watch it over time. We would love to have up to 50% of our oil heads going into 2018, but we’ll just have to kind of look and see what the fundamentals are telling us and then make those decisions as we see opportunities arise.

We’ll go to James Sullivan of Alembic Global Advisors.

You guys went through this kind of basin by basin in the prepared remarks, but are you -- could you just, kind of a housekeeping, quantify the percentage or the number of total wells turned in line in the first half that were vintage DUCs. Just trying to figure out the percentage of not -- of wells those are not drilled with the new technology that were contributing to first half?

The number of completions that we brought on were 233. It’s probably roughly 25% of the wells in the first half were DUCs.

Okay. Great. That’s perfect, just what I was looking for. And then second question was a little bit of a macro topic, I was wondering if I could pick your brain on this, given your market knowledge. And the topic is the average API gravity will be produced, especially out of these growth, unconventional basins and this kind of hasn’t been talked about much. You guys talked about it back in 2013 to make the point that you were producing black oil, while others in the Eagle Ford were largely producing condensate-range material. That issue has kind of gone away with the up and down in unconventional budgeting since the oil swoon here and with the lifting of the export ban. And I know you guys don’t produce -- participate really in the crude export market, but can you characterize whether you, at all, foresee a problem marketing, and let’s just choose a gravity like incremental 45-degree API gravity oil, in the Gulf Coast in the next 2 years? Is this a problem that’s on your radar at all? Or are you not worried about it?

James, this is Lance. We feel like we’ve always been a first mover, whether in the Bakken and also in the Eagle Ford, segregating our crude. But when you look at the Delaware Basin, what we’re seeing with the gathering system and the terminal that we’re going to have, we’re going to be able to keep our crude segregated or move it. And what you’re seeing from a lot of the midstream companies is end segregations. We’re not going to see any degradation that we’re seeing today in terms of how you think about it an API quality, whether it’s a $45 to a $50, we’re not seeing any of that downstream.

We’ll go to David Heikkinen of Heikkinen Energy Advisors.

We’ve been thinking a lot more about how investors can see your results flow into really upstream financial reporting. You just kind of hit on the capital employed that’s holding back double-digit returns because of the base. Can you talk about, maybe by the end of ‘18, how much of your base will be premium locations with those lower [F&B] and better return?

David, the I don’t think we have a number that we can give you other than to say that, as oil prices and cash flow improve, we’ll be able to drill more wells. And as our capital efficiency improves, we’ll be able to drill more wells. And then next year, the percent of premium wells goes from 80% this year to 90% next year. So we’ll just have more and more premium wells every year as we go forward. And that isn’t really, as you noted, that’s important to changing our cost basis, getting those low-cost finding cost reserves into our base.

Maybe another way to look that we’ve been thinking about is in your reserve report. The 2016 and 2017 premium locations, will we see an improvement in additions and revisions or mainly additions?

Mainly, yes. David, it will be mainly in additions. I don’t think you’ll see a lot of revisions. We don’t expect any major revisions. I think you’ll see mainly additions from the new adds continuing to increase. I think the other way to think about that, too, is the overall company production base will become larger, made up -- more largely made up of the volume from the new programs and certainly that’ll help drive returns as well.

Just one more question on this, I really do appreciate it. And then on the future development costs given you guys have had a trend of sustainably lowering well costs, should we see a downward trend on future development costs on your reserve report?

Yes, I would think so. I think you would see that start to affect our reserve report over time as well.

That concludes today’s question-and-answer session. I will now hand back to Mr. Thomas for any closing remarks.

Thank you. In closing, our second quarter results were outstanding due to the excellent work by every EOG employee, and we certainly thank each one of them. And we look forward to continuing to lowering costs, improving well productivity and testing new plays in the second half of this year. We’re laser focused on adding low cost reserves within cash flow to improve EOG’s bottom line and to create long-term shareholder value. So thanks for listening, and thanks for your support.

And that does conclude today’s conference call. We thank you all for participating. Have a great day.