EOG Resources Inc (EOG) — Q2 2017 Earnings Call Transcript

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 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 locations. With everywhere we drill, we collect new data that we incorporate into our big data systems. We are constantly learning how different types of tight rocks respond to horizontal technology. And we apply this knowledge to capture new acreage in exploration plays and to drill better wells in our existing plays. As we’ve said many times before, the key to great wells is high-quality rock. Our multi-decade database and the learning curve give us a huge lead in identifying the best rock to add new and better drilling potential to the company. Each one of our 7 U.S. exploration teams is generating new prospects that make the company better. The exploration potential is a key sustainable advantage for EOG. Disciplined capital efficiency, returns, exploration and growth are EOG hallmarks, and our second quarter performance continues to demonstrate the outstanding results. Looking forward, regardless of where oil prices go from here, EOG will respond accordingly. We are committed to returns, delivering within our means and a strong balance sheet. We believe production growth should be the result of investing in high return drilling and have never been fans of outspending cash flow to pursue growth for growth’s sake. We are doing all the things that keep us marching towards our ultimate goal of delivering sustainable, long-term shareholder value. Now I will turn it over to Gary Thomas to discuss our second quarter production and cost achievements in more detail.

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 480 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 over 10%. 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 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, I want to discuss two new 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 wells. 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, etc. It’s like having a real-time report card. The bottom line is that our drilling engineers and rig personnel are in lockstep 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. For example, on the New Mexico Wolfcamp we recently drilled last month, our company man on location called the well’s drilling engineer requesting to pull a drill bit. The drilling engineer, 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 the drilling engineer viewing the analysis in real-time, they decided not to trip. They drilled a vertical with one less assembly, saving a day of drilling time and an estimated $100,000 for the interval. This improved performance in the vertical contributed to a drilling record for the New Mexico Wolfcamp, reaching 17,000 feet in 10 days. Given the diversity of rock types in the Delaware Basin, the ability for our drilling team to react instantly to changes compared to the initial plan is critical for achieving superior well results that Gary just spoke about. I can’t emphasize enough that EOG’s quantity, quality and breadth of data drives our information technology advantage. First, we believe we have multiple times more data on horizontal oil wells than anyone in the industry. More importantly, the data is proprietary. The type and granularity of data and the frequency of collection is customized to our needs. Second, we are constantly experimenting, applying and learning to the next well. EOG’s culture is to always question and push the envelope on what can be done. The result is terabytes of differentiated data capturing results of thousands and thousands of experiments. The applications they’ve built in-house analyze and deliver all the data in real-time better than any other comparable suite of applications in the industry. However, these applications are virtually useless without the big data and the culture of experimentation and innovation you need to drive data science in the first place.

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 indicates a return to last year's productivity levels, prior to our completion of older drilled but uncompleted wells remaining in our inventory. Many of the older wells completed recently were drilled in 2015, before we improved our targeting strategies. The latest Eagle Ford wells clearly show how precision targeting impacts well performance. Effectively steering the lateral into the highest quality pay zone can significantly improve the well's effectiveness in meeting EOG's premium drilling criteria. From an operational standpoint, this quarter demonstrated solid execution. We maintained, and in some cases reduced, our completed well costs, averaging $4.5 million for a 5,300-foot lateral during the first half of the year. We are on track to reach our year-end target of $4.3 million per well. The Delaware Basin continues to produce exceptional well performance across various 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 exploring three different areas, two within the oil window and one in the combo area, while testing various well-spacing distances. Our first highlight, a four-well package drilled in Southern Lea County, had the Rattlesnake wells spaced 660 feet apart, averaging 30-day initial production rates of over 2,500 barrels of oil per day each from laterals averaging around 6,700 feet. These wells complete a full section developed with eight wells per section in the Upper Wolfcamp interval. Although these wells are still early in their productive life, we are optimistic about the performance of the spacing pattern. A second four-well package, the Whitney Bronson wells, were drilled in the oil window of Loving County, with 440 feet between them. These wells averaged 30-day initial production rates of 2,250 barrels of oil per day each, with laterals averaging around 9,500 feet. The third package is a three-well layout in the combo area, the State Street 20-29 wells in the State Apache 57 number 1610H. These wells averaged 30-day initial production rates of 3,250 barrels of oil equivalent per day each, with a 49% oil cut and laterals averaging 7,200 feet. Overall, the average 30-day production rate from the 25 wells completed in the Wolfcamp exceeds 1,900 barrels of oil per day or 3,000 barrels of oil equivalent per day, considering both the oil window and combo portions of the play. Similar to the Wolfcamp, we continue to experiment with longer laterals in the Bone Springs. We completed a three-well package, the Neptune 10 State Com 503H-505 H, which averaged 30-day initial production rates of nearly 2,800 barrels of oil per day each, with laterals of 9,700 feet. Overall, the 19 wells completed in the Bone Springs during the second quarter averaged over 1,500 barrels of oil per day. Our development strategy involves delineating our acreage and establishing proper well spacing for various target intervals. Our program continues to yield results that surpass our reasonable expectations. We are still at the beginning of assessing the full long-term potential of this world-class play. Although it's early, we are discovering that the best areas for each target interval are highly dependent on the stratigraphic characteristics of the intervals, rather than being uniformly distributed across the entire basin. Next, Lance Terveen will share details about our plans for takeaway capacity in the Delaware Basin.

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 add 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 position in 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.

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 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 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 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 situation is quite similar. As I mentioned, we completed nearly all the DUCs in the Bakken during the first half of this year. Many of these DUCs were drilled as far back as 2014. We've made significant progress over the past two to three years in terms of targeting and completions in the Bakken. We’ve gained a better understanding of how the geology interacts with the completion process, as there are variations in the geology throughout the Bakken. Therefore, it’s essential to align your completion strategy and timing with the geological conditions. This is the key observation we've made as we finished those DUCs and began completing some new drills, like the package we announced that achieved outstanding results at Clark's Creeks. These new wells illustrate the potential for substantial returns in the Bakken.

On a normalized basis, Austin Chalk wells are outperforming Eagle Ford wells by more than two times over the last three quarters. This outperformance seems to be linked to development spacing. Considering this, what are the factors influencing the decision to move the Austin Chalk to full development mode?

On the Austin Chalk, the key factor for its strong performance is the quality of the reservoir, which is better than that of the Eagle Ford. We have utilized much of the data gathered over the years in the Eagle Ford to enhance our efforts in the Austin Chalk. This has allowed us to work with superior rock and employ more advanced completion techniques. In terms of updates regarding resource potential, we are still examining spacing patterns and various targets. We do identify multiple targets in the Austin Chalk, akin to those in the Eagle Ford, but the geology is somewhat more intricate. The Austin Chalk does not precisely align with a typical shale resource play. Therefore, we need to gather more data and conduct additional target and spacing tests before making any resource updates.

With your recount higher across shale, not just for EOG but for the 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 looks 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-the-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 our proprietary systems that Sandeep 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 regarding 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 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, this is Billy Helms. The shift to premium has significantly impacted both the initial production rate and the ultimate recovery we anticipate from these plays. Over time, we are pleasantly surprised by the increase in both production and EUR from these areas. It all relates back to the quality of the rock, as Bill and David mentioned earlier. This improvement is also helping to lower our finding costs, which will eventually reduce our DD&A rate over time. The company's main focus is to return to double-digit ROCEs, and this is closely tied to maintaining a strong emphasis on the quality of the rock, which is crucial.

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 its 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 working together to give us better results. It’s hard to give you an exact percentage of uplift on IP to EUR because each play is a little bit different. But in general, they are going up.

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, we’re not ready to change that guidance. We want to get more well results and see how we align here. Generally, we feel that our capital efficiency is improving, allowing us to increase oil production at a lower cost consistently. Our breakeven costs are also continuing to decline. According to the chart you mentioned, to achieve a 10% return, we would need a $30 oil price. Over time, we’ll reassess that as we gather more data.

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. 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, etc., we’ll take all that into consideration and update when we feel the right time is.

Hopefully, that was my first mission. My follow-up is intended to be a bit quicker. I want to capitalize on what you mentioned about big data earlier in the call this morning, particularly in relation to your exploration efforts. My question is about how you would characterize, at a high level, the extent to which your data sets and analytics enable you to explore a new play before actually drilling a well. In other words, how do you assess the potential of a play before making significant financial commitments? Given your mention of business development on the call this morning, I understand this is a broad question, so I will leave it at that.

Yes, that's certainly an important point. We have decades of trial and error along with extensive core data. Additionally, we've developed our own proprietary petrophysical models to complement that core data and years of experimentation with various completion technologies. We incorporate this information into each rock type we've tested. In recent years, we've learned significantly more about how horizontal technology impacts tight rocks, especially in non-shale plays, than we did over the past decade. The learning curve has been steep recently, and we're leveraging that knowledge this year to search for new opportunities. We believe we have an edge in the industry and a unique opportunity to acquire more acreage in those plays this year. As a result, we've increased exploration spending to support this effort. The process of gathering, collecting, and analyzing data has been crucial, and we are utilizing that advantage effectively this year.

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 I mentioned earlier is intended to address some of the questions you've raised. The cost of finding premium resources is approximately half of that for non-premium. As we concentrate on premium resources, last year we achieved 50%, this year we aim for 80%, and next year we project that 90% of our wells will be premium. It is crucial to quickly add the premium finding costs as it significantly impacts the company's cost structure. Increased growth from premium wells will lead to a more rapid decline in the DD&A rate and enable us to generate return on capital employed more swiftly over time. We are committed to maintaining disciplined cash flow and ensuring that spending remains within this limit. Our objective is to increase our premium well reserves as rapidly as possible while managing cash operating costs, which also contribute significantly to our earnings. Therefore, our focus remains on adding premium wells and incorporating them into our cost structure as quickly as possible within our cash flow parameters.

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?

I believe that the key to growth in cash flow is quickly adding low-cost reserves. This is our main focus. It's important to highlight that the costs associated with finding these premium wells we're drilling are significantly better than those in the rest of the industry. If we're growing at a faster pace than the industry and these are the top wells with the lowest finding costs, our return on capital employed should improve much more rapidly than the industry's.

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. Let me start by reminding everyone that we have drilled over 5,000 horizontal oil wells across various basins, plays, target intervals, and rock types. The quality of the rock is crucial, not only for recovery but also for how the gas escapes from solution. There are many factors that contribute to determining the gas-to-oil ratio for the play, and we pay close attention to that. With our extensive history and the data we’ve gathered, we have significant insight into what influences that. In the Delaware Basin, for instance, it is highly over-pressured, and the rock type we drill and the core size associated with each rock type also affect the gas-to-oil ratio. Those are key points to consider. That said, we are observing that the performance of our wells aligns closely with the type curves we use for our forecasts. We’re not experiencing a decline in reserves or gas breakout beyond our forecasts. In most cases, our wells are performing as we anticipated in our type curves or even exceeding them.

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 think everything else on that list of top wells is quite impressive, especially the Wolfcamp. Could Bone Springs possibly be half of that step change?

Yes, I believe the Bone Springs is meeting or exceeding our expectations. I’m not sure it represents a significant change from what we anticipated. We've always seen Bone Springs as a very productive area. This year, we are completing more wells than in previous years, which relates to the rock quality and our target selection improvements. Therefore, this isn’t unexpected. The Bone Springs is indeed very prolific. However, it's important to note that Bone Springs is a highly stratigraphic play, and results will vary across different areas. You cannot generalize the results across the entire basin. As I mentioned earlier, each play interval is unique to a specific area, and therefore, similar results across the entire basin cannot be assumed.

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, it's 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 added 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 into the Waha Hub. And then from there, we have takeaway that can go into either one of those markets, whether it’s in Southern California, 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, as I mentioned in the prepared comments, we have the flexibility to access all the markets in the Gulf. We have transportation options, including routes through Corpus, Cushing, and into the Houston markets. The Mid-Cush basis swaps are enhancing our transportation capacity. We have a certain volume of production that we sell at the lease and to local refiners in the area, who are reliable customers. We will continue to make sales in Midland based on the Mid-Cush index. Therefore, we view the Mid-Cush basis swaps as complementary to our transportation strategy. When considering the pricing, the current trading levels are around a dollar back from WTI, and even as we look at September, it’s trading more than $1.50 back. Hence, it makes sense to have some protection for a portion of the volumes we plan to maintain in the Midland market.

Could you provide the percentage or the total number of wells turned in line in the first half that were vintage DUCs? I'm trying to determine the proportion of wells that were not drilled with the new technology contributing to the first half results.

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

Okay. That's perfect, just what I was looking for. My second question is more of a macro topic; I wanted to get your insights on the average API gravity that will be produced, especially from the growing unconventional basins, which hasn't been discussed much. You mentioned back in 2013 that you were producing black oil, while others in the Eagle Ford were mainly producing condensate-range materials. That issue seems to have faded with the fluctuations in unconventional budgeting since the oil downturn and the lifting of the export ban. I know you don’t participate much in the crude export market, but do you foresee any challenges in marketing, say, 45-degree API gravity oil in the Gulf Coast over the next two years? Is this something you're keeping an eye on, or is it not a concern for you?

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 API quality, whether it’s a $45 to a $50, we’re not seeing any of that downstream.

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 costs and better return?

David, 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 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 at 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?

Yes, it will mainly be additions. We don’t anticipate significant revisions. You can expect primarily additions as the new increments continue to grow. Additionally, the overall production base of the company will expand, increasingly comprising volume from the new programs, which will surely contribute to driving 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.

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 lower costs, improve well productivity and test 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.