EOG Resources Inc (EOG) 2017 Q1 法說會逐字稿

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

Thank you, and good morning. Thanks for joining us. We hope everyone has seen the press release announcing first quarter 2017 earnings and operational results.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call.

This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website.

Participating on the call this morning are: Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, Senior VP, Marketing Operations; Sandeep Bhakhri, Senior VP and Chief Information and Technology Officer; Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, and we included guidance for the second quarter and full year 2017 in yesterday's press release. This morning, we'll discuss topics in the following order: Bill Thomas will review first quarter highlights; followed by few remarks from Sandeep Bhakhri on EOG's technology-driven culture. Gary Thomas, Billy Helms and David Trice will then discuss operational results. I'll discuss EOG's financials and capital structure; and Bill will provide concluding remarks. Here's Bill Thomas.

Thanks, Tim. Our first quarter performance is a great start to the year. We beat our production targets and are on track to grow oil production 18% this year. As you may recall, last year, we made a permanent shift to premium drilling, which means that new wells must earn a minimum hurdle rate of 30% return on direct drilling and completion capital at $40 oil and $2.50 natural gas. Our shift to premium drilling is a reason we can deliver high-return double-digit oil growth this year within cash flow including the dividend.

Last quarter, we talked about delivering this year's growth at $50 oil. We now believe we can deliver 18% oil growth within cash flow at $47 oil, a record for the company. Our premium strategy clearly sets EOG apart as one of the most capital-efficient and lowest-cost U.S. horizontal drillers. Our focus on growing low-cost premium production will continue to drive down breakeven costs and strengthen our bottom line over time.

Highlights in the first quarter include: One, both U.S. and total oil production beat the high end of our forecast. Two, we increased our premium resource potential by 1.4 billion barrels of oil equivalent by converting 1,200 locations to premium for a new total of 6.5 billion barrels of oil equivalent and 7,200 locations. That's a 27% increase in premium resource potential and 15 years of premium drilling at our current pace. Three, our Delaware Basin Whirling Wind wells set an industry all-time horizontal production record for the Permian Basin. Four, we continued to lower well costs in all our major plays, and we are lowering full year operating cost guidance. And number five, the first quarter drilling program generated more than 70% direct after-tax rate of return.

Generating high returns in today's price environment is a testament to the power of premium. It's also a testament or rather the result of EOG's rate of return-driven culture. When your entire team from entry-level professionals to executive management are incentivized by returns as they are at EOG, it drives innovation. Innovation -- innovative thinking is why EOG is consistently a first mover in the brand-new plays delivering the best-performing wells in the industry for the lowest cost in the industry. EOG was one of the first to both horizontally drill and hydraulically fracture the Barnett and the Bakken; the first to figure out that we can coax oil from the extremely tight shale log leading to our second to none acreage position in the Eagle Ford; the first to understand the benefits of complex near wellbore fractures versus biwing fractures; and the first to deploy high-density completions and precision targeting that enables EOG to consistently deliver premium oil performance. EOG's Innovative culture incorporates rigorous geoscience, petro physics and cutting-edge engineering in order to achieve return-focused technical investments.

Science and engineering, of course, requires data. 10 years ago, that data was analyzed using overengineered spreadsheets. Today, we employ sophisticated analytics using our vast collection of data and technology tools that have been developed in-house at EOG.

Now I'd like to introduce Sandeep Bhakhri, our Chief Information and Technology Officer. Sandeep has been with EOG 25 years on the front lines of EOG's information technology evolution. He will go into more detail on how EOG is using data science tools and mobile technology to enable faster innovation throughout the company.

Thanks, Bill. Good morning, everybody. We've received a lot of questions recently on our in-house information technology, our propriety data marks and apps and especially our use of big data and data science. I'd like to walk you through our evolution and explain how our approach is different than most and why we have 3 key competitive advantages that cannot be easily replicated.

The first competitive advantage is data. Data is king and one of our most valuable resources, and there are 2 pieces to it. One, you need comprehensive, integrated and easily accessible data sets. And two, you have to own the data. You cannot outsource its collection, analysis or delivery. EOG probably has the largest, most comprehensive and integrated data sets of any unconventional operator, having collected detailed data for more than 5,000 horizontal oil wells that we have drilled in almost every major unconventional play in the United States.

The second advantage is data delivery. Data delivery is key to effective decision-making. Data needs to be available 24/7 anytime anywhere in easy-to-use software tools. Over the past 25 years, we have built successful generations of fit-for-purpose software tools such that today, EOG has a suite of best-in-class data delivery systems consisting of 65-plus software applications covering virtually every functional area of the business. These tools power our decision-making delivering raw, analyzed and learned data 24/7 anytime anywhere.

And our most important advantage, we have been doing this a very long time, almost 3 decades. It's simply part of our culture. Without a culture of innovation and continue learning, technology cannot thrive. And without world-class technology, innovation and learning cannot happen. It's a virtuous cycle. Culture and technology aren't built overnight. If you haven't been doing both for a long time, you will have no source of a sustainable competitive advantage.

Let me give you a little history. When I say we've been doing this a long time, I mean since the early 1999s. The cost-saving trends at that time was to outsource information technology. EOG initially followed suit, but soon thereafter recognized a strategic mission-critical importance of IT and we decided to bring it back in-house. Rather than implement one size fits all (inaudible) back-office systems enrolled at that time, we instead opted to customize and maintain our own accounting system.

Then in 2000, the dot-com boom was in full swing, and investments in technology allowed us to tackle our first major IT-enabled transformation, namely, to reduce organizational friskiness -- friction for data access. We call this answering the what question. For example, what is the current production of this well? What is the cost of this well? Et cetera, et cetera. We built 10 web-based self-service applications, eliminating the need for employees to ask each other what questions and to instead focus on why and how questions.

Using IT to help answer the why and how questions became even more important in 2010. The catalyst was the explosion of data and data analysis that was the Eagle Ford. EOG's development of the Eagle Ford generated orders of magnitude more data than at any other time in EOG's past, creating an ever-increasing need to have access to this data and analyze it ASAP.

Our completion engineers were experimenting with completion designs for every well and sometimes every stage, while our production engineers were analyzing high-frequency production and pressure data from all our wells over our increasingly vast wireless field communications footprint. Third-party data collection tools were not keeping up with our demand. This was the start of our data collection and data storage initiatives that led to our 8 huge proprietary integrated data marks that now house data across virtually every functional area of our business. We believe they're the most comprehensive collection of integrated unconventional oil and gas data sets in the industry.

Simultaneously, we began data delivery initiatives that resulted in over 45 desktop applications that were fit-for-purpose custom tools accessing our ever-growing proprietary data marks. The very first in 2008 was a reservoir analysis tool with custom algorithms that allow our reservoir engineers to analyze well performance in a significantly shorter time than standard decline curve analysis. Since then, EOG has built a comprehensive suite of world-class, commercial-grade apps that address every functional area of our business. Combined, our 8 proprietary data marks and our 45-plus desktop applications help EOG engineers answer the why and how questions more quickly than ever before, which in turn shows up as superior well performance, lower cost and innovative exploration ideas.

Our latest technology evolution began 2 years ago with our move to real-time data collection and mobile data delivery systems. While we were already getting production data real time, we built custom black boxes to retrieve real-time data from every rig and every completion spread. This in turn spurred the need for mobile versions of our existing apps. In 2 short years, we have developed what we believe to be 20 of the most sophisticated mobile applications in the oil and gas business. We did it quickly by leveraging our existing proprietary data marks as well as our wireless communication footprint.

Real-time data and our mobile apps are a major productivity game changer. People at EOG are connected 24/7 anytime anywhere to the same data. We call it having a control room in your pocket. Add to this our culture of bottom-up decision-making that doesn't require multiple layers of approvals, and you have an environment of accelerated analysis, innovation and change at the speed of thought. In a moment, David Trice will share a new drilling record reached in the first quarter using one of the tool kits we've built in-house for precision targeting using mobile access to real-time data.

So what's next? How do big data and data science fit into our competitive advantage? It's actually very simple. The incoming real-time data is richer in meaning and significantly larger in volume, and therefore requires newer technologies to efficiently store, organize and access this data, enter big data technologies. And the larger and more multidimensional our data gets, it becomes imperative to revamp our traditional analytical engines enter data science. Big data technologies allow us to solve problems in fractions of the time it took with traditional technologies. And data science or machine learning or predictive analytics are a perfect fit for the rich and variable data sets that resulted from the constant experimentation and learning that is EOG.

To sum up: number one, we believe EOG has the richest, most comprehensive integrated data sets in the world for unconventional oil and gas, powered by the latest data technologies. Number two, we believe EOG has the most comprehensive suite of proprietary, custom-built, fit-for-purpose tools delivering data 24/7 anytime anywhere, be it raw, analyzed or learnt. And number three, #1 and #2 are possible because of and enhanced by our unique culture of innovation and learning.

Thank you very much. And next is Gary Thomas to review our operations performance for the quarter.

Thank you, Sandeep. Last quarter, I talked about our cost-reduction targets for 2017 and sources of savings we expected would offset timing in the oilfield services market and potential inflation. I'm pleased to report that we are on course to reach our cost-reduction goals for the year. And in some basins, we've already achieved the target set at start of the year. During the first quarter, EOG continued to reduce costs throughout our operations. Delaware Basin, completed well costs, averaged $7.8 million during the first quarter, an 8% reduction from 2016. $7.8 million was our original 2017 cost target for this play, so we've set a new lower target of $7.6 million. The Eagle Ford well costs in the first quarter declined 4% from the 2016 average of $4.5 million, which is already halfway to our target of $4.3 million. In the Bakken, we reduced well costs 6% to $4.8 million, which is more than halfway to our $4.8 million target. We updated our cost -- our cash operating cost guidance for the year, and in total, we expect it to be lower than initially forecast.

On the production side, we beat the high end of our forecast in almost every category. Our teams working each play are executing according to schedule and plan, and the production beats are being driven by well results that continue to exceed expectations.

Another notable item regarding our updated 2017 guidance, we now expect to average 26 rigs in 2017, which is 3 more than our initial plan for the same amount of capital. That's further testament to how ongoing cost reductions and well productivity improvement continued to drive record capital efficiency. Even with additional rigs, we're not yet changing our target to complete 480 net wells this early in the year. Additional rigs provide flexibility to our operations and allow us to reduce production lumpiness that resolves from developing larger multiwell pads. Several of our rigs are on well-to-well contracts that we have the flexibility to increase or decrease wells, as we monitor the macro environment and respond accordingly.

I'll turn the call over to Billy Helms, who will provide you an update on our Eagle Ford and Delaware Basin plays.

Thanks, Gary. The Eagle Ford continues to deliver solid results. This world-class play is increasingly being developed with larger multiwell pads, where we continue to achieve efficiency improvements that are helping to drive down costs. Our acreage is currently 97% held by production. And by the end of the year, we expect it to be 99%. As a result, we have even more flexibility to optimize operations using multiwell pads. We're also ringing out additional drilling efficiencies through innovative operations such as off-line submitting. Improvements to drilling and completions that speed our time to first production, not only lowers cost, but also minimizes the impact to volumes due to downtime from nearby well shut-ins.

Through a combination of cost reductions, longer laterals and advancements in precision targeting, we converted 500 net wells in our Eagle Ford inventory to premium status this quarter. That's more than 2x the number of Eagle Ford wells we are completing in 2017. The total premium net count -- net location count is now 2,425, representing more than 10 years of high-return inventory.

In addition, our G&G team continues to refine our targeting model to identify the optimal lateral placement and development spacing. With over 0.5 million acres, we have much left to understand and explore. The play changes significantly throughout our acreage, and we're working hard to delineate where the lower Eagle Ford may have 2 distinct targets and where the quality of the upper Eagle Ford is high enough to produce premium wells.

Delaware Basin is arguably the most prolific (inaudible) play in North America, and EOG continues to deliver the best well results in the industry. See Slides 13 through 15 in our investor presentation for an update. We produced a number of competing headlines with our first quarter performance to lead off this discussion. First, the performance of our Whirling wind wells in Lea County generated record-selling results. This package of 4 wells average 30-day IPs of 3,510 barrels of oil per day each from laterals that averaged about 7,100 feet. While all 4 may have individually set an all-time record, the Whirling wind 11 Fed Com #704H topped the list at 6,230 barrels of oil per equivalent per day, or more specifically, 4,350 barrels of oil per day plus 845 barrels of NGLs and 6.2 million cubic feet per day of natural gas. The 24-hour IP was a staggering 8,990 barrels of oil equivalent per day. We're certain this sets a new horizontal record for the entire Permian Basin.

Take a look at Slide 14 of our investor presentation. Had the Whirling Wind wells not existed, the spotlight would have been on an exceptional through Lea County 3-well package also completed during the first quarter, the Braswell 16-state COM #707 through 709H. 30-day IPs averaged 3,080 barrels of oil equivalent per day each. And notably, these wells were drilled using shorter 4,300-foot laterals.

Our shift to premium has led to increased activity in the Delaware Basin this year, which is delivering overall outstanding results. EOG completed 33 Wolfcamp wells in the first quarter of 2017. Impressively, 27 of those wells exhibited 30-day IPs in excess of 2,000 barrels of oil equivalent per day.

Operationally, our Delaware Basin continues to deliver record-setting results. As Gary mentioned, completed well costs in the first quarter have already met the targets set for the year. And drilling shaved off a full day from spud to total debt compared to the 2016 average. In addition, the capital directed towards facilities and infrastructure is delivering solid results by lowering both our direct well costs as well as achieving lower production costs. This long-term infrastructure plan provides the ability to cost-effectively manage both our needs for water to drilling and complete our wells, but also handle the produced water volumes from these prolific wells. Our water plan also includes an increase in the amount of water we recycle for use in the drilling and the completion process. This investment in infrastructure allowed our Delaware Basin wells to have the lowest operating costs of any of our oil-producing assets in the entire company. All these efforts allowed us to convert another 700 net locations in our Delaware Basin inventory to premium status. Between the Wolfcamp, second Bone Springs and the Leonard, our Delaware Basin acreage now holds a total of 4,150 premium net locations, providing more than 20 years of high-return drilling inventory.

Our exploration team continues to unravel the heterogeneity and complexity of the Delaware Basin's Maldive column, and we expect to test additional target intervals this year. As we have discussed in the past, a thorough understanding of (inaudible) along with EOG's precise targeting capability is a major reason for these outstanding well performance results. Based on early test results, we expect these additional intervals to provide EOG peer-leading results across the basin.

In summary, the additional premium well locations in both the Eagle Ford and the Delaware Basin have replaced our forecasted 2017 drilling program 2.5x just 1 quarter into the year. Here's David Trice to review the progress we've made in the Austin Chalk and our Rockies, Bakken and international activity.

Thanks, Billy. We completed 5 more wells in the Austin Chalk during the first quarter, producing excellent results consistent with the well performance we achieved last year. Our Austin Chalk completed well costs are already averaging a low $5.2 million per well, delivering premium economics. These 5 wells produced an average per well 30-day initial rate of over 2,600 barrels of oil equivalent per day from an average lateral of 5,700 feet.

The 19 Austin Chalk wells we drilled to date along with additional core taken during the first quarter has provided tremendous insight into the Austin Chalk depositional model and reservoir characteristics on our acreage. We are still learning about the Austin Chalk and its potential. For this reason, we are not yet ready to give a resource estimate for this prolific target.

In the Bakken, we continue to draw down our inventory of uncompleted wells in the first quarter. Even when loaded with higher historical drilling costs, these wells have a low average completed well cost of $4.8 million or 8,400 feet of treated lateral. During the first quarter, we completed 3 new wells in our Bakken Lite area using high-density completions for the first time. Two of these wells targeted the Bakken interval, and one targeted the Three Forks. The Rocks 42, 43 and 106 came online with an average per well 30-day rate of almost 1,000 barrels of oil equivalent per day, with a completed well cost of only $4.6 million for an average lateral of 7,700 feet. These wells are premium. With continued success in the Bakken Lite area, we could add to our Bakken premium inventory over time.

While most of the completion activity was in the Bakken during the first quarter, we continue to make premium wells in the Wild (inaudible), DJ and Powder River Basin. In the DJ Basin, we brought online 9 Codell wells in the first quarter. While the 30-day IPs on these wells are not flashy, averaging 710 barrels of oil equivalent per day each on 8,600-foot laterals, the production is flat and the well cost continues to rapidly fall. Normalized to 9,000 feet, DJ Basin well costs are just $4.5 million. In addition, we set some new drilling records in Codell. (inaudible) creek 531-2536H was drilled to a total measured depth of almost 18,000 feet in only 3 days. With a drilled lateral of nearly 9,000 feet, the average rate of penetration in the lateral was over 7,800 feet per day and was drilled 100% in zone, even though the target window was only 10 feet.

This accomplishment was the direct result of EOG's performance-driven culture and integration of drilling technology, real-time data delivery and in-house software applications. Our geo-steering and drilling software serves our needs better than any third-party applications available on the market today. Our geo-steering team can receive a real-time feed off EOG data directly into our software to interpret and integrate with off-set well control inside the data. All this information can be viewed and interpreted on a desktop or mobile application, so everyone associated with the well are in constant communication and can collaborate regardless of where they're located. It's essentially a distributed control room. The benefits are immediately visible as lower costs and better well performance. Furthermore, even though the Pull Creek 531 was the record well, 2 other wells on the same pad were drilled in 3.5 days, demonstrating the ability to consistently perform at a high level.

In the Powder River Basin, we continued delineate and analyze this large and complex basin. While completions were limited in the first quarter, the results are consistently premium. We completed 5 wells averaging 1,160 barrels of oil equivalent per day on 4,900-foot laterals. 3 of the 5 wells were legacy untargeted Yates wells with well cost low so low, they are premium. Normalized 8,000 feet Powder River Basin completed well costs averaged only $5 million. We look forward to a more active program in the Powder River Basin throughout the remainder of 2017 and beyond as we continue to block up acreage on current plays and explore for new play in its resource-rich basin -- In Trinidad we completed our 5-well program for the (inaudible) joint venture projects, bringing the remaining 4 gross wells online during the first part of the year. These successful project came in under cost and produced well rates ranging from 20 to 120 million cubic feet per day of natural gas. For the remainder of 2017, we are on target to drill at least 4 more offshore Trinidad wells in other project areas.

In addition, we recently finished a state-of-the-art ocean-bottom Noble or OBN seismic survey with the JV partner and expect final data to be delivered by the first quarter of 2018. This new seismic will allow to identify new prospects to supplement our future drilling plans.

We're also in final stages of negotiating terms of the new gas contract with National Gas Company of Trinidad and Tobago that will provide price certainty on future gas volumes. In conjunction with this gas contract, EOG has committed to a new proprietary OBN seismic survey over its SECC block that will set up new prospects on EOG acreage for 2019 and beyond. With this new gas contract and new seismic survey, we expect to be busy drilling premium wells and maintaining our gas production in Trinidad for many years to come.

In the [(inaudible), we are not anticipating any oil that's been a convey during the second quarter due to some ongoing facility issues. Full production rates are expected to resume sometime in the third quarter.

I'll now turn it over to Tim Driggers to discuss financial and capital structure.

Thanks, David. We are on track for the first quarter, investing approximately one quarter of our 2017 forecasted capital expenditures. Total exploration and development expenditures for the first quarter were $966 million including facilities of $148 million and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $34 million.

Capitalized interest for the first quarter 2017 was $7 million. At quarter end, total debt outstanding was $7 billion for a debt-to-total capitalization ratio of 33%. Considering $1.5 billion of cash on hand at March 31, net debt-to-total capital was 28%.

In the first quarter of 2017, total impairments were $193 million. Impairments to prove properties of $138 million were primarily the result of a write-down to fair value of legacy natural gas assets.

The effective tax rate for the first quarter was 28% and the deferred tax ratio was 6%.

Yesterday, we included a guidance table with the earnings press release for the second quarter and full year 2017. Our 2017 CapEx estimate remains unchanged at $3.7 billion to $4.1 billion excluding acquisitions. The exploration and development portion excluding facilities will account for about 81% of the total CapEx budget. The budget for exploration and development facilities and gathering processing and other accounts for approximately 19% of the total CapEx budget for 2017. We plan to concentrate our infrastructure spending in the Eagle Ford, Delaware Basin and Rockies to support our drilling programs in those areas and enhance operating efficiency.

Now I'll turn it back over to Bill.

Thanks, Tim. In closing, I'll leave you with a few important points.

First, EOG's Delaware Basin acreage position and results are proving to be the best in the industry. Our record-setting wells and ongoing cost reduction are generating the best capital returns and delivering the highest capital efficiency in the Permian Basin.

Second, we're not just a Permian company. We're achieved premium returns and oil growth in 5 core plays. Every core play continues to get better and provides EOG with the largest and highest quality horizontal asset basin in North America with decades of high-return growth potential.

Third, as we discussed today, EOG continues to be the leader in horizontal technology. Our culture thrives on innovation, and we develop new ideas time and time again. With our extensive, proprietary data basins and sophisticated analytics, we are turning out new innovative ideas rapidly. We believe we're extending our leading technology faster than ever before. EOG's culture and technology advancements are a sustainable competitive advantage.

Fourth, we're on track to deliver high-return oil growth within cash flow. We said last quarter that we could deliver 18% oil growth within cash flow at $50 oil. With our increased confidence in cost reduction, we now believe we can deliver that 18% growth within cash flow, including the dividend, with $47 oil. As more and more of the low-cost premium wells are brought online, our bottom line breakeven continued to improve over time.

And finally, EOG is on target to achieve our 2020 Vision and to accomplish the following 4 goals: first, to be the U.S. leader and return on the capital employed; second, to be the U.S. oil growth leader; third, to be among the lowest-cost producers in the global oil market; and fourth, commitment to safety and the environment.

Thanks for listening. Now we'll go to your questions.

(Operator Instructions) our first question today will come from Brian Singer with Goldman Sachs.

Wanted to get a bit more color on the Eagle Ford. Slide 40 shows the productivity both in the East and the West and you talked in your prepared comments to a number of returns enhancing initiatives via cost reductions. If we look at from a well productivity perspective, when you take into account the benefits of targeting and data analytics that you discussed, what are your expectations for how 2017 and perhaps 2018 wells could look like in the context of Slide 40? How much additional room do see for further well productivity gains, specifically in the Eagle Ford?

So Brian, this is Billy Helms. In 2017, we're seeing -- we don't have it on the chart as you mentioned. But what we're seeing is we're delivering consistently better and better wells in every one of our areas. On the chart, we show producing days of 360 days. We don't yet, being this early in the year, we don't yet have that many days of production on our 2017 wells. That's why the slide is not updated. But generally, what we're seeing is improving well performance, even though in some areas, we're offsetting some depletion in some patterns that we're drilling. But overall, the targeting and the high-density completions are continuing to improve our well performance. In addition, we are moving, as you noted, we're moving to more and longer laterals in our patterns. And that in addition is generating overall higher EURs per well. So I think we're pretty pleased. It's still early yet to say where that's heading, but we're excited about what we're seeing to date.

Great. And my follow-up is with regards to the CapEx budget and then guidance for the year. As you mentioned, you added 3 rigs but no additional completion activity. Can you add a bit more color on what seems like is a buildup by the end of the year-end and uncompleted inventory? And what you would want to see or need to see to begin to complete those wells?

Brian, this is Gary. And as you said, yes, we continue to reduce our costs, so we'll drill more wells with the same CapEx guidance. We depleted our uncompleted inventory last year. And now we're just building that premium inventory. And previously, we would drill 2 to 3 well pads. Now we're drilling 5 to 6 well pads with more wells per pad. That just means that we have fewer overall pads and fewer options or locations for our frac fleets. And this could be a problem if we can't find a pad to move on for some reason. So we just needed the additional pads, which means more wells for each frac fleet. Thankfully our well costs are really low. It's just a low-cost insurance for flexibility and optionality. And it's still too early in the year, and oil prices are too volatile to make adjustments to our guidance. But -- and we can adjust readily and we can lay down rigs. We can add inventory or we can add more completions. But just our primary focus is to invest within cash flow and the highest return premium wells.

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

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

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

Our next question comes from Jeffery Campell from Tuohy Brothers.

I was wondering if first, could you provide some color on which intervals were contained in this 700 premium locations that were added in the Delaware Basin. I mean it seems like you had good results in several different intervals, and I was wondering if we could get little color there.

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

Great. And as a follow-up in the Powder River Basin, the lateral lengths were fairly short this quarter relative to most of the other intervals developed during first quarter '17. I was just wondering if there's any color on that it was determined by least geometry or are you working towards increasing lateral lengths over the rest of the year?

Yes, this is David. In the Powder River as we noted, 3 of the 5 that we brought online were legacy Yates wells and they were short laterals. And then we do on occasion drill some of the shorter laterals due to lease issues. But really on a go-forward basis, we're planning in the Powder to be drilling all 2-mile laterals. So that's what you see in majority of the laterals in the future.

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

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

Yes, Subash. This is Billy Helms. So on the Delaware Basin, I'd say we're still in the early innings of trying to develop our multiwell pads. We're testing largely as you know the Wolfcamp interval to start with. And we still got a lot of horizons to tests both -- most of which are above the Wolfcamp and so we're looking at what is the optimal way to increase our well count in this area and ultimately end up with a greater number of wells in each section or spacing unit that we drill. But in regionally I think right now, we're probably drilling on average 3 or 4 wells per pad initially. And we're coming back in behind that with additional development.

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

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

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

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

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

(Operator Instructions) We'll go next to Irene Haas from Wunderlich.

Congratulation on the Whirling Wind well, they're truly impressive. Just wondering if they are from the upper Wolfcamp? And then what is driving the performance? Is the completion techniques, geo-steering or better rocks? And can this be replicated over a large area?

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

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

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

Our next question comes from Bob Morris from Citi.

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

Bob, this is Bill Thomas. You're asking some information that's proprietary. I'll give you some general guidelines. Certainly, the rock is very variable in the Permian, particularly the Delaware Basin. There is a lot of variability in the vertical sense. And then laterally, it does vary some too. So you need a lot of data to identify it. And we start with cores. We do an extensive amount of core work -- 4 cores and analyze that rock. We integrate that into to a petro physical model. And then we integrate all that data into 3D seismic. And we create very detailed maps the -- structure maps and stratigraphic thickness maps before we even start to drill the well. So it does take a lot of very sophisticated geology to identify these targets and it takes a lot of data and a lot of really good G&G and engineering work to locate that lateral. And then importantly, we developed the in-house software as Sandeep and David describe, to keep a bit in that really good rock, in a 95% to 100% of the lateral. And when we do that, and we do the sophisticated high-density completions, that's why the wells are so good. And so the goal is just to continue to identify better zones to have better execution and to continue to improve the frac technology over time. So we think there's a lot of upside left and we're very encouraged directionally technically where we're headed.

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

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

Next we'll go to Charles Meade from Johnson Rice.

I wanted to ask and Bill, this might be for you or perhaps for Sandeep. But I wondered if you could give us, without giving too much away, could you give us a sense of the kind of data types and streams you're capturing now versus perhaps what you were doing a year or 2 years ago? And what new sorts of data or opportunities for data capture you might be looking at a couple of years down the road?

Yes, Charles. This is Sandeep. I'll take that question. I would say the biggest change for us versus a couple of years ago is the real-time data that's streaming in. And as the data comes in with the [tire] resolution with some of the black boxes that there putting out on the rates in our frac rates we're able to get a lot more insight into the data and we're able to turn that into new learnings and translate that into the hyperactive wells. The best example of that is just the data that we're getting real-time in -- now to help us geo-steer. I think that's the biggest delta change from the past where the data wasn't as real time. And then on the frac side of the business, it's the same thing. We're getting real-time data coming in from every frac lead. And so we're able to change our completion designs and accommodate real-time understanding what the rock is telling us. So that would be -- those would be 2 concepts that are different say from 2 or 3 years ago.

Got it, Sandeep. And that really fits well what, I was going to ask the same question about those Whirling Wind wells, but I think you guys have explained it's in the intersection of the targeting frac and everything well. If I could ask just a question perhaps for Dave Trice about the Austin Chalk. I recognize you guys are not ready to put a resource number on that. But I'm curious if you could elaborate a bit on how you see that the evolving. Is this kind of a -- maybe a sort of polka dots across the map of different hotspots? Or is this kind of all concentrated in one area? And what's the timeline for your best guess as timeline for when you will kind of mature that?

Well, Charles, I would say on Austin Chalk, we've certainly learned a lot over the last several quarters. And we just wanted to continue to do the step-out wells, the targeting test and the [indiscernibl test as well. We've done several spacing tests over the last several months. We've done some at 400 feet, some at 600 feet, and the results are -- good on all of those, but we're still trying to dial in the exact spacing. But just keep in mind that I mean, it's a lot different than what the traditional chalk was like. And if you think the traditional fracture chalk, you had really wide spacing. And this is going to be much more of a resource type play. So nobody has ever really kind of chased the chalk in this play. So we just want to have a little more time and collect some more data. We've collected a couple of cores and quite a few logs and we're really -- most of our testing has been across 10 to 20-mile stretch on our acreage. But in the coming quarters, we'll have some updates.

I think we can close the call.

We -- and we do have one more question. Would you like to take that?

Sure go ahead.

It comes from Marshall Carver from Heikkinen Energyn Advisors.

You highlighted individual wells in the presentation. We tend to think of premium wells as a median results. What are your thoughts around standard deviation around your IPs and EURs as you -- as you're heading forward?

Marshall, I think there is a slide in the IR deck. I think it's Slide 10 that gives the metrics on our premium wells that we completed last year versus the non-premium wells. And they are remarkably better. I think this is one of the things in the street that may be a little bit misunderstood. The premium wells are roughly the returns on them are roughly 5 -- a fivefold increase in returns. The finding costs are less than half. The capital efficiency is more than twice as good. And the first year oil production on the premium versus non-premium is actually doubled. So the premium wells are remarkably better than the wells that EOG has historically drilled in the past. And EOG in a past has drilled the best wells we believe in the industry. So the premium wells are certainly a game changer for the company. And as we go forward, and we add these low-cost reserves to our reserve base, they will continue to drive down our DD&A rate and that will filter the bottom line our breakevens will be better and certainly, help us on ROCE. So there are remarkably better wells. And I think that's maybe not quite understood by the street.

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

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