Good day everyone, 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, 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, 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, we included guidance for the second quarter and full year 2017 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review first quarter highlights, followed by a few remarks from Sandeep Bhakhri on EOG's technology-driven culture. Gary Thomas, Billy Helms, and David Trice will discuss operational results.
I will discuss EOG's financials and capital structure, 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 $250 natural gas. Our shift to premium drilling is the reason we can deliver high return, double-digit oil growth this year within cash flow, including the dividend. Last quarter, we talked about delivering this year's growth at $50 oil. We now believe we can deliver 18% oil growth within cash flow at $47 oil, a record for the company. Our premium strategy clearly sets EOG apart as one of the most capital-efficient and lowest cost U.S. horizontal drillers.
Our focus on growing low cost premium production will continue to drive down break-even costs and strengthen our bottom line over time. Highlights from the first quarter include, one, both U.S. and total oil production beat the high end of our forecasts. Two, we increased our premium resource potential by 1.4 billion barrels of oil equivalent by converting 1,200 locations to premium for a new total of 6.5 billion barrels of oil equivalent and 7,200 locations. That's a 27% increase in premium resource potential and 15 years of premium drilling at our current pace. Three, our Delaware Basin Whirling Wind wells set an industry all-time horizontal production record for the Permian Basin. Four, we continued to lower well costs in all our major plays, and we are lowering full year operating cost guidance. Number five, the first quarter drilling program generated more than 70% direct after-tax rate of return.
Generating high returns in today's price environment is a testament to the power of premium. It's also a testament, or rather the result of, EOG's rate of return-driven culture. When your entire team, from entry-level professionals to executive management, are incentivized by returns as they are at EOG, it drives innovation. Innovative thinking is why EOG is consistently a first mover into brand new plays, delivering the best performing wells in the industry for the lowest cost in the industry. EOG was one of the first to both horizontally drill and hydraulically fracture the Barnett and the Bakken. The first to figure out that we can coax oil from extremely tight shale rock, leading to our second to none acreage position in the Eagle Ford.
The first to understand the benefits of complex near well bore fractures versus bi-wing fractures, and the first to deploy high density completions and precision targeting that enables EOG to consistently deliver premium well performance. EOG's innovative culture incorporates rigorous geoscience, petrophysics, and cutting-edge engineering in order to achieve return-focused technical advancements. Science and engineering, of course, requires data. 10 years ago, that data was analyzed using over-engineered spreadsheets. Today, we employ sophisticated analytics using our vast collection of data and technology tools that have been developed in-house at EOG. Now I'd like to introduce Sandeep Bhakhri, our Chief Information and Technology Officer. Sandeep has been with EOG 25 years on the front lines of EOG's information technology evolution. He will go into more detail on how EOG is using data science tools and mobile technology to enable faster innovation throughout the company.
Thanks, Bill. Good morning, everybody. We've received a lot of questions recently on our in-house information technology, our proprietary data marts and apps, and especially our use of big data and data science. I'd like to walk you through our evolution and explain how our approach is different than most, and why we have three key competitive advantages that cannot be easily replicated. The first competitive advantage is data. Data is king and one of our most valuable resources, and there are two pieces to it. One, you need comprehensive, integrated, and easily accessible data sets. Two, you have to own the data. You cannot outsource its collection, analysis, or delivery.
EOG probably has the largest, most comprehensive, and integrated data sets of any unconventional operator, having collected detailed data from more than 5,000 horizontal oil wells that we have drilled in almost every major unconventional play in the United States. The second advantage is data delivery. Data delivery is key to effective decision-making. Data needs to be available 24/7, anytime, anywhere, in easy-to-use software tools. Over the past 25 years, we have built successive generations of fit-for-purpose software tools such that today, EOG has a suite of best-in-class data delivery systems consisting of 65-plus software applications covering virtually every functional area of the business. These tools power our decision-making, delivering raw, analyzed, and learned data 24/7, anytime, anywhere. Our most important advantage, we have been doing this a very long time, almost three decades. It's simply part of our culture.
Without a culture of innovation and continual learning, technology cannot thrive. 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 1990s. The cost-saving trend at that time was to outsource information technology. EOG initially followed suit, but soon thereafter recognized the strategic mission-critical importance of IT, and we decided to bring it back in-house. Rather than implement one-size-fits-all behemoth back office systems en vogue at that time, we instead opted to customize and maintain our own accounting system.
In 2000, the dot-com boom was in full swing, and investments in technology allowed us to tackle our first major IT-enabled transformation, namely to reduce organizational friction for data access. We call this answering the what question. For example, what is the current production of this well? What is the cost of this well? 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 the demand. This was the start of our data collection and data storage initiatives that led to our eight huge proprietary integrated data marts that now house data across virtually every functional area of our business. We believe they are the most comprehensive collection of integrated unconventional oil and gas data sets in the industry. Simultaneously, we began data delivery initiatives that resulted in over 45 desktop applications that were fit-for-purpose custom tools accessing our ever-growing proprietary data marts.
The very first in 2008 was a reservoir analysis tool with custom algorithms that 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 eight proprietary data marts and our 45-plus desktop applications help EOG engineers answer the why and how questions more quickly than ever before, which in turn shows up as superior well performance, lower cost, and innovative exploration ideas. Our latest technology evolution began two years ago with our move to real-time data collection and mobile data delivery systems. While we were already getting production data real-time, we built custom black boxes to retrieve real-time data from every rig and every completion spread. This in turn spurred the need for mobile versions of our existing apps.
In two short years, we have developed what we believe to be 20 of the most sophisticated mobile applications in the oil and gas business. We did it quickly by leveraging our existing proprietary data marts, as well as our wireless communication footprint. Real-time data and our mobile apps are a major productivity game changer. People at EOG are connected 24/7, anytime, anywhere, to the same data. We call it having a control room in your pocket. Add to this our culture of bottom-up decision-making that doesn't require multiple layers of approvals, and you have an environment of accelerated analysis, innovation, and change at the speed of thought. In a moment, David Trice will share a new drilling record reached in the first quarter using one of the toolkits we built in-house for precision targeting using mobile access to real-time data. 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, therefore requires newer technologies to efficiently store, organize, and access this data. Enter big data technologies. 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. 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 learned. Number three, number one and number two are possible because of and enhanced by our unique culture of innovation and learning. Thank you very much. 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 tightening 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. In some basins, we've already achieved the targets set at the start of the year. During the first quarter, EOG continued to reduce costs throughout our operations. Delaware Basin completed well costs averaged $7.8 million during the first quarter, an 8% reduction from 2016. $7.8 million was our original 2017 cost target for this play, so we've set a new lower target of $7.6 million. Eagle Ford well cost in the first quarter declined 4% from the 2016 average of $4.5 million, which is already halfway to our target of $4.3 million.
In the Bakken, we reduced well cost 6% to $4.8 million, which is more than halfway to our $4.8 million target. We updated our cash operating cost guidance for the year. 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 three more than our initial plan for the same amount of capital. That's further testament to how ongoing cost reductions and well productivity improvement continue to drive record capital efficiency.
Even with additional rigs, we'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 results from developing larger multi-well pads. Several of our rigs are on well-to-well contracts, so we have the flexibility to increase or decrease wells as we monitor the macro environment and respond accordingly. 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 continued to deliver solid results. This world-class play is increasingly being developed with larger multi-well pads where we continue to achieve efficiency improvements that are helping to drive down cost. 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 multiple well pads. We're also wringing out additional drilling efficiencies through innovative operations such as offline cementing. Improvements to drilling and completions that speed our time to first production not only lowers costs, but also minimizes the impact to volumes due to downtime from nearby well shut-ins. Through a combination of cost reductions, longer laterals, and advancements in precision targeting, we converted 500 net wells in our Eagle Ford inventory to premium status this quarter.
That's more than two times the number of Eagle Ford wells we are completing in 2017. The total premium net 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 half a million acres, we have much left to understand and explore. The play changes significantly throughout our acreage, and we are working hard to delineate where the lower Eagle Ford may have two distinct targets, and where the quality of the upper Eagle Ford is high enough to produce premium wells. The Delaware Basin is arguably the most prolific tight oil 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 Lee County generated record-setting results. This package of four wells averaged 30-day IPs of 3,510 barrels of oil per day each from laterals that averaged about 7,100 feet. While all four may have individually set an all-time record, the Whirling Wind 11 Fed Com number 704H topped the list at 6,230 barrels of oil 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've been on an exceptional Lee County three-well package also completed during the first quarter. The Braswell 16 State Comm number 707-709H. 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 team continues to deliver record-setting results. As Gary mentioned, completed well costs in the first quarter have already met the target set for the year, and drilling shaved off a full day from spud to total depth compared to the 2016 average.
In addition, the capital directed towards facilities and infrastructure is delivering solid results by lowering both our direct well cost, 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 drill 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 completion process. This investment in infrastructure has allowed our Delaware Basin wells to have the lowest operating cost 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 mile deep column, and we expect to test additional target intervals this year. As we have discussed in the past, a thorough understanding of the lithology, along with EOG's precision 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 two and a half times just one 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 five 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 five wells produced an average per well 30-day initial rate of over 2,600 barrels of oil equivalent per day from an average lateral of 5,700 feet. The 19 Austin Chalk wells we've drilled to date, along with additional core taken during the first quarter, has provided tremendous insight into the Austin Chalk depositional model and reservoir characteristics on our acreage. We are still learning about the Austin Chalk and its potential. For this reason, we're not yet ready to give a resource estimate for this prolific target. In the Bakken, we continued to draw down our inventory of uncompleted wells in the first quarter.
Even when loaded with higher historical drilling costs, these wells have a low average completed well cost of $4.8 million for 8,400 feet of treated laterals. During the first quarter, we completed three new wells in our Bakken Lat area using high density completions for the first time. Two of these wells targeted the Bakken interval and one targeted the Three Forks. The Ross 42, 43, and 106 came online with an average per well 30-day rate of almost 1,000 barrels of oil equivalent per day with a completed well cost of only $4.6 million for an average lateral of 7,700 feet. These wells are premium. With continued success in the Bakken Lat area, we could add to our Bakken premium inventory over time.
While most of the completion activity was in the Bakken during the first quarter, we continued to make premium wells in the Wyoming, DJ, and Powder River Basin. In the DJ Basin, we brought online nine Codell wells in the first quarter. While the 30-day IPs on these wells are not flashy, averaging 710 barrels of oil equivalent per day, each on 8,600-foot laterals, the production is flat, and the well cost continues to rapidly fall. Normalized to 9,000 feet, DJ Basin well costs are just $4.5 million. In addition, we set some new drilling records in the Codell. The Pole Creek 531-2536H was drilled to a total measured depth of almost 18,000 feet in only three days.
With a drilled lateral of nearly 9,000 feet, the average rate of penetration in the lateral was over 7,800 feet per day and was drilled 100% in zone even though the target window was only 10 feet. This accomplishment was the direct result of EOG's performance-driven culture and integration of drilling technology, real-time data delivery, and in-house software applications. Our 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 of EOG data directly into our software to interpret and integrate with offset well control and seismic data. All this information can be viewed and interpreted on a desktop or mobile application, 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 cost and better well performance. Furthermore, even though the Pole Creek 531 was the record well, two 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 continue to delineate and analyze this large and complex basin. While completions were limited in the first quarter, the results are consistently premium. We completed five wells averaging 1,160 barrels of oil equivalent per day on 4,900-foot laterals. Three of the five wells were legacy untargeted Yates wells, with the well cost so low, they are premium. Normalized to 8,000 feet, Powder River Basin completed well costs average 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 our current plays and explore for new plays in this resource-rich basin. In Trinidad, we completed our five-well program for the Sercan joint venture project, bringing the remaining four gross wells online during the first part of the year. The 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 four more offshore Trinidad wells in other project areas. In addition, we recently finished a state-of-the-art ocean bottom node or OBN seismic survey with a JV partner and expect final data to be delivered by the first quarter of 2018.
This new seismic will allow us to identify new prospects to supplement our future drilling plans. We are also in the final stages of negotiating terms of a new gas contract with National Gas Company of Trinidad and Tobago that would 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 surveys, we expect to be busy drilling premium wells and maintaining our gas production in Trinidad for many years to come.
In the East Irish Sea, we are not anticipating any oil lifting to Conwy 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 financials and capital structure.
Thanks, David. We're on track for the first quarter, investing approximately one quarter of our 2017 forecasted capital expenditures. Total exploration and development expenditures for the first quarter were $966 million, including facilities of $148 million and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $34 million. Capitalized interest for the first quarter 2017 was $7 million. At quarter end, total debt outstanding was $7 billion for a debt-to-total capitalization ratio of 33%. Considering $1.5 billion of cash on hand at March 31, net debt to total capital was 28%. In the first quarter of 2017, total impairments were $193 million. Impairments to proved properties of $138 million were primarily the result of a write-down to fair value of legacy natural gas assets.
The effective tax rate for the first quarter was 28%, and the deferred tax ratio was 6%. Yesterday, we included a guidance table with the earnings press release for the second quarter and full year 2017. Our 2017 CapEx estimate remains unchanged at $3.7 billion-$4.1 billion, excluding acquisitions. The exploration and development portion, excluding facilities, will account for about 81% of the total CapEx budget. The budget for exploration and development facilities and gathering, processing, and other accounts for approximately 19% of the total CapEx budget for 2017. We plan to concentrate our infrastructure spending in the Eagle Ford, Delaware Basin, and Rockies to support our drilling programs in those areas and enhance operating efficiencies. 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 are achieving premium returns and oil growth in five core plays. Every core play continues to get better and provides EOG with the largest and highest quality horizontal asset 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 databases and sophisticated analytics, we are turning out new innovative ideas rapidly.
We believe we are extending our leading technology faster than ever before. EOG's culture and technology advancement are a sustainable competitive advantage. Fourth, we're on track to deliver high return oil growth within cash flow. We said last quarter that we could deliver 18% oil growth within cash flow at $50 oil. With our increased confidence in cost reduction, we now believe we can deliver that 18% growth within cash flow, including the dividend, with $47 oil. Finally, EOG is on target to achieve our 2020 vision and to accomplish the following four goals. First, to be the U.S. leader in Return on Capital Employed. Second, to be the U.S. oil growth leader. Third, to be among the lowest cost producers in the global oil market.
Fourth, commitment to safety and the environment. Thanks for listening. Now we'll go to Q&A.
Kim?
Thank you. If you'd like to ask a question, please press star one on your touchtone telephone. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question today will come from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
I wanted to get a bit more color on the Eagle Ford. Slide 40 shows the productivity both in the east and the west. You talked in your prepared comments to a number of returns-enhancing initiatives via cost reductions. If we look at it from a well productivity perspective, when you take into account the benefits of targeting and data analytics that you discussed, what are your expectations for how 2017 and perhaps 2018 wells could look like in the context of slide 40? How much additional room do you see for further well productivity gains, specifically in the Eagle Ford?
Brian, this is Billy Helms. In 2017, we don't have it on the chart as you mentioned, what we're seeing is we're delivering consistently better and better wells in every one of our areas. On the chart, we show producing days of 360 days. Being this early in the year, we don't yet have that many days of production on our 2017 wells. That's why the slide is not updated. Generally what we're seeing is improving well performance, even though in some areas we're offsetting some depletion in some of the patterns that we're drilling. 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 addition is generating overall higher EURs per well. 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, thanks. My follow-up is with regards to the CapEx budget and guidance for the year. As you mentioned, you added the three rigs, but no additional completion activity. Can you add a bit more color on what seems like is a build-up by the end of the year in uncompleted inventory and what you would want to see or need to see to begin to complete those wells?
Brian, this is Gary. 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. Previously, we would drill two to three well pads. Now we're drilling five to six 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. This could be a problem if we can't find a pad to move on for some reason. 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. It's still too early in the year, and oil prices are too volatile to make adjustments to our guidance. We can adjust readily. We can lay down rigs. We can add inventory, or we can add more completions. 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.
Thank you. Good morning, everybody. Bill, I wonder if I could take a follow-up to that. I guess it's kind of a philosophical question, given oil is back at $46 or something like that today. You're clearly the most efficient operator in the industry. There's no question about that. My question is, what's your appetite for a 15%-25% growth rate in this environment? You're giving up some of the best wells in the industry into one of the lowest oil price environments. 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. I guess my question is, what's the rush in a $46 oil world despite the quality of the inventory? I've got a follow-up specific to the well inputs.
Doug, the returns we're getting on these premium wells at $50, even at $45 is very, very strong. It's in the 40%-50%, 60%+. In the first quarter, we were at 70% rate of return. 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. We don't believe we're spending our best wells in the lowest oil price. We believe that our wells actually will continue to improve over time as we continue to find better rock and apply new technology.
Our commitment is to grow within cash flow and to grow at very, very high return on capital reinvestment rates. We believe that's the way to build shareholder value.
Our next question comes from Jeffrey Campbell from Tuohy Brothers.
Good morning. I was wondering at first, could you provide some color on which intervals were contained in the 700 premium locations that were added in the Delaware Basin? It seems like you had good results in several different intervals, so I'm just wondering if we could get a little color there.
Yeah, Jeff, this is Billy Helms. On the increase there in the Delaware Basin, majority of those were 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. Majority of it was driven by the Wolfcamp.
Great. Thank you. As a follow-up, in the Powder River Basin, the lateral length short this quarter relative to most of the other intervals developed during first quarter 2017. I was just wondering if there's any color on that. Was it determined by lease geometry, or are you working towards increasing lateral length over the rest of the year?
Yeah, this is David. In the Powder River, as we noted, three of the five that we brought online were legacy Yates wells, they were short laterals. Then we do, on occasion, drill some of the shorter laterals due to lease issues. Really, on a go-forward basis, we're planning in the Powder to be drilling all 2-mile laterals. That's what you'll see in a majority of the laterals in the future.
Okay, great. Thank you.
We'll go next to Subash Chandra from Guggenheim.
Yeah, hi. 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. In the Delaware Basin, I'd say we're still in the early innings of trying to develop our multi-well pads. We're testing largely, as you know, the Wolfcamp interval to start with, and we've still got a lot of horizons to test, most of which are above the Wolfcamp. 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. Reasonably, I think right now we're probably drilling on average three or four wells per pad initially, and we're coming back in behind that with additional development.
I think in your intro comments, you talked about EOG's experience in understanding density and well interference in prior plays. 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?
Yeah, 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, and all of our tools that we use to analyze what is the best and most optimal way to develop each zone. 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, we're testing those and pushing the limits as we speak.
Our next question comes from Scott Hanold from RBC Capital Markets.
Thanks. Good morning.
You're welcome.
Good morning. 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 is there yet to do on bolting on acreage, and where do you ultimately think that could end up?
Yeah. The Permian, we have been historically, in the years past, 4,500 to 5,000 foot. I think the average lateral length this year is about 7,000 foot. 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. I think it will grow incrementally over time. It may not be the 10,000-plus lateral lengths like we've done in some of the other plays, 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. You get a big uplift on the economics and the returns on the longer laterals.
We've been able to, I think the most important thing with our Precision Targeting technology and identifying the best rock, and our ability to keep that bit in the best rock the entire lateral length, has allowed us to continue to have the same productivity per foot on the longer laterals as we do on the shorter ones. If a long one lateral is twice as long, we actually get twice as much oil. That's a big technology gain that we've made just recently.
Just a reminder, it's star one if you have a question today. We'll go next to Irene Haas from Wunderlich.
Yes. Hey, good morning. Congratulations on the Whirling Wind wells. They're truly impressive. Just wondering if they are from the Upper Wolfcamp, what is driving the performance? Is it the completion techniques, geo-steering, or better rocks, can this be replicated over a large area?
Yes, Irene, this is Billy Helms. Those Whirling Wind wells are drilled in the Upper Wolfcamp. What really led to the high production rates that we've seen is a combination of several things that we've talked about, I'd say it leads off with understanding the geology and understanding where the best rock is, then being able to keep the target in that best rock throughout the length of the lateral. These are over 7,000-foot laterals. Combining that with the high-density completion technology that we continue to advance. The combination of things is what led to that production increase. We don't think we've reached the peak of that knowledge yet. We think we still have advancements that will continue to drive productivity increases throughout the play.
Every play, the geology changes across the basin, every location won't be exactly like the Whirling Wind wells, there's still a lot of potential for improvement across the play.
Should we expect sort of a more spectacular flow rates as such in the future, maybe from slightly different geographic area? Can this be replicated?
Yeah, Irene. I wouldn't say that we'll continue to set record after record after record every well we drill. I'd say the uplift on the overall program will continue to increase. One thing that I think I would add some color to is that as we have stepped out with the inclusion of the Yates acreage, as we've stepped out across the play, we've seen uplift in the productivity more so than we expected when we acquired that position. We've been pleasantly surprised by the application of the EOG technology to the acreage that we acquired in the Yates position to improve productivity across the basin.
Our next question comes from Bob Morris from Citi.
Thanks. My question actually was along the line of what Irene's was. Congratulations on the great well results, and Sandeep did a great job outlining the big data and analytics that you're using to improve these well results. In the increase in performance in the premium inventory seems, or you've outlined, it's more to do with targeting within the horizontal lateral of the wells, more so than longer lateral length and lower well cost. In understanding that lithology, what is the difference in the rock that you're targeting, and is there that much variability across the zone? In other words, is that rock that you're targeting a lot more fracture prone? Is it just more oil saturated, or what is the characteristic of that zone that you're able to target, and how variable is the rock across the formation when you target that zone?
Bob, this is Bill Thomas. You're asking some information that's proprietary. I'll give you some general guidelines. Certainly, the rock is variable in the Permian, particularly the Delaware Basin. There is a lot of variability in a vertical sense, and then laterally, it does vary some, too. You need a lot of data to identify it, and we start with cores. We do an extensive amount of core work, full cores, and analyze that rock. We integrate that into a petrophysical model, and then we integrate all that data into 3D seismic. We create very detailed maps, structure maps, and stratigraphic thickness maps before we even start to drill the well. 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.
Importantly, we developed the in-house software, as Sandeep and David described, to keep the bit in that really good rock 95%-100% of the lateral. When we do that and we do the sophisticated high-density completions, that's why the wells are so good. The goal is just continue to identify better zones, to have better execution, and to continue to improve the frack technology over time. We think there's a lot of upside left, and we're very encouraged directionally, technically, where we're headed.
I know you said you won't set record after record after record, but you feel that you're still moving up the learning curve and everything you just described, 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. We've consistently improved performance over time, we are continuing to develop new tools and new ideas, we're hopeful that will continue in a very strong direction in the future.
Great. Well, we look forward to that. Thank you.
Thank you.
Next, we'll go to Charles Meade from Johnson Rice.
Good morning, Bill, and to you and the rest of your team there.
Go, Charles.
I wanted to ask, and Bill, this might be for you or perhaps for Sandeep, but I wonder if you could give us, without giving too much away, can you give us a sense of the kind of data types and streams you're capturing now versus perhaps what you were doing a year or two years ago? What new sorts of data or opportunities for data capture you might be looking at a couple of years down the road?
Charles, this is Sandeep. I'll take that question. I would say the biggest change for us versus 2 years ago is the real-time data that's streaming in. As the data comes in with higher resolution with some of the black boxes that we're putting out on the rigs and our frac fleets, we're able to get a lot more insight into the data, and we're able to turn that into new learnings and translate that into the high productivity 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. On the frac side of the business, it's the same thing.
We're getting real-time data coming in from every frac fleet, we're able to change our completion designs and accommodate real time understanding what the rock is telling us. Those would be 2 concepts that are different, say from 2 or 3 years ago.
Got it. Thanks, Sandeep. That really fits well with I was going to ask the same question about those Whirling Wind wells that I think you guys have explained. It's at the intersection of the targeting, the fracking, 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 evolving. Is this maybe a polka dots across the map of different hotspots, or is this all concentrated in one area? What's a timeline for your best guess as timeline for when you will mature that?
Yeah. Charles, I'd say on Austin Chalk, we've certainly learned a lot about it over the last several quarters. We just wanted to continue to do the step-out wells, the targeting test, and spacing test as well. We've done several spacing tests over the last several months. We've done some at 400 feet and some at 600 feet, and the results are good on all of those, but we're still trying to dial in the exact spacing. Just keep in mind, it's a lot different than what the traditional chalk was like. If you think about the traditional fractured chalks, you had really wide spacing, and this is going to be much more of a resource type play. Nobody's ever really chased the chalk in this way. We just want to have a little bit more time and collect some more data.
We've collected a couple cores and quite a few logs. Most of our testing has been across a 10 to 20 mile stretch on our acreage. In the coming quarters, we'll have some updates.
Yeah, that's a helpful color. Thank you.
Okay. I think we can close the call.
Wait. We do have one more question. Would you like to take that?
Sure. Go ahead.
It comes from Marshall Carver from Heikkinen Energy Advisors.
All right. Thank you for squeezing me in. You highlight individual wells in the presentation. We tend to think of premium wells as the median result. What are your thoughts around standard deviation around your IPs and EURs as you're heading forward?
Marshall, I think there's a slide in the IR deck, I think it's slide 10, that gives the metrics on our premium wells that we completed last year versus the non-premium wells. 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, the returns on them are roughly a fivefold increase in returns. The finding costs are less than half. The capital efficiency is more than twice as good. The first-year oil production on the premium versus non-premium is actually double. The premium wells are remarkably better than the wells that EOG has historically drilled in the past. EOGs in the past has drilled the best wells, we believe, in the industry. The premium wells are certainly a game changer for the company.
As we go forward and we add these low-cost reserves to our reserve base, they will continue to drive down our DD&A rate, and that will filter to the bottom line. Our break evens will be better and certainly help us on ROCE. They're remarkably better wells, and I think that's maybe not quite understood by the street. Thank you, Marshall. In closing, the company's getting off to a great start in 2017. Each division in the company is focused on delivering industry-leading premium wells, and we're tremendously excited about the future of the company. Over time, those low-cost reserves will improve our bottom line and continue to create long-term shareholder value. Thank you for listening, and thank you for your support.
That concludes our conference today. Thank you all for your participation. You may now disconnect.