Good morning, welcome to the EOG Resources third quarter 2017 earnings conference call. As a reminder, this 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, sir.
Thank you. Good morning. Thanks for joining us. We hope everyone has seen the press release announcing third 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 and 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. 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; Sandeep Bhakhri, Senior VP and Chief Information and Technology Officer; David Streit, VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, we included guidance for the fourth quarter and full year 2017 in yesterday's press release. This morning, we'll discuss topics in the following order. Bill Thomas will review third quarter highlights, followed by operational results from Gary Thomas, David Trice, and Billy Helms. I will discuss EOG's financials and capital structure, Bill will provide concluding remarks. Here's Bill Thomas.
Thanks, Tim, good morning, everyone. EOG is focused on returns. We demonstrate that focus in the third quarter. We added two new premium oil plays, continued cost reductions, delivered strong well performance. The Woodford Oil Window in the Anadarko Basin and the First Bone Spring in the Delaware Basin add 800 premium drilling locations and 750 million barrels of oil equivalent resource potential net to EOG. As a reminder, for a well to be classified premium, it must have an after-tax rate of return of 30% or greater at $40 oil. Combined with additions made earlier in the year, we have increased our premium inventory by 2,000 locations, which is four times as many wells as we plan to complete in 2017. EOG continues to improve both the size and the quality of its inventory, organically adding better and better locations substantially faster than our drilling pace.
Strong operational execution was also highlighted from the quarter. We exceeded all our production targets. We delivered beyond expectations across all per unit costs, LOE, transportation expense, and DD&A. Our 2017 plan is coming together nicely. We're on target to deliver 20% oil growth and pay the dividend, all within cash flow. This morning, I'd like to take a moment to discuss EOG's multi-basin premium portfolio. As we've discussed many times before, the most important point to understand about exploration is that not all rocks are equal. Every play has geologic sweet spots with superior rock quality that drives well productivity. We do not want to own the whole play. Our focus is to capture only the best rock in the best plays. We did that in the Bakken in 2005.
We did it again in the Eagle Ford in 2009. Last year, we solidified sweet spot acreage in the Delaware and Powder River Basins with the Yates acquisition. Our ability to identify and capture the best rock is the major reason EOG wells consistently outperform the industry in productivity and returns. With the addition of the Woodford Oil Window and the First Bone Spring, our premium inventory now totals a massive 8,000 crude oil drilling locations contained in geologic sweet spots across all six major horizontal oil plays. We don't think there's another company in the U.S. with comparable assets, specifically the enormous size and quality of EOG's premium inventory. This premium inventory will fuel EOG's industry-leading returns for many years to come. The diversity of our portfolio is a powerful competitive advantage with multiple benefits. One is that single basin risk is minimized.
EOG is active across multiple basins. Therefore, temporary conditions in a single basin, such as market tightness or weather events, will have limited impact on our performance. Additionally, EOG's diverse multi-basin portfolio allows the company to grow each asset at the optimum pace to maximize its profitability and long-term value. Each play is unique and has a technical and cost optimization learning curve. It's easy to go too fast and potentially risk the long-term value of the asset. There are two other points I want to drive home this morning. First is that our decentralized structure was instrumental to accumulating the premium portfolio we have today and will continue to be critical to our success in the future. We have 17 teams operating in North America. These are dedicated individual offices covering every major basin and specializing in each play. That means seven prospect-generating machines and seven cost-savings idea teams.
Focused teams dedicated to each asset, armed with our powerful information technology, drive down costs, increase well productivity, and maximize the value of each play. Exploring rock and developing wells in multiple diverse basins means generating multiple sets of diverse data. While each play is unique, geologic learnings and technical innovation often transfers to other plays and, in turn, accelerates the pace of learning across all basins. The final point I want to make is that since our formation, EOG has been a return-incentivized company. Last quarter, we discussed EOG's history of discipline, return-based capital allocation. The capital discipline this company has demonstrated since its founding is driven by a transparent, return-based incentive structure that runs through the entire organization. Evidence of that discipline can be calculated directly from our financial statements as return on capital employed. Our historic ROCE performance averages over 13%.
Return-based decision making is the reason we initiated our premium strategy last year. Rather than patiently wait for commodity prices to improve and allow the cycle to drive our profitability, we permanently redefined our investment hurdle rate and reset the company to be successful in a low commodity price environment. EOG's ability to capture the best rock in multiple plays is the core reason we have been able to permanently shift to premium drilling. We believe our drilling inventory is the largest and highest quality in the U.S., and it's the reason we're able to grow U.S. oil production this year by 20% and cover the dividend, all within discretionary cash flow. Most importantly, our diverse and industry-leading acreage positions are the reason we are generating the best reinvestment returns among our peers.
I will turn it over to Gary Thomas to discuss our third quarter production and cost achievements in more detail.
Thank you, Bill. In the third quarter, Hurricane Harvey presented EOG with a first-of-its-kind operational challenge, one that our decentralized multidisciplined teams in Corpus Christi and San Antonio did an excellent job tackling. Our largest concern was the safety of our employees and facilities. I'm happy to report we experienced no major damage or environmental incidents related to the storm. I want to thank and congratulate our employees in Corpus Christi, San Antonio, and Houston for their exceptional performance during a very difficult time. During the third quarter, there were a few notable achievements to highlight. Time is money. Our teams continue to reduce drilling and completion time in every play. After ten years of drilling Eagle Ford wells, we reduced spud to TD time another 5% this year. In our newer Delaware Basin plays, the wells are being drilled in 15% less time.
The DD&A rate continued to decline, coming in below the low end of our targeted range. The benefits of ongoing operational efficiencies, record low finding and development cost, and the addition of premium well reserves are beginning to show up in our financial performance. Per unit LOE beat expectations, despite the double impact from Harvey of both cleanup and repair cost and curtailed production. As noted in the 8-K we issued September 5th, the production impact of Harvey on all our oil volumes was about 15,000 barrels of oil per day during the quarter. With a few adjustments to our completion schedule, we expect to offset the production impact in the fourth quarter. To accommodate the new schedule, we were able to secure additional completion crews. Based on their performance and tightness in that market, we elected to tie up those crews for the remainder of this year.
This was a performance and rate of return decision. As a result, we are completing approximately 25 additional wells, bringing the total to 505 net completed wells for 2017. Due to the timing of the additional 25 wells late in the year, there will be a limited impact on our volumes for the full year. We now have 28 rigs working, and we have the best performing services EOG has ever assembled. We do not want to release any of these top-tier service providers. The additional rigs and crews give us a head start as we plan for 2018. Due to the stellar cost savings and efficiencies gained throughout this year, we don't need to change our capital guidance. However, it is likely we will spend towards the high end of the range.
EOG is one of the few E&P companies with the ability to commit capital right now, and as a result, we are securing favorable pricing agreements. We've locked in a major portion of services and supplies to further lower cost and improve our returns in 2018. Next up is David Trice with the exciting news about our new Oklahoma play.
Thanks, Gary. This morning, we introduced a new premium oil play in the Eastern Anadarko Basin. Located primarily in McClain County, Oklahoma, adjacent to the gas condensate plays, popularly known as the SCOOP and the STACK, the Woodford Oil Window is a black oil play with a concentrated sweet spot of high-quality rock. Our discovery of the Eastern Anadarko Woodford Oil play is a great example of how EOG's decentralized structure is a perfect fit for exploration-driven organic growth. Our team in Oklahoma City identified the potential of this area based on historical log and production data and began leasing in 2013. We accumulated our 50,000 net acre position at an average cost of just $750 per acre. Over the last four years, we collected additional data through vertical logs, core, and 3D seismic to delineate the sweet spot.
We were then able to compare and model this data against the vast amount of proprietary data collected in other EOG plays to determine the viability of the Woodford Oil Window as a premium play. Similar to the Eagle Ford, the Woodford is a shale play with very good rock quality and fairly consistent geology. We completed three horizontal wells in the Woodford Oil Window and applied EOG's refined targeting techniques and EOG style completions to confirm the premium return potential of the play. The Curry 21X number one VH, which IP'd in August, was the third well drilled and had the longest lateral at 10,500 feet. Data collected on the first two wells was used to dial in the correct target before drilling the two-mile Curry Well.
The average 30-day initial production was over 1,700 barrels of oil equivalent per day, while the 60-day average is holding up at over 1,600 barrels of oil equivalent per day with an oil cut of 85%. The relatively low decline is evident in the performance of all three wells drilled and speak to the premium rock quality of this sweet spot. Based on analysis of publicly available production data, we believe that the Curry is potentially the most prolific horizontal Woodford Oil Well drilled to date in Oklahoma. Furthermore, the NPV on the Curry Well using the current strip is about $10 million. We've essentially paid for a quarter of the entire play's acreage cost with this one well. We currently estimate that EOG's position in the Woodford Oil Window will support 260 premium locations using 660-foot spacing.
The estimated ultimate recovery is 1 million barrels equivalent per well on a gross basis and 800,000 net after royalty, for a total estimated resource potential of 210 million barrels of oil equivalent, 70% of which is oil. To reiterate what Bill said earlier, we are not interested in leasing entire plays, but instead, we are focused on leasing the geologic sweet spots at low acreage costs to maximize long-term ROCE growth. The Woodford Oil Window in the Eastern Anadarko Basin is a perfect example of this strategy. Within EOG, all projects compete for capital based on returns. The Woodford Oil Window is more than competitive with the rest of EOG's premium inventory on a rate of return and NPV basis. Billy Helms will now tell you about the new First Bone Spring play in the Delaware Basin and provide an update on the Eagle Ford.
Thanks, David. Our 2017 development plan in the Delaware Basin has been focused on increasing our understanding of the geological complexities of the various target intervals, testing spacing patterns, and delineating our acreage position. As a result, we are providing our initial assessment of yet another target, the First Bone Spring Sand. After 15 successful tests across our position, we have the confidence to define the net resource potential of 540 million barrels of oil equivalent from 555 locations, of which 540 remain to be drilled. The seven wells completed in 2017 span a distance of 30 miles and produced on average 1,825 barrels of oil equivalent per day, with initial oil cut of 66% over the first 30 days. For the play, the typical well will target 7,000-foot laterals with a well cost of $7.3 million.
We estimate the EUR for a 7,000-foot lateral in the First Bone Spring Sand is 1,185,000 barrels of oil equivalent gross and 975,000 barrels equivalent net after royalty. The oil cut through the producing life of the well is estimated at 55%. It is important to point out that all of the wells in our resource estimate meet or exceed our initial premium rate of return hurdle and will compete for capital with the rest of the Delaware Basin program. Our technical team in Midland has defined multiple horizons across our acreage position and used the latest interpretation to geo-steer the drill bit into the best target intervals. Targeting, along with our high-density completions, is yielding industry-leading performance, as evidenced in slide number 17 of our latest investor presentation.
Our total Delaware Basin premium well inventory now stands at almost 4,700 locations, which represents over 25 years of drilling inventory at our current pace of development. For the third quarter, we completed 22 wells in the Wolfcamp Oil and Combo plays. All of the active areas continue to meet or exceed our expectations for both well performance and reserves. Out of the third quarter activity, I would like to highlight a three-well package drilled in southern Lea County. The Antietam wells are 660 feet apart and average 30-day IPs of 2,725 barrels of oil per day, each from laterals that averaged about 7,000 feet. This year has been another stellar year for the Delaware Basin team, as we explore and define the potential of this target-rich area.
We are advancing our development plans to address the well spacing and timing needed to maximize the net present value of this asset. We have over a decade of experience with large horizontal programs. We use this knowledge to address the challenge of developing this multi-target inventory. Once again, our culture and decentralized organization allow our technical teams to focus on these challenges in order to maximize the recovery and the economics of our acreage. We are excited about the tremendous potential we see in the basin. The Eagle Ford continues to be a consistent source for delivering both production volumes and economic reserves. In the third quarter, the average 30-day initial oil production rate from the 44 wells completed was about 1,340 barrels of oil per day, with an average well cost of $4.5 million.
Acreage in the Eagle Ford is close to 99% held by production. Our efforts are focused on maximizing the net present value of every acre through multi-well pad development with increasing lateral lengths. The vast majority of the wells are drilled on larger multi-well pads, which are well suited to the rigs and completion crews that allow for quick moves and efficient operations. In many of these drilling units, we are targeting additional pay intervals within the lower Eagle Ford, as well as adding the upper Eagle Ford, where appropriate. As a result, we are harvesting more of the resource in each drilling unit, and the productivity per well continues to deliver steady and predictable results. The Angus pattern identified on slide number 33 of our investor presentation is an example of this tightly spaced, targeted development program that generated improved results with staggered 200-foot spacing.
Another important point to remember about EOG's Eagle Ford asset is its proximity to a higher priced market. All of the oil from the Eagle Ford receives LLS prices and typically trades at a premium to WTI. This provides a boost to the already premium results, and with more than 2,400 premium locations remaining, the Eagle Ford will continue to be a solid foundation for EOG's success. Now here's David again for a quick update on the Austin Chalk and Trinidad.
Thanks, Billy. In the South Texas Austin Chalk, we continue to drill very prolific and highly economic wells. We've delineated a sweet spot in Karnes County that consistently delivers premium well economics that compete handily with the rest of our portfolio. In the third quarter, we completed eight wells in this sweet spot that delivered a 30-day average IP rate of almost 4,500 barrels of oil equivalent per day, each from an average treated lateral of about 6,000 feet. Well costs remain low, averaging under $4.5 million. The most impressive well during the quarter was the Elbrus Unit 103H, whose 30-day IP exceeded 7,700 barrels of oil equivalent per day on a lateral length of only 3,700 feet. Incredibly, this well paid out in less than a month. Our exploration work in the South Texas Austin Chalk is focused on identifying additional sweet spots across our acreage.
The play is geologically and stratigraphically complex. We expect our ongoing exploration efforts will take time. In Trinidad, we've stepped up activity and continue to drill really good wells in the prolific shallow water reservoirs offshore Trinidad. We completed two wells during the third quarter in the Banyan and Osprey areas, each with initial production rates in excess of 30 million cubic feet a day of natural gas. We expect to complete another three wells before the year is out and estimate that some of these wells have the potential to produce 100 billion cubic feet of gas over their economic life. This will allow us to maintain production in the years ahead and generate strong rates of return from this cash-generating asset. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, David. We are maintaining our full year 2017 capital expenditure guidance at $3.7 billion-$4.1 billion. As Gary mentioned, we are more likely to be at the high end of the range in order to hold on to equipment and services as we prepare for 2018. Total exploration and development expenditures for the third quarter were $1.1 billion, including facilities of $147 million and excluding acquisitions, non-cash property exchanges, and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $50 million.
Capitalized interest for the third quarter was $7 million. During September, we repaid our $600 million, 5.875% senior notes. At quarter end, total debt outstanding was $6.4 billion, for a debt-to-total capitalization ratio of 31%. Considering $846 million of cash on hand at September 30, net debt to total cap was 28%. In the third quarter of 2017, total impairments were $54 million. The effective tax rate for the third quarter was 31%, and the deferred tax ratio was 175%. I'll turn it back over to Bill.
Thanks, Tim. In closing, I will leave you with a few important points. Over the last few months, the investment community's emphasis on capital discipline has certainly grown. I'll repeat what I said at the end of 2014 when the downturn began, and what we have repeated virtually every quarter since. We are committed to returns, living within our means, and maintaining a strong balance sheet. We believe production growth should be the result of investing in high return drilling, and have never been fans of outspending cash flow to pursue growth for growth's sake. Second, we have become a permanently premium company. Our track record of adding premium level inventory over the last two years is evident that our premium strategy is sustainable. Our premium resource potential now totals more than 7.3 billion barrels of oil equivalent in 8,000 locations.
That's more than double the resource potential and more than double the locations from the start of 2016, when we introduced the premium strategy. Furthermore, we are still exploring, still improving existing plays, and we don't see any end to the opportunities to expand our portfolio further. Third, the benefits of a diverse portfolio drive a real competitive advantage for EOG. A strong, stable growth profile that generates high returns and maximizes the value of each asset. It's difficult to sustain both high growth and high returns without the flexibility that multiple premium assets provide. With diverse assets, the result is a focused, disciplined, high return road to growth. Finally, EOG is like the Houston Astros. We never give up. We are never satisfied. We never quit getting better. Quarter by quarter, we are adding low cost premium wells to drive down our cost and deliver strong growth.
Going forward, our return focus and sweet spot portfolio of assets, supported by a bottom up, flat, decentralized organization, will drive differentiated ROCE performance in the E&P space. Our number one goal is getting ROCE back to our historical average of 13% or better. We believe this is the best way to create sustainable long-term shareholder value. Thanks for listening. Now we'll go to Q&A.
Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key, followed by the digit 1 on your touch tone phone. 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 touch tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. I'll pause for just a moment to give everyone an opportunity to. We'll take our first question from Evan Calio with Morgan Stanley.
Hey, good morning, guys.
Good morning, Evan.
Hey, congratulations on the organic premium location additions. On the Woodford, what drove the timing of the reveal? Is it that you believe you've acquired all you could? You mentioned it as a sweet spot, yet how prolific or extensive do you see the Woodford with premium characteristics in the SCOOP?
Yeah, Evan. First of all, the Woodford play, we got a lot of confidence in it. We drilled three wells, but we have a lot of data, and it's a pretty simple play with the modeling we've done and the analysis we've done and the history we have in shale plays. I'm going to ask David to expound on this and give you a little bit more color on the detail.
Evan, like Bill mentioned, the difference with the Woodford and some of the other plays is that the Woodford is a shale play, so it's fairly simple from a geological standpoint. We started working this area back in 2012, 2013, and had a pretty good idea that it could be premium. We began collecting data, we've got nearly 400 full petrophysical models built in and around our acreage that's tied to core data. What we've been able to do over the years, drilling all of these horizontal oil plays, is we've been able to collect the data, and we've gotten very good at building some sophisticated reservoir models. What we did on this particular play is we modeled it ahead of time.
We took industry data, we took all the petrophysical models and compared it against, in this case, particularly the Eagle Ford, and compared the completions versus the reservoir response. Going into it, we felt very confident that we could make premium wells here in the Woodford. We were able to confirm that with the well results that we've had, we feel confident about the premium status of this. Just the timing of it's pretty tightly held acreage in this part of the world. We felt comfortable going ahead and releasing the results on it.
Let me just follow to your responses. Is 50,000 acres sufficient scale to develop?
I think, just like we talked about in our prepared remarks, our focus is on identifying sweet spots and drilling sweet spots. Be that the Austin Chalk or the Woodford, we want to drill premium wells that are going to continue to lower our finding cost over time and increase our ROCE. For us, as a decentralized company, it works really well. This is an instance, like Bill had said, where we can allocate capital to a different play and develop it at the appropriate speed. We think it's sufficient scale.
We'll go next to Paul Sankey with Wolfe Research.
Hi, good morning, everyone.
Morning, Paul.
Bill, it's very impressive from a growth standpoint. I was wondering when will we get a bigger dividend? When are you going to start growing the direct cash return to shareholders? Thanks.
Paul. The dividend is a very strong priority for EOG. We've increased the dividend 16 times in the last 17 years. Consistent with our commitment, our board continues to evaluate the business environment every quarter, with a goal of returning cash to shareholders through the dividend and increasing that when appropriate. That's very high on our list, and we're evaluating it and hopeful as the business environment proves to be stable and improving, that we will continue to work on that.
Yeah. If I could just observe, Bill, it has to really be at least above the S&P 500 yield to be worth paying. I'm looking here at $100 million a quarter. It doesn't seem too onerous to at least double it. Bill, the other thing I'd like to ask you about is the scale of the company. With all of the success that you're having geologically and operationally, how big, is there an optimal size at which you're going to perhaps think harder about disposals, and taking stuff off the table as opposed to just adding and adding? Thanks.
I'm going to ask Billy Helms to talk about our divestitures.
Yeah, Paul, this is Billy Helms. I think it's fair to keep in mind that all these plays we're adding are certainly premium quality, so they're adding to the high end of our portfolio, which we think adds to the net present value of the company. At the same time, we always manage the bottom end of our portfolio. If you look back over the last several years, we've sold over $6 billion of assets. That's not to be overlooked. It's a big part of managing our overall asset base, and it's part of our long-term strategy to continue to do so. Every year it fluctuates depending on where that property is in the life cycle of its development and plays. It's something we constantly look at and evaluate and actually do each year.
We'll go next to Bob Morris with Citi.
Thank you. You just addressed my question on effectively high-grading the inventory with continuing to add to these premium locations, which congratulations, by the way, on that. As you look at your opportunity for continuing to do that, I notice you continue to spend about $150 million a quarter on exploration. With a lot of companies focusing on capital discipline and sort of turning to manufacturing mode, has that created more opportunity for you to identify further premium locations as others focus more on manufacturing and you have the flexibility to look for new plays or repeatable type things like the Woodford that you announced this morning?
Yes, Bob, that is our focus, and that's the reason that we continue to have a very robust exploration effort. We don't need more locations. We just are looking for better locations and to be additive to the quality of our already high-quality inventory. The two plays we talked about today, the First Bone Spring and the Woodford, already will fall in the upper part of our premium inventory. They'll get more focus than some of the other even premium inventory we have in the company. We believe, as we said many times before, that geology makes a huge amount of difference in the productivity wells. We've had a
A two decade learning curve on horizontal technology and rock quality. We're going to continue to use that to increase the productivity of our wells and the plays that we're looking for. We want to get better. We're never satisfied, and we see a lot of opportunity out there to continue to increase the quality of the plays we're in.
That's great. My second question is, you're one of the very few, if maybe only, companies that didn't add hedges in the quarter, and you're still very minimally hedged in 2018. What does that say, or how does that speak to your view on the commodity price and managing that?
Yeah, our view on the macro is we're, I think, certainly encouraged by the improving market conditions as we look forward. The market obviously is continuing to rebalance nicely. Inventories are moving towards the five-year average. We are watching the market closely for opportunities. I'm going to ask Lance to comment a little bit more on that.
Yeah, no. Bob, good morning. Really as we think about it, we're going to stay poised. As Bill mentioned, inventories continue to draw globally, but also in the U.S. You look at the market, it's in backwardation, too, for WTI and Brent. Also in our view, we think U.S. production hasn't been growing quite as prolific as what others have originally estimated. As we look at those dynamics in the market, we're going to really stay poised here. We've been disciplined since 2015, and we've been waiting for this turn, so we're going to continue to watch here going into 2018.
We'll go next to Leo Mariani with NatAlliance Securities.
Yeah. Hey, guys. Just a quick question on the First Bone Spring here. Obviously, the Bone Spring's been a target for a number of years out there in the Permian Basin. You guys have been active drilling wells here for a little while. Was there some dramatic change that happened recently that caused you guys to move this up into a premium position? Maybe you could just discuss that a little bit.
Yeah, Leo, this is Billy Helms. For the First Bone Springs, it's just yet another pay zone that we've certainly had been identified, and we've been testing over the last several years. Most of our activity in the past year or two has been focused on certainly the Wolfcamp, which is highly prolific, and we've got multiple zones there. We've also previously announced the Second Bone Springs resource estimates. This was just the next step. The First Bone Springs is certainly a highly prolific and very competitive zone with those targets, and we've now delineated the program with about 15 wells over a fairly extensive area and had confidence enough to come out and delineate the resource potential on our acreage there. It's really just the next step in the evolution of the Delaware Basin.
Okay. That's helpful. Just wanted to follow up a little bit on some of the 30-day oil production rate data you guys provided in the third quarter. Just in the various different Delaware plays, Eagle Ford and DJ, just noticing that your 30-day oil rates, while still strong, were down a little bit from second quarter averages. Just wanted to see if there was anything in particular driving that.
No, there's nothing out of the ordinary there. They vary from quarter to quarter based on lateral lengths and where we're drilling in each part of the play. There's no really distinct trend you can draw from it. It's up and down a little bit every quarter. We are doing appropriate spacing tests, especially as we're pretty new in the Delaware Basin. That may affect volumes a little bit from quarter to quarter, and then the parts of the play vary quite a bit. There's nothing unusual there. I wouldn't try to read anything in any of that that would be out of the ordinary.
Okay, thanks guys.
I'll go next to Doug Leggate with Bank of America.
Thanks. Good morning, everybody. Bill, I wonder if I could ask a slightly different question about the premium inventory. The Woodford, as is disclosed, I mean, obviously great news, but it's 3% of your locations. The Bakken is now about 4% of your locations. I guess my point is that, is there a point down the line where you start to think about monetizing some of these high quality smaller portfolio positions, given how long dated that your premium location inventory now is across the piece? I'm just wondering if there's another optimization decision to be had here as you bring these smaller assets into the portfolio.
Doug, the Woodford and the Bakken you mentioned specifically, those would not be ones that we would think about monetizing at this point because obviously the Woodford's got tremendous upside to it and is on the high end of our quality of the premium inventory. We also believe the Bakken is too. It's still got a lot of upside. We have
As I said in the opening, that we captured the sweet spot there, continue to think that there is quite a bit of additional premium drilling to go on both of those. We like having multiple high-quality assets because it allows the company to increase capital or disperse capital with discipline. It allows us to put to work capital with a lot of confidence that we can continue to have very strong returns and execute each one of those plays at the proper speed to maximize the NPV and the finding cost. That is what really will drive the ROC improvements in the company going forward.
Each one of our plays, we have a slide in the slide deck, I believe it's slide 16, that shows you that the returns that we have in each one of our plays, if we drill premium wells, is very strong. They're all fairly equal. That's the advantage of having multiple plays and having a decentralized organization that can focus, reduce the cost, improve the quality of the wells at the same time, maximize the value of each one of them.
I know it's a bit of a stretch, but I wanted to just get your opinion on portfolio high grading. My follow-up, Bill, it seems that 15%-25% at $50-$60, with the well results you've had, it strikes us you can probably do that same range of growth at a lower oil deck. I guess my question is, as we see oil starting to get a little bit healthier, at least on the out years, how would you think about incremental allocation of capital? Would it be the 15%-25% is sacrosanct and anything beyond that goes back to shareholders? Just how are you thinking about the upside case for production growth? I'll leave it there.
If prices rise, obviously our discretionary cash flow is very strong. It's increasing even if prices don't rise. The first thing is when we decide to reinvest additional cash, we're going to do it with this one. We're not going to sacrifice returns to grow faster. We only incrementally invest if our returns are equal or better. Again, that is, I think, an advantage of multiple plays and the decentralized system that we have in place to execute that. What I'd say, the highest priority in the company is really to continue to reinvest in the premium inventory, because we believe that's the best way to increase shareholder value. We also want to continue to firm up the balance sheet, we want to work on that and getting our net debt down lower than what it is now. That will be a priority.
The third thing, as I've talked about already, is we have a very strong commitment to the dividend. We want to continue to increase cash to the shareholders through the dividend going forward.
We'll go next to Scott Hanold with RBC.
Good morning. Could I ask a little bit more on the Woodford? You drew a box on your presentation of where you all see that as perspective and marked it about 50,000 acres. Excuse me. Can you talk about the working interest you have in there, and where do you expect that to go over time?
Yes, Scott, this is David. Far the wells we've drilled there in the Woodford, they've been very high working interest, probably close to 100%. I would think, going forward right now, we're probably on average, it's going to vary quite a bit across the play, but probably on average, it's probably around 50%. We've got work to do there as far as trading and blocking up and force pooling and things like that. Right now, I'd say it's probably around 50%. The numbers we've given you as far as resource estimate, that's all net numbers, the 260 net locations and the acreage position there.
Right. On the gross location, you've got a good 500 plus, it sounds like. When you talk about ramping that opportunity up in 2018, what kind of pace are you generally thinking about right now?
Yeah, I think we're going to wait to give any kind of specific guidance until the next call on our plan. We would say that we do intend to ramp that up next year.
We'll go next to Charles Meade with Johnson Rice.
Good morning, Bill, to you and your team there.
Morning, Charles.
Congratulations to your teams for maturing those two new premium plays. I'd like to go back to an earlier question, I believe it was from Bob Morris, was asking about your macro outlook, given that you're unhedged. There was another comment you made in your prepared remarks that you're going to be near the high end of your CapEx guidance to secure the services you guys need going into 2018. To me, putting those two together really looks like a management team that's pretty bullish on the commodity and activity levels. I'm wondering if that's a fair read, not just on the commodity, but on the activity levels and if it is, if you have any concerns or any lookouts for pinch points on service availability in 2018.
Charles, just first off on our, I think our confidence in the macro and the oil price. We do feel like the market is in an improving situation, there's no doubt about that. Even if oil prices stay at $50, no better than they are this year, our discretionary cash flow is growing substantially. I'm going to ask Gary Thomas to comment on the services and the availability of equipment and maybe the pricing there.
Yes, Charles. As is brought up this morning, all of our decisions is really based on increasing our rate of return. You mentioned pinch point, and pinch point would probably be in just thinking about the various services that are available. There's been little equipment added over the last couple of years, and that's one of the main reasons that we've increased our activity here with the additional 25 wells, is just to ensure that we have top-tier services available to continue to reduce our cost and just develop and produce more of the low-cost oil, which is going to increase our return on capital investment. Our divisions have just done an outstanding job assembling best performing drilling rigs, completion services, all those services, probably the best ever.
We just want to be careful not to lose those, because our intent is just to continue to reduce our cost over time.
Charles, I'd also like to add that we always build in flexibility to respond to whatever oil price presents itself next year. We're always thinking about that and built that into our thinking on what equipment and how much of it that we put on long-term contracts versus short-term, and how we manage our business.
Thank you, Bill and Gary. That's helpful color. If I could have one other question or my follow-up question on the Delaware Basin, perhaps this would be best for Billy Helms. Billy, you talked about you guys had the emergence of the first Bone Springs this quarter, but as I look at maps or the charts you guys have in your investor book, the Wolfcamp section is about as thick as that whole Bone Springs section put together. You're just identifying one target there right now. Could you talk about what are the prospects over the next coming quarters for you guys to mature another horizon within the Wolfcamp?
Yeah, Charles. I'd say our focus there has been mainly on identifying the best target intervals within the Wolfcamp. We've tested a number of different prospective pay targets. Really what we're trying to better understand is, and as we move into development mode, how's the best way to develop the asset. We're testing a lot of different Along with testing different target intervals, we're testing a lot of spacing patterns. What's the right spacing pattern within each well, between wells, between target intervals, and those kind of things. As you know, as you get into these large horizontal programs, you have to be able to manage the parent-child interference, the offset depletion appropriately to maximize the recovery and the economics of every play. Just a reminder, we've got over a decade of doing that kind of thing in various plays.
We're utilizing all that knowledge that we've gained in all these different plays to better understand how to do that. I'd say it's a little bit early to think about what we would roll out next. I'd say that there's certainly upside we see in the basin for continued growth, and we're very excited about what we see for the potential of the Delaware Basin.
We'll go next to Ryan Todd with Deutsche Bank.
Great. Thanks. Maybe a question on allocation of capital. How should we think about the relative prioritization of capital within the portfolio amongst the assets as we look into 2018? I know you're working on the budget right now, but should we expect a similar mix of Eagle Ford versus Permian versus other, as we saw in 2017? Are there going to be additional relative shifts towards some others? In particular, how should we think about allocation to capitals of the two new assets? Maybe start there.
Ryan, the capital allocation, certainly, the Permian would be a high priority. Obviously, the Eagle Ford continues to get a lot of capital. Then the plays in the Rockies, and certainly the new Woodford play, as David talked about, will get quite a bit more capital than it had obviously this year. We'll get into development mode on that. I think it's the advantage again that we have in the company is that we can disperse capital very easily and have a lot of confidence that we're generating really high returns because of our
Decentralized structure, all the plays are very, very high quality. It's pretty easy for us to disperse capital out and have a lot of confidence in it.
Within that framework, I guess, historically or in the past, at some point you had talked about in that kind of $50-$55 world that the Permian would be the largest growth driver. The Eagle Ford would be probably more of a mid to high single digit trajectory. Is that the right way to think about the Eagle Ford within this current framework?
Ryan, yes. That's a good way of thinking about it. The Permian, the Delaware is the primary driver of growth, and the Eagle Ford is in a secondary position on that right now. But all of them are getting fantastic returns, and that's the way we want to do it. We're really focused on returns first, and that's the top priority of the company, to maximize the ROCE.
We'll go next to Arun Jayaram with JPMorgan.
Yeah. Good morning, Bill. I was wondering if you could give us some commentary on how you're thinking about 2018. On slide 19, you've given us your 15%-25% long-term growth, the CAGR. The Street for 2018 is at 18% growth. I was just wondering if you could just give us how you're thinking about your planning for next year.
Arun, we're not going to give out a specific number at this point, so everybody, you'll just have to wait until our February call on that. Certainly our long-term guidance or outlook that we've given, 15%-25%, is still valid. We'll work through the plan, and then we'll let everybody know the specifics in February.
Yeah. Can we read into anything the fact that you've added a couple of rigs, or have added frac crews as any indication about next year?
No, you shouldn't read really anything in that. We wanted to secure those because they're very, very high quality. That kind of equipment is hard to get if you're trying to add something new. We didn't want to let it go. We've captured it at very low cost too, so we wanted to lock that in. I wouldn't read really into anything. We're still working through our plan, and we'll let you know that in February.
We'll go next to David Kistler with Simmons Piper Jaffray.
Good morning, guys. Speaking a little bit about the decentralized structure and a lot of questions regarding capital allocation, can you talk a little bit about, even though it's decentralized, how flexible you can be to redirect capital or activity to basically optimize returns in not just an annual basis, but in a shorter term basis? For example, LLS prices are great right now. Service environment in the Eagle Ford isn't quite as pressured as other areas. How quickly can you redirect capital, or do you think about doing that in a decentralized environment?
David, this is Gary Thomas. Really, the decentralized nature of EOG helps us to turn on a dime. We got all of these different plays working. We can ramp up, ramp down. The way we've structured our contracts with our vendors, we can move equipment from one to the other. Bill brought this up, is us being able to share what the breakthroughs are, the efficiencies. We often get together with our technical groups. We have those conferences that are going to be starting up here right after the first of the year. There's a tremendous amount of sharing among divisions to ensure that these different divisions that are working different plays, finding new and better ways to improve our efficiencies, are just continually shared. We like to think of it as having various think tanks, and it works really well for us.
Well, I appreciate that tremendously. Then one last maybe macro question. In the past, you guys have talked about scarcity of premium resources across the total U.S., and that you obviously feel advantaged, and rightfully so, with what you've been able to put together, but that has enhanced your macro outlook. As you guys continue to grow premium resources organically within your current acreage base, but also, as an example, with the Woodford outside of it, does that change your thoughts in terms of total resource content in the U.S. or total premium inventory, and what that might mean to macro supply on a longer term basis?
Dave, no, it really doesn't. We think the highest quality sweet spot parts of the crude oil plays are relatively small compared to the total. When you look across the U.S. horizontal oil plays, there is a very large % of wells that we believe are not economic, certainly at $50 oil, and need a much higher oil price to be economic. These premium plays, the sweet spots, are really the economic parts of these horizontal oil plays, and those are the ones we're focused on, obviously, only. We're not really interested in most of the acreage. We believe if oil stayed at 50, the economic limits of the industry, U.S. horizontal oil, are somewhat limited by that.
At this time, this does conclude the question and answer portion of today's call. At this time, I'd like to turn the call back over to Mr. Thomas for any final remarks.
In closing, EOG's third quarter results were remarkable in many ways. As reported today, the company is focused on delivering strong returns by reducing costs, completing great wells, and increasing the size and quality of our drilling inventory. We have a sustainable business model. We're excited about EOG's ability to create long-term shareholder value. In addition, I would like to say thank you to the EOG family for the tremendous contribution of time and money to Hurricane Harvey relief. Our combined efforts raised over $2.8 million. Thank you for listening. Thank you for your support.