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EOG Resources Inc (EOG 0.83%)
Q3Â 2018 Earnings Conference Call
Nov. 02, 2018, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, everyone, and welcome to EOG Resources Third Quarter 2018 Earnings Results 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 the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.
Timothy Driggers -- Chief Financial Officer
Thank you. Good morning, and thanks for joining us. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.
Some of the reserve estimates on this conference call may include estimated potential reserves not necessarily calculated in accordance with the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to US investors that appears at the bottom of our earnings release issued yesterday.
Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, President; Billy Helms, Chief Operating Officer; David Trice, EVP Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; and David Streit, VP Investor and Public Relations.
Here's Bill Thomas.
William Thomas -- Chairman and Chief Executive Officer
Thanks, Tim, and good morning to everyone. EOG is a higher return organic growth company and we are delivering what we promised, a compelling combination of high returns, disciplined growth, and free cash flow. In the third quarter, we lowered well costs and improve well performance. As a result, year-to-date we are generating triple digit well level returns. We grew our oil production 27% year-over-year and total production 25%. And we generated over $0.5 billion in free cash flow. This is a rare performance not often seen in our industry or even in the broader market.
Our third quarter results demonstrate the value of EOG's unique culture of innovation supported by a rich history of a data-driven, non bureaucratic flat organization, innovations, real-time data gathering, rapid analytics, and redeployment of learning's to the field are continually producing improving results through the company. For example, in the Delaware Basin, we are making significant progress and breaking the code for optimal well spacing. Likewise, on the cost side, we are making significant progress driving down drilling and completion costs. The same is true for our Woodford oil play, we're just like in the Delaware, we're finding better drilling targets, discovering improved completion techniques, and lowering costs, all at the same time. We're excited about our progress and the continuous improvements we are seeing this year, and more importantly, we believe there's plenty of momentum to continue to get better in 2019.
EOG's unique culture of innovation and focus on exploration are fundamental to our sustainable business model. Our culture of innovation drives continuous improvements in each play we developed, maximizing the value of our leasehold by optimizing NPV returns and finding in development costs. Our focus on organic exploration makes EOG a prospect generating machine, and we continue to generate significant new ideas and to be clear about it, we are only interested in adding new plays that will increase the quality of our premium inventory. And we're encouraged with the new prospects we're currently evaluating.
Innovation and exploration are key to EOG's sustainable business model and creates long-term value for our shareholders. We're on track to deliver double-digit ROCE and strong double-digit production growth in 2018. Those two milestone achievements combined with returning cash to shareholders through a 31% increase in the dividend this year, debt reduction and the generation of substantial free cash flow make EOG a unique and compelling investment, not only in the E&P industry, but in the broader market.
Looking forward to 2019. We're not going to increase capital at the expense of efficiencies and returns. We will develop our assets and spend capital at a pace that will optimize our learning curve and allow sustainable improvement to our well productivity and cost structure. Any production growth is strictly the result of disciplined capital allocation to higher return assets. Furthermore, capital allocation will continue to be based on returns measured against our premium price deck of $40 flat oil and $2.50 flat natural gas prices. No matter, if commodity prices improve next year.
Our goal of being one of the lowest cost producers in the global oil market has not changed. We are continuously resetting the company to deliver strong returns even in the low-to-moderate oil price environment. Next step is Billy to discuss third quarter highlights -- the results of a well executed capital and operational plan and how we plan to maintain that performance for the remainder of the year and into 2019.
Billy Helms -- Chief Operating Officer
Thanks, Bill. Our operating teams continued to deliver solid performance executing our 2018 program. As a result, we are seeing returns on a direct basis, reached levels previously not achieved in the history of the company. New technology is increasing drilling speeds, drilling more consistent targets and lowering cost all at the same time, combined with cost reductions from local sand, water recycling and infrastructure projects. We are well on our way to achieving our stretch goal of reducing average cost 5% by year-end 2018. Our goal is to be one of the lowest cost producers in the global E&P industry, and we are very pleased with our progress through the third quarter. As we near the end of 2018, industry activity is slowing. Consequently, the service sector is experiencing a period of softness in the market. To take advantage of market conditions, we elected to secure some of our existing service providers through the fourth quarter for next year's program. This will capture favorable prices and sustain the operational continuity of these high performing service providers into 2019. For example, we retained a number of high performing completion crews that we had initially planned to release in the fourth quarter. Retaining these crews means we will complete 20 additional net wells compared to our prior forecast and accomplish our objective of maintaining our momentum into next year. We have contracted for about 65% of our anticipated services and materials needs in 2019, which is higher at this point in the calendar year than in past years. By doing so, we expect to reduce total well cost again in 2019, and negotiate a structure for these services provides EOG with a great deal of flexibility to adjust our activity level in 2019. We also anticipate opportunities to capture additional leasehold before year end. As Bill mentioned, our exploration efforts are key to our proven sustainable business model by both replenishing and improving the quality of our premium inventory.
As we begin planning for 2019, disciplined capital allocation is key. We view growth as a byproduct of focusing on returns first, while we aren't providing specific guidance for 2019 today, we can provide some broad outlines of how the plan is shaping up. We are targeting an arbitrary growth rate. We are seeking to reinvest capital to the point that allows us to continue to lower cost and improve efficiencies. Again, capital allocation will continue to be based on returns measured against our premium price deck of $40 oil and $2.50 natural gas.
I'll turn the call over to Ezra to update you on the Delaware Basin and Eagle Ford.
Ezra Y. Yacob -- EVP, Exploration and Production
Thanks, Billy. In the Delaware Basin, we have made remarkable progress determining how to optimally develop this technically complex basin. During the first three quarters of 2018, we put 201 net wells to sales in various spacing and target patterns, which generated more than 150% direct after-tax rate of return. Well results across all of our Delaware Basin targets are consistently outperforming their respective type curves and early production observations and data have been incorporated into our ongoing development to further improve future well productivity. The geology in this basin is variable and complex. So there will not be a single answer on spacing or package size. However, the ultimate goal is to maximize capital efficiency by optimizing the numerous drivers of finding cost, returns and NPV. We are also making significant progress reducing well costs in a number of areas. Like many operators, we are benefiting from local sand, most of our gains are from operational efficiencies. Drilling days are down 10%. We steadily increased the use of zipper fracs throughout the year, contributing to a 20% increase in stages completed per day and a more than 10% decrease in completions costs.
Finally, our investment in water infrastructure is paying off. We are moving 95% of our water on pipe that includes water used for drilling and completion operations, as well as produced water. Our progress in Delaware Basin is a prime example of EOG's culture of innovation and entrepreneurship. We continue to experiment with operational and logistic changes and targeting and completions advances, all supported by real-time data capture to quickly respond to changing conditions at the field level, the result is better wells at lower costs.
The Eagle Ford continues to deliver consistent performance quarter-after-quarter. We've begun drilling this -- we've been drilling this world-class asset for almost 10 years, and we are still growing production, innovating our operations and experimenting with well completions, targeting and spacing. The well mix in the Eagle Ford during the third quarter included a higher proportion of western acreage wells, while the pay is thinner in the west, there's less faulting, which allows for longer laterals. The longer laterals you can drill, the better the efficiencies to be gained during drilling and completions. Wells drilled in the west this year averaging over 3,500 feet per day and are delivering the highest direct NPV of our Eagle Ford program. These long lateral western Eagle Ford wells will make up a growing proportion of our total Eagle Ford development in the future. Across our 520,000 net acre position in the Eagle Ford oil window, we have a massive inventory of 2,300 net undrilled premium locations. We continue to make progress maximizing value through technical innovation and operational efficiency, which in turn generates additional premium wells. The Eagle Ford remains core to EOG's business and one of the most important assets driving our production growth.
Here's David Trice.
David Trice -- Executive Vice President-Exploration and Production
Thanks, Ezra. We are in the initial innings of our Woodford oil window play in the Anadarko Basin, and are experimenting with completion designs, testing various targets, confirming well spacing and lowering cost. Late in the second quarter, we brought online a four-well 660 foot space package that targeted the same landing zone. The four Ted (ph) wells have over 120 days of production and are matching or exceeding our 1 million barrel oil equivalent per well type curve for the play. The Ted's (ph) average per well 30-day initial production delivered 660 barrels of oil per day, and their 90-day IP held up at 530 barrels per day. These results are consistent with the performance we have seen, since we started actively developing the Woodford last year. Initial IPs in this play tend to be lower than those in our other plays. However, they also have a lower decline rate. The performance of this four-well package supports our initial estimate that 660 foot spacing is optimal in the Woodford and delivers premium economics at low finding and development cost. Going forward, we will be working to optimize spacing, while targeting multiple landing zones. On the cost side, we are making great progress toward our target well cost of $7.8 million per well. Recent wells have come in at or even below our targeted cost and we anticipate that cost in 2019 could average below $7.8 million. One significant source of future cost reduction is the water reuse program, that is being rolled out in our Oklahoma operations. We expect at least 50% of our water need in 2019 will be sourced through recycling and that percentage will increase overtime. We're currently moving up the learning curve in the Woodford. In typical EOG fashion, we're innovating and experimenting with completion and targeting technology, capturing data in real time, then rapidly redeploying what we've learned in the field. As a result, we expect to continue to improve the Woodford plays well productivity and cost structure as it grows to contribute meaningfully to EOG's production and premium returns. We mentioned on our year end call that starting this year we decided to take a more seasonal approach to developing the Bakken. Historically, activity in the winter has come at a higher cost due to harsher conditions, so we decided to make it a practice to minimize activity through the winter months. As a result, most of our 2018 Bakken program started production in the second and third quarter. During the third quarter, we completed 12 net wells, with an average 30-day IP of almost 1,400 barrels of oil equivalent per day per well. These wells are solidly premium due to high oil cuts, low decline rates and very low well cost. The wells brought online in the third quarter cost approximately $5 million for laterals and averaged about 9,400 feet. The cost structure in the Bakken is one of the primary reasons we consistently deliver premium economics that are sustainable through commodity price cycles. The Bakken remains an important asset and EOG's diverse portfolio of plays, providing flexibility for reinvestment at our premium return hurdle rate. Our Powder River Basin activity during the third quarter was focused on the Turner play, where we completed 11 net wells that produced an average of 1,700 barrels of oil equivalent per day per well in the first 30 days. In the Mowry, we drilled two wells that we are currently completing and expect to spud a Niobrara well in the fourth quarter. From a technical standpoint, we continue to fine-tune target identification and execution in both plays as well as dialing in the right completion practices.
In the early life of any new play, this tends to be an iterative process as we collect data and rapidly integrate the new information on a go-forward basis. We are also in initial planning stages for two spacing test that will target the Mowry and Niobrara. We are planning to spud the test by year-end and the results will help determine how we co-develop the Mowry and Niobrara going forward. Co-development of these targets will drive additional long-term efficiencies, lower cost and increase returns in the Powder River Basin. As we plan for 2019, we are in active discussions with third-party service providers to ensure we have capacity to transport and process production next year and beyond. In addition, we will begin to add EOG owned infrastructure at a pace that is commensurate with development. This pay as you go strategy will ensure that we can maintain our capital efficiency even as we increased activity in the basin. EOG owned infrastructure will potentially include oil, gas and water gathering facilities, water recycling facilities, oil terminals, and compressor stations. The main advantage to EOG owned infrastructure is that it dramatically lowers lease operating and transportation expenses, as well as future capital cost associated with water handling. It also gives us greater control and flexibility along with access to multiple markets, which will ultimately result in higher netback prices.
In summary, we are planning for long-term high return growth out of the Powder River Basin, the newest addition to our portfolio of premium assets.
Here's Tim.
Timothy Driggers -- Chief Financial Officer
Thanks, David. EOG's financial position improves significantly during the third quarter. The company generated discretionary cash flow of $2.3 billion. EOG invested $1.7 billion in exploration and development expenditures and paid $107 million in dividends. Free cash flow was $503 million. Cash on the balance sheet at September 30 was $1.3 billion and total debt was $6.4 billion. For a net debt to total capitalization ratio of 22%. The same ratio was 28% just a year ago. Our goal is to repay $3 billion of debt through 2021. The first repayment was for $350 million bond that came to maturity, October 1, 2018. We also reached an agreement to divest of our UK operations including the Conwy asset and expect to close before year-end.
With the recent volatility in commodity prices, projections of future cash flow move around considerably, even on a daily basis. But EOG's priorities are steadfast. Invest with discipline, focus on rate of return, and maintain a strong financial position. Our goal is always is to create significant shareholder value over the long-term.
I'll now turn it back over to Bill for closing remarks.
William Thomas -- Chairman and Chief Executive Officer
Thanks, Tim. I would like to share the following concluding remarks. First, we are making significant progress on optimizing well spacing in the Delaware Basin and other plays. We're breaking the code on how to increase well productivity and lower finding and development costs, while optimizing NPV. We feel next year our capital efficiency will be much improved. Second, we're on track to reduce well costs 5% by year end 2018, and we believe we can continue to reduce costs further in 2019. Third, as we demonstrated last quarter with the addition of the Powder River, Niobrara and Mowry plays, the company continues to organically add significant new high return premium drilling inventory much faster than we are drilling it. More importantly, EOG's inventory is growing in quality, not just quantity. Better rocks make better wells, and enhance the company's ability to deliver higher returns in the future. And we are encouraged with the new ideas we're generating through our exploration efforts. Fourth, EOG's unique innovative culture, real-time data gathering, advanced analytics and quick deployment of new ideas for the field are delivering sustainable cost and productivity improvements across the company. The combination of our pleased, but not satisfied culture and industry-leading information technology is delivering sustainable results and provides a significant competitive advantage for the company. Fifth, we are systematically resetting the company's performance to be one of the lowest cost producers in the global oil market. Step by step, we believe we're continuously improving the company to produce strong returns through the commodity price cycles. And finally, our third quarter results demonstrates EOG's ability to deliver strong double-digit return on capital employed, strong double-digit production growth and generate free cash flow. This combination is rare in the energy sector and places EOG in line with the top performers in any sector of the market. It's a unique and compelling combination that create significant long-term shareholder value.
Thanks for listening and now we'll go to Q&A.
Questions and Answers:
Operator
Thank you. The question-and-answer session will be conducted electronically. (Operator Instructions) Our first question today will come from Ryan Todd of Simmons Energy. Please go ahead.
Ryan Todd -- Simmons Energy -- Analyst
Great. Thanks, and congratulations on a good result. Maybe if I could start with one as we think about, right, maybe a couple of questions on capital. Can you breakdown, I mean, I know you mentioned some of the -- a few of the drivers in the $300 million increase to the CapEx budget and with implied spending falling to just over $1 billion in fourth quarter, which is obviously low. Could you give us an idea of maybe what a normalized run rate would be on CapEx right now? Then I've a follow-up.
Billy Helms -- Chief Operating Officer
Yes. Ryan, this is Billy Helms. So, yes, the fourth quarter, we expect to be down relative to the third quarter. And that's simply because our activity was planned that way at the start of the year. We are going to have fewer wells completed in the fourth quarter than we did in the third. And as an election I'm trying to maintain our momentum on driving cost down. We are going to retain some equipment that we previously planned to release. In doing so, we'll end up completing about 20 additional wells, and that will be the majority of the increase that we're seeing in the fourth quarter that will give us momentum going into 2019 by capturing these high performing service providers and maintaining the efficiency gains that we have realized to date. We'll be able to continue to drive our well costs down into 2019. We're pretty excited really about the progress we've made on lowering well cost. In general, we'd say that our well costs are down about 3% year-to-date across our plays. For example, we're down about 2% in the Eagle Ford, and the Wolfcamp we're down about 3%, and the Bakken we're down about 4%. We're making similar progress across all of our plays and on average we're about 3% down for the company. Headed toward our goal of 5%, which we believe will accomplish in the fourth quarter. So our plan this year was -- as everybody recognized it was loaded to the front end with CapEx, the production showed up really in the third quarter. All intended to drop a little bit in the fourth quarter. So our run rate this year on a capital basis by quarter was a little bit lopsided. Going into 2019, we do not expect the same thing. Our 2019 program would be a little more balanced. We can't give you any guidance or any numbers on that yet. We're still working on that, but we would expect the run rate going into next year to be more balanced. And then capital efficiency continue to improve, and that's the whole basis of which we allocate capital these days is we're only going to do so as we can continue to improve our capital efficiency.
Ryan Todd -- Simmons Energy -- Analyst
Great. Thanks. And then maybe just a higher level, I mean, I appreciate the effort to talk about your reinvestment philosophy. But I guess, how is the right way to think about, I know growth is an output, but you've got a relatively unique growth in free cash flow profile. How do you think about balancing more or less growth with more or less free cash flow, and I guess, returns are a part of it, but you clearly have far more opportunity to deploy capital, high rates of return than you do in any given year. So, where do you draw a line between the amount that you're willing to grow versus a higher or lower amount of free cash? I'll leave it there. Thanks.
William Thomas -- Chairman and Chief Executive Officer
Ryan, this is Bill. Yes, certainly we're very committed to operating within cash flow and generate free cash flow every year. Our goal is to generate free cash flow every year. So, we look at the program every year with not a volume number that we're really focused on, we really look at the program as we've already talked about extensively to continue to get better. So we want to improve capital efficiency, continue to lower the finding and development costs and improve returns. And we believe we've got a sustainable business model, because it's based on $40 oil, which we believe is well below the marginal cost of oil. So we created as you -- have already commented on. We've got a very powerful engine, and we certainly have the ability to grow very fast, but we're not really focused on growth. We're really focused on getting better at increasing returns. So every year, we throttle back to allow us to learn and get better. And we believe as long as we continue to add new plays, we do not see our growth dropping significantly in the next several years at current process.
Ryan Todd -- Simmons Energy -- Analyst
Thanks, Bill.
Operator
Our next question will come from Arun Jayaram of JPMorgan. Please go ahead.
Arun Jayaram -- JP Morgan -- Analyst
Yes. Good morning. Bill, I wonder -- if you could elaborate on your comments on capital efficiency being better in 2019 versus 2018. Do you believe that on spending per unit of production basis, and I'm thinking about oil that your CapEx dollar will deliver more oil growth on a year-over-year basis for dollar invested?
William Thomas -- Chairman and Chief Executive Officer
Yes, Arun, that's absolutely what we believe. It's based on a number of different ideas. So first one is Billy has already commented on, we're going to get off to a better start, a faster start next year than we did in 2018. And then we really believe we're going to be entering the year at lower costs and higher well productivity than we entered 2018. And we believe with our ability to continue to learn, capture data, integrate the data, analyze the data and put it back into the field very quickly that we would be able to continue to improve lower costs and continue to improve our spacing patterns, development patterns and continue to improve well productivity going forward. So, our goal every year not just in 2019 is to get better, and that's a core culture of the company. We consistently done it for many, many, many years, and we do not see any end in that process.
Arun Jayaram -- JP Morgan -- Analyst
Great. And just my follow-up. Bill, I totally appreciate the fact that EOG allocates capital on returns basis. But just had a philosophical question on growth. You guys have previously highlighted a 15% to 25% kind of oil growth outlook, assuming 50 to 60, one question we think about if you get to the middle part of that range, the organization would essentially have to grow kind of a Parsley Energy in terms of size, in terms of oil growth. So we'd argue, maybe toward the lower end of that range, maybe better from a longer-term perspective, would love to hear your thoughts on that?
William Thomas -- Chairman and Chief Executive Officer
Arun, again, we don't give you any specific numbers, but in general, just as I've commented, because we have multiple plays, we're developing currently 11 different oil plays in the company and because we have a very decentralized structure that we can focus our divisions on each one of these plays put the proper people, the proper process in plays to continuously improve. As long as we continue to add new potential to the company every year through that whole process, we believe that our growth will not drop significantly in the next several years at current prices.
Arun Jayaram -- JP Morgan -- Analyst
Thank you very much.
Operator
Our next question will come from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer -- Goldman Sachs -- Analyst
Thank you. Good morning. Can you discuss the decision to lock in services costs for 2019, specifically do you think that market prices are near trough. And then if you were to create a waterfall for 2019 like you have on Slide 16 for 2018, do you think we -- you need to deliver efficiency gains and multiple green bars from here to keep well cost down or are you already seeing well cost down year-on-year in '19 based on the pricing terms you've locked in?
Billy Helms -- Chief Operating Officer
Yes. Brian, this is Billy Helms. The decision to go ahead and lock in or capture these service providers that are -- if we think a very favorable prices was really to maintain those efficiencies. We feel like that we're getting some highly efficient crews at what we believe is near the market conditions that we have today or probably near the low end. We don't know if we can capture the absolute bottom of the trough, but we do feel like we're capturing some of the best providers out there at very favorable prices. So it gives us confidence to be able to continue to lower our well cost in '19. Yes. We believe that the momentum we've created on efficiency gains and the progress we're seeing across all of our plays will continue to deliver solid results going into 2019, which is the whole reason we made this decision. We want to -- as we started 2018, we had to pick up quite a few crews and equipment and certainly those don't operate at the efficiency levels that we anticipate or expect, and it took us a while to get there, but we're very satisfied where we are today and the progress we're making on continuous improvement. I always want to maintain that into 2019, we're -- yes, we're going to continue to push every one of those categories you mentioned there on that Slide 16, I believe for the Wolfcamp, and I believe that one is going to continue to get better overtime.
Brian Singer -- Goldman Sachs -- Analyst
Great. Thanks. And then to follow-up on the capital efficiency improving in 2019 point, and Arun's follow-up there, you mentioned that well productivity expect to improve next year, can you talk about what and where the drivers of that are?
William Thomas -- Chairman and Chief Executive Officer
Yes. Brian, this is Bill. It's really in multiple different areas. We're seeing still very significant frac technology applications and improvements. We're seeing better execution in our targets, and which we're able to drill even faster and stay in a very narrow window even more precisely than we've done in years past. And we continue to learn how to pick our targets better, so our target selection is better. So, just in general the quality of the rock that we target is improving overtime, and all these are incrementally and moving continuously at the same time. So, we just don't really see an end or a plateau and being able to improve the company going forward. We have a very sustainable business model, a very sophisticated information technology process, and I think I'll ask Sandeep, maybe to comment on some of the things that we're doing in the information system to continue to improve.
Unidentified Speaker --
Yes. Sure, Bill. Yes, Brian, like Bill said, the main goal is really to continue to improve our capital efficiency and that means drilling better wells for lower cost, the game changer for us really has been the ability for us to capture data at a very, very high frequency, at a very, very granular level in real time and deliver it to all our engineers. I mean, the level of innovation that is currently that we're seeing continues to amaze me, in terms of the inventiveness of our completion engineers and their ability to almost custom design fracs to take advantage of the unique rock that we steered through and the ability of our Geo steers and our G&G folks to continue to fine-tune the target and stay in the real time basis, regardless of running, maybe crushing falls even and getting back into zones much faster. I mean, the whole system is geared toward becoming better with data, assimilating the understanding of potential depletion dialing that into the frac designs to make better wells on an ongoing basis. So there is innovations going on in drilling, in completions, in production optimization, all with the goal of improving capital efficiency. So the levers of capital efficiency improvements in 2019, I would say are just numerous, countless almost.
Brian Singer -- Goldman Sachs -- Analyst
Great. Thank you very much.
Operator
Our next question will come from Leo Mariani of NatAlliance Securities. Please go ahead.
Leo Mariani -- Nat Alliance Securities -- Analyst
Hi, guys. Just wanted to follow-up a little bit on sort of your comments around capital efficiency. Obviously, you had a really nice ramp in production here in 2018, and certainly as you guys have pointed out well cost have fallen. So, I guess all things being equal, I mean, it certainly looks like we're going to see higher operating cash flows in 2019 versus 2018 here. So, I mean, just high level, I mean, should we expect to see some higher overall, just activity levels from EOG and obviously looks like free cash flow will go up. So maybe just talk about sort of prioritizing the uses next year?
William Thomas -- Chairman and Chief Executive Officer
Yes. Leo, again, we're going to maintain very strict discipline. So, the Governor (ph) is -- we're only going to increase spending if we can get better, so that's absolute thing I think you've heard that. So, the priorities have not changed. We're getting currently at current prices, we're getting triple-digit rates of returns at the well level. So that's the first priority for cash. We're very excited about new exploration potential that we're generating inside the company, so we want to continue to pick up better rock at low cost. And we're certainly have debt reduction is a very high priority in the company, and as Tim said, we have already reduced about $350 million this year and we plan to retire another $900 million next year, and we target over $3 billion of debt reduction over the next -- in four-year period. And then we want to continue to work on increasing the dividend. We have a very strong commitment to returning cash to our shareholders through the dividend, as we increased at 31% this year. And if we have a healthy business environment, we'll evaluate quarterly on that, but our goal is to continue to increase that at stronger than our historical rate of 19%, compounded annual growth rate. And then I just want to reiterate, we have no interest, no need, and even thinking about expensive corporate M&As. So we're very focused and very disciplined, and we're going to continue to remain focused on increasing returns by getting better.
Leo Mariani -- Nat Alliance Securities -- Analyst
Okay. That's great color. And also just wanted to focus quickly on the Austin Chalk, I know this is an emerging play for you folks, but obviously you've been in the play for a while. Just wanted to get a sense of where we are in the evolution here, I mean you guys feel like you've got a better handle on sort of the economics, as well as just productive extent of your sizable acreage position at this point in time?
Ezra Y. Yacob -- EVP, Exploration and Production
Hi. Leo, this is Ezra Yacob. Yes, I think, as we've talked about we've been developing Austin Chalk, we've been co-developing it now with our Eagle Ford program, and it's a little bit more of a complicated play than the Eagle Ford certainly. And so, well, it's perspective across our entire South Texas acreage position there. The sweet spots are a little more discontinuous, and we've done a very good job integrating not only core data and log data that we've collected while we've been developing the Eagle Ford, but we've also tied that into our seismic coverage, which extends across our entire acreage position. So, yes, we're feeling very good with it. The benefit that Austin Chalk also has is that since we do co-development with the Eagle Ford and that's within our core area, it has a lot of -- it benefits from a lot of the existing infrastructure, and obviously all of the operational performance that we have there that we increased -- that we continue to increase in the Eagle Ford, Austin Chalk continues to benefit from that. So this quarter we brought on 10 net wells. They had an average 30-day rate, they're just over 1,800 barrels of oil per day. And so (Technical Difficulty)
Operator
The next question will come from Bob Brackett of Sanford Bernstein. Please go ahead.
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
(Technical Difficulty) 65% of --
Billy Helms -- Chief Operating Officer
That's 65%. Bob, this is Billy Helms by the way. This is 65% of our typical average well cost in the company. So, we look at our typical well costs being somewhere in that $6 million range, and it's about 65% of that number.
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
Okay. So that's a per well number, it's not a total capital number?
Billy Helms -- Chief Operating Officer
No. It's a per well, it's an average for the per well drilling complete cost.
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
Okay. That's understood. Separate question, if I look at sort of where you are in spacing in the Delaware Basin, there's a fairly wide range from 660 up to 1,000, and it doesn't seem to be a function of depth or oil cut. Can you give some color what's driving that well spacing and how fixed are those numbers?
Ezra Y. Yacob -- EVP, Exploration and Production
Yes. Bob, this is Ezra Yacob. So that is a good observation you have, I appreciate the question. The first part of our well spacing, it does actually began with the oil cut, I think our announced type curves for the oil play where we have 226,000 net acres is based on 660 foot spacing, and then for our combo play, which is a little bit shallower, a little bit less of an oil cut is that type curve is based on an 880 foot spacing, that would be some of our Reeves County acreage down there. But then more than that the spacing really across the Permian is going to be tied to the local geology. We continue to kind of monitor the long-term performance of lot of those spacing and different targeting patterns that we've tested, and we've discussed those on past calls, where we've been testing space in the oil window down to 500 foot to 700 foot spacing depending basically on the local geology, the number of targets, and as such, it is a complicated play in the Delaware Basin. But I think what we see this year as we've made tremendous progress on the finding kind of our optimal spacing and targeting packages for our core acreage positions. We brought 180 wells in the Wolfcamp to sales this year and it's reinforce, so we feel very confident with our announced resource potential on that type curve at 1.3 million barrels of equivalents, and again that's for a 7,000 foot lateral, 660 foot spacing. I think the way to think about that 660 is if you just look at our remaining premium inventory that's going to be a good average over that acreage position. We feel very good about the work that's been done this year in the Permian. Our ability to increase returns and optimize NPV and ultimately increase the capital efficiencies, we finish out 2018 and move into 2019.
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
Great. Appreciate that. Just to be explicit, those numbers account for things like parent-child relationships and downspacing well interference effects?
Ezra Y. Yacob -- EVP, Exploration and Production
Yes. That's correct, Bob. When we put our resource potential on our type curves out there, we've baked all of that in, and so, as we continue to integrate our data, not only from the early package development, the early and long-term production profiles of the wells are real time completions data, as we integrate that into the next well of packages, really we consider the improvements and the gains that we're able to make as upside.
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
Great. Appreciate it.
Operator
The next question will come from Charles Meade of Johnson Rice. Please go ahead.
Charles Meade -- Johnson Rice -- Analyst
Yes. Good morning, Bill to you and your whole team there. I was listening to your prepared comments, and I wanted to go back and explore a little bit the idea that you are ranking these plays at $40 oil, it makes sense to me that your best play at $40, would still be your best play at $60 or $70, but it also seems to me that the way you would develop your assets -- your spacing pattern to pick up a brackets point or how intensively you go after those assets would be different at $60 or $70, than it would at $40. So can you talk about whether that's a -- whether you agree with that point of view, and if you do, how you modulate that density aspect of your program?
William Thomas -- Chairman and Chief Executive Officer
Charles, we run all of our economics based on our premium price deck of $40 flat, and $2.50 flat natural gas prices. So, our focus on all of our properties is to develop those to continue to lower the finding costs, that's really, really important -- to improve the capital efficiency, that's really, really important. To continue to improve the returns and ultimately to optimize the NPV. And so we're really able, we believe to optimize those all at once, and we have a very strict $40 flat, $2.50 flat price deck that we manage the company on, and we believe that will continue to improve the cost structure of the company, and that is what we believe will continue to help us to generate double-digit returns and double-digit growth through the commodity price cycles, and that is what will continue to help us become one of the lowest cost producers in the global oil market. So, we're very strong, we are very focused, we're very strict, and we're committed to that process.
Charles Meade -- Johnson Rice -- Analyst
Thanks for that clarification, Bill. That's it from me.
Operator
Our next question will come from Irene Haas of Imperial Capital. Please go ahead.
Irene Haas -- Imperial Capital -- Analyst
Yes. My question is on Powder River Basin, very glad to see that the company is pre-emptively working on infrastructure, and my question has to do with just permitting on the state and federal level, how is it coming along, any progress on the EIS. And also really any gating factor that needs to be taken care of before you guys really, really ramp up, such as oil and gas takeaway?
David Trice -- Executive Vice President-Exploration and Production
Yes. Irene, this is David Trice. On the regulatory side, we have captured the permits that we need for operatorship out there, so we've been busy doing that for really the last couple of years, as you know Wyoming's kind of capture the flag state, so you have to actually file the permit to get operatorship, no matter what your interest is there. And so, we've done that for essentially all of our acreage out there. And as far as the infrastructure goes, we had mentioned on our last call that we -- 2019 was really where we're going to be focused on adding infrastructure and takeaway. Our drilling activity will not be up significantly in '19, it will probably be up slightly there, but mainly the focus in '19 is going to be more focused on putting the pieces in place to go and bring the Powder forward in 2020 and beyond.
Irene Haas -- Imperial Capital -- Analyst
Okay. May I have a follow-up, feels like the basin, really kind of benefits larger well organized producers kind of like EOG scope and scale, so are there any both on that might make sense down the line for EOG understanding that you guys are not into buying big companies?
David Trice -- Executive Vice President-Exploration and Production
Yes. Again, I think I'd reiterate what Bill said earlier, I mean, we're certainly not interested in any of these expensive corporate level acquisitions. We're always looking to add high quality acreage at low cost, and so some bolt-on would make sense and its low cost then we would certainly look at it. But again, our focus is more on the exploration side, finding low cost, high quality acreage.
Irene Haas -- Imperial Capital -- Analyst
Thank you.
Operator
The next question will come from Subash Chandra of Guggenheim Partners. Please go ahead.
Subash Chandra -- Guggenheim Partners -- Analyst
Yes. Thanks. Good morning. I was hoping you guys could just comment on some public data that's out there. Just showing, I guess in New Mexico, the well results being sort of incrementally lower than in prior years, and if that's sort of a data integrity thing or if there's something else going on and this is just an interim event?
Ezra Y. Yacob -- EVP, Exploration and Production
Yes. Subash, this is Ezra Yacob. With the results in the Delaware Basin there in the New Mexico portion, I'm not sure if I can speak directly to the state data that you're seeing. But what I will say is that we're very pleased with the results that we're seeing out there. As I discussed earlier in the opening remarks, all of our well performance are actually outperforming, the respective type curves for each of the plays that we're drilling, and we've made a tremendous amount of progress this year, I think this quarter's early time 30-day results are actually the highest of the year this year, and part of that is those quarter-over-quarter numbers will move around a little bit, just depending on which package of wells you're bringing on from which part of the basin. But really I think in general, our team out there has done a great job, integrating the data from some of our packages that we've been drilling early in the year, making some adjustments to the spacing and targeting, as well as on the completion side, and really increasing the well productivity of those wells. And I think that's showing up a little bit here in this last quarter. in addition to that, as Billy highlighted, we're making pretty good gains on our operational efficiency, which is translated into lower well costs, and so when you combine those two things together, we're seeing a decrease in our finding and development costs in the plays, which result in better returns and a higher capital efficiency, which is what our goal is for that basin.
Subash Chandra -- Guggenheim Partners -- Analyst
Yes. Thanks, Ezra. State data can be a dangerous thing that's what I thought I'd ask. The second question is just in Eastern Anadarko, if next batch of wells that was the very similar sort of high rate artificial lift. And if so, would this open up, maybe some other plays for you that are not as in the geopressured area as you typically prefer?
William Thomas -- Chairman and Chief Executive Officer
Can we get the first part of your question, we didn't quite understand the first sense?
Subash Chandra -- Guggenheim Partners -- Analyst
Yes. Sure. My understanding is that Eastern Anadarko is that the wells brought on with very high rate gas lift, and I could be wrong there. So, just curious if that's the situation or not, and if it is, if there's other plays better and less geopressured areas that you can apply a similar artificial lift on the front end to open the plays out?
David Trice -- Executive Vice President-Exploration and Production
Yes. This is David Trice. Yes, in Anadarko Basin, we do use gas lift there, we bring those wells on initially with gas lift and really got the lift well. We use gas lift really throughout the company, so that's nothing new for us. In the Eastern Anadarko, we do it a little bit different than we do in other areas, but basically it's the same around the company, and it's a very low cost method that we use and we get a very good return LOE on that.
Subash Chandra -- Guggenheim Partners -- Analyst
Got it. Thank you for the clarification.
Operator
The next question will come from Paul Sankey of Mizuho Securities. Please go ahead. We'll move on to the next question. The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Jeffrey Campbell -- Tuohy Brothers Investment Research -- Analyst
Good morning and congratulations on the quarter. I wanted to just quickly return to this discussion of the premium locations and just ask, is it fair to think that some of the -- even though they're all great, some of the locations are better than others or maybe to put it another way, since all the premium locations have high potential for outperforming. What informs the choice to develop some of them now and wait on others for later?
David Trice -- Executive Vice President-Exploration and Production
Yes. All the premium locations are quite outstanding, they're quite different. I believe in the average well that the industry is drilling, so they're in a very high elevated level. And of course, it's a huge inventory, it's 9,500 locations, and some of them are much better than others. And as we continue to add to that premium inventory, our goal is to bring the quality of the inventory up, just like we drilled, build the quantity of the inventory. And so, we do develop all of it and we believe that every well in the inventory and every play in that inventory has got continuous room for improvement going forward. And so, we developed the plays based on returns and the allocation of the capital in the company is strictly based on returns, and so we drilled the highest rate of return wells we have in (inaudible) in the company every year, and we develop on a play basis. In the pace of learning in the company, because of the information technology and the culture of the company continues to increase.
Jeffrey Campbell -- Tuohy Brothers Investment Research -- Analyst
Okay. That was very helpful. I appreciate that. I'll ask a more narrow question for my follow-up. I noticed on the call, you mentioned there's going to be the spacing test of the Mowry and the Niobrara together. And so, I'm just wondering, since the Turner wasn't mentioned, does that imply that the Turner sweet spots are discrete from the premium Mowry and Niobrara locations?
David Trice -- Executive Vice President-Exploration and Production
Yes. Jeff, this is David, again. On the Turner, we feel like we understand that play a lot better. We've been drilling the Turner for years, and we've done various test over the years. And so, we have a good handle already on what the spacing should be in the Turner. Just the fact that the Mowry and the Niobrara are new, we're going to go ahead and do some spacing test there similar to what we did in the Woodford. And so, we're planning to do those, those are two separate test, and we're going to do those at 660 foot spacing.
Jeffrey Campbell -- Tuohy Brothers Investment Research -- Analyst
Okay. Great. Thanks for that clarification. I appreciate it.
Operator
Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Mr. Thomas.
William Thomas -- Chairman and Chief Executive Officer
In closing, our third quarter results were outstanding. The company continues to improve systematically by lowering cost and improving productivity with new technology and efficiency gains. Many thanks, again, to all the EOG employees for demonstrating the innovative returns, focused cultures that makes EOG successful. Our culture is a driving force of the company's sustainable business model and we're excited about the future and our ability to continue to create significant long-term shareholder value. Thanks for listening, and thanks for your support.
Operator
The conference is now concluded. We thank you for attending today's presentation. You may now disconnect your lines.
Duration: 60 minutes
Call participants:
Timothy Driggers -- Chief Financial Officer
William Thomas -- Chairman and Chief Executive Officer
Billy Helms -- Chief Operating Officer
Ezra Y. Yacob -- EVP, Exploration and Production
David Trice -- Executive Vice President-Exploration and Production
Ryan Todd -- Simmons Energy -- Analyst
Arun Jayaram -- JP Morgan -- Analyst
Brian Singer -- Goldman Sachs -- Analyst
Unidentified Speaker --
Leo Mariani -- Nat Alliance Securities -- Analyst
Robert Alan Brackett -- Sanford C. Bernstein & Co. -- Analyst
Charles Meade -- Johnson Rice -- Analyst
Irene Haas -- Imperial Capital -- Analyst
Subash Chandra -- Guggenheim Partners -- Analyst
Jeffrey Campbell -- Tuohy Brothers Investment Research -- Analyst
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