Good day everyone. Welcome to the EOG Resources 2016 third quarter results conference call. 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.
Thank you. Good morning. Thanks for joining us. We hope everyone has seen the press release announcing third quarter 2016 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the press release and EOG's SEC filings. We incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines.
We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release on the investors page of our website. In addition, for the purpose of this call, reserve estimates for basin and well level resources are net after royalty, unless otherwise stated. References to well locations, wells drilled, and wells completed are net to EOG's interest unless otherwise stated. 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, VP Marketing Operations; and Cedric Burgher, Senior 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 2016 in yesterday's press release. This morning, we'll discuss topics in the following order.
Bill Thomas will review our shift to premium drilling and the updated 2020 growth outlook. Billy Helms will provide an update to our Permian Delaware Basin resource. David Trice will discuss notable achievements in our other select plays. Gary Thomas will go over our operational accomplishments. I will discuss EOG's financials and capital structure. Bill will then provide concluding remarks. Here's Bill Thomas.
Thanks, Tim. Good morning, everyone. EOG has responded to the downturn in oil prices with an unrelenting focus on capital returns. In 2016, we increased well productivity and lowered well and operating costs at a record pace. The company projects our all-in return on the 26 capital program looks at a company record, and we achieved this in one of the lowest commodity price environments we've experienced in a long time. Our tremendous success improving capital return this year, combined with the addition of the Yates acreage, increased the company resource potential in both size and quality at a record pace. As a result, we've reset the company to deliver high return oil growth within cash flow in a $50 oil environment. We believe this is unique to the industry.
In this price environment, our ability to generate high capital rates of return and achieve strong double-digit oil growth with a balanced CapEx to cash flow program sets EOG apart as the industry leader in capital efficiency. In early 2016, the talented teams working each play across EOG identified 3,200 locations, representing 2 billion barrels of oil equivalent reserve potential. That met a new rate of return standard we designated premium. To meet the premium standard, a well has to earn a minimum of 30% direct after-tax rate of return at $40 oil. The process of first defining premium and second identifying the inventory was to ensure that during 2016, year two of the downturn, we did not spend a single dollar drilling uneconomic wells.
What we didn't anticipate about the new premium standard is the fire it would light under each of the teams working EOG's plays across the company. Since the start of 2016, we've converted more than 1,000 additional locations to premium on our existing acreage. The Yates merger added another 1,700 premium locations. Our premium resource potential now totals more than 5 billion barrels of oil equivalent and 6,000 locations. That's more than double the resource potential and almost double the locations from the start of 2016. More impressively, when you do the math on those numbers, you see that net reserve per well of our premium inventory went from 625 MBOE at the start of the year to 850 MBOE today. We're not only adding more premium inventory, the productivity of that inventory is growing.
Another important factor in improving capital efficiency has been a 29% reduction in cash operating unit costs and over $1 billion in annual operating savings compared to 2014. For the third quarter in a row, we have lowered our operating expense forecast for the year. Over the last number of years, EOG has consistently added locations faster than we drill them. Over the next number of years, we fully expect to do the same with our premium locations. We stated at the beginning of the year that EOG's shift to premium was permanent. Our performance this year should leave little doubt of EOG's ability to execute that shift. Before I hand it over to Billy Helms to review the Delaware Basin, I want to discuss the other big news from the press release last night, our updated 2020 outlook.
We introduced 2017 to 2020 outlook last quarter at 10% compounded annual growth rate at $50 oil, increasing to 20% at $60 oil. We provided this long-term framework for the reasons I just mentioned. Our premium inventory is growing in size and quality, and we expect to replace it faster than we drill it. With continued capital efficiency gains, we're increasing our 2017 through 2020 CAGR outlook by 5%. At $50-$60 oil, we are now capable of growing a compounded 15%-25% annually. Given the size of our base production today, that growth is remarkable. Also remarkable is that we can deliver that growth and the dividend within cash flow. It's important to note that our 2020 outlook includes growth throughout our large, high-quality, diversified portfolio of plays.
As discussed in the opening remarks, our organization structure and cutting-edge culture are driving new technology advancements, cost reductions, and exploration efforts across the company at a record pace. Our 2020 outlook envisions high return growth from the Eagle Ford, Rockies, Bakken, and Permian. Additionally, we continue to work on other emerging exploration plays and expect they will become a material part of our future. EOG is a resilient company. Our unique culture continues to produce sustainable gains in capital productivity and generate years of high-quality drilling potential. We are a leader in capturing high-quality acreage in the best horizontal oil plays in the U.S., and the Yates transaction is just the latest example of EOG's ability to add high-return growth potential. Now I will turn it over to Billy Helms to update the Delaware Basin results.
Thanks, Bill. 2016 is turning out to be a tremendous year for EOG in the Delaware Basin that can be highlighted in a couple of ways. First, our Permian team's progress delivering increased well performance and cost reduction has been outstanding. As illustrated on slide 11, EOG continues to deliver exceptional industry-leading well productivity. This outperformance was accomplished in multiple ways, which I will discuss in more detail in a moment. Second, with the combination of technology gains, cost reduction, and the Yates transaction, we increased the Delaware Basin's resource potential by 155%, bringing the new total to a massive 6 billion barrels of oil equivalent from 6,300 net drilling locations. The increase is 3.7 billion barrels of oil equivalent larger than our total announced just one year ago on the third-quarter call.
Now that the resource potential has been further defined, our efforts will focus on converting the identified locations to premium. Approximately 55% of the 6,300 locations are currently premium, and we are confident that the majority of the non-premium locations will be converted over time. There are two ways to convert the inventory. One is by increasing well productivity through technology, such as our precision targeting process and improved completion techniques. Two is through lowering cost, both capital cost as well as operating expenses. Just like the Eagle Ford, we are confident that our premium inventory in the Delaware Basin will continue to increase over time. As we have discussed in the past, the Delaware Basin is a large, very complex geological basin.
Our first step entering any play is to focus our exploration team on understanding the details of the rock characteristics and then acquire our acreage position in areas that exhibit high-quality rock potential. The majority of the acreage acquired in the Yates transaction demonstrates strong geologic characteristics and complements EOG's existing acreage position. The added acreage inventory will allow us to trade and block up acreage to provide opportunities for longer laterals and more efficient use of infrastructure. Blocking up acreage will, over time, continue to drive down operating costs and convert the existing location inventory to premium status. Most of the increase in the resource estimate is from the Wolfcamp. Our new estimate of total resource potential is 2.9 billion barrels of oil equivalent. This represents a 123% increase to the previous estimate of 1.3 billion barrels.
The well inventory increased by 500 locations. More impressively, the average lateral length increased by 60% to over 7,000 feet. We are steadily increasing the length of our laterals. More importantly, maintaining our focus on targeting and completion effectiveness do not diminish the productivity per foot of lateral. We have previously subdivided the Wolfcamp into an oil window where the production is more than 50% oil and a combo play where the production is a balanced mix of oil, natural gas, and NGLs. In addition, we have tested multiple target intervals within each zone.
The resource estimate uses the confirmed test results from the different tested intervals in both the oil window and the combo play. In general can be summarized as including at least one productive interval across our acreage, with well spacing averaging 660 feet between wells in the oil window and 880 feet between wells in the combo play. A few highlights in the third quarter are from two 660-foot spacing patterns, one with two wells and the other with four wells, both in the Upper Wolfcamp. The two-well pattern had average 30-day production over 3,000 BOEs per day, with 2,100 barrels of oil per day per well. Both were drilled using short laterals averaging 4,500 feet. The four-well pattern had average 30-day production over 2,800 BOEs per day with 1,900 barrels of oil per day per well. These wells were drilled using about 4,900-foot laterals.
Similar to our other resource plays, we continue to test tighter spacing and evaluate the optimal development plan for each area. In the Second Bone Spring, we updated our resource potential estimate from 500 million barrels of oil equivalent to 1.4 billion barrels. Another massive increase that is almost three times our estimate from a year ago. The Yates acreage added about half the increase, with the remainder due to targeting and technology driving tremendous efficiencies. While the Leonard, also known as the Avalon, is the most mature of our Delaware Basin plays, we have had minimal activity in 2016. Based on longer-term production performance and a detailed assessment of drilling locations, we now estimate that the Leonard resource potential is 1.7 billion barrels of oil equivalent, as compared to our previous estimate of 550 million barrels.
Finally, we not only expect to convert the majority of the existing 6,300 locations to premium, we anticipate discovering new sources of premium drilling as we test additional areas and identify new target intervals within this geologically complex basin. We are still in the early innings of the Delaware Basin and are excited about the future. EOG's Delaware Basin potential is rapidly improving in both size and productivity and adds to EOG's deep portfolio of U.S. unconventional assets and unique growth story. Here's David Trice.
Thanks, Billy. In the Eagle Ford, we continue to make tremendous progress on cost. In the third quarter, we drilled and completed 47 wells for a remarkable $4.6 million per well. Well costs are being driven lower for all the reasons we mentioned on our last call. More efficient rig operations are driving drilling days down to less than six days a well. Completions are also getting more efficient. In 2014, we were completing 600 feet of lateral per day. During this downturn, we've taken a harder look at completion operations and logistics and are now completing wells 66% faster at almost 1,000 feet per day. At the same time, we continue to enhance the effectiveness of our completions, as shown on slide 28. Additionally, Eagle Ford well performance continues to grow even as we push wells closer together.
During the third quarter, we completed a set of five infill wells down spaced to 200 feet that were some of our best-performing wells for the quarter. The fourth unit, 10H through 14H, averaged over 2,000 barrels of oil per day per well for their first 30 days on production. We have been drilling the Eagle Ford going on seven years, and we still have so much to learn in this world-class play. Also in the Eagle Ford, our enhanced oil recovery project, or EOR, is progressing on schedule. We completed the initial phase of the 32-well pilot, our largest to date. We look forward to having results to share with you sometime in 2017. In the Rockies, we continue to get excellent results from the Turner Sand in the Powder River Basin.
Our drilling program there is delivering consistent premium-level returns, and we're looking forward to expanding activity there next year. The nine wells we drilled in the third quarter are producing on average almost 1,600 BOEs per day for the first 30 days, were drilled in under six days, and have a total well cost of just $4.9 million normalized to a 6,500-foot lateral. In addition, the decline rates are relatively low, so on average, the wells produce almost 100,000 BOEs per well in 90 days. The average lateral length in the third quarter was short at just 4,100 feet. We expect to move to longer two-mile wells, particularly now that the Yates transaction blocks up much of our existing acreage in the sweet spot of the play.
Longer laterals will enhance economics similar to what we've realized in other plays and is particularly helpful with respect to surface permitting efficiencies in the Powder River Basin. Precision targeting has allowed us to convert the Turner into a premium play. We use advanced techniques to identify, map, and steer our wells in a narrow 15-foot window. We are able to accomplish this even while we continue to push the envelope on drilling speeds. We plan to complete a total of 25 net wells in the Turner this year. Here's Gary Thomas.
Thanks, David. EOG's operational performance in 2016 in terms of cost and efficiency gains has been one of the best in company history.
In addition to making huge improvements in well productivity, we have driven so much cost and time out of our operations that we significantly increased the number of wells we are drilling and completing. EOG will now drill approximately 90 more wells and complete 80 more wells than were originally forecasted for 2016, while only increasing our development capital by $200 million. As a result, our fourth quarter domestic oil production before the addition of Yates is forecasted to be 36,000 barrels of oil per day above our forecast at the start of the year. That's an amazing accomplishment and a testament to the tremendous capital efficiency gains we have made this year. When we add Yates and international volumes, we expect that EOG's oil exit rate will be near the company's all-time high, set in the fourth quarter of 2014. Now let's talk about cost reduction and efficiency gains.
Since 2014, EOG's drilling days and total well cost in our large Eagle Ford, Bakken, and Wolfcamp plays are down 25%-45%. Another measure of our drilling efficiency is the number of wells drilled per rig per year, which increased 40% in our top three plays. For example, in the Eagle Ford, we're drilling 32 wells per rig year. On the operating side, we reduced cash unit cost 29%, and 2016 LOE alone has come down almost to half a billion dollars compared to 2014. While the major driver of cost reductions has been efficiency gains, we're also benefiting from approximately half of our high-cost drilling and completion contracts being replaced with rates that are 40% lower. In addition, tubular and well head costs will come down 25% with our 2017 arrangements. The market is speculating about service cost increases and how they will impact the industry.
For EOG, due to our integrated operations, current arrangements, and continued efficiency gains, we're well-insulated. At a minimum, we expect to at least hold well cost flat in 2017. Our teams continue to make significant efficiency gains. EOG's rate of return culture and our large-scale sweet spot positions in the best North American reserve plays facilitates continual improvement across all cost categories. Now for a word on DUCs. Our cost savings and additional $200 million of capital will allow EOG to complete almost all the DUCs we had in inventory at the beginning of the year. The rate of return on additional capital is very strong, and as I noted earlier, it allows us to exit the year with oil production on an upswing at near record rates and will get EOG off to a great start in 2017.
We will end 2016 with approximately 140 uncompleted wells, a normal level of working inventory. EOG thrives during downturns due to our strength as a low-cost operator. Our strategy of low debt, living within cash flow, and focusing on returns has allowed us to be one of the few companies that has preserved our balance sheet without diluting our shareholders by raising equity to pay down debt. Furthermore, we are in the best cost and inventory position I've seen in my near 40 years with the company. Our 2020 outlook is testament to that. We accomplished this through our permanent shift to premium drilling and a widespread focus on cost control. You're all familiar with our extensive inventory of premium locations. However, as COO, I am most proud of the highly integrated efforts of our teams to deliver sustainable cost reduction. They're doing an outstanding job.
We're committed to maintain this focus, and we're uniquely positioned for the future. Here's Tim Driggers.
Thanks, Gary. Capitalized interest for the third quarter 2016 was $8 million. Exploration and development expenditures were $660 million, excluding property acquisitions. Which is 32% less as compared to third quarter 2015, while our total production volumes decreased by just 3%. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $16 million. We are increasing full-year capital expenditure guidance to $2.6 billion-$2.8 billion. At the end of September 2016, total debt outstanding was $7 billion, and the debt-to-total capitalization ratio was 37%. At September 30, we had more than $1 billion of cash on hand, giving us non-GAAP net debt of $5.9 billion, for a net debt to total cap ratio of 33%.
Year to date, we have sold assets generating approximately $625 million of proceeds and associated production of 80 million cubic feet per day of natural gas, 3,400 barrels of oil per day, and 4,290 barrels per day of NGLs. Assets sold include Midland Basin, Colorado DJ Basin, and Haynesville properties. The effective tax rate for the third quarter was 30%, and the deferred tax ratio was 132%. I'll turn it back over to Bill.
Thanks, Tim. Our macro view has not changed. Over the long term, we believe oil in the 40s will not sustain enough production to meet demand worldwide. While EOG can deliver strong oil growth within cash flow with $50 oil, we believe the U.S. industry as a whole needs sustained $60 oil prices and extended lead times to provide a moderate level of growth. Worldwide base decline rates are slowly reducing supply, and the consensus view is the current large inventory overhang could return to normal levels by late 2017. We plan to issue official guidance on 2017, along with our year-end results early next year. Our overarching goal in 2017 is to build momentum off the foundation of premium inventory EOG established in 2016.
As Gary explained, we are completing 180 more wells than previously forecasted, we are exiting 2016 with strong oil production, and we will complete a higher percentage of premium wells in 2017 versus 2016. After two years of this down cycle, we are more than ready to resume high return oil growth. EOG's vision for 2017 through 2020 can be summed up with four goals: be the leader in return on capital employed, be the U.S. leader in oil growth, be one of the lowest cost producers in the global oil market, and remain committed to safety and the environment. EOG's long-term forecast has not wavered during the downturn. Our purpose is to create significant long-term shareholder value. As we enter a recovery, our unique and resilient culture has positioned the company to achieve strong results for years to come. Thank you for listening.
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 phone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the pound key. We'll pause for just a moment to give everyone an opportunity to signal for questions. We'll take our next question. Our first question from Scott Hanold with RBC Capital Markets.
Good morning.
Good morning.
Hey, impressive job this quarter, congratulations on the increased outlook. As you step back and look at the big opportunity you all have in the Permian that you described, can you give us a sense on, generally, how you're looking at developing that in terms of what formations may be higher on the top of the list over the next couple of years, and how do you see pad development going forward in that play?
Scott, this is Billy Helms. Yeah, in the Delaware, we do expect with this increase that our activity over time will continue to increase, especially going into next year. Our activity to date has been focused largely on the Wolfcamp, and I think the majority of the focus will stay on the Wolfcamp. Just to reiterate, all three plays are considered premium today, and we're excited about the potential. We're further along in our development of the Wolfcamp, for that reason, we'll continue that. It's an excellent volume growth generator, extremely high rate of return play. By drilling it first, it also allows us to take a look at the shallower objectives as we drill down through those. It gives us a better idea of long-term potential and how the drilling program in those plays will develop.
In the future, in the second part of your question there about pad drilling, we are continuing to develop pad drilling as we develop the field now, that will continue as we add the shallower zones as well. The good thing about that is we put in the infrastructure once for all those wells to share in the future. Incrementally, the overall rate of return for those programs in the future will continue to increase as we share that infrastructure that's built out for the initial completions.
Great. That's good. In my follow-up, this quarter, you guys are now producing more. It's over 50%, which was a pretty good heavy lifting here over the last few years to get. When you look at your long-range outlook, could you give us a sense of how some of the resource pieces contribute to that? Specifically, what is the Permian producing today? What's the Eagle Ford producing today? In your long-range outlook, where do those plays go?
Scott, we haven't broke it out by play. I think the way you want to think about the company is that we have a very strong, diversified portfolio
From year to year, actually from maybe even quarter to quarter, we shift our capital to wherever we're receiving the highest rate of return. Things change over time. As Billy said, obviously, the Delaware is getting bigger and better for us, so it will get more capital next year than it got this year. The Eagle Ford will still get a lot of capital. The Rockies play, particularly the Powder River Basin, will get a lot of capital. I think you need to be thinking of EOG as very balanced, very large, and a very diversified portfolio.
Thank you.
We'll take our next question from Subash Chandra with Guggenheim.
Yeah. Hi, good morning. The first question is, when I think about the number of location, the Wolfcamp, is it 2 intervals that you're thinking about in each of the oil and combo plays? What's the status of the Lower Wolfcamp, if you've had any results there?
Yeah, Subash. This is Billy Helms again. In the Wolfcamp, we generally think about, yes, mainly two zones. The upper and middle is what we've assessed resource potential to. Within each one, there are multiple target intervals. You can think about it as having multiple targets within each play. We've assessed the potential mainly in areas where we've tested each one, and we've based that on our confirmed test, confirmed results of each one. That's how we've kind of rolled up the resource potential there. I'm sorry, what was the second part of your question?
Lower Wolfcamp.
Yes.
Yeah, Lower Wolfcamp.
I'm sorry. The Lower Wolfcamp, we have had some tests. I'd say majority of our tests so far have been in the upper part of the zone, but we have had some tests in the, what we call the Middle Wolfcamp, and those results are encouraging as well.
Okay. If I hear it correctly, it's a very highly risked measure, your locations that you've published to date, right? If I just did resource map across multiple intervals, I can get many more locations than what you've published.
Yes. I think the way to think about that is, our results are based on our confirmed tests in each one of the intervals, then we allocate that to sticks on a map kind of approach, where it's not just taking the total number of acres and dividing it by well spacing. It's actually geologically looking at where those prospective intervals are, exist. We've mapped them out pretty extensively and then placed well locations in those spots to assess the potential. You're right. It only goes to the zones we've tested, we do feel like there's additional target intervals to test going forward.
Thank you.
We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.
Thank you. Good morning, everybody.
Good morning, Doug.
Bill, a tremendous update. I wonder if I could ask about the 22 wells that you get on in the Delaware this quarter. They're still the shorter laterals it would look like, but the well rates appear to still be, maybe I'm getting this wrong, but it looks like they're still substantially better than even your longer lateral implied type curve. Can you help me understand what the implications are of the run rate that you're having on those recent completions?
Doug, this is Billy Helms. We're very excited about the potential that we're seeing in these zones more recently. The longer laterals are giving us a lot more efficiency, a lot more reserves per well, higher production rates. Our EUR assessment for the play, though, is taking what we've tested across the play, and some of those tests are a little older. We're trying to incorporate all the tests we have, and all of the wells are not benefiting from the latest results. Our results continue to improve, and we assess that as time goes forward. I think the tremendous thing that we're seeing is just the benefits from our targeting and how that's really enhancing the productivity. That really comes from our detailed look and continual work on assessing the geological potential of the play.
That's why we're confident that as we continue to improve that technique and gain more understanding, that we're going to see additional intervals that will add to the resource over time. We fully expect that the resource and the play will continue to increase.
Billy, let me just get a point of clarification just to make sure you know what I'm asking. The new type curve on the Wolfcamp oil is $1.3 million. It looks like the wells you completed in the third quarter are even better than that. Am I getting that wrong? Or in other words, is there still upside to your assessment?
No, that's exactly right. The wells we completed in the third quarter are improving, and actually year-to-date, the results are still stronger than what our resource update is. Again, I think that's a testament to the technology and the things we're continuing to expand on and learn. I think there's additional upside potential there.
Doug, I may want to.
[audio distortion]
If I could add a little bit more color there, Doug. This is Bill Thomas. The rock quality drives the productivity of all these plays. We're getting better and better at identifying the better quality rock at each one of these plays. We're getting considerably better at locating the lateral with the precision targeting and keeping the lateral in that good rock for a long period, a long part of the lateral. That's a process we're learning. We probably learn more about rock quality and targeting and execution on that part of the process in the last year or so than we've ever learned. There's a lot of upside, as Billy said and talked about. We think there's a lot of upside left to go in that process.
My follow-up, Bill, hopefully is a little quicker. It's kind of a related question. If you can achieve 15%-25% at $50-$60 oil, if these wells continue to get better, would you choose to raise the growth rate again or do more with less? I'm thinking about constraints around infrastructure and things of that nature. I'll leave it there. Thank you.
Well, there is a limit on how fast we want to go, Doug, in each one of these plays, because you don't want to go faster than the learning curve, and certainly you do have to stay ahead of the infrastructure process. We don't want to lessen the capital efficiency. We'd like to continue to increase the capital efficiency as we go along. We're going to be very disciplined in our spending approach. The rates of return, just to say a bit about that, the rates of return that we're getting on the premium is that the minimum return, that means the lowest return well in the 6,000 well inventory generates a 30% rate of return at $40 oil and $2.50 flat gas prices. The returns on the average well is much, much higher than 30%. These are exceptionally strong wells.
Thanks for the clarification, Bill. Appreciate it.
We'll take our next question from Evan Calio with Morgan Stanley.
Hi. Good morning, guys, and impressive results again. Bill, my first question is, you guys have added 2 billion barrels of Permian resource and indicated that's likely to rise over time, and that's the best it's been in your 40 years. You're clearly not resource constrained. How do you think about potential asset sales given acreage prices and given it appears like lots of E&Ps are reaching a similar conclusion at a similar time? Is there first-mover advantage? What are your thoughts there?
Evan, as we continue to generate more potential and we continue to high-grade that, it does give us a lot more opportunities for just high-grading our asset portfolio through property sales. We're going to continue that process, evaluating each asset, seeing how it mixes and fits into the future of the company. The non-core assets are the ones that we don't think will reach the premium category. They'll certainly be candidates for asset sales in the future. That'll help keep our balance sheet strong. From a spending standpoint, we want to operate within cash flow. The property sale proceeds will continue to help us keep our balance sheet strong.
By increasing the quality of things we drill over time, obviously increasing the returns, but we're also lowering the finding cost, which will filter back down through the base reserves of the company and lower the DD&A rate. It's a process of just getting better in all areas through time.
Great. Maybe my second question, it's a follow-up to Doug's. You introduced the higher oil growth guidance here, 15%-25%. The entire industry, from small cap to Chevron, is projecting impressive and rising growth targets and largely in Texas at low prices. Where do you think the limitations of growth are for EOG or where they are, or levels? What will differentiate EOG in the execution? How are you preparing to deliver that and execute better than the industry? Thanks.
Well, I think the real advantage we have, Evan, is the rates of return that we're generating off each one of these wells is, we believe, is significantly higher than industry. That will filter down through the financials, and in due time, it will show up in ROCE. Our first goal, as I mentioned, is to be the U.S. leader in terms of ROCE. That's a position that we've historically held, and I think it's a big distinguishing factor in the company.
Is there any level as you think about maximum growth rate achievable just within the organization outside of [Rochin]?
Well, I don't want to speculate on that. We want to stay efficient, and we want to continue to get better. As I talked about before, we want to stay disciplined and under control. The goal is to get better, not just to get bigger. We're going to tackle that from that standpoint.
Great. Thanks, guys.
We'll take our next question from Charles Mead with Johnson Rice.
Good morning, Bill, to you and the rest of your team there. I'd like to ask a question about the resource estimate of the Yates transaction. I think you guys put some information on your slides, specifically slide nine. You have the resource per well for the Yates acquisition around 920, and that's higher than what you had incumbent in your portfolio. Can you talk about what factors that higher per well resource reflects? Maybe is that a piece of a bigger picture that, in general, the rock quality is higher as you move up into New Mexico, whether you have a deeper, higher pressure or the lateral length that is driving that?
Charles, this is Billy Helms. When we assessed most of the potential on the Yates acreage, it was generally on the basis of one-mile laterals. Since then, we've come back in and assessed the potential across all the plays. As you've noticed, the lateral length across the whole portfolio has increased to about 7,000 feet per well in the oil window and even greater than that in the combo window. I think a lot of the initial estimates you saw there on slide nine were based on our assessment when we made the transaction for Yates, and those were based on essentially one mile per well. That's the majority of the difference.
Thank you for that, Billy.
I might just add, as we move into this, the one thing that Yates does allow us to do is to block it up with our existing acreage. We fully expect to be able to drill these longer laterals across all the portfolio.
Got it. Thank you. Then Bill, if I could ask a question about the 15%-25% CAGR that you put out. You touched on this, I believe, on the last conference call about how that trajectory might shift or evolve over the 2017-2020 framework. Do you see that CAGR, whether we're talking about the $50 low end or the $60 high end, do you see that being back-end weighted or that growth accelerating through your timeframe, or is it more likely to be front-end weighted?
Charles, if you look at the slide, in the front part of the slide deck, it shows the curve. It shows that in 2017, the growth rate is smaller, and it grows over time. In 2017, it's less than 15% at $50. Then in 2020, it's probably more than 15% at $50. It's more back-end weighted.
Got it. That's the details I was looking for. Thank you, Bill.
You're welcome.
Our next question will come from Pearce Hammond with Simmons Piper Jaffray.
Good morning, thanks for the helpful color in the release on the Delaware Basin. My first question, Bill, is on rigs and what the rig count could look like based upon this long-term oil production growth plan. Where are you right now on rig count? I know you haven't given 2017 guidance, but looking at this long-term oil production growth plan, where do you see rigs traversing to? Any color you can provide on that would be helpful.
Pearce, this is Gary Thomas. Right now, we have 15 rigs operating domestic. We've got one international, that being in Trinidad. As you say, we haven't disclosed what we had planned for 2017. However, just with the rig efficiency that we've seen over these last two years and with the type of rigs we have in place, we will not be required to ramp up the number of rigs very much for most any plan that we've put in place. Just have a tremendous amount of flexibility. The one thing that we've had, 2016, most of our rigs were under long-term contracts, high rates. As we mentioned, yes, we'll have only about half that number for 2017. We've put in place rates that are about 40% lower for essentially the same number of rigs.
Great. Those 15 rigs, how are those broken out right now?
Right now, we've got five in Midland. That's really what we've averaged this year, and that is Delaware Basin. We have six now in San Antonio. We have four in Rocky Mountains because we have one rig that was required on the Yates position in the Powder River Basin, and we'll be letting it go. As we mentioned earlier
We're going to be picking up an additional rig for the Delaware Basin at year-end, and also for San Antonio for the Eagle Ford.
Great. Then my follow-up pertains to sand loadings. I'm just curious, in the Delaware Basin specifically, where are you on sand loadings right now? Have you reached a point of diminishing returns on sand loadings, or are we not there yet?
This is Gary Thomas. We're still experimenting there in the Delaware Basin. I might just take you back to the Eagle Ford, where we've operated for so many years. We've found a point of diminishing returns. As a matter of fact, here, our sand loading for 2016, on the average, is slightly less than what it was in 2015. We've got a pretty good handle as to what we anticipate as an optimum sand loading rate there for the Delaware Basin.
Can you share what that is on a pounds per foot basis?
I think, Pearce, this is Billy Helms adding that too. It'll vary on each area and by zone, too. We've tested as much as maybe 3,000 pounds per foot, which is probably not going to be applicable across all the plays in every area. It's probably going to average somewhere between 2,000 and 2,800, probably in that range, depending on the zone and where it is. It'll be a broad range depending on the play and where it is within the play.
Thank you very much.
Well, that's what we're in the process of trying to dial in, as Gary's mentioned.
Thank you, guys.
Thank you.
We'll take our next question from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Morning, Brian.
First couple of questions on the Eagle Ford. Can you add some more color on the stacked staggered spacing tests, put 200-foot spacing into context in terms of how widespread that may be applicable, and the total locations per unit that would represent? How do you view the well economics and EURs, given that you've been applying some enhanced targeting and completions for more than a year?
Yeah, Brian, this is David Trice. On the stacked staggered targeting and the spacing, we've been working on that for well over a year, and we're seeing good results on that as we noted there on the Quartz wells. I mean, we're not seeing any degradation in the areas that we're doing that. It's not applicable over the entire position. Some places we do have two good targets in the lower Eagle Ford. We're certainly doing that there. I think over time, we'll continue to see that improve as we dial the targets in a little bit better and we work on the completions. Again, it's not applicable over the whole area because some areas have really just one target. Really, throughout the play, we're looking at anywhere from 200-foot spacing, to 300 or 350, depending on the area.
Got it. Thanks. Shifting over to the Powder River Basin, which it seems like you're employing a similar strategy here as with post-Yates as you are in the Permian, can you talk to the potential cost savings per BOE from deploying longer laterals in the PRB? Post-Yates, what type of activity do you think we could see, and how prospective do you view opportunities beyond the Turner Sand?
This is David again. In the Powder River, we're still really in early innings there. We've been testing various zones, and we've been focused mainly on the Turner lately. We do see a lot of upside as far as extending these laterals. Like we mentioned earlier, that we're seeing a big uplift on the economics in the Powder River as we do in other plays. We do think, going forward, it's going to be a bigger part of the program.
Got it. Thanks. Is this an area that you mentioned exploratory, the potential for further exploration, this may not count as exploration since you already have some premium locations built, how does the Powder fall in terms of incremental opportunities for EOG beyond the big three?
Well, again, I think it's an area where we have stacked pay. We've got 4,000-5,000 feet. The potential here is similar to the Delaware Basin. Like I mentioned, we are early. We are still testing a lot of targets, we do have a substantial acreage position there. We've got 200,000 net acres really in the core of the play. Really across the basin, we've got more of an exploration area. We've got more like 400,000 acres. Again, I do think there's potential for additional activity here in the Powder.
Thank you.
We'll take our next question from Ryan Todd with Deutsche Bank.
Great. Thanks. Good morning. Maybe a longer-term strategic question for you guys. How do you think about the potential to generate free cash flow? Prior to the collapse in crude, we had seen you reach a point where
Cash return to shareholders became a slightly more meaningful component of shareholder return, as reflected by some pretty substantial increases to the dividend. When you look out over the next few years, do you envision dividend growth becoming more meaningful again, or has the outlook for growth changed enough that we should expect all incremental cash flow to go into drilling for the foreseeable future?
Ryan, the dividend certainly is very important to us, as the business environment improves, as prices improve, we'll start considering increasing the dividend again. Certainly generating free cash flow is a goal that we want to begin to do. We generated just a slight amount in the third quarter. That's a goal that we want to continue to focus on as we go forward. Free cash flow and dividend growth will be a part of the game plan as the business environment improves.
Okay, thanks. Maybe, one, just as we think about infrastructure, I know you've talked about a little bit. Any constraints in the permitting from an infrastructure side and in terms of a rough outlook for what we should expect you to spend on infrastructure spend? Is 15% of the capital budget a reasonable amount or anything to ballpark what your needs are going to be as you ramp over the next three or four years?
Ryan, this is Gary Thomas. Just to address the infrastructure spending for next year, it'll be very similar to what we've had the last several years. We want to stay up or a little bit ahead, and it'll be in that 18%-20% of our capital. We'll let Lance address our positioned infrastructure there for Delaware.
Thanks, Gary. Hey, Ryan, good morning.
Morning.
The team has done a great job on gas takeaway. When you think about the extensive gas gathering system that we put into service, we're going to have multiple market connections in the area. We plan on exiting this year with over 300 million a day of firm plant capacity. When we think about that coupled with our NGL transportation or fractionation capacity too, we really don't see any constraints from the gas standpoint at all.
Great. Thanks.
Also maybe just to add on oil too, we're actually finalizing agreements for a new oil terminal that's going to be hopefully coming in service in late 2017. With that, we'll have all the market diversification, whether that's to the Gulf Coast, to Cushing, and also just continuing to align ourselves with our strategic refining partners. We couldn't be more excited about the developments and the things that's going to occur.
Great. Thanks. That's helpful.
That does conclude our Q&A session. I would now like to turn the call back over to Mr. Thomas for any additional or closing remarks.
In closing, I want to say thank you to all the tremendous EOG employees for making the record-setting accomplishments we've done this year a reality. To everyone listening, do not think EOG is maxed out on room to improve. We see miles of improvement opportunities ahead of us, and we look forward to 2017 and beyond. Thank you for listening, and thank you for your support.
This does conclude today's conference call. Thank you all for your participation. You may now disconnect.