EOG Resources Inc (EOG) — Q3 2016 Earnings Call Transcript

Thank you. Good morning and thanks for joining us. We hope everyone has seen the press release announcing the third quarter 2016 earnings and operational results. This conference call includes forward-looking statements. The risks associated with the forward-looking statements have been outlined in the press release and EOG's SEC filings, and they incorporate those by reference to 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 crude 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 the quarter and not contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. In addition for the purpose of this call, the reserve estimates for basin and low level resources are net after resources unless otherwise stated. In reference to well location, wells drilled and wells completed are after 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, and 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 premium Delaware Basin resource and David Trice will discuss notable achievements in the other select plays. Gary Thomas will go over our operational accomplishments and I will discuss EOG's financials and capital structure. And Bill will provide concluding remarks. Here's Bill Thomas.

Thanks, Tim, and good morning, everyone. EOG has responded to the downturn in oil prices with an unrelenting focus on capital turns. In 2016 we increased well productivity and lowered well and operating costs at a record pace. The company projects an all-in return on the capital program on the company record and we achieved this in the lowest commodity price environment that we have experienced in a long time. Our tremendous success in proving capital return this year, combined with the addition of the Yates acreage, has also increased the company's resource potential in both size and quality at a record pace. As a result, we reset the company to deliver high return oil growth within a cash flow well with 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 growth with a balanced CapEx to cash flow program sets the industry apart, making us a leader in capital efficiency. In early 2016, the team working on each play across identified 3,200 locations representing 2 billion barrels of oil reserve potential. That meant a new rate of return standard we designated as premium. To meet the premium standards, a well has to earn a minimum of 30% direct after-tax rates of return at $40 oil. The process of first refining premium and second identifying the inventory will ensure that during 2016, we did not spend a single dollar on un-economic wells. What we anticipated about the new premiums standard is the fire it would light under each team working on EOG's plays across the company. Since the start of 2016, we have 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 in 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 that math on those numbers, you see that net reserves for oil for our premium inventory went from 625 MBOE to 860 MBOE to date. We are not only adding more premium inventory, but the productivity of that inventory is also growing. Another important factor in improving capital efficiency is a 29% reduction in cash operating unit costs and over $1 billion annual operating savings compared to 2014. For the third quarter in a row, we have lowered our operating expense forecast for the year. In the last number of years, EOG has consistently added locations faster than we have grabbed 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 wanted to discuss the other big news from the press release last night: our updated 2020 outlook. We introduced our 2017 through 2020 outlook last quarter at a 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 grow it. With continued capital efficiency gains, we are increasing our 2017 through 2020 PAGR outlook by 5%. At $50 to $60, we are now capable of growing at a compounded rate of 15% annually. Given the size of our base production today, that growth is remarkable. Also remarkable is the link in the river that growth and in the dividend with the 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 organizational 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 exploits 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 leaders in capturing high-quality acreage in the best oil plays in the U.S. The Yates transaction is just the latest example of EOG's ability to add highly turned 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. It's highlighted in a couple of ways. First, our Permian team's progress in 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 reductions, and the Yates transaction, we increased the Delaware Basin's resource 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 oil productivity through technology, such as our precision targeting process and improved completion techniques. Two is through lowering costs, both capital costs as well as operating expenses. Similar to 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 compliments EOG's existing acreage position. The added acreage inventory will allow us to trade blocked-up acreage to provide options for longer laterals and more efficient use of infrastructure. Blocked-up acreage will over time continue to drive down operating costs and convert the existing inventories to premium status. Most of the acreage 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 elementary increase amounts to about 530 net locations but more impressively, the average lateral length increased by 60% over 7,000 feet. We are steadily increasing the length of our laterals but more importantly, maintaining our focus on targeting and completion to not diminish the productivity preferred of the 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 sub; the resource estimate uses confirmed test results from the different tested intervals in both the oil window and the combo play, which can generally be summarized as including one productive interval across our acreage with well spacing averaging 660 feet between oil windows 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 has an average 30-day production of over 30,000 BOEs per day with 2,100 barrels of oil per day per well. Both were drilled using shorter laterals averaging 4,500 feet. The four-well pattern had an average 30-day production of 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 Springs, we upgraded our resource potential estimate from 500 million barrels of oil equivalent to 1.4 billion barrels, another massive increase—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 material of our Delaware Basin plays, we have had minimal activity in 2016. Based on longer-term production components 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 do expect to convert the majority of the 6,300 locations to premium, and we anticipate discovering new sources of premium drilling as we test additional areas and find new target intervals within this geologically complex basin. We are still in the early innings of the Delaware Basin, and we are excited about the future. EOG's Delaware Basin potential is rapidly improving in both size and productivity and adds to EOG's portfolio of US unconditional assets and unique growth story. Here's David Trice.

Thanks, Billy. In Eagle Ford, we continue to make tremendous progress in costs. In the third quarter, we drilled and completed 47 wells at a remarkable $4.6 million per well. Well costs are being driven lower for all the reasons we mentioned in our last call. More efficient rates of operations are driving drilling days down to less than 6 days a well. Completions are also getting more efficient. In 2014, we were at 600 feet of lateral per day. During this downturn, we have 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 completion. 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 interim wells down spaced to 200 feet that were some of our best-performing wells for the quarter. Core unit 10H through 14H averaged over 2,000 barrels of oil per day per well for the first 30 days of production. We have been drilling in the Eagle Ford for seven years, and we still have so much to learn in this world-class play. Also in the Eagle Ford, our enhanced oil recovery (EOR) is progressing on schedule. We completed on schedule the initial phase of the 32-well pilot, our largest to date. We look forward to having results with you sometime in 2017. In the Rockies, we continue to get excellent results from the firm sand in the bottom of the basin. Our drilling program there is delivering consistent premium level returns, and we are looking forward to expanding activity there next year. The 9 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 6 days and have a total well cost of just $4.9 million normalized to a 6,500-foot lateral. In addition, the decline rates were relatively low, on average the wells produced 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 toward two-mile wells, particularly now that the Yates transaction blocked as much of our existing acreage in the sweet part of the play. Longer laterals will provide economics similar to what we have realized in other plays and are 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 used advanced techniques to identify and steer our wells in the narrow 15-foot window. We were able to accomplish this even while we continue to push the envelope on drilling speed. 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 increase 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 forecast for 2016, while only increasing our development capital by $200 million. As a result, our fourth quarter domestic oil production before the addition of the Yates is forecast to be 36,000 barrels of oil per day above our forecast at the start of the year. That's an amazing accomplishment and is a testament to the tremendous capital efficiency gains we have made this year. When we add Yates in international volume we expect EOG's all exit rates 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. In 2014, EOG's drilling days and total well costs in our large Bakken are down 25% to 45%. Another measure of drilling efficiency is the number of wells drilled per rig per year, which increased 40% in our top three plays. For example, we are drilling 32 wells per rig per year. On the operating side, we reduced cash costs by 29% and 2016 LOE alone has come down almost $0.5 billion compared to 2014. While the major driver of cost reduction has been efficiency gains, we are also benefiting from approximately half of our high-cost drilling and completion contracts being replaced by 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 costs increases and how they will impact the industry. For EOG, due to our integrated operations, current arrangements, and continued efficiency gains, we are well insulated. At a minimum, we expect at least the well cost to flatten in 2017. Our teams continue to make significant efficiency gains. EOG's rate of return culture and large-scale sweet spot positions in the best North American reserve plays mean it still takes continual improvement across all categories. Now for a word on ducks. Our cost leading and additional $200 million of capital will allow EOG to complete almost all of the debts 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 near record rates and will give EOG 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 to preserve a balance 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 40 years with the company. Our 2020 outlook is a testament to that. We have accomplished this through our premier shift to premium drilling and a widespread focus on cost control. For me, whether extensive inventory or premium locations, however, I am most proud of the highly integrated efforts of our teams to deliver sustainable cost reduction. They have done an outstanding job. We're committed to maintain this focus, and we are uniquely positioned for the future. Here's Tim Driggers.

Thanks, Gary. Capitalized interest for 2016 was $8 million. Exploration and development expenditures were $660 million excluding property acquisitions, which was 32% less compared to the third quarter of 2015, while our 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 from $2.6 million to $2.8 million. 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 leaving us with non-GAAP net debt of $5.9 billion or 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 a 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%. Now I will turn it back over to Bill.

Thanks, Tim. Our micro 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 at $50 oil, we believe that the U.S. industry as a whole needs to sustain $60 oil prices and an extended lead time to provide a moderate level of growth. Worldwide, base decline rates are slowly reducing supply and consensus view is the current large inventory overhang could return to normal levels by late 2017. We plan to issue official guidance in 2017 along with our year-end results early next year. Our overarching goal in 2017 is to build momentum on the foundation of premium inventory EOG has established in 2016. As Gary explained, we are completing 180 more wells than previously forecasted, so we are exiting 2016 with strong oil production and we will complete a higher percentage of premium wells in 2017 compared to 2016. After two years of this down cycle, we are more than ready to resume high-return oil growth. EOG's vision for 2017 to 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. And as we enter our recovery, our unique and resilient culture has positioned the company to achieve strong results for years to come. Thank you for listening. Now we will go to Q&A.

Good morning.

Good morning.

Impressive job this quarter and congratulations on the increased outlook. If you step back and look at the big opportunity we all have with the premium that you described. Can you give us a sense of generally how you are looking at developing that in terms of what formations may be high on the top of the list over the next couple of years? And how do you see pad development going forward in that play?

Yes, Scott, this is Lloyd W. Helms. So on the Delaware we do expect with this increase our activity over time will continue to increase—especially going into next year. Our activity today has been focused largely on the Wolfcamp; I think that will stay, as 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 at the Wolfcamp and so, for that reason, we will continue that as it's an excellent volume growth generator and an extremely high rate return play. And what really is first, it also allows us to take a look at these shallower objectives as we drill through those, which 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 about pad drilling, we are continuing to develop pads that are 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. So the incremental return for those programs in the future will continue to increase as we share that infrastructure—that’s no doubt for the initial completions.

Great, that's good. And then in my follow-up. This quarter you guys are now producing more oil than—it's over 50% which was a pretty good heavy lifting over the last few years to get there. 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 premium producing today and in your long-range outlook, where do those plays go?

Scott, we never broke it out but—and so I think really what I think about the company is that we have a very strong diversified portfolio. From year to year, or maybe even quarter to quarter, we shift our capital to where we are seeing the highest rate of returns. And I think that changes over time. As Billy said, obviously the Delaware is giving that bigger and better for us, so it will get more capital next year than it got this year. And EOG will still get a lot of capital; a lot of capital in the Rockies play, particularly the Powder River Basin will get a lot of capital. But I think you need to be thinking of a very balanced, very large, and very diversified portfolio.

Hi, good morning. First question is, when I think about the number of locations in the Wolfcamp, is it two zones that you're thinking about in each of the oil and combo plays? What's the status of the lower Wolfcamp if you had any results there?

Yes, Subash, this is Billy Helms again. So when we think about the Wolfcamp, we generally think about two zones, the upper and middle, which is what we assess resource potential to. But within each one, there are multiple target intervals. You can think about it as having multiple targets with each play, and we assess the potential mainly in areas where we tested each one, and we've based that on our confirmed tests, comparing results for each one. That's how we've rolled up the resource potential there. As for the second part of your question regarding the lower Wolfcamp, we have had some tests; I'd say the majority of our tests so far have been in the upper part of the zone, but we have had some encouraging results from the testing in the lower Wolfcamp.

Okay. If I hear you correctly, it's a very highly risked measure of your locations that you published to date, but if I just did a resource map across multiple levels, I could get many more locations than what you published.

Yes, I think the way you think about that is; our results are based on our confirmed tests in each of the intervals, and then we allocate that to sticks on the map kind of the approach. It's not just taking the total number break-evens and dividing it by well spaces; it's actually geologically looking at where those perspective intervals exist. We've mapped them out pretty extensively and then placed well locations on the spot to assess the potential. But you're correct; it only goes to the zones we tested, and we do collect additional intervals to test going forward.

Thank you.

Thank you, good morning everybody. But I wonder if I could ask you about the 22 well on Delaware this quarter. There are still shorter wells, but with well rates appearing to still be—maybe I'm getting this wrong, but they are still substantially better than you can go longer lateral implied type. Can you help me understand what the implications are, the run rate that’s been on those recent locations?

Yes, this is Billy Helms. We are excited about the potential that we're seeing in these zones more recently. The longer laterals are giving us a lot more efficiency and a lot more reserves per well, higher production rates. Our EUR assessments for the play, though, are taking what we've tested across the play. Some of those tests are a little older, so we're trying to correlate all the tests we have. All of the wells are not benefiting from the latest results, and our results continue to improve. We assess that as time goes forward, and I think the tremendous thing we are seeing is just the benefits from our targeting and how that's really enhancing the productivity. That comes from our detailed working and continual work on assessing that geological potential in the play. That's why we're confident that as we continue to improve that technique and gain more understanding, we will see additional intervals that will add to the resource over time. So, we fully expect the resource in the play will continue to increase.

Thanks, Billy. The Wolfcamp oil at 1.3 million. It was quite a while you completed in the third quarter.

No, that's exactly what I think. The wells that were completed in the third quarter are included, and actually year-to-date the results are still stronger than what our resource update is. I think it's a testament to technology and the things we're continuing to expand on and learn. Yes, I think there is additional upside potential there.

Yes, if I could add a little more color there. This is Bill Thomas. The quality drives the productivity across all the plays, and we're getting better and better at identifying the better quality rock in each of these plays. They are giving considerably better at locating the lateral with a precision targeting and keeping the lateral in that good rock for longer periods along that lateral. There is a learning process. We probably have learned more about rock quality and targeting and execution on that part of the process in the last year than we have ever wanted. So, there’s a lot of upside as Billy said, and there is a lot of upside left to go in that process.

My follow-up is a quicker; it is kind of a related question. If you can achieve 15% to 25% at $50 to $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 on the infrastructure of things about nature.

Well, there is a limit on how fast we want to go in each of these plays because you don't want to go faster than the learning curve. You do have to stay ahead of the infrastructure process. We don't want to use less than the capital efficiency; we like to continue to increase the capital efficiency as we go along. But we're going to be very disciplined in our spending approach. The rates-of-return just to say a bit about that, the rate-of-return that we're getting on the premium is that minimum return, that means the lowest return well, in the 6,000 well inventory generates a 30% rate of return at $40 in 2015 flat gas prices. So the returns on the average well is much, much higher than 30%, and these are exceptionally strong wells.

Good morning guys, and impressive results again. Bill, my first question is you got about $2 billion resources and indicated that's likely to rise over time. That is the best it has been in 40 years. So you're clearly not resource constrained, so how do you think about potential asset sales given acreage prices and given it appears like lots of BMPs are reaching a similar conclusion at a similar time? It's first mover advantage; what are your thoughts there?

Evan, as we continue to generate more potential, we continue to high grade that, which gives us a lot more opportunity for just high grading our asset portfolio for good property sales. So we're going to continue that process, evaluating each asset and how it fits into the future of the company. And on core assets, that are the ones that don't reach the premium category, they'll certainly be candidates for our asset sales in the future. That will help keep our balance sheet strong, and we want to operate from our spending standpoint. We want to operate within cash flow, but the property sale proceeds will continue to help us keep our balance sheet strong. By increasing the quality of things we drill over time, we obviously increase the returns, but we are also lowering the cost which will filter back down through the base. We'll hire a company and lower the drilling rate. So, it's a process of just getting better in all areas through time.

Great. My second question is a follow-up to Doug's point. You mentioned the high or low growth guidance of 15% to 25%. The entire industry, from small-cap companies to Chevron, is projecting impressive growth targets, largely driven by low prices in Texas. What do you believe are the limitations of growth for EOG, and how do you differentiate EOG's execution? How are you preparing to outperform the industry? Thanks.

Well, I think the real advantage we have, Evan, is the rates of return that we're generating out of each one of these wells is we believe significantly higher than the industry, and so that will filter down through the financials. And in due time, it will show up in ROCE. So our first goal, as I mentioned, is to meet the U.S. leader in terms of return on capital employed. That's a position we have historically held and I think it's a big distinguishing factor in the company.

And in your rating level, if you think about it max growth rate achievable within the organization outside of your sheet?

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 there, we want to stay disciplined and under control. The goal is to get better, not just to get there. We're going to try to tackle it from that standpoint.

Great, thanks guys.

Good morning, Bill, to you and the rest of your team there. I'd like to ask a question about the estimate resources assessments on the Yates transaction. I think you get pertinent information on your slides, specifically Slide 9. You have the resource per well for the Yates acquisition around 9-20 of next year, higher than what you had for the incumbent in your portfolio. Can you talk about what factors that product that higher per well resource reflects? Is that a piece of a bigger picture that, in general, the rock qualities are higher as you move up into the Mexico, whether you get deeper, higher pressure, perhaps longer lateral life that is driving that?

Yes, Charles, this is Billy Helms. So when we assess most of the Yates on average, it was generally on the basis of one-mile laterals. We sense that we come back in and assess the potential across all the plays. As you've noticed, lateral lengths on most of the plays across the portfolio have increased to about 7,000 feet per well in the oil window and even greater in the combo window. I think the initial estimate you saw in Slide 9 were based on our assessment at the time of the transaction and were based on essentially one-mile wells. That's the majority of the difference.

As we move into this, the one thing that the Yates does allow us to do is to block it out with our existing acres. We fully expect to be able to drill these longer laterals across the entire portfolio.

Got it, thank you. And then, Bill, I thought I could ask a question about the 15%, 25% 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 to 2020 framework. Do you see that—whether we're talking about that $50 low end or the $60 high end—do you see that being back end weighted or do you expect growth to accelerate to that two-year time frame, or is it more likely front-end weighted?

Charles, as you look at the slides, the growth rate in 2017 is smaller, and it grows over time. So in 2017, it's less than 15% at $50, and into 2020 it's probably more than 15% at $50. It's a more back-end weighted outlook.

Good morning, and thanks for the helpful color in the release on the Delaware base. My first question, Bill, is on our rigs and what the rig count could look like based upon this long-term production oil production growth plan. Kind of where are you right now on rig count? I know you haven't given seventeen guidance, but looking at this long-term oil production growth plan, where do you see rigs reverting to? Any color you can provide on that would be helpful.

This is Gary Thomas. Right now, we have 15 rigs operating domestically; we have one international that is being traded. As you say, we have disclosed what we had planned for 2017. However, just with the rig efficiencies that we've seen over the last two years and the types of rigs we have in place, we will not be required to ramp up the number of rigs very much for both the standing plan that we put in place. We have tremendous flexibility. The one thing we've had in 2016 is most of our rigs were under long-term contracts at high rates. As we mentioned, with Yates, we will have only about half that number for 2017. We have put in place that about 40% lower for especially the same number of rigs.

Great. Within 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 in the Delaware Basin. We have six now in San Antonio. So we have four in the Rockies because we have one rig that was required on the Yates position in the Powder River Basin. We will let it go, but as we've mentioned earlier, we're going to be picking up an additional rig for the Delaware Basin year-end, and also for San Antonio for Eagle Ford.

Great. As of my follow-up, pertains to sand loading. 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 loading or are we not there yet?

This is Gary Thomas. We're still experimenting in the Delaware Basin; I might just take you back to the Eagle Ford, where we have operated for so many years. We found the point of diminishing returns. As a matter of fact, our sand loading for 2016 on average is slightly less than what it was in 2015. So we got a pretty good handle on what we anticipate as an optimum sand loading rate there for the Delaware Basin.

Just to add a little more color on that, it will vary in each area, and 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 an average somewhere between 2,000 to 2,800, probably in that range, depending on that play and where it is. But it will be a broad range depending on that play and where it is in that play.

Thank you very much.

Well, that's what we're in the process of trying as Gary mentioned.

Thank you, good morning.

Good morning, Brian.

First couple of questions on the Eagle Ford. Can you add more color on the stacked staggered spacing test? Put 200 foot spacing into context in terms of how widespread that may be applicable, and then the total locations per unit that would represent. How do you view well economics as you apply some enhanced targeting and completion over more than a year?

Brian, this is David Trice. On the stack stagger 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 during the quarter, 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 are certainly doing that there, but I think over time, we will continue to just see that improve, the targets get a little better, and we work on the compilations. But again, it's not applicable to all areas because some areas have only one target, so really throughout the play we're looking at anywhere from a 200-foot spacing or 350, depending on the area.

Got it, thanks. And then shifting over to the Powder River Basin, which it seems like you're employing a similar strategy here as with that—you're in the premium. Can you talk to the potential cost savings for BOE from deploying longer laterals in the Powder River Basin? What type of activity do you think we can 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 the early innings there. We've been testing various zones; we've been focused mainly on the Turner lately, but we do see a lot of upside as far as extending these laterals. Like we mentioned earlier, we're seeing a big uplift on the economics and about our rivers as we do in other places. Going forward, we do think that it'll be a bigger part of the program.

Got it, thanks. And just an area that you mentioned exploratory—the potential for further exploration, this may not count as exploration because you already have some premium locations built, but how does the Powder fall in, in terms of incremental opportunities for EOG on the trajectory?

Well again, I think the area where we have stacked by nearly 4,000 to 5,000 feet of potential there is similar to the Delaware Basin. But like I mentioned, we are early; we are still testing a lot of targets. We do have a substantial acreage position there; we got 200,000 net acres really in the core of the play, but really across the basin we have got kind of more than exploration—we've got more like 4,000 acres. So again, not that big thing; there is potential for progression and additional activity here in the Powder.

Thank you.

Thanks, and good morning. A longer-term strategic question for you guys; how do you think about the potential to generate free cash flow prior to the collapsing crude? We've seen you reach a point where cash return for 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 visualize dividend growth becoming more meaningful again, or is the outlook for growth sufficient enough that we should expect all incremental cash flow going to drilling for the foreseeable future?

Ryan, the dividend is certainly very important to us. As the business environment improves, and prices improve, we'll start considering increasing the dividend again and certainly generating free cash flow as we go. I think we want to begin to do that; we generate just a slight amount in the fourth quarter. So that's a goal that we want to continue to focus on as we go forward. Free cash flow and dividend growth will be part of our game plan as the business environment improves.

Okay, thank you. Then maybe one just as we think about the infrastructure. I know you talked about it a little bit: any constraints on the permanent infrastructure side in terms of—you mentioned what we should expect to spend, like is 15% of the capital budget a reasonable amount or anything in the ballpark of 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 will be very similar to what we've had the last several years. We want to stay a little bit ahead, and they'll be in that 18% to 20% of our capital budget to address our position on infrastructure there.

Yes, Hi Ryan, good morning. The thing is we have done a great job on gas takeaway, and when you think about the expenses of gas gathering, we're going to have multiple market connections in the area, so we plan on exiting this year with over $300 million today of strong position, so when we think about that coupled with our NGL transportation and vaccination capacity, we really don't see any constraints on the gas at all. Also to add on oil too, we're actually finalizing agreements with renewable terminal that's going to be all service late in 2017. The work that will have market diversification whether that's the Gulf Coast or also just continuing to align ourselves with our strategic providing partner. We wouldn't be more excited about the development to say nothing have occurred.

In closing, I want to say thank you to all the tremendous EOG employees who are making the record-setting accomplishments we went down this year a reality. Everyone listening, do not think EOG is maxed out; we are willing to improve, and we've seen modeled on the trade opportunities ahead of us, and we look forward to 2017 and beyond. So thank you for listening and thank you for your support.