EOG Resources Inc (EOG) — Q3 2019 Earnings Call Transcript

Good morning and thanks for joining us. We hope everyone has seen the press release announcing third quarter 2019 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release in EOG's SEC filings and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. Definitions as well as 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 and in the accompanying investor presentation slides may include estimated resource potential and other estimates of potential reserves, not necessarily calculated in accordance with the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings release issued yesterday. Participating on the call this morning are: Bill Thomas, Chairman and CEO; Billy Helms, Chief Operating Officer; Ken Boedeker, EVP Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; David Streit, VP Investor and Public Relations. Here's Bill Thomas.

Thanks Tim and good morning everyone. EOG has a deeply rooted competitive advantage and that is our culture. Our culture drives innovation and a long history of continuous improvement and success. Most importantly, our culture drives resiliency. In an ever-changing business environment, we have demonstrated this resiliency time and time again during the past 20 years, as we will continue to do so moving forward. In the 1990s when vertical prospects were in short supply, our culture fostered innovations that made EOG our first-mover in horizontal shale gas technology. As natural gas prices came under pressure in the late 2000s, we introduced horizontal shale oil with the Eagle Ford discovery. As a result of our first-mover advantage, EOG is now the largest onshore oil producer in the Lower 48 states and among the lowest cost producers in the world. In the wake of a pronounced commodity price down cycle beginning in late 2014, the company has remained a leader in low-cost, high-return oil growth by switching to a premium drilling strategy. Our premium strategy uses a strict investment hurdle that produces strong economic returns using a flat $40 and $2.50 natural gas price scenario ensuring that the company will generate strong financial performance even in commodity down cycles. After our third consecutive quarter of exceptional results, we believe that EOG's 2019 operational performance will be the best in the company's history. To reflect our year-to-date performance, we have raised our U.S. oil growth target from 14% to 15% along with lowering our well cost and per unit operating cost targets. Strong well results have compounded the benefit of cost reductions to further improve capital efficiency, allowing EOG to deliver strong above-target production growth with lower-than-expected capital investment. With confident strong returns in growth in the third quarter, the company delivered over $330 million of free cash flow after paying the dividend. EOG continues to deliver returns, growth and free cash flow competitive with the best companies in the S&P 500. In addition to outstanding operating results, we continue to organically grow our premium well inventory in both size and quality. This quarter we added 1,700 premium net wells which represents a replacement rate of more than two times our 2019 drilling program and brings our total premium drilling inventory to 10,500 net wells. That is more than 14 years of drilling at our current pace. EOG's diverse assets and exploration-led business model position the company to navigate political and regulatory changes. The company maintains tremendous flexibility to adjust operations and activity across six different basins and has identified over 5,400 premium well locations representing more than seven years of premium drilling on non-federal acreage. In the Permian, one of our most active drilling areas approximately 90% of our federal acreage position is held by legacy production and we have 11 years of premium inventory on non-federal leases. The 3.2 million net acres of non-federal leases in the U.S. which is approximately 75% of the company's total acreage, we are confident that we will continue to organically grow our premium inventory in size and quality much faster than we can drill. EOG has approached reducing environmental footprint in the same manner that it continues to improve operational performance. The company looks to innovate through returns-focused initiatives aimed at reducing greenhouse gas emissions and expanding water reuse throughout our operations. Last quarter we introduced our pilot project for a combined solar and natural gas-powered compression station in the Delaware Basin. This is just one of the many projects that our team is working on that we believe will contribute to reducing greenhouse gas emissions and generate positive economic returns. EOG and its employees are committed to environmental stewardship. We believe we are a leader in our initiatives to address environmental stewardship and we are focused on finding new opportunities to continue to improve going forward. Finally, as we close in on the end of the year, our focus begins to turn to 2020. While it's too early to discuss specifics of our plan next year, we can say the following: number one, our priorities have not changed. We firmly believe that investing in high-return production growth, generating substantial free cash flow and delivering strong dividend growth delivers the highest long-term business value. Number two, our plan is based on a conservative outlook for commodity prices. At $55 WTI, we can deliver mid-teens production growth, grow our dividend and generate significant free cash flow. Number three, we believe well costs and per unit operational costs will continue to decline. Number four, we believe capital efficiency and F&D costs will continue to improve. Number five, we have high confidence in the ability of our organic exploration efforts to add and improve our premium drilling inventory faster than we are drilling. And number six, we have no plans for large, expensive M&A. Any potential bolt-on acquisition must compete with our premium drilling returns. As we look to the future, we know that the business environment will continue to change. But our competitive advantage is rooted in our culture, ensuring that we can meet these challenges head-on. EOG is a resilient company that will continue to differentiate itself as a leader among any company in any sector of the S&P 500 by creating significant long-term value for our shareholders. Next up is Billy to review our third quarter operational performance and outlook for the remainder of 2019.

Thanks Bill. For the third quarter in a row we exceeded expectations delivering more oil for less capital than we forecasted at the start of the quarter. Oil production beat the high end of our target range at over 464,000 barrels per day and we spent less capital than expected coming in right at the low end of the target range of $1.5 billion. Well performance continues to drive production to the high end of our estimates. As discussed during the second quarter call the primary reasons for the improved well performance are enhanced completion designs along with the use of diverters and a heightened focus on target selection. Capital expenditures continue to trend to the low end of expectations as our operating teams identified new techniques to lower well costs to improve capital efficiency. As of the third quarter, I can report that we have achieved our year-end goal of reducing well costs by 5%. We believe the cost reduction to be sustainable as it is driven by continued efficiency improvements not service cost reductions. For example, if you look at our two most active plays; the Delaware Basin and the Eagle Ford, the average time to drill a well has collectively been reduced by 20%. As our drilling teams maintain their steady push to reduce drilling times, we require fewer rigs to execute our program compared to last year. Specifically, we now plan to only average 36 rigs this year as compared to 40 rigs back in February. This is a tremendous testament to the efficiencies of EOG's drilling teams. They were able to realize faster drilling times with innovative advancements such as in-house designed drilling motors engineered to improve performance and reduce failures. We still plan to complete about 740 wells this year and expect quarter-over-quarter production growth entering 2020. As Bill stated earlier, if oil prices are in the mid-50s, we expect growth in 2020 to be similar to 2019. Capital expenditures and capital savings from efficiencies realized throughout the year are being allocated to one of two areas: leasing acreage and new exploration plays and high-return infrastructure projects that are lowering lease operating expense. Across the board, 2019 is shaping up to be the best year we've had operationally and is particularly notable across our company-wide per unit operating expenses. At the start of 2019, lease operating expense on a unit basis was initially forecasted to be flat year-over-year. However, we now expect full year 2019 LOE to be 4% lower than 2018. At the midpoint of our 2019 DD&A guidance range of $12.65, we were on track to deliver the lowest rate since EOG's transition from a natural gas company to oil. Our permanent switch to premium drilling continues to transform the company, driving down finding and development costs, reducing D&A and enabling EOG to deliver double-digit returns throughout commodity price cycles. Also of note during the third quarter, we entered into long-term gas supply arrangements with Cheniere Energy. Consistent with our strategy of having flexibility and diversity in marketing our products, these arrangements provide additional markets for off-take and pricing diversity for up to 440 million BTU per day starting in 2020 with the ultimate goal of maximizing the realized price for our growing production of low-cost natural gas. Now I would like to provide some color on the Bakken and other Rockies plays. In the Bakken this quarter we completed 15 wells with an average IP-30 of 2,150 barrels of oil per day, 300 barrels of NGLs and 2 million cubic feet a day of natural gas. Our strong well results reflect the impact of EOG precision targeting and our new completion techniques. The highlight for the quarter was the Clarks Creek 18 well that was completed in the Three Forks with an IP-30 of 3,800 barrels of oil per day. This well is our best well to date in the Bakken, which along with strong performance from other wells completed this quarter are a testament to the continued improvements we see across our entire inventory. In the Powder River Basin, we completed a total of eight wells including four wells in the Parkman, three wells in the Turner and one well in the Niobrara. It is worth noting that our premium inventory in the Powder River Basin now includes the Parkman which we have combined with the Turner play. The Niobrara completion, the Arbalest 473 had an IP-30 of 1,250 barrels of oil per day with 250 barrels of NGLs and 4 million cubic feet a day of natural gas. We continue to be encouraged by the results of our program in the Powder River and look forward to its growth in the near future. Next up is Ken to discuss the Eagle Ford.

Thanks, Billy. Year-after-year, quarter-after-quarter EOG's Eagle Ford asset delivers strong consistent results and the third quarter of 2019 was no different. The Eagle Ford delivered high-return oil volume growth with a continued decline in well costs. We have exceeded our full year cost reduction goal of 5% in the third quarter by continued improvement in operational efficiencies. Specifically, our drilling time has been reduced by 10% to 20% depending on the lateral length in the third quarter of 2019 compared to 2018. We also drilled our fastest well to date in Eagle Ford, the Meadowlark B2H, which was drilled to a measured depth of 17,288 feet with a 7,500-foot lateral section in a remarkable 2.4 days. Even after nearly a decade of development our premium well inventory in the Eagle Ford remains strong at 1,900 net locations representing over six years of drilling at current activity levels. We continue to have high confidence in our ability to grow our premium inventory in this play. Our best well to date has a cost that is 20% below our average 2019 well cost. This difference in cost between our best well and the average well this year is evidence of the opportunity ahead to convert our approximately 2,200 remaining non-premium locations to premium over time. EOG is in the best position it has ever been in to maximize the value of this flagship asset. Now here's Ezra for an update on the Delaware Basin.

Thanks, Ken. In the Delaware Basin we announced the addition of just under 1,700 net premium locations including two new plays, the Third Bone Spring, which accounts for 615 net premium locations and the Wolfcamp Middle or M for short, which contributes 855 net premium locations. The Third Bone Spring and the Wolfcamp M combined added approximately 1.6 billion barrels of equivalents of incremental resource potential net to EOG. Additionally, we added over 200 net premium locations from previously identified plays in the Delaware Basin. These locations not only benefit from this year's reduced well costs and increased well performance but also reflect further delineation and greater confidence in areas outside of our core acreage position. The Third Bone Spring is an example of making an old play new again. EOG began drilling the Third Bone Spring sand in our core Red Hills area in Southeast New Mexico over 25 years ago through vertical and horizontal development to exploit these high-quality reservoir sands. Fast forward to today, where modern drilling and completion technology along with the benefit of a large data set of core samples and logs has allowed EOG to exploit the tighter sands shales and carbonate rocks in the Third Bone Spring. While over 1,000 horizontal wells have been drilled in the traditional Third Bone Spring sand target across the basin, less than 50 wells have exploited these tighter reservoir targets. With the advantage of a rich trove of technical data, EOG has identified the sweet spots of these new targets and the result is an $8 per barrel of equivalent finding and development cost with a production decline profile somewhat shallower than other plays in the Delaware Basin. We anticipate developing the Third Bone Spring at approximately 880-foot spacing between wells with per well gross reserve potential of approximately 1.2 million barrels of equivalents for a targeted completed well cost of $7.6 million. We also announced the Wolfcamp M with 855 new net premium locations identified across a wide expanse of EOG's acreage position in Lea, Eddy, Loving and Reeves Counties. This combo play with 63% liquids sits below the Upper Wolfcamp plays and is planned to be developed on 1,050-foot spacing. A typical Wolfcamp M well is expected to produce approximately 1.5 million barrels of equivalents over its life for a $7.7 million targeted completed well cost. EOG began data collection analysis and delineation of this interval in 2014 and refined our precision targets to the highest quality portion of the reservoir. Utilizing proprietary steering software, we have reduced our specific drilling target by over 20% while simultaneously decreasing our drilling days by 50% compared to the 2014 delineation tests. The combination of increased well productivity, operational efficiency lowering well costs and utilization of water, gas and oil infrastructure has delivered another premium play to EOG's portfolio. Altogether in the Delaware Basin, EOG now has an inventory of approximately 6,500 future net premium drilling locations or 24 years of inventory at the current drilling pace. This inventory is based on actual locations customized to the local geology across our over 400,000 acre position and includes multiple targets within the 5,000-foot thick column of pay. We use proprietary core log and completions data to determine our targets and spacing and integrate real-time data from every well we drill to improve future wells. In contrast, to a one-size-fits-all manufacturing mode, our continual process of data collection, analysis and application allows us to continue improving our wells, lower finding and development costs and optimize returns and net present value for each development unit. We're also confident in our ability to add future premium locations to our current inventory through lower well costs, increased well productivity and additional delineation of targets outside of our core area. For example, in the Wolfcamp oil play, the well count averages a single target being developed at 660-foot spacing across the 226,000 acre play. During 2019 EOG has regularly drilled patterns of wells on tighter spacing including the State Atlantis seven Unit number 1H through 5H, a five-well Wolfcamp oil development at 440-foot spacing. These two-mile laterals averaged less than a $7 per barrel of equivalent finding and development cost generate over $50 million NPV and average payouts in approximately three months. The bottom line is EOG is very confident that a lot of upside remains to the currently identified drilling potential in this world-class basin. In addition to the updated inventory, EOG's outstanding operational performance during the first half of 2019 has continued through the third quarter in the Delaware Basin. Total well cost for the Wolfcamp oil play has already reached the full year goal of $7.2 million, while operating expenses in the Delaware Basin are also moving down notching a 7% improvement year-to-date compared to 2018. Well productivity in the Delaware Basin also continues to improve across our various plays. Average cumulative oil production for the first 90 days compared to 2018 was up 15% in the Wolfcamp oil play and up 20% in the Second Bone Spring. The standout for the quarter is the McGregor D unit number 5H, which came online at an initial 24-hour rate of 11,500 barrels of oil per day and nearly 20 million cubic feet per day of rich natural gas. For its first 30 days, the well averaged 6,400 barrels of oil per day. The McGregor was drilled as part of a three-well package on 700-foot spacing in the Wolfcamp upper target. The entire package produced a staggering 445,000 barrels of oil and 1.2 Bcf of natural gas in the first 30 days of production. These wells benefited from EOG's highly integrated multidisciplinary technical approach to development. Data collection and applying real-time analysis to improve well performance is a hallmark of EOG's approach to unlock upside potential across all of our assets and as highlighted with our announcement of additional premium plays in the Delaware Basin. I'll now turn it over to Tim Driggers to discuss our financials and capital structure.

Thanks, Ezra. The benefits of EOG's balanced high-return growth strategy continued to shine through in the financial results in the third quarter. During the quarter, the company generated discretionary cash flow of $2 billion, invested $1.5 billion in capital expenditures before acquisitions toward the low-end of our guidance and paid $166 million in dividends. This brought $337 million in free cash flow. Cash on the balance sheet at September 30 was $1.6 billion and total debt was $5.2 billion for a net debt to total capitalization ratio of 15%. A strong balance sheet is a strategic imperative for EOG. As Bill mentioned, our first priorities for capital allocation in 2020 will be investing in high-return drilling and supporting dividend growth. Two bonds totaling $1 billion are scheduled to mature in 2020. As those dates get closer, we will decide whether to use cash on hand to redeem the bonds or to refinance one or both of them. I'll now turn it back over to Bill for closing remarks.

Thanks, Tim. In conclusion, there are several important takeaways from this call. First, EOG's 2019 operating performance is the best in company history. Our high-return disciplined growth strategy is producing strong returns, strong growth, and substantial free cash flow. At the same time, we continue to get better in every area of the company. Second, our premium inventory continues to grow in both size and quality much faster than we drill it. Third, the company continues to reduce costs and with our pleased-but-not-satisfied mindset, we see endless opportunities to continue to lower costs in the future. Fourth, our GHG reduction and water reuse efforts demonstrate our leading, innovative and returns-focused approach to environmental stewardship and sustainability. And fifth, EOG is a resilient company. Our culture produces sustainable success. As we look ahead, we're confident and excited about the company's ability to continue to create significant long-term shareholder value with performance that competes with the best companies in the S&P 500. Thanks for listening. Now we'll go to Q&A.

Thank you. Good morning.

Good morning, Brian.

Can we start on the two new zones in the Permian Basin? First, how are these being integrated into the drilling program? And given the greater wet gas mix, what are the implications for gas NGLs growth and infrastructure needs? And second, in your prepared comments, you mentioned the Bone Spring three helps mitigate the decline profile of the company. Can you add more color on the reasons? And is this the type of decline rate improvement you've been referring to in the past? Or would that be driven by other exploratory projects under evaluation?

Brian, I'm going to ask for Ezra to comment on the two new zones.

Yes, Brian. This is Ezra. Thanks for the question. There's kind of a lot there. So let me tear it apart piece by piece and maybe I'll start with the Wolfcamp Middle first, the Wolfcamp M. With regards to how it will be integrated into our development, that's a deeper zone across much of our core acreage position. So one great thing about being able to turn this new bench premium is that it has the benefit of having pre-existing well control seismic infrastructure for both oil, gas and water gathering. And one way to look about that the greater wet gas mix is I think it's on slide 47 in our slide deck where we have the Delaware Basin play matrix. It's very similar to the Wolfcamp combo in per well reserves in the gas, oil and NGL make up kind of a combo percentage there. And it's also very similar in cost. And so that gives us great confidence in having a premium play there and the fact that it's going to be a high-return play for a long time. In the Wolfcamp combo, we've turned about 50 wells to sales in the past two years and they're generating over 100% rate of return and approximately $8 million of NPV per well. So we're very excited about that play. On the Third Bone Spring sand shifting gears to that. As we talked about that's kind of a tale of two plays. We've got the more traditional sand target, which definitely because of the better porosity and the better permeability the decline rates are very similar to those in the First Bone Spring and the Second Bone Spring. And yes, I would say on a sidebar that that is the type of reservoir quality that we're looking for in our exploration program. And then the second part of that Third Bone Spring probably a little bit slower to integrate it, because it's really as you step outside of our core area and we're delineating some of the new acreage positions on it are these emerging targets that I talked about the Third Bone Spring, the shale and carbonate targets in there. Industry has drilled about 50 wells in those targets and we're very excited about the potential there again as we move into those new areas.

Great. Thank you. And then my follow-up is if you could talk a little bit about the operational momentum into 2020. It is a daunting task to grow 15% from your large base of oil production. So how are you setting up in terms of late 2019 and early 2020 activity? And do you expect ratable growth through the year or a bit more back-end loaded?

Yes, as we mentioned earlier, we are experiencing fantastic operational momentum this year, which we believe will carry over into 2020. I will have Billy share more specifics on that.

Yes, thanks Bill. Yes, Brian, as we go into 2020 first of all, it's a little bit early to kind of give you too much detailed guidance on where we are. We don't expect to be able to reduce our rig count any further in 2019. As we go into 2020 depending on what oil prices look like, we'll set what our activity is going to look like, but we certainly have the capability of increasing rig activity if the prices so warrant. The bottom line is we fully expect to deliver quarter-over-quarter production growth as we enter into 2020. So the growth of the amount of which would be dependent on what the oil prices look like.

Yeah. Good morning. First question is on, I guess, deflation. Understanding that you're budget for next year and your capital efficiencies aren't dependent on it. I'm curious, if you're seeing any evidence as some of the other operators are slowing down, or at least say they are slowing down.

Yes, I think the U.S. shale industry is experiencing slower year-over-year production growth. However, that is not true for EOG. We continue to set ourselves apart by improving our well productivity, which remains very strong. As Ezra mentioned, we are drilling record wells and achieving record drilling times, setting new benchmarks for well costs across nearly every play. The key to success in any business is to continuously improve, reduce costs, increase production, and maintain strong performance. The culture at EOG is quite distinctive and truly sets us apart in the industry.

Yes. I guess, the question was, do you see cost deflation actually occurring?

Well, I'll ask Billy to comment specifically on that.

Yes. This is Billy Helms. We observe that the service industry is currently at a low point. I don't anticipate further cost reductions in this area. Services are priced quite low at the moment, and in order to remain viable, there's limited room for further decreases. It's crucial to highlight, as Bill mentioned, that EOG is not reliant on service costs to continue lowering our well costs. This is an important distinction. Our operational teams are consistently discovering methods to drill wells more quickly, developing more efficient completion techniques, and driving down our lease operating costs to enhance our overall economics. This is the key factor behind EOG's ongoing efficiency improvements.

Right. Okay. Got you. And then, my follow-up is, I guess, a philosophical question. And acquisitions, you've ruled out corporate. And maybe it's a moot point, because you have so much inventory that you can find organically. But it just seems that the A&D market is at sort of, at least in recent history, historical lows. And the cost of your growth, I think, your slide suggests $30,000, $35,000 for flowing BOE per day. And there's acquisitions there equal to or less than that number. Do you see an opportunity to exploit what hopefully is a temporary divergence in the market?

We want to be very clear that we do not plan to pursue any large or expensive mergers and acquisitions. Larger M&As are simply not part of our strategy. We have strong confidence in our ability to generate high-quality inventory organically, and we can achieve this at a significantly lower cost compared to any M&A options. Our focus will remain on organic, low-cost growth that enhances our existing inventory. We believe we can increase our inventory substantially this way. Currently, we are engaged in six different basins and have active prospects in ten basins. This is the most vigorous exploration effort I have witnessed in my 40 years with the company. We are confident in our ability to replace and improve our inventory at very low costs going forward.

Good morning, Bill, and the entire team. I would like to revisit the points you just mentioned and approach them slightly differently. Referring back to your prepared comments, in point three regarding differentiation, you noted that for mid-50 WTI oil prices, you anticipate achieving oil growth comparable to what you achieved in 2019, along with growing the dividend and free cash flow as well. It appears that you are expecting improved capital efficiency in 2020 compared to 2019. Could you provide some clarity on the specific increment we should be monitoring? Did I capture that setup correctly?

You are correct, Charles. We believe we can achieve mid-teens growth, increase the dividend, and generate significant free cash flow with oil prices around $55. We aim to maintain our current efficient operation and have been generating substantial free cash flow alongside strong growth. Over the past two years, we've increased the dividend by over 70%, and we intend to continue this trend. Our focus remains on maximizing returns, as returns are our priority, while volume growth reflects our reinvestment strategy. We aim to improve each year, and next year, we expect to carry forward our operational momentum and ongoing cost reductions into our future performance. We aim for better returns that will support healthy growth and substantial free cash flow. Regarding the dividend, we've indicated a strong track record with annual increases of at least 30% over the past two years, and we plan to maintain this growth. Although we won't specify the exact level of future increases, we are committed to sustaining strong dividend growth, which will depend on the macro environment and oil prices, assessed on a quarterly basis by our Board. Our goal is to increase our dividend yield to 2% as quickly as possible.

That's a helpful elaboration. Thank you. If I could ask a follow-up about the Middle Wolfcamp, Ezra, you mentioned earlier in relation to the Third Bone Spring how many wells in the industry have targeted the carbonate and the shale. Do you have a similar insight into how many other industry wells have targeted this section in the Wolfcamp M?

Yes, Charles. This is Ezra. I'm glad you asked that question. I was just trying to determine whether I had mentioned that before. The Wolfcamp Middle, or M, as we refer to it, roughly corresponds to the Wolfcamp B and part of the C as referred by some other operators. Across the Delaware Basin, there have been several hundred wells drilled targeting similar areas. That’s one of the reasons we analyzed all the data regarding their landing zones and combined it with our own data to announce this premium play.

Good morning and congratulations on the quarter. I thought the supply agreement with Cheniere was both interesting and innovative and it brought up two questions. So the first one is, what sort of long-term price uplift versus Henry Hub do you expect from that portion of your supply that's indexed to the JKM Marker? And second, is this kind of a deal that you're looking at repeating again in the future, maybe with Cheniere or maybe another LNG exporter?

I'm going to ask Lance to comment on that one.

Good morning, Jeff. Thank you for your question. To begin, my remarks will build on what Billy mentioned. The new transaction and gas sales agreements we have with Cheniere align perfectly with our marketing strategy, which focuses on diversifying our sales channels and maintaining multiple options. We are thrilled to expand our business with Cheniere, as they are the industry leader, exporting 5.5 Bcf out of the total 7.5 Bcf of LNG being exported today. The new agreement will start with 140,000 MMBtus per day in January next year and ramp up to 440,000. Regarding your question on price realizations as the contract initiates, we will include that in our guidance, but I won't provide specific details right now. What excites us is the anticipated LNG demand growth over the next ten years, particularly in the Asia Pacific region. Given the significant weather events in those areas, there is potential for substantial upside, which is why we are enthusiastic about this deal. To address your last question on new structures and deals, we are eager about this initial agreement and will remain vigilant in the market, always on the lookout for new opportunities to diversify our portfolio. We plan to stay active as we explore additional potential deals in the future.

Thanks for that color, Lance. I appreciate it. My other question was earlier in the call there was some discussion of the corporate decline. And slide 49 notes that longer laterals exhibit shallower declines than shorter laterals, and I assume that's a comparison within a given play. I wondered if some of the portfolio plays as a whole exhibit shallower declines than others. And does this help influence attracting capital?

Yeah, Jeffrey. That decline rate is something that we're very much focused on in the company. And so as we continue to focus our capital and high grade our capital, we do consider that as part of the process. And so we're looking at low decline, lower decline plays particularly in our exploration efforts. Some of the newer plays we've announced in the last several years have lower declines than some of our historical plays. And then we're also looking and focused on lower finding costs. So low finding costs, low decline plays are certainly preferred for us and that's a focus of our exploration effort. And it really is a function of the quality of the rock in combination with the completion technology and they work together to help in that regard. So we're focused on that and that helps the company get better. That's part of the process. We've been going on for the last several years. It's helped us get better in the last couple of years; certainly this year and we think that will continue to help us in the future.

I want to go through all the details. You mentioned a bit about slide 5, where you outline the premium parameters. My question is more about slide 36 and what led to the changes in both the additions and the adjustments in the Eagle Ford, Bakken, and Woodford, particularly as those appear to be somewhat lower. I'm curious about what caused that.

Billy would you comment on that?

An important point to note is that this represents our best estimate moving forward regarding each play. As we've discussed, the Eagle Ford update takes into account the number of wells we've drilled and what remains. It's crucial to acknowledge that, as Ken mentioned, we have 2,200 remaining locations that we can develop to convert to premium over time as we explore less developed areas. This presents an upside for the Eagle Ford. For the other plays, it simply reflects our view of the remaining inventory at this time for each play mentioned. Overall, we are on track to replace more than what we drill each year.

Very good. And then Bill maybe just one broad question. I'm just wondering when you look at what's been mentioned today about the growth versus the free cash versus shareholder return, I'm just wondering when you sort of put out there the 15% growth to $55 is your primary delta, kind of, what free cash flow you want to achieve? Or what shareholder return? I'm just wondering how you all go about thinking about that.

Yeah. Certainly the free cash flow is an important component of it. So it's a balance of allocating capital at the right that we can get better and can increase our returns every year. It is certainly focused on generating substantial free cash flow and continuing to increase the dividend in a very strong manner too. So we want to work on all three of those. And then as you know we have been reducing our debt. And Tim talked about that in the opening remarks. And so we want to continue to pay off those bonds as they mature. So we look at all that but, primarily it's really focusing the capital on generating really strong returns and certainly working on the dividend.

Hey guys, I fully appreciate that you guys don't have 2020 guidance out there. You certainly talked about the mid-teens oil growth rate at $55 WTI, which sounds great. I guess just from a high level philosophical perspective, in order to kind of achieve that, do you guys think you'd have to increase activity and CapEx at all? Or maybe a little bit to do that? Or do you think the efficiencies are such that you could do that with a similar type of activity?

I'll ask Billy to comment on that.

Yeah Leo. This is Billy Helms. I think the takeaway would be we're going to be targeting as Bill said how do we continue to improve, what we do. We're not going to give you any specific guidance on how much capital that's going to deploy. We have the capability of increasing activity if the commodity outlook supports that. But we're going to stay extremely flexible at this point in time to make sure that as we go into the next year, we're doing so with the discipline that we want to maintain in each one of our programs. So I guess we certainly have the capability of doing whatever the market shows us that is prudent to do. And our programs will support it. And we have the teams to execute any of those programs. So we'll just, kind of, leave it there for right now.

Okay. I guess just wanted to see if we can get maybe a little bit more kind of a high-level update on some of the new plays. I certainly realize you guys aren't ready to announce any of the exploration plays but I know you've drilled a number of wells in 2019. Really just wanted to get a sense of whether or not on some of the wells you've drilled you think that you're getting competitive economics even in these early stages here to the point where you can foresee some new premium drilling inventory? Any comments on that?

I'm going to ask Ezra to comment on that.

Yeah, Leo. Thank you for the question. This is Ezra. As we've discussed previously, we're very excited about our exploration program. And Bill had mentioned that we're currently leasing and testing in over 10 different basins across all of our divisions, our focus primarily on oilier plays with higher rock quality that we've applied. We're searching for these plays. We're prospecting for plays that we've applied core and log data in our reservoir models developed from our multi-basin approach. So really leveraging off of our efforts in the Delaware Basin, the Powder River Basin, the Eagle Ford and Woodford oil window to really identify rock quality that will perform very well in combination with our horizontal drilling and completions technology and hopefully deliver slightly shallower declines. And hopefully we'll be very competitive with our current inventory. Again we want to increase the quality of our inventory not just add to the back end. As far as that, we're confident in our reservoir models. And hopefully we'll be able to update you on a future call.

Thank you. You mentioned achieving some of your cost reduction targets this year, and it seems you have implemented some new efficiencies. Can you highlight any specific advancements beyond the fact that you are drilling faster? What is actually happening on the ground and what technological improvements are contributing to this increased efficiency?

Yes, Billy will comment on that.

Yes, Scott. It's not any one specific thing that helps us achieve these improved efficiencies. It goes back to what Bill talked about in his opening comments. It's the culture of the company. It's the drive of every one of our operating teams to continue to get better. And I couldn't be prouder of the execution those guys have made. One example on the drilling side to help us get the wells drilled faster as I mentioned in the prepared remarks the innovations we've made on designing drilling motors that enable us to increase the speed at which we do and the reliability of those tools to keep them in the ground is just one example. There's several examples on the completion side that go along with that to allow us to complete more of the lateral feet per day than we used to a year ago at a much lower cost and still deliver the same productivity improvements that we're seeing as we deliver the production from our wells. So it's just a number of different things. And it's hard for us to capture them all in one call like this, but just to say, that everybody in each division is working hard to try to continue to improve every day.

Okay, understood. If I could ask a question about next year's activities at a high level. It seems like this year you have around $400 million of the $6.3 billion budget allocated for research development and technological improvements. For 2020, should we expect a similar amount? I thought 2019 would have had a heavier investment. What does 2020 look like?

Scott, we're not I think ready at this point to give you a specific number on that. But we do certainly have an ongoing exploration and leasing program and so we'll continue to keep that up. But we won't give you a specific number on that. We're still working through all those details.

Thank you. Good morning. My question is on political risk. Bill, EOG has been very good at reducing political risk, for example, not operating in Colorado. What steps might you take to reduce the political risk that you addressed in your slides related to federal acreage?

We have a very active permitting process underway and are ahead of schedule, with two to four years of permits secured. We have the capacity to adjust our operations and enjoy a lot of flexibility regarding different operating areas and the movement of rigs. We have been and will continue to strongly develop our federal acreage position. We have not encountered significant issues with regulatory changes and maintain excellent relationships with the Bureau of Land Management and the state governments where we operate. This collaborative approach has worked well for us in the past.

Thanks, Bill. My second question is about the Austin Chalk. What is holding the Austin Chalk back from being recognized as a top play? You clearly have many successful wells. Is it simply a matter of not having enough to classify it as a top play? Or is it more related to costs? You're drilling several dozen wells each year, so it seems to be at least a strong play, if not a top play.

Yes, the Austin Chalk is a large and complex play that extends over a significant area. We have achieved excellent results from our Eagle Ford acreage within the Austin Chalk, making it a key exploration target for us. We are currently evaluating multiple locations within the play, which helps us maintain a competitive edge in securing the best acreage. While we haven't disclosed specific details yet, we plan to provide updates on our progress in the Chalk in the future.

Hey, Bill, I wanted to talk to you or ask you about the potential sensitivity to your 2020 program to lower oil prices. I think you outlined a mid-teens oil growth at $55. If oil prices average closer to $50 per barrel would you adjust activity accordingly? And could you discuss broadly the sensitivity to your oil growth rate at a $50 number?

Well, we can't give you any specifics there Arun. But certainly we would adjust our capital. Again, we want to have great returns. That's number one. We want to have strong oil growth. We want to have substantial free cash flow. So we continue to work on the dividend. So we really balance all those. And we would set it appropriately based on our macro view of oil in 2020. And at this point, we don't want to speculate, whether it's going to be higher or lower. We're just trying to give you some guidelines of kind of where we see our efforts next year.

Great, great and just a follow-up, I know the reduction in your rig count in the second half has garnered a lot of attention. But it sounds like this decline was driven by rig efficiencies. I guess my question is, in 2019 Bill, you're delivering call it 740 net wells for $6.3 billion, in capital. If we were going to bake in the rig efficiencies, you're seeing today OFS deflation do you have any thoughts on what your CapEx dollar could do incremental to 2019? Could we see another call it 5% to 10% improvement in well cost next year?

We are not going to provide specific numbers. However, we certainly believe that our capital efficiency will improve next year compared to this year. We are also confident that our well costs will continue to decrease next year. Additionally, we are optimistic that operating costs will keep going down. Overall, the company is incrementally improving each quarter, thanks to our culture, our people, and our divisions doing an excellent job. When we take into account oil prices, all of this will really shape our plans moving forward.

Yeah. Good morning, everybody. If you are successful with these new exploration plays, they turn out to generate better returns than even your premium inventory. I just want to see how quickly they could move to the top of the drilling inventory. And if they're not just additive, would that allow you to actually replace some inventory to where you could look at monetizing some of the inventory that's maybe at the end of the spectrum?

Thank you for your question, Michael. Regarding the plays we're evaluating in these 10 different basins, most of them are in locations where we can ramp up activity fairly quickly. We're not planning to deploy 10 rigs in a single year, but we could gradually add rigs to each of these plays and develop the necessary infrastructure. Most of these areas allow for that quick ramp-up. If these plays contribute positively to our returns, we will definitely pursue each opportunity as fast as we can. Additionally, we have a substantial inventory within the company and have divested over $6 billion in properties over the past decade. We will continue to explore ways to derive value from such assets, although we don't expect them to reach a premium valuation. This could also serve as another path to enhance the company's value.

Okay. Thanks. And then, Bill you mentioned last quarter you were pleased with those first three Niobrara wells in the Powder. And then it looks like you added another one this quarter. One of your nearby competitors had some favorable things to say about the Niobrara this quarter. I just want to see, how you're viewing that zone relative to the other targets in the Powder River Basin.

I'm going to ask Billy to comment on that.

We are very pleased with the early results from the Niobrara play. It appears to be in line with our expectations. This area is becoming more focused on oil production within the Powder River Basin, allowing us to increase oil volumes and remain competitive with our other resources. Our current pace of work is guided by the insights we've gained and the existing infrastructure. As we've discussed in previous calls, the rate of our activities will align with our investment in infrastructure to expand this play. It seems to be a promising opportunity for future growth.

Yeah. So I'd just like to say that again, we're just so pleased with another outstanding performance by EOG in the third quarter. And we want to say many thanks to everyone in the company for making it happen. They're doing a fantastic job. The company continues to improve in every area. Our costs continue to fall. Oil well results are very strong. Capital efficiency continues to improve. And our premium inventory continues to grow. So our high-return organic growth machine is running at the most optimum level in the company's history. And most importantly, we're very excited about performing at an even higher level in 2020. So again, thank you for listening. And thank you for your support.