EOG Resources, Inc.

Good day everyone and welcome to EOG Resources' Third Quarter 2019 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

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 and 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 .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 Betticker, EVP, Exploration and Production, Ezra Jacob, EVP, Exploration and Production, Lance Terveen, Senior VP, Marketing, David Streit, VP, Investor in 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 for 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 $250 natural gas price scenario, ensuring that the company will generate strong financial performance, even in commodity down cycles. After a third consecutive quarter of exceptional results, we believe that EOG's 2019 operational performance will be the best in company's history. To reflect our -to-date performance, we have raised our U.S. oil growth targets 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. To complement strong returns and 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 percent of our federal acreage position is held by legacy production and we have 11 years of premium inventory on non-federal leases. With 3.2 million net acres of non-federal leases in the U.S., which is approximately 75 percent 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 matter 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 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 initiative 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-cost 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 advantages rooted in our culture ensure 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 the 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 identify new techniques to lower well cost to improve capital efficiency. As of the third quarter, I can report that we have achieved our year-end goal of reducing well cost 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 Eagleford, 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 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 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 forecast 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 are 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 DD&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 Chenier 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-fourths 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 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 Eagleford.

Thanks Billy. Year after year, quarter after quarter, EOG's Eagleford asset delivers strong consistent results and the third quarter of 2019 was no different. The Eagleford 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 the Eagleford, the Metalarc 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 Eagleford 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 Wolf Camp middle or M for short which contributes 855 net premium locations. The third bone spring and the Wolf Camp 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 identified across a wide expanse of EOG's acreage position in Lee, Eddie, 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 percent while simultaneously decreasing our drilling days by 50 percent compared to the 2014 delineation tests. The combination of increased well productivity, operational efficiency lowering well cost, 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 completion data to determine our targets and spacing and integrate real-time data from every well we drill to improve future wells. In contrast to -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 are 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 Wolf Camp 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 7 Unit Number 1H through 5H, a five-well Wolf Camp oil development at 440 foot spacing. These two-mile laterals average less than a $7 for barrel of equivalent finding and development costs, 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 costs for the Wolf Camp 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 -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 Wolf Camp oil play and up 20% in the second mown 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 Wolf Camp 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 is 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 continue 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 expenditure before acquisitions toward the low end of our guidance, and paid $166 million in dividends. This left $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 net debt, the 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 discipline 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, sir. The question and answer session will be conducted electronically. If you'd like to ask a question, please do so by pressing star key followed by the digit one on your touchtone telephone. If we'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 touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the star key followed by two. We'll pause for just a moment to give everyone an opportunity to signal for questions. And the first question we have will come from Brian Singer with Goldman Sachs. Please go ahead.

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 and GL's growth and infrastructure needs? And second, in your prepared comments, you mentioned the bone string 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 Wolf Camp Middle first, the Wolf Camp 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-controlled 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 Wolf Camp combo in per well reserves in the gas, oil, and MGL makeup, kind of the 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 Wolf Camp combo, we've turned about 50 wells to sales in the past two years, and they're generating over 100 percent rate of return and approximately $8 million of MPV 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 rateable growth through the year or a bit more back-end loaded?

Yes, as we said early in the remarks, Brian, that we're really having a fantastic operation this year, and the operational momentum that we've got going in the company is going to carry over into 2020. So I'm going to ask Billy to comment a little bit more on the specifics about 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.

Next, we have Subhash Chandra of Guggenheim Partners.

Yes, good morning. First question is on, I guess, deflation, you know, understanding that your 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, you know, are slowing down or at least say they are slowing down.

Subhash, yes, I think, you know, just in general, the U.S. sale industry, I think, you know, year over year production growth is slowing. That's certainly not the case for EOG. I think we continue to differentiate ourselves by continuing to improve and our well productivity remains very, very strong and robust. We continue to, as Ezra pointed out, we continue to drill record wells and we continue to have record drilling times and we're setting new records really literally almost every play on well cost. So the key to success in any business is getting better all the time and lowering your cost and getting your production up and maintaining a very, very strong, you know, performance. And I think the EOG culture is quite unique in a business and it really sets EOG apart.

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

I'm going to ask Billy

to

comment specifically on

that. Yes, this is Billy Helms. What we see on the service side, I guess, is the service industry is pretty much at a low, I wouldn't expect to see much further cost reductions on the service side. I think services are at a pretty low price period point at this present time and for them to stay healthy, to be able to service our industry, I think there's not much room to go any lower. So I think the important thing to differentiate, as Bill said, on EOG is that we're not dependent on service cost to really continue to reduce our well cost. I think that's an important point to make. Our operating teams continue to find ways to drill the wells faster, figure out more efficient completion techniques, drive our lease operating costs down to improve our overall economics and that's really what's driving EOG's continued efficiency gains.

All right, okay, got you. And then my follow up is, I guess, a philosophical question. 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 a, at least in recent history, historical lows and the cost of your growth, I think your slide suggests, $30,000, $35,000 for a 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?

I think we want to be really clear on that. We do not envision doing any large M&A, expensive M&A, especially expensive M&A is, large M&As are just really not in our game plan. We have tremendous confidence in our organic ability to generate very strong, even better quality inventory than we currently have and we can do that organically at a much, much lower cost, even compared to what you might think M&A could produce. Our game plan will continue to focus on organic growth, low cost growth, adding inventory that would be additive to the quality that we have and adding that at really low cost. We believe we can add very much a large amount of inventory that way. I think we commented that we're operating in six different basins and we have active prospects in ten different basins ongoing right now. It's the most robust exploration effort. I've been with the company 40 years that I've seen in the company. We've got a lot of confidence in our ability to more than replace and to improve our inventory going forward at very, very low cost.

Next we have Charles Mead with Johnson Rice.

Good morning Bill, to you and the whole team there. I want to just pick up maybe on the points you were just commenting on and try them a little bit differently. Going back to your prepare comments, I think it was point three on your points to differentiate. You said for mid-50s WTI you grow oil comparable to the rate that you grew in 19, grow the dividend and then I believe it was also grow free cash flow. It makes sense that you guys would have better capital efficiency in 20 and you have 19, but can you give me an idea what is that increment that we should be looking for and did I kind of get that whole set up correct?

No, you're exactly right Charles. What we say is that we believe we can deliver mid-teens growth, we can grow the dividend and generate substantial free cash flow with oil at about $55. We want to continue to operate, obviously if you look at the company right now we're operating at a very high level, an optimum level and we're generating a lot of free cash flow, we're producing really, really strong growth and if you look over the last two years we've grown the dividend over 70%. That's what we want to continue to do in the future. We want to continue to make sure that first of all that we're maximizing our returns. Our company's focus has always been on returns and returns come first and volume growth is just an expression of reinvesting at high returns. We want to operate at a point, at a level, at a growth level where we continue to get better every year. So next year because of the operational momentum we have this year and the ongoing cost reductions, we see that continuing in the next year. Our focus is to get better and to make better returns next year. That will help us to grow at a very healthy rate and it will also help us to generate very substantial free cash flow. And so we're also focused on the dividend. We want to have, as we've talked in the past, I think we've had a very good indication of the last two years with dividend increases of 30% or better per year and we want to do that going forward. We're not going to commit to the level we're going to increase the dividend specifically but we want to continue to have strong dividend growth in the future. So of course that all depends on the macro environment, what the oil price is and we evaluate that every quarter, our board does and we'll make those decisions on a quarterly basis but our goal is to get our dividend yield up to the 2% yield level as quick as possible.

That's a helpful elaboration. Thank you. And then if I could ask a follow up on the middle Wolf Camp and perhaps of Ezra. Ezra, you talked a little bit about when you were talking about the third bone springs in response to an earlier question, how many other wells in the industry have targeted the carbonate in the shale but do you have a similar sense for how many other industry wells have targeted this section in the Wolf Camp end?

Yes, Charles, this is Ezra. I'm glad you asked that question. I was just sitting here trying to figure out if I'd actually mention that or not. The Wolf Camp middle or M as we call it, it roughly correlates to the Wolf Camp B and part of the C as known by some other operators and so really across the Delaware Basin there have been a few hundred wells drilled in the similar target there and so we've got, that's one of the reasons we've looked at all that data, their landing zones. We've incorporated that with our own data to go ahead and announce this premium play.

Got it. That's what was after things,

Ezra. Next we have Jeffrey Campbell of Tui Brothers Investment Research. Please go ahead.

Good morning and congratulations on the quarter. I thought the supply agreement with Sheniro was both interesting and innovative and it brought up two questions. 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 J-CAM marker? Second, is this kind of deal that you're looking at repeating again in the future, maybe with Sheniro or maybe another LNG exporter?

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

Yes, Jeff. Hey, good morning. Thanks for the question. First, to start off, it kind of follows up with what Billy talked about. This new transaction in the gas sales agreements that we've done with Sheniro, it's really consistent with our marketing strategy and how we're trying to diversify our sales points and having multiple options. Really, when we undertook this process, when you really look at Sheniro, they are the industry leader. You look at the 7.5 BCF a day that's being exported today on LNG, they represent 5.5. Expanding our business with them, we're very excited about. Just a reminder, that starts at 140,000 MMBTUs a day starting in January of next year and then ramps up to the 440. But on your question just on the price realizations, as that contract starts up next year, we'll be incorporating that into our guidance. I'm not going to give any specific color on that. What I can tell you, that's what got us excited about is just when you look at the amount of LNG demand growth that's going to be coming on, especially over the next 10 years, it's definitely all in the Asia Pacific region. So tying it to that industry, especially with significant weather events in those areas, it can provide, as you look historically, for significant upside. That's what got us excited about that. Then your last question there just about new structures and new deals, we're very excited about this first. We're going to stay poised. I think we're going to continue to watch the market. We're always looking for new opportunities and diversifying our portfolio. So we'll definitely be staying active in the future as we look at new structures that may come in front of us.

Thanks for that color, Lance. I appreciate that. My other question was earlier in the call there was some discussion of the corporate decline. Slide 49 notes that longer laterals exhibit shallower declines than shorter laterals. 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 declined 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 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.

And next we have Neil Dingman of Sunchest.

I want to guess for all the details, could you talk a little bit, I see, as you always have done in your slide five, where you break out the premium sort of parameters, because my question is more around slide 36 and just what caused the changes in both what you were able to add, but also to the Eagleford box and Woodford, I think. There was down a little bit on those. I'm just wondering what contributed to that.

Billy, would you comment on that?

Yeah, I think the important point to take away, Neil, is that this represents our best estimate going forward on each play. The Eagleford, as we've talked about, it's an update relative, taking into account the number of wells we drilled and then what we have remaining. The important point on the Eagleford is to recognize, as Ken discussed, we have 2,200 remaining locations that we can continue to work on to convert to premium over time as we continue to move into areas that are less developed. So I think that's the upside on the Eagleford. For the rest of the plays, it just represents kind of what we see as the remaining inventory at this point in time for each one of these plays that are mentioned here. Overall, it's in keeping with replacing more than replacing what we drill every year.

Very good. Bill, maybe just one sort of 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. It's a balance of allocating capital at the right rate that we can get better and increase 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.

Very helpful. Thanks, guys.

Next, we have Leo Moriani of KeyBank.

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 kind of philosophical perspective, in order to kind of achieve that, do you guys think you'd have to increase activity in capex at all, 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'm going to 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. I guess we certainly have the capability of doing whatever the market shows us that's proven to do, and our programs will support it, and we have the teams to execute any of those programs. 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 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, do you think that you're getting competitive economics, even 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 Eagleford and Woodford oil window to really identify rock quality that will perform very well in combination with our horizontal drilling and completion 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.

And next we have Scott Hanold of RBC Capital Markets.

Yeah, thanks. You all talked about hitting some of your cost reduction targets this year, and it sounds like you've got some new efficiencies you're seeing in place. Is there anything specific you can point out too, you know, outside of, you know, hey, we're drilling faster, but like specifically what's happening on the ground and maybe even from a technological side that's, you know, causing that improved uplift?

Yeah, Bill, we will comment on that.

Yes, Scott. You know, it's not any one specific thing that helps us achieve these improved efficiencies. It goes back to what Bill talked about in his open 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 is, as I mentioned in the prepared remarks, the innovations we've made on designing drilling motors that enable us to increase the speed of 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 motor 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. And then, you know, if I could try, you know, a question on next year's activity just at a high level. I mean, it seems like this year, if I'm not mistaken, you know, you've got around $400 million of that $6.3 billion budget allocated to, you know, kind of resource development and technological improvements. You know, as you look into 2020, you know, should we expect a very similar amount or, you know, if I'm not mistaken, I thought 2019 was going to be heavier. 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 a ongoing, you know, exploration and lacing 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.

And next we have Joseph Allman of Baird.

Thank you. Good morning. My question is on political risk. Bill, EEOG 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?

Well, I think as we talked about, I think in the opening remarks, we do have a very active permitting process going on, and so we're well ahead of that. We have two to four years of permits in hand. And, you know, we have the ability to modify our operations, and we have a lot of flexibility with, you know, different operating areas and shifting rigs here and there. And so we will, we have been and we will continue to actively develop our federal acreage position, you know, very strongly. So we'll, we've not really ever, I think, had a problem working with any of the regulatory changes. We have a great relationship with BLM and a great relationship with the state governments that we are active in. So it all works together. We try to be a good citizen and good operator, and it really has worked out well for us in the past.

Great. Thanks, Bill. And then my second question is on the Austin Chalk. What is preventing the Austin Chalk from making it to the list of premier plays? You clearly have many great wells. Do you just not have enough to call it a premier play, or is it really on the cost side? And, you know, you're drilling a couple dozen wells a year, so it would seem to be it's at least a great play, if not a premier play.

Yeah. Well, I think the first thing is when you think about the Austin Chalk, it's a really big play. It goes a long ways, and it's got all different kinds of aspects to it. And we've been very successful under our Ecopor acreage. We have great results in the Austin Chalk, and it's certainly an exploration target for us. And we have multiple places in the play that we're looking and testing. And so, you know, to keep our competitive advantage on making sure we get the acreage in the right spot, you know, we haven't talked about anything specific, but we will at some point, and we'll give you some updates on our progress in the Chalk.

Next, we have Arun Jayaram of JPMorgan.

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, you know, have great returns. That's number one. You know, we want to have strong oil growth. We want to have substantial free cash flow, so we continue to work on the dividends. So we really balance all those, and we would set it appropriately, you know, based on our macro view of oil in 2020. And at this point, you know, we don't want to speculate, you know, 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 to 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, you know, 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 percent improvement in well cost next year?

Again, Arun, we're not going to give you any specific numbers, but we do certainly believe that our capital efficiency will improve next year over this year. We definitely believe that our well cost will continue to decrease next year, too. And we're certainly hopeful operating costs will continue to go down. So the company just incrementally is getting better every quarter, and our culture and our people and our divisions are just doing a tremendous job in doing that. And so along with oil prices, you know, we bake all that in, and that'll really determine what our plan will be.

Next, we have Michael Scala of Stiefel.

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?

Yeah, Michael, thank you for your question. The plays, the ones we're looking at in these 10 different basins, most of them are in areas where we could increase activity reasonably fast, not jump in with 10 rigs in one year, but we could incrementally, I think, add rigs to each one of these plays and develop the infrastructure. Most of them are not in places where you couldn't do that fairly quickly. So if they were incremental to our returns, we would certainly move that way on each one of them as quickly as possible. And we have a lot of inventory, obviously, in the company. And we have sold, I think, about over $6 billion of properties over the last 10 years. And we'll continue to look to get value through possibly monetizing any of that that we don't think that we'll ever get to a premium category. So certainly that would be another avenue to add value to the company.

Okay, thanks. And then, Billy, you mentioned last quarter you were pleased with those first three Niobrara wells in the powder, and 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.

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

Yeah, I think we're very pleased with the early results we're seeing from the Niobrara play. It looks to be something that we would hope for. You know, it's going to be more of an oily play in that Powder River Basin so that we can grow oil volumes and be competitive with the rest of our inventory. And we're going at a pace now that's really dictated by the learnings that we're taking into account, but also the infrastructure we have there now. And as we mentioned in earlier calls, the pace of activity will be really married up with our level of spending on infrastructure to grow that play. But it looks to be a play that we can see as another leg of growth that we'll have in the future.

Well, ladies and gentlemen, this will conclude our question and answer session. I would now like to turn the conference call back over to Mr. Thomas for his closing remarks. Sir?

Yes, I'd just like to say that, again, you know, 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. Well-reduced 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 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.

And we thank you, sir, and to the rest of the management team for your time also today. Again, the conference call is now concluded. Again, we thank you all for attending today's presentation. At this time, we may disconnect your lines. Thank you. Take care and have a great day, everyone.