Good day, everyone and welcome to EOG Resources Second Quarter 2021 Earnings Results Conference Call. As a reminder, this call is being recorded. And it's time for opening remarks and introduction. I would like to turn the call over to 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 second quarter 2021 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 www.eogresources.com. Some of the reserve estimates on this conference call or in the accompanying investor presentation slides may include estimated potential reserves and estimated resource potential, 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; Ezra Yacob, President; Ken Boedeker, EVP, Exploration and Production; Jeff Leitzell, EVP, Exploration and Production; Lance Terveen, Senior VP Marketing; and David Streit, VP Investor and Public Relations. Here's Bill Thomas.

Thanks, Tim. And good morning, everyone. EOG is focused on improving returns. Results from the first half of the year are already reflecting the power of EOG's shift to our double premium investment standard. Once again, we posted outstanding results in the second quarter. We delivered adjusted Earnings of $1.73 per share and nearly $1.1 billion of free cash flow, repeating the record level of free cash flow we generated last quarter. Our outstanding operational performance included another beat of the high end of our oil production guidance, while capital expenditures and total per-unit operating costs were below expectations. We're delivering exceptional well productivity that continues to improve. In addition, even though the industry is in an inflationary environment, EOG continues to demonstrate the Company's unique ability to sustainably lower costs. Our performance clearly proves the power of doubling our reinvestment hurdle rate. Double premium requires investments to earn a minimum of 60% direct after-tax rate of return using flat commodity prices of $40 oil and $2.50 natural gas. I'm confident our reinvestment hurdle is one of the most stringent in the industry and a powerful catalyst to drive future outperformance across key financial metrics, including return on capital employed and free cash flow. As double premium improves our potential to generate free cash flow, we remain committed to using that cash to maximize shareholder value. The regular dividends, debt reduction, special dividends, opportunistic buybacks, and small high return bolt-on acquisitions are our priorities. In the first half of this year, we reduced our long-term debt by $750 million and demonstrated our priority to returning significant cash to shareholders with a commitment of $1.5 billion in regular and special dividends. We also closed on several low-cost, high-potential bolt-on acquisitions in the Delaware Basin over the last 12 months. Year-to-date, we have committed $2.3 billion to debt reduction in dividends, which is slightly more than the $2.1 billion of free cash flow we generated. Looking ahead to the second half of the year and beyond, our free cash flow priorities and framework have not changed. As we generate additional free cash, we remain committed to returning cash to shareholders in a meaningful way. We are focused on doing the right thing at the right time to maximize shareholder returns. Over the last four years, we made huge progress, reducing our GHG and methane intensity rates, nearly eliminating routine flaring and increasing the use of recycled water in our operations. We're focused on continued progress towards reducing our GHG emissions in line with our targets and ambitions. This quarter we announced the carbon capture and storage pilot project, which we believe will be our next step forward in the process of reaching our net zero ambition. Ken will provide more color on this and other emission reduction projects in a few moments. Driven by EOG's innovative culture, our goal is to be one of the lowest cost, highest return, and lowest emission producers, playing a significant role in the long-term future of energy. Now, here's Ezra to talk more about how our returns continue to improve.

Thanks, Bill. While we announced our shift to the double premium investment standard at the start of this year, the shift has been underway since 2016 when we first established our premium investments standard of 30% minimum direct after-tax rate of return using a conservative price deck of $40 oil and $2.50 natural gas for the life of the well. In the three years that followed, our premium drilling program drove a 45% increase in earnings per share, a 40% increase in return on capital employed in an oil price environment nearly 40% lower compared to the three-year period prior to premium. This comparative financial performance can be reviewed on Slide 15 of our investor presentation. In addition, the premium enabled this remarkable step-change in our financial performance while reinvesting just 78% of our discretionary cash flow on average, resulting in $4.6 billion of cumulative free cash flow. The impact from doubling our investment hurdle rate from 30% to 60% using the same conservative premium price deck, is now positioning EOG for a similar step-change to our well productivity and costs, boosting returns, capital efficiency, and cash flow. Double premium wells offer shallower production declines and significantly lower finding and development costs resulting in well payouts of approximately six months at current strip prices. The increase in capital efficiency resulting from reinvesting in these higher-return projects is increasing our potential to generate significant free cash flow. This year, we're averaging less than $7 per barrel of oil equivalent finding cost. Adding these lower-cost reserves is continuing to drive down the cost basis of the company, and when combined with EOG's operating cost reductions, is driving higher full-cycle returns. Looking back over the last four quarters, EOG has earned a 12% return on capital employed with oil averaging $52. We are well on our way to earning double-digit return on capital employed at less than $50 oil, and it begins with disciplined reinvestment and higher-return double-premium drilling. While EOG has 11,500 premium locations, approximately 5,700 are double premium wells located across each of our core assets. We're confident we can continue to grow our double premium inventory through organic exploration, improving well costs and well productivity, and small bolt-on acquisitions, just like we did with the premium over the last five years. In the past 12 months, through eight deals, we have added over 25,000 acres in the Delaware Basin through opportunistic bolt-on acquisitions at an approximate cost of $2,500 per acre. These are low-cost opportunities within our core asset positions, which in some cases receive immediate benefit from our existing infrastructure. Premium and now double premium established a new higher threshold for adding inventory. Exploration and bolt-on acquisitions are focused on improving the quality of the inventory by targeting returns in excess of the 60% after-tax rate of return hurdle. EOG's record for adding high-quality, low-cost inventory, predominantly through organic exploration, is why we do not need to pursue expensive large M&A deals. 2021 is turning into an outstanding year for EOG. Our exceptional well-level returns are translating into double-digit corporate returns, and our employees continue to position EOG for long-term shareholder value creation. Here's Billy with an update on our operational performance.

Thanks, Ezra. Our operating teams continue to deliver strong results. Once again, we exceeded our oil production target, producing slightly more than the high end of our guidance, driven by strong well results. In addition, capital came in below the low end of our guidance as a result of sustainable well cost reductions. We have already exceeded our targeted 5% well cost reduction in the first half of 2021. We now expect that our average well cost will be more than 7% lower than last year. As a reminder, this is in addition to the 15% well cost savings achieved in 2020. We continue to see operational improvements outpace the inflationary pressure in the service sector. Average drilling days are down 11%, and the lateral completed in a single day increased more than 15%. We are utilizing our recently discussed super-zipper completions on about a third of our well packages this year, and I expect that percentage to increase next year. In addition, our sand costs are flat to slightly down year-to-date. We have a line of sight to reduce the cost of sand sourcing and processing and expect to start realizing savings in the second half of 2021 and into 2022. Water reuse is another source of significant savings, and we continue to expand and reuse infrastructure throughout our development areas. Finally, we have renegotiated several of the expiring higher-price contracts for drilling rigs and expect to see additional savings the remainder of this year and next. We also used the strength of our balance sheet to take advantage of opportunities to reduce future costs in several areas. As an example, last summer we pre-purchased the tubulars needed for our 2021 drilling program when prices were at their lowest point. EOG is not immune to the inflationary pressures we're seeing across our industry. But this forward-looking approach helps EOG mitigate anticipated cost increases. As a reminder, 65% of our well costs are locked in for the year and the remaining costs, we're actively working down through operational efficiencies. As usual, we have begun to secure services and products ahead of next year's activity with a goal of keeping well costs at least flat in 2022. But you can rest assured that with our talented and focused operational teams, our ultimate goal is always to push well costs down each year. The same amount of effort is being placed on reducing our per-unit operating cost with the results showing up in reduced LOE, driven mainly by lower workover expense, reduced water handling expense, and lower maintenance expenses. Savings are also being realized from our new technology being developed internally to optimize our artificial lift. We have several new tools that help us reduce the amount of gas-lift volumes required to produce wells without reducing the overall production rate. These optimizing tools not only reduce costs, but also help reduce the amount of compression horsepower needed, which ultimately reduces our greenhouse gas footprint as well. These and other continual improvements are a great testament to our pleased, but not satisfied, culture. This quarter, we can also update you on our final ESG performance results from last year. We reduced our greenhouse gas intensity rate by 8% in 2020, driven by sustainable reductions to our flaring intensity. Operational performance in the first half of 2021 indicates promise for further improvements to our emissions performance in 2021, putting us comfortably ahead of pace to meet our 2025 intensity targets for GHG and methane, and our goal to eliminate routine flaring. Achieving these targets is the first step on a path towards our ambition of net-zero emissions by 2040. Water infrastructure investments also continue to pay off. Nearly all water used in our Powder River Basin operations last year was sourced from reuse. For Company-wide operations in the U.S., water supplied by reused sources last year increased to 46%, reducing freshwater to less than one-fifth of the total water used. These achievements, along with the insight into ongoing efforts to improve future performance, will be detailed in our sustainability report to be published in October. We're starting to fill in the pieces on the roadmap to get to net-zero by 2040. Here's Ken with the details.

Thanks, Billy. Earlier this year, we announced our net-zero ambition for our scope 1 and scope 2 greenhouse gas emissions by 2040. Our ambition is aggressive, but achievable and we expect it will be an iterative process requiring trial and error. This approach mirrors how we develop an oil and gas asset. We pilot creative applications of existing and new technologies to determine the most effective solutions to optimize efficiencies by minimizing costs and maximizing recoveries of oil and natural gas. Here, we are aiming to maximize emissions reductions. We then apply the successful technologies and solutions across our operations where feasible. Our net-zero strategy generally falls into three categories: reduce, capture, or offset. That is, we are focused on directly reducing emissions from our operations, capturing emissions from sources that can be concentrated for storage, and offsetting any remaining emissions. Reducing emissions intensity from our operations is a direct and immediate path to reducing our carbon footprint. Our approach is to invest with returns in mind and seek achievable and scalable results. We made excellent progress in the last four years through initiatives to upgrade equipment in the field, invest in pilots using existing and new technologies, and leverage our extensive big data platform to automate and redesign processes to improve emissions efficiencies. As a result, since 2017, we have reduced our greenhouse gas intensity rate by 20%, our methane emissions percentage by 80%, and our flaring intensity rate by more than 50%. We recently obtained permits to expand the successful pilot of our closed-loop Gas Capture Project, which prevents flaring in the event of a downstream interruption. We designed an automated system that redirects natural gas back into our infrastructure system and injects the gas temporarily back into existing wells. The project requires a modest investment to capture a resource that would have otherwise been flared and stores it for future production and beneficial use. The result is a double-premium return investment that reduces flaring emissions. Our well-head gas capture rate was 99.6% in 2020 and rollout of additional closed-loop gas capture systems will hopefully capture more of the remaining 0.4%. Turning to our efforts to capture CO2, we're launching a project that will capture carbon emissions from our operations for long-term storage. This project is designed to capture and store a concentrated source of EOG's direct CO2 emissions. We believe we can design solutions to generate returns from carbon capturing and storage by leveraging our competitive advantages in geology, facility design, and field operations. Our carbon capture and storage efforts are directed at emissions from our operations, and we are not currently looking to expand those efforts into another line of business. We will provide updates on our pilot CCS Project as it progresses. EOG is also exploring other innovative solutions for GHG emissions reductions. Over the past 18 months, we have deployed capital into several fuel substitution projects to power compressors used for natural gas pipeline operations and natural gas artificial lift. Compressors are the largest source of EOG's stationary combustion emissions. By replacing NGL-rich field gas with lean residue gas, EOG can reduce the carbon intensity of the fuel, which lowers CO2 emissions and improves engine efficiency. Using lean residue gas also earns a very favorable financial return by recovering the full value of the natural gas liquids versus using those components as fuel. Another fuel substitution test we conducted recently was blending hydrogen with natural gas. While it is still in the early stages, we are analyzing the test data to evaluate the emissions reductions that would be possible from this blended fuel at an operational and economic scale. We're very excited about this part of the business, just like cost reductions, well improvements, or exploration success. This is a bottom-up-driven initiative. EOG employees thrive on this type of challenge. We create innovative solutions and apply technology to solve problems, improve processes, and optimize efficiencies while generating industry-leading returns. The EOG culture has embraced our 2040 net-zero ambition and we are focusing our efforts to minimize our carbon footprint as quickly as possible. Now, here's Bill to wrap up.

Thanks, Ken. In conclusion, I'd like to note the following important takeaways. First, by doubling our reinvestment standard, the future potential of our earnings and cash flow performance are the best they've ever been. Results from the first half of this year demonstrate the power of double-premium and the beginning of another step change in performance. Second, EOG is not satisfied. We're committed to getting better. Sustainable cost reduction and improving well performance are driving returns and free cash flow potential to another level. At the same time, the same innovative culture that is driving higher returns is also improving our environmental performance. Third, our commitment to returning cash to shareholders has not changed. As we have already demonstrated, returning meaningful cash to shareholders remains a priority. And finally, as Ezra transitions into the CEO role, I could not be more excited about the future of the Company. The quality of our assets, and the quality of this leadership team are the best in Company history, all supported by EOG's talented employees and unique culture that continues to fire on all cylinders. The Company is incredibly strong and our ability to get stronger has never been better. The future of EOG is in great hands. Thanks for listening. Now we'll go to Q&A.

Thank you. The question-and-answer session will be conducted electronically. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. The first question comes from Leo Mariani with KeyBanc. Please go ahead.

Hey guys, you obviously highlighted some success on the small bolt-on deals here. And I guess just from my perspective, it seemed like those were very, very economic, just very cheap per acre costs at around $2,500 per acre. A lot of it's just a function of the fact that these are very small deals and in captive to EOG existing acreage and infrastructure, which just gives you the natural ability to buy things without a lot of competition. And I just wanted to get a sense of how repeatable these types of bolt-ons can be for you guys going forward.

Yes, thanks, Leo. I'm going to ask Ezra to comment on that.

Leo, you described that very well. These are smaller deals, as I highlighted. It's 25,000 acres across eight different deals that we've captured and put together over the past 12 months. And these are low-cost opportunities in our core positions within the Delaware Basin. And typically, these are things that are either contiguous with our pre-existing acreage position or very, very close to our acreage position. And so there's not a lot of outside competition. A lot of times, by all regards, we're the partner that makes sense to go ahead and get these deals because, like I said, we have the surrounding wells information, seismic, and oftentimes some of these deals can go immediately right into our existing infrastructure. We highlighted the last 12 months, but we wanted to give a sense of the type of scale and the impact that these low-cost opportunities can have when we're focused on them. And these deals are pretty continuous throughout all of our plays and throughout the year.

Okay. That's helpful. And I guess I also wanted to ask about your comment around seeing a less than $7 per BOE finding and development cost year-to-date. Clearly, you attributed some of the factors there to how your well costs are coming down as part of it, and also the move to double-premium. But maybe you can provide just a little bit more color, I mean, I guess that less than $7 seems like a very low number out there. Are there any other just key factors where maybe there's more of a mix shift to certain plays where perhaps your higher concentration of certain zones in the Delaware this year? And I know you guys are also drilling some gas wells in South Texas that might be helping; just any color around some of the key drivers for getting it to under $7?

Hi Leo, Billy Helms will comment on that.

Yeah. Good morning, Leo. It's strictly a function of moving to our double premium strategy. We saw a similar change, if you remember back when we shifted to premium a few years ago, and we're seeing that same compounding effect as we shift to double premium. The quality of our wells improves. And as you noted, we have a history of continuing to focus on lowering well costs and just our continued effort in those areas. So it's not really attributable to one basin or the other, it's just a function of the impact of shifting to double-premium across our portfolio. And I might add, as we look to add wells to the inventory of double-premium wells, they will all be in that same category to compete on both returns and finding costs.

Thanks, guys.

The next question is from Neal Dingmann with Truist Securities, please go ahead.

Good morning, guys. Nice quarter. My first question is really just around when you talked about shareholder return, obviously that seems to be the hot topic these days. Billy, I'm glad you don't do this, but my thoughts about if you guys would ever... There's been others out there that have guaranteed a type of return, or amount, or something like that; you guys seemed to want to stay more flexible, but I would just love to hear more color on obviously, you guys have significant amounts of free cash flow coming in, that's not the issue. I'm just wondering how you think about if you put any sort of guarantees on the type or amount going forward.

Yeah, Neal. We've outlined a very clear framework and we've consistently delivered on our priorities. And so maybe the best way to think about the future is to look at what we've done in the past. And I want to ask Ezra to give more color on that.

Yes, Neal. In our investor presentation there on slides 5 and 6, I think we can reference that. This year we've been very successful executing on all of our cash flow priorities in the framework that we've laid out. We've been able to increase the regular dividend by 10%, which we feel is our primary motive of capital return. Secondly, we're able to reduce our debt earlier this year by $750 million by retiring a bond. And then third, we just paid a $600 million special dividend on July 30th of this year, which we had announced during the last earnings call. So our year-to-date free cash flow commitment is $2.3 billion, which is slightly more than the $2.1 billion we generated. And going forward, our framework and priorities have not changed. Lastly, we also highlighted in the opening remarks, as we just spoke about a little bit with Leo, some of the small bolt-on acquisitions we've done, which is one of the avenues to growing our inventory, and that's really where the entire process begins, is having the depth in quality of inventory to continually improve the business. And with our shift to drilling these double-premium wells, the free cash flow potential, the Company continues to expand and as it does, and as we realize the cash, we're well-positioned to continue executing on our priorities. We're committed to creating the most shareholder value and our cash return strategy is really a reflection of that. So, as the Company continues to improve, we're excited about that potential.

I agree with you. I really appreciate the cash return strategy. Just a follow-up on exploration opportunities, which you continue to excel in as leaders. You mentioned several factors that excite you. Could you remind us of the number of unique projects in the U.S.? Was it around 13 or 15? Could you discuss the upside potential you foresee for that business this year as we head into 2022?

Neal I think what we've outlined is we've got about 15 exploration wells built into the CapEx this year in the U.S. So I am going to ask Ezra to give us some more color on that.

Yes, Neal. The exploration prospects are all moving forward. As we discussed on the last call, the prospects have all started to move at different phases, really as a result of some of the slowdown during COVID and during 2020. As Bill just mentioned, we're planning on drilling 15 wells outside of the publicly discussed assets. Some of these, in some of the prospects, our initial exploration wells. Some of them are more what we'd call appraisal wells, evaluating the repeatability of these plays. We're still leasing across many of the plays as well. And as we've discussed, the opportunities are really targeting higher quality rock and what's typically been drilled horizontally. That's an outgrowth of a lot of technical work we've done across multiple basins to combine modern drilling and completion technologies, and apply those to reservoirs that have been traditionally overlooked. And really, we're very happy with our progress to date and we look forward to sharing additional information at an appropriate time.

Great details. Thank you, all.

The next question comes from Doug Leggate with Bank of America. Please go ahead.

Thank you, everyone. This is the first time I've had the opportunity to see Bill. Congratulations on your retirement. Ezra, I'm looking forward to seeing how you progress the business. Bill, could you share some reflections as you exit? There have been many changes in the business model, with a shift towards free cash flow. I'm curious about your thoughts on how the business should develop going forward, both at the sector level and specifically for EOG, as you reflect on your time and the transformations that have occurred.

Yeah, Doug. Well, thank you very much. And you're right. I mean, the business has evolved over the last year since the shale business really started. And it's obviously moving in an incredibly positive direction right now, with the focus on returns, that we've always been I think a leader in focus on returns, and we're super excited about that. The capital discipline, spending well below cash flow and generating high returns, and giving a significant amount of cash back to shareholders, I think is certainly all very positive. And so I think, really, we're entering a super new era. And I think it's more positive than it's ever been before. I think we, as an industry, are going to generate better returns and going to give more back to the shareholders. And I think we're in a more positive macro-environment than we've been in since really the shale business started. I think OPEC + is solid. I think the U.S. will remain disciplined. And so I think the industry is in for a long run of really good results.

We've been bumping heads with you over the years, Bill, so congratulations again, and good luck. Ezra, my follow-up is maybe for you. EOG has obviously been an organic story for many, many years and you've touched on exploration again today, but Yates was one of the, I guess, the step-out acquisitions that you did and if you look at your portfolio position today. There's clearly a large asset potentially for sale right in your backyard and a very high-quality acreage position you could argue, why would M&A not be a feature of the business at some point, and maybe I go so far as to say would you rule yourself out of being interested in that shell package. Thank you.

Yes, Doug. No, we're not evaluating any large acquisition packages at this time. We're focused on these small high-return bolt-on acquisitions. And as discussed in opening remarks, the larger expense of M&A deals, the opportunity struggled to compete with the existing return profile that we have within the Company due to either high PDP costs, the high acreage costs, or both. Oftentimes the acreage being marketed might be additive to the quantity of our inventory, but not additive to the quality. And as we've discussed we're always working to improve the quality of our assets. We're having great success with the small bolt-on acquisitions. We're feeling very confident with our ability to increase the quality of our deep inventory through our organic exploration program. And so we're excited about our prospects there.

The next question comes from Paul Cheng with Scotiabank, please go ahead.

Thank you. Good morning, everyone. I have two questions. First, Bill, could you help clarify the decision regarding the special dividend? Last quarter, when you announced the specialty, you outlined several key conditions that have been met, like significant free cash flow in January, minimal near-term debt maturities, and cash levels exceeding what you consider reasonable. This quarter, those conditions are still in place, so why was the decision made not to pay the special dividend? We're trying to understand what additional factors influenced that choice. Also, could you discuss the comparison between buybacks and special dividends at this stage in the cycle, which is more favorable for you or how you see the differences?

Paul, regarding your first question, it's crucial to note that we have a clear framework that we've consistently adhered to. We've returned significant amounts of money to shareholders and, going forward, our priorities remain unchanged. As we continue to generate free cash flow, we plan to return cash to shareholders in meaningful ways. It's about making the right decisions at the right time. As the company improves, we're optimistic about increasing total shareholder return. Within our framework, we have the option for opportunistic buybacks and special dividends. We view buybacks as a viable option in counter-cyclical environments when the market is struggling and our stock price is undervalued. In prosperous times, we believe special dividends are the preferred approach, and that's what we're currently executing and plan to continue.

In response to the second part of your question regarding large-scale M&A, I will have Billy address that and share his thoughts. We are not focused on increasing the quantity of our inventory; rather, it is about the quality of our existing assets. When considering potentially forming a larger joint venture, this approach remains crucial. If our assets fall within what we view as our core acreage position, adding acreage beyond that could undermine our efforts. As you know, we've invested significantly in building infrastructure to reduce our unit costs and enhance our returns, and this infrastructure aligns with our development volume expectations. The relevance of this infrastructure could change if we were to incorporate additional acreage outside our core. Each operator aims to maximize the efficient use of their acreage and capital, and joint ventures may not necessarily enhance the overall metrics for the company. While we have explored bolt-on acquisitions to strengthen our core area, this strategy also applies when considering joint venture expansions. It's important to maintain asset quality and avoid dilution while expanding in a basin.

Thank you.

Your next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yeah. Good morning. Tim, maybe starting with you. I just wanted to get maybe some of the order of operations around a potential incremental cash return beyond the dividend. Last quarter, you mentioned that EOG likes to keep a $2 billion minimum cash balance plus fund, the $1.25 billion bond maturity. So that suggests that you'd like to get to $3.25 billion of cash, and anything beyond that is available for cash return beyond the dividend?

Certainly, you can do that math, but it's more than that with us. As Ezra and Bill talked about further, we have to look at all of our priorities and the timing of those priorities to determine when and if there is another special dividend, or share repurchases, or bolt-on acquisitions. All those things are in play at all times. And the $2 billion is not the end of the month number; it's during the cycles, so cash can vary tremendously during a month. The $2 billion is the low point during the month, it's not necessarily the end of a month. So you have to keep that in mind as well, but yes, you can do that math. But that's not all there is to it. We have to look at all of our priorities and where we're at in the cycle. And as it has been pointed out on Slide 6, we've already distributed more cash than we brought in, in the first half of the year. So we're well on our way to achieving that. As we move through the second half of the year, we'll look at what other cash is generated and we'll evaluate how to use that cash at that time.

Great. And maybe just a follow-up to Paul's question. Could you give us maybe some feedback you've gotten from some of the shareholders on the special dividend and your thoughts on the pros and cons of moving to a formulaic type of approach around cash return and even especially in terms of buyback?

Yeah, Arun. This is Bill. We've gotten enormously positive responses from every shareholder on the special dividend and that was a super hit. And they like our framework; when you really think through it, it's not really a complicated framework. It's a framework where we want to be in a position to maximize total shareholder returns. And as I've said, to be able to do the right thing at the right time. If you look at the history of what we've been doing really over the last several years, we've increased the regular dividend by 146%, and now we're working on special dividends. As we go forward, it is certainly our goal to continue to return meaningful cash back to the shareholders through the process. So really, it's a pretty straightforward process if you think through it, and the framework is pretty simple. And it's just a matter of giving us the ability to have the options to do the right thing to maximize total shareholder return.

Great. Bill, thanks a lot.

The next question is from Michael Scialla, with Stifel, please go ahead.

Hey, good morning, everybody and Bill, I'd like to offer my congratulations on a great career as well. I know it's too early to give details on 2022, but want to see if you could speak to at least at a high level given your outlook for flat to lower well costs next year. If you still see barrels held off the market by OPEC +, would you just look to hold production flattish, and could you do that with equal to lower capital than you spent this year?

Well, thank you very much again; we appreciate your comments. It's a team effort in EOG. I'd tell you what, we've got a lot of great employees and a super management team. It's a team effort and it's been an honor to be able to work with everybody. About 2022, it's really too early to talk about growth. We need to watch the pace of demand and recovery on the spare capacity drawn down. So we don't want to really speculate on anything specific for 2022, but I want to ask Ezra to make some additional color on that.

Yes, Michael. As Bill mentioned, it's still early to discuss growth for 2022. EOG is committed to not growing until the market demonstrates a clear need for barrels, and we have specific criteria in mind. We are dedicated to maintaining discipline. Right now, we want to see demand return to pre-COVID levels, low spare capacity, and inventory data below the five-year average. Each year, market factors will dictate our plans, and we will remain flexible to adjust them according to market conditions. However, we have made significant strides this year in reducing our total well costs. Looking ahead, this will enhance the underlying capital efficiency of the company and further decrease our cost base. As we progress, irrespective of growth rates, we have established a double-premium investment plan to continue enhancing EOG's free cash flow generation potential.

Okay. And I guess, really just my question there was, if you were to hold the production flat, it looks like the capital required to do that is not going up, at least over the next 12 to 18 months as you see the world now; is that fair to say?

Yes, Mike. That's certainly fair to say. I mean, we're reducing costs all the time and improving well productivity. So, we're hopeful that our maintenance costs in the future will be lower than they are today. And that's certainly directionally what we've done in the past, and hopefully what we're going to do in the future.

Okay, great. I want to follow up with Ken about the CCS pilot you mentioned. Can you provide more details regarding whether it's focused specifically on EOG at this stage? Can you elaborate on the sources of emissions you are targeting within your area? Additionally, are you considering storing CO2 in depleted fields or working with partners? Any further information you can share would be appreciated.

Sure. Thanks for that question. At this point in time, we really don't anticipate any partners on our pilot project, but with our geologic and operational expertise, we'll evaluate partnering on future projects on a case-by-case basis. This project is really part of our broader strategy of reduced capture and offset. And it's focused on capturing our CO2 emissions in an area where we can generate a return via some tax incentives, and have a concentrated stream of CO2 that can be aggregated to an injection well for permanent and secured geologic storage, in an interval of thousands of feet below the surface. And that's pretty much what we're giving out at this time.

Very good. Thank you.

The next question comes from an unknown speaker, please proceed.

Good morning. To put you on the spot a little bit. You highlighted the various well cost categories, tubulars stick out as being both significant and also exposed to inflation. You tackled the problem last year with pre-purchasing. Can you throw out some ideas that the organization has come up with to attack that cost category?

Billy, do you want to comment on that?

Yeah, good morning, Bob. Obviously, yes, steel costs are going up, which is affecting tubular costs. This last year, we were very fortunate to take advantage of pre-purchasing the tubular we needed for this year's program and benefited greatly from that. As costs go up in the future, we use the same approach and try to take an opportunistic look at when to secure tubulars for the next coming drilling program. And so, we'll continue to look at that. Undoubtedly, it's likely that the costs for tubulars will be higher next year than they are this year, which is why in that slide number 10, we tried to give you some color on other ways we're trying to keep our well costs flat to down going into next year and those come from the efficiencies we're seeing across the operation from drilling times to the implementation of our super-zipper technology on the completion side to newer contracts at lower rates for some of the services we have. So it's a mixture of things we use to offset those inflationary pressures that we see in the different parts of our business.

Okay, that's clear. And just as a quick follow-up, could you contrast super-zipper the way you think about them versus say, a traditional zipper frac that we might think of where even a dual frac?

Sure. So our super-zipper technique is very similar to what the industry calls zipper fracs. The differences would be in how we actually implement it on a well-to-well basis. We keep very close control over the injection rates and pressures of individual wells within the super-zipper operation. So it's a very scripted and very detailed procedure that allows us to control the rates and pressures, just like we're doing a conventional frac with any other fleet. But the advantage is of course being able to double the amount of stages you get in a particular day by attacking the locations two at a time. And we really are advancing that technology quite a bit. Last year, we probably did less than 10% of our wells, across the Company benefited from super-zipper, this year, it's probably directionally closer to a third of the wells. And we expect that percentage to increase going into next year. We think it's going to give us tremendous cost advantages next year as we go into the program.

Great, thanks for that.

The next question comes from Scott Hanold with RBC Capital Markets, please go ahead.

Thanks. And Bill again. I also want to give you congratulations on your tenure. Obviously, you all navigated a lot of ups and downs over the past few years fairly successfully. So congrats for that. I just have one question, and you all seem to be doing better than expected. I mean, certainly, it seems like production, especially oil production on the upper end of your range. And can you just give us some general thoughts, I know you're not in a position where you're going to talk to 2022 and how you think about growth? If you are running a little bit ahead based on the outperformance of your wells, would you think about tapering as you get into 2022 a little bit just to maintain the flattish kind of production you all expected this year?

Yeah, Scott, again, thank you so much for your comments. I'm going to ask Billy to comment on the remainder of this year and particularly the Fourth Quarter.

Yeah. Good morning, Scott. So, certainly, we're very pleased with the progress we've made on both reducing our well costs and the performance we're seeing from the wells we are bringing to production this year. It's a testament to the strategy of shifting to the double-premium standard again. So, as you go into the rest of the year, we started out the year with a little bit higher activity level, we had a little bit higher rig count at the start of the year and this tapered off and we're running at a pretty consistent rate now and expect that to continue through the end of the year. And then next year, as Bill elaborated, it's hard to anticipate what we'll need this year, but I think the performance that we're seeing this year will continue into next year, certainly. And the pace of activity will be dictated by what we see in the market conditions. So that's the color I could give you. But our performance will continue to at least stay flat or improve.

Understood. Thank you for that.

The next question comes from Neil Mehta with Goldman Sachs and Company.

Good morning, team. And congratulations, Ezra. Congratulations, Bill. Bill, last Quarter, you talked a little bit about the analytics that you are building around monitoring the oil macro. I would love your latest real-time thoughts, a lot of moving pieces here. OPEC, demand uncertainty, barrels, U.S. supply, how are each of these parameters evolving here as you guys are evaluating them?

Yes, Neil, as we've all observed, demand is experiencing a strong recovery, although it's somewhat uneven due to the resurgence of the virus in certain regions. However, we anticipate that pre-COVID demand levels will be reached by early 2022. Inventories have already fallen below the five-year average, both in the U.S. and globally. This situation has already been addressed. On the supply side, as I mentioned earlier, we believe that the U.S. will maintain a disciplined approach, with modest growth expected next year, but nothing substantial. OPEC+ appears to be quite stable, and they will continue to incrementally restore their shut-in volumes as necessary. If the recovery progresses as we predict, we foresee spare capacity being very low by the second quarter or mid-next year. We'll need to monitor how it unfolds, but overall, we view the macro-environment positively.

The follow-up is just, as you think about the U.S. production profile, maybe you can get a little bit more granular in terms of how you're thinking about those volumes. But the question we continue to get asked is, where are we in terms of resource maturity? Has the best of efficiencies been driven out of the shales? And maybe you talk about the Permian, the Eagle Ford, and the Bakken. What are you seeing in each of those plays? Where are we in terms of efficiencies? And then is the slowdown in U.S. production being driven by resource maturity or is it really being driven by capital discipline?

We analyzed the data from various groups, including private, public, and major companies, and found that particularly in the private sector, productivity is definitely declining. This means that it requires significantly more wells for that segment to either maintain or consider increasing production. Generally, across other groups—not just EOG—we observe that well production is remaining flat or not improving over time. This situation seems to be related to resource maturity. Factors such as down-spacing, spacing, and timing appear to be dampening productivity. The main factor at play is capital discipline, as companies are spending much less cash flow compared to the previous year. When we consider all these factors, we do not expect to see significant growth in U.S. production next year. This outlook is likely positive for shareholders and beneficial for the broader market.

Thanks, Bill.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Thomas for any closing remarks.

In closing, I'd like to say thank you to all the EOG employees who continue to make EOG so successful. It's truly a privilege and an honor to be on the same team with each one of you. As Ezra transitions into the CEO role and Billy steps up to President and Chief Operating Officer, along with the rest of the senior management team, I could not be more excited about the future of the Company. So to all shareholders and future shareholders, we want to tell you thanks for listening and certainly thank you very much for your support.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.