EOG Resources, Inc.

Good day, everyone, and welcome to the EOG Resources First Quarter 2022 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. This conference call includes forward-looking statements, factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call also contains certain non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures can be found on EOG's website. This conference call also include estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Jacob, Chief Executive Officer, Billy Helms, President and Chief Operating Officer, Ken Bedecker, EVP Exploration and Production, Jeff Leitzel, EVP Exploration and Production, Lance Turveen, Senior VP Marketing, and David Streit, VP Investor and Public Relations. Here's Ezra.

Thanks, Tim. Good morning, everyone. EOG's cash return strategy demonstrates our commitment to deliver long-term shareholder value. Yesterday we declared a second special dividend for the year of $1.80 per share following last quarter's $1 per share. Combined with our peer-leading annualized regular dividend of $3 per share year-to-date, we have announced $3.4 billion in cash return to shareholders in 2022. EOG has a strong history of cash return. Since we began trading as an independent company in 1999, we have delivered a sustainable, growing regular dividend. It has never been cut or suspended, and its 23-year compound annual growth rate is 22%. Since the transition to premium drilling in 2016, our dividend compound annual growth rate has been even higher at 28%, including doubling our dividend last year. Today, our regular dividend not only leads our E&P peer group, it is more than competitive across all sectors of the market. More recently, we have supplemented our regular dividend with significant special dividends, reflecting our commitment to both capital discipline and returning cash to shareholders. While we are proud of our cash return track record, we acknowledge shareholders' desire for more transparency and predictability. To provide both, we recently formalized and yesterday announced our cash return commitment of returning a minimum of 60% of annual free cash flow. Going forward, our intention is to evaluate and pay the regular dividend and consider options for additional cash return every quarter. The addition of quantitative guidance to our cash return framework reflects our confidence in our business. The pandemic-driven volatility in the oil and gas market is stabilizing. However, the macro environment continues to evolve with the war in Ukraine and other geopolitical events. We have proven to ourselves over the last several years that our business is resilient through the cycle. including unprecedented shocks to the industry. Credit for EOG's resilience for the steady improvement in our ability to generate free cash flow in any environment and the ability to make this free cash flow commitment to our shareholders goes to our employees who embraced our premium return hurdle rate six years ago, which requires that all investments earn a minimum of 30% direct after-tax rate of return using a $40 flat oil and $2.50 flat natural gas price. Last year, we doubled the minimum return to 60%. Both the premium and now double premium hurdle rates have positioned the company to have an outstanding year in 2022. In spite of the ongoing inflationary and supply chain issues facing our industry, our employees outperformed during the first quarter in our position to deliver on our annual capital and volumes plan. We have decades of low-cost, high-return inventory that support the consistent financial performance that our shareholders have come to expect and that drives long-term value. Our inventory spans multiple assets across oil, combo, and dry natural gas basins throughout the country, which enables us to pursue the highest netbacks by diversifying both our investment and sales market options. We also continue to explore. A year and a half ago, we announced Dorado, a premium dry natural gas play where we've captured 21 TCF of resource potential net to EOG. In a moment, Ken will update you on the progress we've made on well performance and well costs in what we believe is the lowest cost and lowest emission source of natural gas onshore U.S. Our organic exploration program has grown our premium inventory by more than three and a half times since the premium metric was introduced in 2016. So our exploration program isn't focused on adding more. We are looking for better inventory. New plays like Dorado and the potential we see in our current exploration pipeline gives us confidence we will continue to grow and improve our double premium inventory in the future as we have done in the past. While we have earmarked and committed to return a minimum of 60% of annual free cash flow, our longstanding framework and priorities for total free cash flow are unchanged. a sustainable growing regular dividend, a pristine balance sheet, additional cash return to shareholders through special dividends and opportunistic stock buybacks, and low-cost property bolt-ons. Sustaining and growing the regular dividend remains our highest priority and reflects our confidence in the long-term performance of the company. A pristine balance sheet is a strategic advantage functioning as a shock absorber that also provides the flexibility to exercise a buyback when the opportunity arises and to take advantage of other counter-cyclical investments. Additional cash returns through special dividends and buybacks complement our other priorities and together with our free cash flow minimum return guidance support our goal to create significant long-term shareholder value. Now here's Tim to review our financial position.

Thanks, Ezra. Our ability to refine our long-standing cash return framework by providing quantitative guidance is made possible by EOG's outstanding operational and financial performance. In the first quarter, EOG earned $2.3 billion after adjusting items, or $4 per share. We generated $2.3 billion of free cash flow. Capital expenditures of $1 billion were near the low end of the guidance range, while production volumes and total per unit cash operating costs finished better than targets. Our confidence is further bolstered because we finished the quarter in an incredibly strong financial position. Total debt on March 31st was $5.1 billion. This includes the current portion of debt of $1.25 billion, reflecting a bond that matures in March 2023 that we intend to pay off with cash on hand. Cash on March 31st was $4 billion for a net debt of $1.1 billion. This yields a debt to total capitalization ratio of 4.8%. The $4 billion cash balance excludes $2.4 billion of collateral for hedges held by our counterparties. The amount of collateral fluctuates with oil and natural gas prices. These short-term timing differences in cash flows are not considered in our calculation of free cash flow and do not influence our decision on the timing or amount of cash return to shareholders. To that end, EOG has declared special dividends so far this year totaling $2.80 per share on top of the regular dividend of $3 per share on an annual basis, totaling $3.4 billion. Our objective in establishing our cash return guidance was to make it simple yet dynamic so that it is easily communicated and understood while remaining suitable under a range of commodity price scenarios. The actual amount of cash returned each year is a product of our longstanding free cash flow priorities. These have not changed. The size of our regular dividend is now the largest of our EMP peers, and the strength of our balance sheet supports our ability to return a large portion of free cash flow back to shareholders going forward under a range of scenarios. The $1.80 special dividend declared yesterday, along with the $0.75 regular quarterly dividend, demonstrate significant progress toward our commitment to returning at least 60% of our 2022 free cash flow to our shareholders. Subject to commodity prices, the amount of free cash flow available, and the board's discretion, our intention is to return cash through special dividends or stock buybacks on a quarterly basis going forward. Here's Billy.

Thanks, Tim. We've had a great start to the year. Our first quarter volume, capital expenditure, and total per unit cash operating cost performance exceeded our forecasted targets. We're also pleased with our progress to date, offsetting inflation and managing well cost. Our drilling teams continue to reduce drilling days and generate consistent performance improvements. Use of self-sourced downhill tools, as well as minimizing downtime and mud losses, remain areas of focus to improve performance. For example, drilling times in our Eagleford oil play continue to improve, decreasing 28% in the last five years. The average well is now drilled in less than five days. On the completion side, we have increased the amount of treated lateral per day by about 10% over the last year as we further deploy the super zipper technique. We are now using this technique on more than half of the wells completed in the company and expect to increase its use further as we progress through the year. In addition, our self-sourced sand program is providing a tremendous advantage that we expect to further offset additional inflation throughout the year. When we established our plan at the beginning of the year, we knew the unusually tight supply constraints initially sparked by the economic recovery from the pandemic would present a unique challenge. Taking these headwinds into account, this year's plan was developed with known efficiency improvements that would maintain well cost flat with this last year. While we have since seen increased steel and fuel prices directly associated with the war in Ukraine, we are confident we can still deliver on the CapEx and volume targets in our original plan. Rather than accept inflation as a given, our employees remain proactive. We have a track record of lowering costs and developing efficiencies through periods of economic expansion and other drivers of inflation. Our operating teams are ever more diligent in their quest to identify new areas of performance enhancements that will lower well cost. EOG's advantage lies with our people and our culture. Today's challenges are met with innovation and value creation in the field through our multi-basin decentralized approach. This period of inflationary fuel prices is the primary driver of the 2% increase in our full year per unit cash operating costs versus our previous guidance. However, higher commodity prices also present an opportune time to enhance our workover program, which will be reflected in LOE expense. These additional workovers bring on low-cost production. They pay out within weeks and increase the long-term performance of our assets. All in all, we're thoughtfully managing our assets to offset a small effect from inflation. While we have flexibility to adjust our plan in any given year to respond to unique or extreme market conditions, such as the pandemic in 2020, our capital plan is thoughtfully planned across all our assets to support the pace of operations that is optimal for each individual asset to continue to improve. We believe we have the best people, assets and plan to mitigate any headwinds and continue to improve the company for the long term. Here's Ken to discuss the incredible improvements we made in our premium gas play Dorado.

Thanks Billy. A year and a half ago we announced a major new natural gas discovery in South Texas we named Dorado. It's a dry gas play with 21 TCF of resource potential, net DOG, across stacked pays in the Austin Chalk and Eagleford formations. Our break-even cost in Dorado is less than $1.25 per MCF, which we believe represents the lowest cost of supply of natural gas in the United States. Dorado is the most recent double premium play to emerge from our organic exploration program. We began technical work on Dorado back in 2016, captured a large acreage position in the core of the play as a first mover during 2017 and 2018, and drilled test wells in late 2018 and 2019. After pausing during the downturn in 2020, we moved Dorado into active development last year and completed 11 net wells. This year, we anticipate completing 30 net wells, nearly tripling activity. Since last year, we have doubled our production rate out of Dorado, producing 140 million cubic feet per day in the first quarter of 2022. We are leveraging our proprietary knowledge built from prior plays to move quickly down the cost curve as we increase activity at a pace that allows us to incorporate learnings and savings. We completed seven net wells during the first quarter of 2022 while keeping well costs flat compared to similar designs in the first quarter of last year. successfully offsetting inflation. Since our first wells drilled in 2018, we have reduced well costs over 35% and are approaching our target well cost faster than we anticipated. In addition, well performance is improving. Productivity from recent wells is significantly beating our initial forecast. Refined completion techniques and a focus on targeting have increased our performance projections on a per foot basis. This year, we have also moved to longer laterals, which, combined with the improvements to per-foot productivity, have resulted in an 80% higher two-year cumulative production volume than our 2018 wells, compounding our capital efficiency. Our preliminary plan for the play was to focus initial development on the Austin Chalk Formation and then follow that with development of the Eagle Firth. so it would benefit from well cost reductions as well as water and gas gathering infrastructure installed for the Austin Chalk. With the dramatic improvements to our Eagle Ford Formation well results, we now expect to co-develop it with the Austin Chalk, which will provide additional opportunities to lower costs through scale and simultaneous operations. As a dry gas play in close proximity to multiple markets, We expect Dorado's gas will have a lower emissions footprint compared to other onshore gas supplies in the U.S. In addition, we continue to leverage company-wide expertise to build out an operationally efficient and low emissions field. As we expand development of Dorado into a core asset, it will contribute to lowering EOG's company-wide emissions intensity rate. Combined with EOG's low operating costs and advantaged market position, Located close to several major sales hubs in South Texas, including access to pipelines to Mexico and several LNG export terminals, Dorado is in an ideal position to supply low-cost, low-emissions natural gas into markets with long-term growth potential. Now, next up is Ezra for concluding remarks.

Thanks, Ken. I'd like to note the following important takeaways from the call today. Formalizing our cash return strategy demonstrates our commitment to our free cash flow priorities that, along with high return, disciplined reinvestment offers significant long-term shareholder value. Second, EOG is realizing another tremendous year of improvement. We are set to deliver outstanding returns while demonstrating capital discipline within an inflationary environment, delivering on both volumes and capital as announced at the beginning of 2022. Third, our most recent organic exploration announcement, Dorado, has positioned us with over 20 TCF of low-cost natural gas with access to multiple markets. Our progress in Dorado is on pace to make this North America's lowest cost of supply. Thanks for listening.

Now we'll go to Q&A.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. If you are 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 from the queue by pressing star and two. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question today comes from the line of Doug Leggett with Bank of America. Doug, your line is open.

Well, thank you. Good morning, everybody. And Ezra, I think I'll speak for everybody in saying we're delighted to see the framework you've introduced for cash returns. I do have a question around this, however, and it is, I'm just curious what's changed to move you in that direction. And I wonder if I could ask you to, you're obviously talking about percentage of free cash flow. So I wonder if you could frame some similar parameters around how you think about reinvestment rates or the planning assumptions that go around that so we can get some kind of idea as to what free cash flow ultimately looks like versus the level of spending, if you see my point.

Yes, Doug, I sure do. So let me start with, you know, the what is now, you know, why now. And, you know, simply we feel that this is the right time for our business to come out with the additional guidance. We've got the regular dividend increase to be competitive with the broad market. We've got the balance sheets, you know, in a very strong position. And we're basically emerging stronger from the downturn and confident that we can deliver this minimum amount of cash return going forward. You know, it's consistent with our long-term free cash flow priorities, so it's not really a change in strategy. In fact, in 2021, we returned about 49% of free cash flow, and we paid off a $750 million bond. So when you combine those, that was about 60%. And so it's a range internally we've discussed, and the announcement really just provides a bit of transparency. Now, on the second part of your question with regards to How are we thinking about the reinvestment growth and to get to free cash flow? One reason we have given this guidance as a minimum of 60% return on free cash flow is because it's a guide that can be consistent and long-term in nature through the cycle, like how we manage the business. Basing the guide off of a free cash flow puts us in what we feel is the best overall position to create shareholder value through the cycle. So nothing's really changed in the reinvestment strategy. It's first always based on returns and our ability to get better each year. As we've said in the past, there's no reason to invest in growth if you're not generating high returns and you're not doing it with an ability to improve the underlying business year after year. And what that means is not chasing free cash flow just because of high prices if you're investing in something that's eroding the business long term. You can take today, for example. We could increase activity today into these high prices, but in the inflationary environment, that's going to erode our capital efficiency. And then the second piece that we've talked about as far as reinvestment or growth is based on the macro environment and market fundamentals. Does the market really need the barrels? What's supporting the global supply and demand fundamentals? Ultimately, investing in premium and double premium, as you know, has made us somewhat price agnostic, basing those decisions on $40 oil and $250 natural gas. And so it's really the capital discipline comes down to what can we do and are we investing at a pace where each of our assets can get better year after year and ultimately improve the overall returns and company profile?

I appreciate the answer, Ezra. I think, as I say, we are welcome by what you've done, so thank you for that. My follow-up is hopefully a quick one. So some years ago, you guys pivoted away from natural gas. The Rado, obviously, is the exception today, but you also took a right off. of a lot of your legacy gas assets. The world has obviously changed, so I'm just wondering, within the company, is there any effort or, I guess, initiative to pivot back to some of those legacy gas assets that are obviously still in your portfolio in light of what's going on as it relates to LNG expansion longer term? I'll leave it there. Thank you.

Yes, Doug. You know, as you said, the world's changed a lot and the company's changed quite a bit. The biggest thing for us is that introduction of the premium and now double premium reinvestment hurdle rate. So all of our gas assets now are judged at $2.50 flat natural gas price for the life of the well. And that really high grades our reinvestment opportunities into any of our assets, but especially the natural gas ones as we're talking about right now. Ultimately, what we see with Dorado is that we've captured a very significant resource geographically in the best spot. We think onshore U.S. with access to multiple markets, and we're very excited about being able to focus in on really that asset that we have. We think it's going to be the premier asset in North American natural gas.

Question for sure. Thanks for taking my question. Thank you.

Our next question comes from Charles Mead with Johnson Rice. Charles, your line is open.

Good morning, Ezra, and to the whole EOG team there. Ezra, kind of picking up on the point you just made, I'm curious. I get that you evaluate all your projects at 40 and 250, and that services the best oil projects and best gas projects. Is there any concern or discussion inside EOG that maybe evaluating projects at something so far below the strip is actually giving you a suboptimal relative ranking across oil and gas assets?

Yes, Charles. The way we look at it is we've been fortunate. We've been in unconventional North American exploration here for nearly two decades, honestly. What that's allowed us to do is put together a multi-basin portfolio of what we think is really the deepest and highest quality asset inventory. When we switched to premium, it was really taking a long-term look at that $40 price, $2.50 natural gas price, to not only help the immediate returns, the rate of return, the IRRs up front, but really thinking about longer term through the cycles. What does it mean to really build a company where, based on a commodity price, you can still be successful and create value through the cycles? Ratcheting that up to double premium in 2020 was really a reflection of our ability to have grown our premium inventory three and a half times through organic exploration since 2016. So actually, I think the focus on double premium drilling and that reinvestment hurdle rate actually provides us with an optimal way to rank our assets.

Okay. Thank you for that insight. And perhaps going back to Dorado, I caught during the prayer comments that I think that the two-year QM is 80% higher than your 2018 case. And part of that uh, is longer laterals. And I think that the base was, uh, the, the kind of the 2018 case was 9,000 foot lateral. So it is, am I making, am I in the right ballpark to thinking that if, uh, you know, 80% higher two year cum, some of that's longer lateral. So we're looking at maybe 40 or 50% higher, uh, productivity per lateral foot in the Dorado play versus, uh, versus the earlier case.

Yeah, Charles, this is Ken. Um, We haven't really given out a number on how much higher the productivity is. If we look back to those 2018 wells, they were shorter laterals in the 6,000 to 7,000 foot range. We now have some extended laterals even past our original 9,000 foot range that we thought we'd get. And those things, both the improved performance and the lower costs have really driven that finding cost down to almost the 40 cent target that we're showing on slide 11 there.

but, but no, no, uh, you don't care that well for any, uh, comments on the productivity per lateral foot, I guess. And, uh, that's fine. Thank you.

I guess Charles, just what I would say is, you know, it is, uh, our, our wells are beating our type curves that we have. And those type curves do have a fairly low decline over the first several months of production. So we are seeing beating, seeing them, them beating our type curves and, and, uh, If you look at it, we've really only drilled 30 of our 1,250 wells in that place, so we're continuing to learn.

Thank you, Ken.

Our next question comes from with JP Morgan. Your line is open.

Good morning. My first question is just on the supply chain. You guys are holding the line on CapEx. A number of your peers have raised CapEx expectations. So I was wondering if you could comment what's unique about the way you're managing the supply chain to give you confidence on delivering the $4.5 billion CapEx budget and do some of these supply chain headwinds we're seeing within the industry, how does that influence your thoughts about 2023 given shortages of OFS equipment, labor, and just challenges on things like OCTG.

Yeah, Arun, this is Billy. Let me start by providing maybe an overview of how we're managing the year's capital program. Then I'd like to get Jeff to add some color, and then I'll circle back to 2023. Let me first start by saying that we kind of look at each year the same way. As you know, I would tend to bucket this in maybe three or four different areas. One, we self-source a lot of materials that insulates us from a lot of the supply chain issues. We also do a lot of innovation and efficiency gains. The third bucket might be the pace of the adoption of these new efficiencies across the company, and then maybe finally flexibility with our multi-basin approach. So just to elaborate on that a little bit more, you know, at the beginning of the year, we constructed our plan, certainly recognizing the inflation we saw from the recovery of post-COVID, and we were confident in looking at that, that we could offset inflation and maintain flat well cost. What we didn't anticipate was the war in Ukraine and that additional pressure and increased inflation we saw in commodities such as fuel and steel. But we're still working to offset this additional inflation through our efficiencies and new innovations. These improvements and efficiency gains are certainly happening largely in the areas where we have the most activity, such as the Delaware Basin and the Eagle Ford. But I would also say that The pace of the adoption of these new technologies, the rapid adoption of the SuperZipper technology across the company, is happening faster than we expected. We also have the advantage of being in multiple basins, so that gives us a lot of flexibility to shift activity between areas. We're very comfortable that we can maintain our plan, delivering our original volumes within our stated CAPEX goals that we laid out at the start of the year. So with that, maybe I'll turn it over to Jeff to give you some more details.

Yeah, good morning, Arun. This is Jeff Leitzel. So, you know, as Billy stated, our ability to counter, you know, these inflationary pressures and, you know, some of the supply chain constraints that you talked about, it's really just a huge credit to our team's operational execution, their innovative culture, and really continuing to, you know, improve on the efficiencies. Just to give you a little bit of color and some examples, start off with our drilling operations. Our teams continue to increase their efficiencies, and that's primarily with EOG's in-house motor program and our proprietary bit cutter development, which we can kind of design both of these uniquely around all the formations we drill in each of our plays. And our Eagleford operations, they're just a perfect example of this. We've increased the drilled footage per day by over 17% this year, and this is one of our more mature plays that we've been drilling in for 13 years. So Really to EOG, no matter how far along we are in development, there's always improvements that can be made. And then on the same topic there with the Eagleford, they've just done an outstanding job of reducing their drilling fluid costs also, even as diesel prices have risen, and that's primary base in those fluids. We've done this by optimizing the density and the additives in the drilling fluid in each area really to try to reduce those fluid losses, which has resulted in a per barrel savings of about 20% so far in 2022. And then just a couple more basic examples and completions. Our field team, they continue to see really good improvements there and they've increased their overall completed lateral per foot per day by 10% compared to 2021 for the total company. And as we've talked about in the past, one of the main drivers in this is really our continued implementation of SuperZipper operations. So we've talked about last year we were about a third of our activity with SuperZipper, and this year we had a goal of trying to get to 60%, and we're just about there right now. This is really significant because pretty much every additional well that we super zipper, we realize the savings of up to $300,000 per well, or that equates to about 5% of the total well cost. So another kind of new process on the innovation side that we've been implementing and testing is something called continuous frack pumping operations. So just a little bit of a rundown, typically in any completion operations, you have some unplanned maintenance. And in order to be proactive, our field teams have started planning some of that scheduled maintenance periods of about three to four hours every three days. And what this has helped us do is really minimize any of that unplanned maintenance and really greatly increase our overall efficiency. So in the past quarter, really primarily in the Eagleford, we've started some testing in the Delaware Basin, but we've been able to increase our completed lateral per foot per day by roughly 30%. That's really just a huge time and cost savings there, and what we plan on doing is as we optimize this process, we'll continue to roll it out to all of our operating areas. And then lastly, more on the supply chain and material side of things, I just wanted to touch on a couple of our savings from the water and the sand cost side of things. In the Delaware Basin, our team continues to reduce their water costs by optimizing the reuse process, which right now is approximately 90% of all their sourced water. And they're really doing this just through increasing the automation of all of our infrastructure and reducing the overall treatment cost per barrel, which we realized about a 9% reduction in each barrel of reused water for 2022. And this is pretty significant, not just for CAPEX, but also on the operating expense, because every barrel we're allowed to reuse is one less that we have to dispose of. And then finally here, over on the sand logistics side, you know, EOG, we've been in the sand business in self-sourcing for about 15 years now, and we continue to reduce those costs across the company. For example, out in the Delaware Basin, we continue to advance our abilities to get that sand closer to the wellhead. and ultimately reduce the amount of trucking needed. And plans are we're going to open up a second plant in the second half of next year, and we really anticipate to see some pretty good savings from Q1 through the rest of the year of about 20% per pound. So these are just a few of the many examples of, you know, how our operations team is just, you know, performing and really giving us great confidence that we'll be able to counter a lot of these inflationary pressures and supply chain constraints, you know, through 2022. And as Billy will talk about here, 2023.

Yeah, Ron, just to summarize maybe, I know that's a lot of detail for you, but obviously we're very proud of the efforts of our employees to continue to fight against the rising well cost in this period of inflation. As we move into 2023, you know, it's really early to talk about specifics about next year, but let me just kind of give you an overall impression of how we think about going into any year. Certainly we have a long history of managing through inflation. to maintain or lower well cost that gives us confidence to be able to meet our goals. And we have two fundamental things that we think about. One is our contracting strategy and how we approach that. For example, this year, just a reminder, we have about 50% of our well cost secured with contracts with service providers that provide about 90% of our drilling fleet and about 60% of our frack fleet locked up under existing contracts. Not all of those service contracts are set to expire at the end of this year, so we try to stagger those as we go through a year to make sure that we have some continuity going into the preceding year. And then the lastly would be, as Jeff mentioned there, innovation and efficiency improvements. So we are already confident. We're seeing ideas that we can continue to push and explore to continue to reduce cost and offset inflation going into next year. So we're always chasing those kind of things. I know that's a lot of color, but it's certainly something that we're very proud of for our employees and their efforts and just want to make sure you fully understand it.

Yeah, I appreciate the detail, Billy. My follow-up is maybe for Ezra or Tim. You guys have now committed to a 60% minimum return of free cash flow kind of framework. I wanted to get your thoughts on the other 40% bucket and what the priorities are between the balance sheet, additional cash return, and the bolt-ons. I know last quarter Tim did message EOG's intention to build more cash on the balance sheet for countercyclical opportunities at other points in the cycle. So I wondered if you could give us some updated thoughts on that.

Yes, Arun. This is Ezra. I can start right there with where you left off, you know. Pardon me. Let me say that we're just thrilled to be in a unique position here to be able to strengthen the balance sheet and return $2.4 billion to shareholders in the first half of 2022. But ultimately, you know, with the remaining 40%, it comes back to the fact that, you know, we're committed to delivering on our free cash flow priorities and doing the right thing at the right time to maximize long-term shareholder value. and it does include that balance sheet. Some of the things with the balance sheet we've discussed in the past is to have cash available just for running the business for operations, to have cash for the small bolt-on acquisitions, as you mentioned, to have cash available for the $5 billion stock repurchase authorization, which we've said we prefer to look at that as an opportunistic repurchase rather than something more programmatic. And then the last thing with regards to our balance sheet and cash on hand would also be our commitment there to retiring a bond, a $1.2 billion bond that's coming due here in the first quarter of 2023. So really, as we started off with the guide of returning a minimum of 60% of free cash flow, it's really not a change in strategy by any means. It's just to provide a little more transparency, a little more clarity. We've heard some of our shareholders who have asked for a bit more transparency and clarity on the cash returns, and that's really what the change in messaging is, but our strategy remains very consistent.

Great. Thanks, Ezra.

Our next question comes from the line of Janine Way with Barclays. Janine, your line is open.

Hi. Good morning, everyone. Thanks for taking our questions. Our first question, maybe if we can just hit back to Dorado, nice update on that. In the slides, you highlight potential export markets. Can you talk about how much midstream capacity EOG has currently or maybe what you see down the line in order to get Dorado gas to those sales points?

Yeah, Janine. Good morning. This is Lance. Yeah, as you think about Dorado and takeaway there, we're very well connected. I mean, you can see that in slide 11. Obviously, you can see the proximity to market. But as we talk about capacity, we have sufficient capacity there, plenty of running room as we look forward. And just really want to highlight, too, as you think about the proximity to those markets, especially the demand growth that's expected to see and the potential, that's equally important and what we're excited about. As you think about the proximity, less than 100 miles to get to the Agua Dulce market, and then the connectivity that we have even to get up into the KD Houston Ship Channel market. As you look forward over the next five years, you have the potential to see an additional potential of like five BCF a day of new demand growth. So the proximity, the connectivity that we have, and obviously as you've seen as evidenced through our other plays, as we think about capacity, we're always very forward-looking in making sure that we have enough ongoing capacity as we think about our program.

Okay, great. Thank you. And then maybe just following up on Arun's question, Ezra, we appreciate all the details you just provided about the cash buildup there. I guess just generally speaking, and I know it's never this simple about back solving to a cash number, but is net cash, or is that like a suboptimal place for the business, or would you be perfectly fine with the balance sheet getting to that point? Thank you.

Yes, Janine. No, we don't believe that's a suboptimal place in an industry like ours that's proven to be cyclical in nature, obviously, and at times very volatile. Even our current cash position, I'd say, you know, the cash on hand as a percent of market cap places us roughly in the upper half of the S&P 500. And we think that's a fantastic position to be in, especially when you think about a cyclical industry like ours.

Thank you. Our next question is from Leo Mariani with KeyBank. Leo, please go ahead with your question.

I wanted to follow up a little bit on the gas macro here. Obviously, very topical these days. In the past, I know EOG has spoken about a longer-term oil growth target, 8% to 10% per annum. Do you guys feel that at this point in time, just given the changes in the world, that U.S. gas is really just going to be higher for longer? And do you think it would be appropriate to maybe do something similar on the gas side as well? And obviously, you kind of talked about the accessibility of your gas to LNG markets down there as well. So just wanted to get a sense if you guys are actively working on perhaps expanding activity over the next few years at Dorado in trying to get that gas to international markets.

Yes, Leo, this is Ezra. Let me maybe make a few comments and then Lance can follow up on some more detailed LNG perspectives. In general, what I would say, you know, from the macro perspective is, I know this will sound a little bit repetitive, but we base our decisions on investment in gas the same as we do on investment in oil, and that's on the premium price deck. So for us, it really comes down to the first question is returns. How quickly can we invest in an asset and still generate high returns year over year, still continue to improve upon the asset? And what that means is lowering the finding and development costs every year and adding lower cost reserves to the base of our company. That's how we drop the cost base of the company and basically expand the margins going forward. With regards to global supply and demand, that comes in second, same as on the oil side. I wouldn't say that we have an optimal level growth because obviously there's associated gas, but then we've got these pure dry gas plays. So we look at them a little bit agnostically. Long-term, how we do feel, going out longer and thinking about the long-term global energy solution, we do feel that gas is going to play a significant role in that. and that's why we're very committed to the $2.50 price that we evaluate the reinvestment on because we think that's globally going to be a very competitive and compelling price to be able to base the investments on. Lance?

Yeah, Leo, good morning. Maybe just to add a little bit more color, too, as you think about just LNG and kind of LNG offtake, but, yeah, I mean, it's an exciting time, and it's fascinating. been excellent having some exposure, especially as you think about our JKM exposure and the first mover advantage that we have. Because the pendulum, like you're saying, you're seeing in the environment today, the pendulum is swinging. You're seeing more of a demand pool. And so as we think about that, you know, especially from a customer standpoint, I mean, we're very well positioned. I mean, the way we think about it, there's really three important components of it. And You know, one of them that's critical is investment grade status and the pristine balance sheet that we have that absolutely puts us and differentiates us. And then as you think about the control that we have with our firm transportation, when we think about LNG offtake, it's not just from Dorado, but we have firm offtake that can get us from each of our major plays. And then also when you think about supply flexibility, too. I mean, we have a lot of scale and a lot of flexibility. And so we're excited about it. Obviously, you saw the deal that we've done with Chenier. You know, that's expanding and increasing our sale that we have there. We feel that that's very strategic. You know, that helped commercialize, you know, Stage 3, which we're anticipating hopefully by the end of 2025. I think expected maybe in early 2026. all kind of in line with what we've been talking about for a long time. We've been working LNG since 2017, you know, entered into our first agreements in 19, and then just recently expanded that again. So, yes, we definitely have a constructive view as we think about LNG, and all those components that I just talked about earlier, we feel puts us very advantaged because we can transact quickly and we can move with scale because we have the supply flexibility as well.

Okay, that's helpful. Definitely sounds like you guys are looking at more deals. Also, just wanted to ask about the earlier target that you all had put out kind of pre-Ukraine of flat well costs year over year. I'm certainly aware that you guys have efficiencies and you're working really hard on this, but at this point, Manny, do you think that's still a realistic goal just given inflation? I think I heard you say that you got about 50% of the well costs locked up in 2022.

Yeah, Leo, this is Billy Helms. We tried to address that certainly in the last answer we had, but I guess the bottom line is we're very confident we're going to be able to keep our well cost flat this year, and we're going to work hard to do it next year. So it's early to say what next year is going to be, but we just have line of sight on so many improvements we can continue to make in our business to fundamentally offset inflation. So we're very confident in this year's capex and volume targets.

Okay, appreciate it. Thanks.

Our next question is from Neil Dingman with Truist Securities. Neil, please go ahead.

Yes, thank you. My first question, as we're maybe on expiration, I'm just wondering, what would it take, would it take initial success, maybe on a large acreage position, such as wet gas or whatever, for you to announce another plate, or really just a broad question, what generally do you all like to see before publicly rolling out and talking about the next best opportunity you'll have.

Yes, Neil. You know, we like to have confidence in what we're talking about and bringing out to the public. And what that means for us these days, and we've talked about it a little bit before, is these days it's not just a matter of trying to find oil or gas. that has become relatively not too difficult. The challenge for us is to make sure that it's additive to the quality of our inventory. Like I said earlier, we believe we've got really the highest quality and deepest inventory across a multi-basin portfolio as far as North American E&P companies go. And so trying to add to that, trying to add to the double premium rates of return program is challenging. And what it takes is some longer-term production results. Going back to Dorado and the Powder River Basin, before we announced those basins to the public, we had some pretty significantly long production results to really make sure that we had captured what we had anticipated capturing. The last thing we want to do is mislead anybody. And so especially looking at some of the new plays that we're talking about with these hybrid reservoirs, These things are relatively new in nature to the industry, and so gathering some longer-term production results and appraisal wills to really define the extents of these plays is very important and critical before we'd be comfortable talking about them.

Got it. Great, great details. And then my follow-up, either for you or Billy, just on OFS inflation and maybe logistics, you all continue a great job of mitigating even better than most OFS inflation. I'm just wondering... on when you look out remainder of this year into 23, if things sort of stay like they are now, you know, we've heard some, you know, issues of sand and different things in the Permian, maybe bring it up now with Northern White from Wisconsin. Could you talk about, are you all, you know, I guess two questions here. One, are you all locking in and continue to do sort of longer term, whether that be on the sand pipe or other side? And then, you know, number two, just wondering, would you, you know, when you think about, If you have opportunities like you did a year or two ago about drill pipe, if those persist, I assume you'll continue to go after and do some opportunities like that.

Yeah, Neil, this is Billy. Certainly it's a very dynamic situation we're dealing with here, but part of the reason we have so much confidence is in being able to offset inflation, especially the inflation that the industry is seeing today, really goes back to the involvement or engagement of our employees and how committed they are to achieving the goals that are set out. And you might, for example, talk about sand, especially sand in the Permian. And Jeff kind of went through some of this in detail earlier. The big overlying reason that we have so much confidence is we took ownership. We took control of that many, many years ago. I want to say about 15 years ago. Certainly, through that taking ownership, we've learned a lot in the past. We continue to look for ways to reduce that cost. Lately, it's been by getting sand closer to the wellheads. As we move to locate near wellhead, so kind of close to the end user sources of supply, we can move closer and closer and continue to reduce our cost, both on the cost of the sand itself, but also transportation to the wellhead. All the logistics that you see are diminished. We take trucks off the road. It's just good in many, many different ways. We also stay very engaged on the a material side, tubulars and those kind of things. We work with mills really across the globe directly. We don't really go through distributors per se. We work directly with the mills and that way we are able to establish the relationships and capture opportunities at the right time. So it's just that further engagement in all aspects of our business that allows us to do that and the creativity of our employees that allows us that opportunity. So that's why we still remain so confident.

Very good. Thank you, Melanie, for the details.

Our next question comes from the line of Neil Mehta with Goldman Sachs. Please go ahead, Neil.

Thank you, team. I have one micro question and then one macro question. The micro question is, as you think about your growth assets, the Delaware, the PRB, and Dorado, how do you think about the relative capital allocation and how would you prioritize them based on returns and cost of supply?

Yes, Neil, this is Ezra. You know, it's great to have, you know, such high-quality inventory across multiple basins. It makes our job with capital allocation and portfolio management exciting. The way we approach each of them is, you know, looking at where they're individually at in the life cycle of the play and basing it off on returns. And so even through... You know, the Eagleford in there, certainly not a growth asset anymore. But by right-sizing that program, last year, and I think we highlighted this in February, last year we turned in the highest rate of return drilling program we ever had in that play. When you think about a play like the Eagleford, you know, that's really a trailblazing type of asset for the entire industry to see how to continue to make one of these resource plays, long-life resource plays, even better year after year after 12 or 13 years of drilling it. So when we think about the Delaware Basin, the Powder River Basin, and Dorado, just at the high level, we would say the Delaware Basin is kind of in the sweet spot as far as drilling activity, our knowledge base, infrastructure. And the PRB and Dorado are a little bit behind that. We definitely slowed down. As Ken had mentioned, we paused drilling in Dorado during 2020, and we did the same in the Powder River Basin. And so we're early in the life on those plays. And so the capital allocation of those two really progresses with the build-out of infrastructure and at the pace at which we can incorporate our learnings and continue to make the wells better.

That makes a lot of sense. The second, Ezra, is a big picture question. You guys have been doing a lot of work on the oil macro, and it's obviously a very dynamic environment, but there are two questions associated with it. One is, What do you think the long-term implications of potentially structurally lower Russian production capacity will be for the U.S. producers and for global oil producers? And the second is, how are you thinking about exit-to-exit U.S. oil production this year, given some of the constraints that you talked about earlier on the call?

Yes, Neil. I'll start with the second one and reiterate our perspective. Our position on exit-to-exit U.S. oil hasn't really changed since February. When you look at kind of the range of, you know, forecasts that are out there, we're on the lower end is the way that we set it in February, and that's what we would stick to today. We think the supply chain constraints and the inflationary issues, the discipline that you're seeing in North American E&P sector, We think that the U.S. exit-to-exit oil production growth is going to be on the lower end of most of the forecasts. Longer term, with the structural implications for Russian capacity for U.S. and global and how that plays in, you know, we're watching that the same as everyone else. It's a volatile situation. situation. There are things developing as we speak, including the sanctions that are being discussed, and how are those Russian barrels actually continuing to flow, and how are they getting discounted, and where are they showing up, and what is that doing? Ultimately, I'd take a bigger step back and just say for the last few years, Neil, we've been pretty consistent with our model that chronic underinvestment and exploration in our industry is really going to lead to generally lower supply, undersupplied for the global supply and demand market longer term. That's why we continue to explore, and we continue to explore for lower cost, higher return assets. And we think that really, you know, as we've said in the past, there's only a handful of North American E&P companies that have the asset quality, the size, the scale to compete on a global scale with that cost of supply. And on top of that, deliver the barrels with a lower environmental footprint And in the future, you know, those are the companies that the world's going to want to fill in additional barrels. And especially with our operational results in this first quarter, we think, we know, we feel that EOG is a leader of that group of North American EMPs.

The underinvestment point is definitely playing out. We appreciate it, Ezra.

Thank you, Neal.

We have time for one more question today, and our next question comes from Paul Cheng with Scotiabank. Paul, your line is open.

Thank you. Good morning. Urza, two quick questions. One, I think you sort of follow up to Neil's question. So does the Russian invasion in any shape or form change the way how you look at the global market and perhaps that you're production outlook or development plan for the company. I think you've been saying that you guys will be ready to grow if you think there's a need from the market and you will be growing at maybe in the future 8 to 10% annual kind of growth rate on the maximum. So wondering if those kind of yield has been changed in any shape or form because of the recent events. The second question that you talk about powder recertification. So what will it take for that development pace to accelerate?

Yes, Paul. This is Ezra.

I think I can answer both of those questions almost in the same manner. You know, when we came out with the 8 to 10 percent growth, which was gosh, maybe close to 20 months ago now. You know, that was, and I think we said it at that time, it's dynamic. At that time, that 8% to 10% model was reflective of what we could do to optimize near-term and long-term free cash flow with the current inventory and our current knowledge base. And as you can see, things continue to change for the better for us. We continue to drive down costs. We continue to drive forward each of our, let's call them emerging plays with the Powder River Basin and Dorado. And so when we talk about what's a good growth rate going forward, it comes back to those two things that I started off the call with Doug with. The first is optimizing our returns, investing at a pace where we can really create long-term shareholder value. And you do that through adding lower cost reserves to the base of the company, so driving down the cost base of the company, while also reinvesting so that you can turn your cash over quickly. Our wells this year at strip price, since we base it on a $40 investment, what that really translates to are wells that pay out on average in two to three months right now in the strip price. So it's a fantastic place to be and it's really strengthening the base of the business and the company going forward. With regards to the PRB, it falls under the same type of line. It all depends on how we build out our infrastructure in that basin and moving at a pace to be able to incorporate our learnings to drive down the well costs. Last quarter, I think we highlighted we had dropped the Niobrara well cost pretty significantly over the past year, 2021. which was just tremendous results. As we continue to see progress like that, we feel more confident to go ahead and allocate more capital to that portfolio, to that basin.

Thank you.

That is all the time we have for questions today, so I'll now hand the call back to Mr. Jacob to conclude.

Yeah, we'd like to thank everyone for participating on the call this morning and thanks to our shareholders for your support. We especially want to recognize each of our employees for their commitment to excellence and on delivering such an outstanding start to the year for EOG.

Thank you everyone for joining our call today. This concludes our call. You may now disconnect your lines.