Good day, everyone, and welcome to the EOG Resources second 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 in 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 may 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 Yacob, Chief Executive Officer, Billy Helms, President and Chief Operating Officer, Ken Boedeker, EVP, Exploration and Production, Jeff Leitzell, EVP, Exploration and Production, Lance Terveen, Senior VP, Marketing, and David Streit, VP, Investor Relations. Here's Ezra. Thanks, Tim. Good morning, everyone. Yesterday, we declared a third special dividend for the year, demonstrating our commitment to deliver long-term shareholder value through our cash return strategy. The $1.50 dividend is supported by another outstanding quarter. We posted adjusted earnings of $2.74 per share and nearly $1.3 billion of free cash flow. So far this year, we have declared $4.30 per share of special dividends. Combined with our peer-leading annualized regular dividend of $3 per share, we are on pace to pay out a minimum of 60% of annual free cash flow. What continues to differentiate EOG is our people and our assets. We have cultivated an inventory of premium and double premium wells that provide a 20-year runway for the company through our focus on organic exploration, supported by a decentralized organizational structure. Our multi-basin portfolio is predominantly the result of having seven North American and one international cross-functional exploration teams that work independently but collaborate on shared learnings. Our role here in Houston, beyond capital allocation, is to facilitate those shared learnings across all eight teams. The result is a robust exploration pipeline that continues to both improve the quality of and expand our more than 20-year inventory of premium and double premium wells. Our portfolio includes the Delaware Basin, which remains the largest area of activity in the company and is delivering exceptional returns. After more than a decade of high return drilling, our Eagle Ford asset continues to deliver top-tier results while operating at a steady pace. Our emerging South Texas Dorado Dry Natural Gas Play and Powder River Basin Mowry and Niobrara Combo Plays are contributing to EOG's success today and laying the groundwork for years of future high return investment. In addition, we have tested our Mowry and Niobrara plays in the northern Powder River Basin. Our initial results have demonstrated the untapped potential of this oilier part of the basin as a complement to the outstanding performance in the southern part of the basin. EOG's current multi-basin portfolio, offering exposure to both geographic and product diversity alongside several other prospects in our exploration pipeline, will continue to expand EOG's premium inventory and provide through-the-cycle value creation. Disciplined reinvestment within any given play depends on where we are in the development life cycle of that play. Our multi-basin portfolio of high return assets, all competitive against our premium hurdle rate, provides invaluable flexibility to invest at the pace that allows each play to get better. It also allows us to plan around basin-level market dynamics impacting services and infrastructure to minimize inflation and bottlenecks. We are able to optimize reinvestment across our total portfolio to add reserves at lower finding costs, lower the overall cost base of the company, and continue to improve EOG's company-wide capital efficiency. This quarter, we are highlighting iSense, our continuous methane monitoring system that we piloted in the Delaware Basin and are now deploying in our most active development areas. iSense is yet another example of how EOG's decentralized model not only fosters innovation across eight teams, but also compounds the impact of innovation by taking ideas born in one operating area and expanding them across multiple basins. From the latest in information technology-driven solutions to reduce emissions, to innovation focused on drilling and completions operations, to procurement of casing and sand, EOG is unique in its ability to leverage its culture and operating structure to get incrementally better every year. The tremendous inventory and cost improvements we've made over the last several years provides high confidence in the low breakevens and operational flexibility of our business. This confidence in our business, along with the strength of our industry-leading balance sheet, led to our decision this quarter to terminate a significant portion of our oil and natural gas hedges. Going forward, we expect to hedge significantly less than the 20%-30% of volumes we typically hedged in prior years. The current operating environment is challenging given the volatility of commodity prices and inflation headwinds. Through it all, our employees have remained focused on execution and have improved the business. Our second quarter performance is proof of that. We delivered more oil for less capital, and in the face of a unique inflationary environment, our forecast for capital expenditure this year remains unchanged. EOG's consistent execution, low cost structure, reduced hedge position, and transparent cash return strategy based on a regular dividend that we have never suspended or cut, that has grown 21 of the last 24 years, and is now competitive with the broader market, puts EOG in its strongest position ever to deliver significant value to shareholders through the cycle. Here's Billy with an operational update and early look at 2023. Thanks, Ezra. We posted outstanding results in the second quarter. Our performance included exceeding the midpoints of our production guidance, while capital expenditures and total per unit operating costs beat forecasted targets. Once again, more oil for less capital. I'd like to thank our employees for their dedication and persistence to execute and deliver such outstanding results. As we have guided to all year, our oil growth year-over-year will be about 4% to return our production to pre-COVID levels. Halfway through the year, we're on track to deliver that objective and have done so against a challenging supply chain backdrop. The upward price pressure on steel, fuel, and labor continues due to ongoing supply constraints initiated by COVID and extended by the war in Ukraine. The impact of this has resulted in inflationary headwinds that have meaningfully exceeded our initial expectations earlier this year, making it increasingly challenging to maintain flat well cost. However, our employees continue to innovate and deliver efficiencies that offset a significant portion of this inflationary pressure. For example, in our Delaware Basin drilling operation, our downhole drilling motor program is providing solid performance improvements, generating a 13% year-over-year increase in the footage drilled per motor run. The motor program and other improvements are reducing drilling times versus last year. In the Eagle Ford, our drilling teams have improved the footage drilled per day by 11% versus last year, while also managing drilling parameters to reduce the cost of drilling fluids by 10%. In our completion operations, we had previously discussed the company's plans to increase the use of super zipper completions, which are 40% faster than normal zipper operations. We have now utilized this technique on about 65% of EOG's completed wells year to date, which is yielding an 11% improvement in the lateral footage completed per day. Super zipper completions, combined with our focus on more efficient operational practices, has increased the amount of pumping hours per day by 24%. In addition, we continue to progress our self-source sand program and expect to further reduce sand cost in the second half of the year and extend those savings into 2023. All in all, we now expect our well cost to see a modest single-digit increase over last year, and most of this increase will be seen in the second half of the year. However, we're able to leverage our operational flexibility within our multi-basin portfolio such that our capital and volume plan remains unchanged. Now turning to the macro backdrop, oil field service capacity remains extremely tight and is further constrained by the limited availability of materials and experienced labor, driving uncertainty in the cost of services not only for this year, but also for 2023. These constraints are more concentrated in areas with the highest activity, such as the Permian Basin. EOG's multi-basin portfolio provides us the flexibility to manage these constraints by optimizing activity between our multiple plays to maximize our return on investment. Just as in the past, EOG will play to its strengths to mitigate, where possible, the inflationary pressure and operational constraints facing us. We are currently taking steps to secure services for next year and will know more about the 2023 outlook next quarter. Regarding production growth, it's too early to discuss next year's plans with any degree of precision. However, it is important to recognize we will maintain our discipline, and as we see things today, would expect low single-digit oil growth similar to this year. On the natural gas side, we're excited about the results of our South Texas Dorado play and its ability to play an increasing role in supplying the growing demand of petrochemical and LNG markets along the Gulf Coast. As we allocate future capital based on returns, this play will command additional investment, not only to meet the growing demand, but also for infrastructure needed to capture the value chain from the wellhead to the market center. These investments not only generate healthy returns, but ultimately lead to lower well cost and lower long-term unit operating cost. We also expect to fund our emerging and promising exploration plays as we improve the company for the future. Now, here's Ken to give you an update on our emissions reductions effort. Thanks, Billy. This quarter, we are providing details on our continuous methane monitoring project, which is an example of the progress we're making in our emission reduction efforts. Over the last several years, our leak detection and repair program, or LDAR, has advanced from sound, sight, smell surveys to surveys using more accurate optical gas imaging to today's deployment of scalable solutions of the latest technology, continuous methane monitoring. This technology detects potential leaks and provides real-time alerts to help accelerate repairs and will provide data and trend analysis to potentially prevent future methane releases. We've been evaluating continuous methane monitoring technology for a few years. There are several third-party systems and technologies available to monitor and detect potential methane leaks, which use intermittent or continuous monitoring technology. About 18 months ago, we began a pilot project using a solution we built in-house named iSense, which is a fence line monitoring solution that uses methane sensing technology to continuously monitor facilities and provide real-time alerts of potential leaks to a central control room. We tested iSense against monitoring solutions in use and available in the market today and confirmed that our sensor detected methane release events consistent with these third-party systems. The results from these tests confirmed that iSense is the most effective solution for EOG to use to detect and accelerate leak repairs while also being scalable and economic. Like so many of our innovations, this technology is being spearheaded by our employees across the company. Since the pilot, our employees are rapidly deploying iSense in the field, prioritizing areas of highest potential impact. The initial installations are focused in the Delaware Basin and currently cover about 60% of our production. We expect that most of the remaining Delaware Basin production will be monitored by iSense by year-end. We'll continue to roll out iSense in other operating areas next year. Using our proprietary system allows us to own the data creation, flow, and storage, which is a priority with all our information systems. Owning the iSense data and retaining direct control of its collection provides invaluable flexibility to improve both data quality as well as the tools to analyze and integrate iSense data with existing operational data from our production facilities. This data, along with our ability to monitor our operations from any of our four control rooms, will enhance the 24/7 capability to continuously identify, prioritize, and repair leaks. In the future, when data from iSense is paired with other real-time production data, we expect to be able to make improvements in the design of facilities to minimize releases. We're also optimistic that we will be able to more readily predict the likely size and source of a methane release. Leveraging technology to enhance our methane leak detection and repair program is another great example of EOG's culture of continuous improvement throughout all our operations. Our employees have embraced the company's emission reduction efforts, and I'm excited to see how EOG's culture of innovation and technology will continue to drive creative solutions. Now here's Jeff to discuss the progress we've made in our premium combo play in the Southern Powder River Basin. Thanks, Ken. Our emerging Mowry and Niobrara plays in the Southern Powder River Basin have made significant progress recently. The Powder returned to steady development last year after a pullback in 2020 driven by the pandemic. Results in 2021 were stellar with respect to both well performance and well cost reduction. Strong results to date, combined with the benefit of infrastructure investments, have positioned the Mowry and Niobrara plays to command more capital in 2023 and beyond. The Powder River Basin is an established operating area for both EOG and the industry that has experienced several chapters of development over its history. The latest chapter for EOG kicked off in 2018 when we moved the Mowry and Niobrara plays into commercial development. We identified nearly 1,500 net premium locations between both targets over our 130,000 net acre position in the southern part of the basin. Since 2018, we have made great strides in fine-tuning our technical model to improve the predictability and performance of the wells. We've delineated the different parts of the basin, high-grading the specific landing zones. The basin has stack potential similar to the Permian, with two widespread, well-known, very robust source rocks in the Mowry and Niobrara. Among those two source rocks are hybrid opportunities such as silt zones and sand zones, a whole section of reservoir that really lends itself to horizontal drilling and completions. We have also made targeted infrastructure investments in recent years, which have helped lower the cost structure in each play. We have added nearly 40 miles of water pipeline and 2.5 million barrels of water storage capacity. Our water infrastructure investment in the PRB has allowed us to source about 90% of our water used in our operations from reuse, reducing costs for both water sourcing and disposal. We have also invested in infrastructure to enable local sand sourcing. The installation of a high-pressure gas gathering system has been instrumental in achieving a 99.8% gas capture rate. The infrastructure is also benefiting our operating costs. Per unit lease operating expense in the Powder is among the lowest in the company. The PRB is farther from market than some of our other premium plays. However, the Mowry and Niobrara have several advantages that more than make up for it. First and foremost, the wells have some of the largest per well reserves in the company on a barrel of oil equivalent basis. In the southern PRB, the Niobrara and Mowry formations are more combo. That is, they produce a mix of oil and natural gas. While the laterals are also longer at 9,500 feet, which contributes to the higher recoveries, well performance is mostly due to the quality of the reservoir and composition of the products, with a large component of natural gas that supports higher recoveries. To date, EOG has completed about 40 net Mowry and Niobrara wells in the southern PRB. This year, we anticipate completing 15 net Mowry and Niobrara wells and expect to significantly increase that activity next year. As a result of our exploration work on the entire Powder River Basin hydrocarbon system over the last few years, we have also built an additional 110 net acre block in the north, extending our acreage in the productive fairway to 90 miles. The northern area is a historically underexplored part of the basin. After recognizing the potential in the area, we cored up acreage adjacent to our legacy Yates acreage through a series of trades and small bolt-on transactions. Utilizing reservoir data from multiple plays, we identified landing zones in the Mowry and Niobrara Formation with favorable petrophysical and geomechanical properties and began testing. We drilled 4 successful delineation wells, which we believe are industry first in the area. While it is still early in the delineation, we've confirmed the development potential of our northern Powder River Basin acreage to add to our future premium inventory. The Mowry and the Niobrara combo plays in the Southern Powder River Basin stand today well-positioned to compete for capital within the portfolio. Combined with our position to the north, the basin has significant investment potential for years to come. Next up is Lance to provide some color on our marketing position in the Powder. Thanks, Jeff. As we look further downstream, the investment in infrastructure that has lowered the cost structure in the southern Powder River Basin also allows us to apply our time-tested marketing strategy of establishing multiple connections to provide market pricing diversification. Today, we hold sufficient processing, transportation, and fractionation capacity for natural gas liquids out of the PRB. We have access to both the Mid-Continent at Conway, Kansas, and the Gulf Coast at Mont Belvieu, Texas. An underappreciated aspect of the Mowry and Niobrara wells is their prolific NGL production and the heavier post-processing mix of NGLs they produce. After processing to minimize ethane extraction, our Powder River Basin NGL barrel contains approximately 10% ethane, 45% propane, and the remainder being butanes and more of the heavier NGLs, resulting in an NGL to WTI price ratio of over 50%. In the first half of this year, our NGL price realization was $53.01, which is a $7.17 premium to the Mont Belvieu typical barrel. In addition, the quality of the Powder River Basin oil has an average API gravity of 44-47 and remains in high demand. During the first half of this year, realized prices for our oil production out of the PRB were WTI plus $1.63, with access to both Guernsey, Wyoming, and Cushing, Oklahoma, markets. Stepping back, I'd like to review our marketing strategy for the company as a whole. In all our active development areas, we want to retain control of our products and establish multiple sales points, which adds significant value. For example, in the first half of this year, we transported an average of 188,000 barrels of oil per day for export, which represents about 30% of gross production, with optionality to sell based on a WTI or a Brent index. With the widening of the Brent WTI spread, we have the opportunity to take advantage of our capacity to deliver up to 250,000 barrels of oil per day for export. For propane, we have delivered 19,000 barrels per day for export at premium prices to Mont Belvieu. We also continue to see strong uplift in our natural gas price realizations due to our early mover advantage, securing 140,000 MMBtu per day linked to JKM through Cheniere's LNG facility in Corpus Christi. Cheniere recently announced FID or final investment decision on stage three in Corpus Christi. Once stage three goes in service, EOG will triple its exposure to JKM to 420,000 MMBtu per day. We continue to see constructive long-term demand for all our products, both domestically along the Gulf Coast and internationally. To unlock that value, you need control of your products, transportation capacity, and an early mover advantage to capture spreads quickly. As we look down the road, EOG is well-positioned to capture the strength of prices in these export markets to generate additional cash flow and value to shareholders. Next up is Ezra for concluding remarks. Thanks, Lance. We believe EOG is differentiated for the following reasons. We have a diverse portfolio of assets across multiple basins, providing geographic and product diversity. We are a reliable and consistent high-performing operator. We have among the lowest cost structures. We are committed to sustainability. We maintain an exceptional balance sheet. Our cash return strategy is transparent. Our regular dividend is competitive with the broader market. Finally, the EOG culture is one of a kind, and it's at the core of our differentiated performance. We believe there are only a handful of North American E&P companies that have the asset quality, the size, the scale to compete globally on oil and gas cost of supply, and on top of that, produce the barrels with a lower environmental footprint. In the future, those are the companies that the world is going to want to deliver additional barrels. We firmly believe that EOG is a leader in that group of North American E&Ps. Thanks for listening. We'll now 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 touch tone 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 touch tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question comes from Leo Mariani from MKM Partners. Leo, please go ahead. Hey, guys. Totally realize that it's obviously, you know, way too early for 2023 guidance at this point. You guys did have some prepared comments which kind of said as things stand today, you would look to grow oil kind of low single digits next year. It feels like a bit of a pivot from, you know, what y'all have said in the past, which was kind of this 8%-10% oil growth would kind of be optimal sort of operating speed, you know, for EOG. Has kind of something changed in terms of how you look at kind of optimizing the operations, you know, versus the growth of the company? Yeah, Leo, this is Ezra. I appreciate your question. You know, really what we've always talked about is that our growth is really the output of our ability to generate high returns from a disciplined reinvestment strategy. And that's really what we've tried to describe today is, you know, as you pointed out, first of all, it is early to talk about 2023. But ultimately, we're committed to remaining disciplined. We want to focus investment in each of our assets at a level where they can continue to improve every year. Directionally, as we see it today, how the supply and demand balances look, the constraints on services, the associated inflationary pressures, oil growth will likely be similar to this year. As Billy highlighted, we'd expect to direct additional investment towards our Dorado Natural Gas play, based on the positive results that we're seeing there. Okay, that's helpful. I just wanted to ask on the capital. Obviously, you're one of the few companies that did not raise the CapEx budget, you know, thus far here in 2022. You described a lot of the ways that you're able to kind of, you know, keep costs lower and some of the innovation that you've sort of had. I did notice that you did pull some of the wells out of the schedule this year. It's not, you know, big numbers, just talking, you know, a few on the margin. Just wanted to get a sense. Is there, you know, any thought that you're maybe doing a little bit less to kind of stay within the budget and just kind of looking at where you were in the first half and third quarter guidance? Is it fair to say you're probably kind of in the upper half of the CapEx for the year? Yeah. Leo, this is Billy Helms. The small change in well count is really just a result of two things. One is timing. Some of the wells that were scheduled to complete at year-end are gonna slip into the next year. It's just a timing thing. The other factor that plays into that is a change in working interest in some of our plays. We've had slightly lower working interest in some of our Delaware Basin wells in the second half of the year. Just to illustrate how minimal that is, that's only about a 2% average change in working interest across the year. It's a very minuscule amount, but that explains the change in the well count. As far as the CapEx, we're very pleased, as you can tell from the comments we made about the ability of our teams to continue to innovate and drive efficiencies in our business to offset inflation. Inflation turns out to be just a little bit higher than we anticipated this year. We are gonna see a slight increase in our well cost, as we go through, especially the second half of the year. We're still confident we're gonna stay within our guidance and don't expect to face additional costs that will increase our budget. Okay. Thanks, guys. Thank you. Our next question comes from Arun Jayaram from JPMorgan Chase. Arun, please go ahead. Yeah, good morning. Appreciate the color on the Powder River Basin. I guess my first question is just thinking about capital allocations between the basins, you know, as we think about next year. You know, today, Ezra, I think 22 of 24 of your rig lines are either in the Delaware or Eagle Ford. You have 1 rig in the Powder River Basin. You mentioned in your comments you plan to lean a little bit on Dorado next year and significantly increase perhaps the mix of activity in the Powder River Basin. I'm wondering if you can give us a sense of, you know, how your activity could shift as we think about next year and how many rig lines you may have in the Powder. Yeah, Arun, this is Billy. As far as capital allocation, as we see it today, there's a lot of factors playing into that, of course, and it's early to say where we're gonna be. Still, we'll have quite a bit of activity in the Delaware Basin going forward. It is a premier play in the company, and certainly that'll continue to command quite a bit of capital. Eagle Ford has been, as you know, a performance engine for the company for the last decade or longer, and they're generating outstanding results. So that'll still command capital. As we compare, you know, we allocate capital based on returns, and certainly the encouragement we're seeing from Dorado and the activity there is showing us the ability to be able to continue to fund that program going forward. The confidence we have in the new emerging Powder River Basin gives us a sense that that will also command quite a bit of activity. The ratios I would say are going to say, stay similar. As far as the Powder River Basin and our overall capital plan, that will depend on the outlook for commodities at that time. What we're gonna see in the Powder, just to be clear, is a shift of activity from some of their older traditional plays, the Turner and the Parkman. To some of the deeper, more emerging plays in the Mowry more specifically and the Niobrara. You'll see that shift. The amount of capital allocated to that play will also depend on just the commodity price outlook that we see for the year once we get closer to that. Overall, we're you know, the takeaway from that, I would think would be that the flexibility we have with the multiple plays we have to chase to continue to add value long-term to the shareholders. Great. My follow-up is just, maybe one for Tim. Just maybe a housekeeping question. Tim, in the 10-Q, you have $1.8 billion of collateral postings associated with hedge activity. I was wondering if you could help us think about the potential runoff of those collateral postings as well as maybe the timing of when you plan to pay off the $1.25 billion of bonds. Is that later this year or in 2023? Yeah, this is Tim. As far as the bond, that is 2023. It's in the first quarter of 2023 is when that will mature. We have no plans to pay it off early. As far as the collateral, they run off kinda like the hedges. We've given you the timing of when those hedges are in our 10-Q. It kinda runs off as that timing comes off. It all depends, of course, on where the strip goes, how that comes off. Right now, it's based on the strip, and that would be how it would come off. It's just as those run off. All right, great. Thanks. Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Scott, please go ahead. Yeah, thanks. You know, if I can ask a question, one more question maybe on, you know, the PRB. You know, you all highlight some good commodity price realizations that you're all seeing there. Is that something that you think can persist going forward? Is it a function of, you know, you know, what's happening in the basin overall, or is it specifically something EOG's got in place that allows you to kind of benefit there a little bit more? Hey, Scott, this is Lance Terveen. Thanks for your question. Yeah, when you think about the price realizations, I think the broader message is just you can really just see how competitive the Powder is with all our other plays. I mean, operationally, you know what I mean, you heard Jeff Leitzell kind of outline a lot of things in the opening comments, but even for our products, we continue to just really see it being in high demand. You know, for example, like even on the crude, you have to remember one of the important attributes up in the Powder, especially related to EOG, is just think about the crude quality. I mean, today we're kind of seeing right around $44-$45. We expect that to kind of be $44-$47 over time. We really wanna protect that quality. You know, we've secured, you know, 500,000 barrels of storage kind of in the field. We've got firm capacity to both Guernsey and the Cushing market. Having that multiple flexibility where we can show that kind of high demand barrel and the API quality that we have, keep it kind of segregated with that API quality, it's really a value when we sell direct to our refiners. Just being able to have that value and have that quality and consistency is key. We draw a lot of that experience from what we've done in the Eagle Ford and also in the Powder, I mean, in the Delaware Basin. It's the quality is what you're seeing on the price realizations. As you think about the NGLs, you know, you're seeing mostly ethane rejection that's happening there. Most of that, you're seeing the ethane is gonna be going more towards like an MMBtu. We're selling that as a gas. That is a heavier barrel that you're seeing that we kinda show. Again, we have the market flexibility. We can show that barrel in a Conway. We can also show that barrel in Mont Belvieu. We can kinda arb that flexibility too and look at those spreads. Getting kind of back to your question, it's, I mean, really the quality, you know, and then the flexibility that we have with the multiple markets, and it's in an area that's absolutely in demand as we. Got it. Thanks for that. As my follow-up, you know, I wanna ask a question on Trinidad. It looks like you're guiding down a fair amount for gas production in Trinidad. I know you've had some, you know, exploration success there, and I think you're drilling a development or you have or you're gonna be drilling a development well this year. Can you give us a sense of like what to expect from Trinidad? Is it more of, you know, the relative pricing dynamic there versus Dorado in terms of like which play is gonna get, you know, sort of more capital investment? Yeah, Scott, this is Billy Helms. For Trinidad, we've had, as you know, a long successful history of really maintaining pretty much flat production with minimal investment, and it generates quite a bit of cash for the company, cash flow for the company. It's been a very successful project for multiple decades now. We still see exploration opportunities and are still counting on exploration success going forward just based on the things we see today. The small guide down in gas production, especially in the next, let's say the rest of this year, is based on some turnaround projects we have on some of the compressor stations and platforms in the field. It's just an operational issue really in the manifest in the third quarter mainly. As we start to drill some of these exploration wells, we still have confidence that production base will continue. It should turn around back to sort of normal levels then by early 2023. Is that right? Yes, that's right. Got it. Thank you. Thank you. Our next question comes from Scott Gruber from Citigroup. Scott, please go ahead. Yes, good morning. Just coming back to the inflation question. I know you guys have previously commented that you don't see an outsized inflationary impact on EOG next year from contract roll or any other factors. But as you engage in these, you know, earlier than normal discussions for services and consumables, et cetera, are you still confident that the, you know, inflation that you experience next year will not be any worse than the, industry trend? Yeah. Scott, this is Billy Helms again. On the inflation question, I think I would distinguish a little bit there. I think we're recognizing the inflation that everybody else in the industry is seeing. We're able to combat that really through a lot of the efficiencies we drive through our business, and that's really a result of the culture we have of continuous improvement and the quality of the staff we have in each of our operating divisions. Now the contracting strategy has always been a long-term thing for EOG. We work with, you know, our vendors, our partners on the service side, and our contracts are always a little bit staggered so that all the contracts don't roll off at the same time. That gives us a lot of flexibility to also manage the commodity cycles to make sure we have a consistent operating performance level, going into the year. We always start about this time of year. I wouldn't say we're starting any earlier than we typically do. I think we always start at some time here in the middle part of the year to start securing services for the next year as we see things play out. We take opportunities as we see those emerge to make arrangements with vendors and our service partners to secure those services in the upcoming year. That determines the level of services that we can secure for next year's well cost. We typically like to think about securing about 50%-60% of the well cost ahead of any given year, and that range depends on the opportunities we see with service partners to lock in those services. This year, we expect to be somewhat the same as we go into next year. We'll see as we get closer to the year-end. That's how we see the inflation. Obviously, we expect with the tightness in the market, we're gonna see some additional inflationary pressure, going into next year. Just anticipating that we could see another uptick in our well cost going into next year, but we expect to again moderate a lot of that with our efficiency gains. Got it. Then, a follow-up here on the 60% distribution threshold, and really in light of the early hedge settlement payments you made this quarter. If you include those payments, which you guys are doing in your reporting, then you guys are running ahead of the threshold. But if you know, assume those are more of a one-time hit to free cash, then you're running a little bit, you know, behind that threshold. I know you look at the threshold at, on an annual basis. I guess the question is, you know, what's your appetite to approach the 60% payout for the year, you know, removing the impact of the $1.3 billion in early hedge settlement payments? Yeah. Scott, this is Ezra. You know, just a little bit of color on that. Obviously, you know, the board decides the dividend each quarter. They review, you know, our business needs, the macro environment, the cash position, so on and so forth. As you said, the $1.50 per share special this quarter, which brings the total dividend commitment to right at $7.30 per share, is on pace to achieve the minimum of a 60% free cash flow return. I think that's the emphasis on there is that the 60% is a minimum. Ultimately, it's up to the board, like I said, to return additional cash in 2022. The way to think about those early terminations of the hedges is really a reflection, I think, of our confidence in improving the financial profile of the company. You know, our ability to navigate inflationary pressures this year, flexibility to allocate capital across multiple resource plays, which are each delivering exceptional returns, and really our ability to continue to lower the cost base of the company. These are all things that deliver expanded free cash flow opportunities for EOG. Great. Appreciate the color, Ezra. Thank you. Thank you. Our next question comes from Neal Dingmann from Truist Securities. Neil, please go ahead. Good morning. My first question is maybe for you or Tim on a little bit different on capital allocation. Specifically, I'm trying to get a sense of what you all would need to see either quantitatively or qualitatively to start potentially looking at more and more, I guess, as guys call it out there, leaning into buybacks. You know, given I understand you all haven't bought back shares for years and, you know, we did see a you know, decent decline a month or so ago from the highs. I'm just wondering when you guys think about buybacks, what you know, when you say opportunistic, what really goes into that? Yeah. Neal, this is Ezra. Thank you for the question. You know, basically, we evaluate a buyback just like any other investment decision. Really what we do is we look to see how it's gonna create long-term shareholder value. As you highlighted and as we've discussed previously, the $5 billion share repurchase authorization that we have in place, we've talked about using it opportunistically. What that means for us is using it during times of what we would say are significant dislocations in the market. That's as opposed to a more, you know, programmatic system. Quite frankly, you know, this year during Q2, we didn't really see what we would say was a significant dislocation. We definitely witnessed a lot of volatility, I think, rather than a dislocation. The volatility was due, you know, it was driven by changes to the oil inventories that we saw, that was really due to the SPR releases. We saw some concern over demand destruction associated with the inflationary pressures across the broad market. We saw some potential for weaker demand associated with the uptick of COVID cases. But ultimately, in our view, you know, these are all kind of short-term events that really don't change the fundamental supply and demand picture. I like how you all are thinking about that, Ezra. My second or follow-up, slightly for, likely for Billy, just on vertical integration specifically. You all have other oil field service areas besides you mentioned the self-source sand, and I'm just wondering, do you have other areas that, you know, I guess you would call it more vertically integrated or, you know, you know, that you would think about doing that. I'm just wondering on that. Also, on that self-source sand, how much capacity do you have on that side? Yeah, Neil, this is Billy. Certainly on the self-sourced sand, you named one of the primary ones. It's a big part of our program. We've been doing that, as you might remember, for more than a decade. What we've been able to do is find ways to get the source of the sand closer and closer to the wellhead, minimizing not only the cost of the product, but also the transportation involved in getting it to the wellhead. We are expanding that through the rest of this year such that we'll be able to continue to supply greater and greater amounts from our own self-sourced mines. We're excited about the growth in that. Other areas that we self-source, there's a number of them. I mentioned briefly in the prepared comments a note to our efforts to take control of the drilling motors that we use in our drilling operation. That's a small thing maybe, but it's a big driver of performance when it comes to that part of the business. We recognized that a couple of years ago, built up some expertise in our staff to address that. We worked specifically to not only design, but also build and oversee the maintenance of those motors that ultimately drives the improved performance. We're seeing great results from that program. That's another differentiator in our drilling performance that allows us to continue to offset inflation. Some of the other things is, as you know, we've been managing our tubular inventory for many, many years as well. We deal directly with the steel mills, which gives us a lot of advantages in the sense of having some clarity or some certainty on the market, kind of what that's indicating to get ahead of issues where we see it, take advantage of opportunities to secure those at lower cost, and make sure that we have pipe for our programs on a go-forward basis. Those are maybe a couple of other things that would give you some color on what we're doing. No, that's great details, Billy. Thank you, Ezra, for the time. Thank you. Our next question comes from Doug Leggate from Bank of America. Doug, please go ahead. Doug Leggate, your line is now open. You can proceed with your question. No. Good morning, everyone. Thanks for letting me on. Ezra, slide 5 on your latest assessment of cash flow doesn't give any numbers around it in terms of breakevens. I wonder if I could just ask you to look into 2023 and give us an update of where you see your sustaining capital and the breakeven oil and gas prices that go along with that or the assumptions behind it, if you don't mind. Yeah. Doug, we haven't released that, and we did remove the breakeven slide from earlier this year because of the significant change in gas prices that have gone on in the first six months of the year. The best thing I can point to is the fact that we continue to bring on lower cost reserves, basically focused on the premium and double premium wells into the cost base of the company. You can look at the reduction in our unit costs and the reduction in our DD&A rate year-over-year to kinda infer the reduction in our breakevens. Okay. I'll push David on this and see if we can get him to put it back in because it's a pretty critical input to obviously the market's perception of free cash flow, but I appreciate the answer. My follow-up, Ezra, I apologize in advance. You're not gonna like this, but it's a follow-up on the share buyback question. You know, a valuation in your stock is subjective, obviously. If I look at your share performance in both absolute terms and in relative terms, in particular for the last four or five years, it's really struggled against the rest of the sector. One could interpret from your comments about dislocations and, you know, aversion perhaps to buybacks that you don't see value in your stock. I wonder if you could address that versus the transitory nature of a special dividend, why you wouldn't want to step in, because just about every one of your peers is doing something on buybacks, and their share performance is quite different from yours on a relative basis. Any thoughts around that would be appreciated. Yes, Doug. You know, the first thing I would say is that's right. I think it's stating the obvious that I feel that our stock is undervalued right now. Again, we look at that buyback and investment in that buyback, we compare it against other opportunities in the business to create shareholder value, long-term shareholder value. When we do that, when we compare it versus reinvesting in the business, drilling these double premium, these premium wells at a 30% and a 60% direct after-tax rate of return based on $40 oil and $2.50 natural gas, it's a very, very high hurdle. When we think about what can create longer term value for the shareholder, we see the benefit of reinvesting in the business, driving down our long-term well costs, lowering the breakevens, as we talked about, as a very, very competitive portion of allocation. Now, with regard to the transitory nature comparison with the transitory nature of a special dividend, I think again, it goes back to the way that we look at the buyback with regard to our shareholders. You know, repurchasing shares during a volatile movement in the stock price, I think our shareholders prefer to have the certainty of special dividends coming back to them as opposed to us trying to time the volatility in the markets. Now that's different from what, again, I would go back to what we call a significant market dislocation, where I think that you'd have an opportunity there that would compete very favorably to create long-term shareholder value. All right. It's a tricky one. I guess a special dividend isn't reinvesting, and if you think your stock is undervalued, then one could argue that the volatility is, you know, something you've got to live with, but you think is. I guess we're never gonna, you know, we're probably not gonna agree on this, but it seems to me the special dividend is, yeah, it's the less permanent, you know, impact on the share price, I guess, is what I was getting at. Anyway, I appreciate your answer, Ezra. I always appreciate your perspective. Thank you. Thank you. Thank you. Our next question comes from Paul Cheng from Scotiabank. Paul, please go ahead. Thank you. Good morning. Two questions, please. Ezra, could you comment on the A&D market, for example, in Eagle Ford? I think you gentlemen have said the asset is getting a little bit higher. So do you see opportunity to make maybe more sizable bolt-on acquisition that to beef up the operation there? Secondly, just wondering, have you guys get a chance to review the new standard proposal on the tax law changes and what will be any major impact to EOG? Thank you. Thank you, Paul. This is Ezra. Let me attack that first question on the Eagle Ford, and then I'll hand it over to Tim Driggers to give some feedback on the tax law proposals. On the A&D market there in the Eagle Ford, yeah, let me clarify how we're viewing the Eagle Ford right now. You know, we're on pace to deliver, for the second year in a row, basically, record rates of return and record finding costs, in our drilling program there. The big thing that it comes to is it kind of fits back into some of my opening comments, talking about the right investment rate, for plays at different life cycles. Clearly our Eagle Ford position has reached a point where it's not a main focus area for growth anymore. What we see is a very, very long runway of exceptional returns on those wells as you re-invest in them, assuming that we're moving at the right pace where our team has the ability to execute on lowering costs, increasing incrementally the well productivity. As far as expanding our footprint there, we still have a very robust Eagle Ford inventory position. When I think about the Eagle Ford position, you know, we've talked about 7,000 locations and being approximately halfway drilled through those locations, still well over 10 years worth of inventory to drill on. The other thing about looking to do A&D in an established basin like that is just gonna be the cost of acquisition. You know, we primarily focus our exploration efforts, and we always have for the you know two decades that we've been involved in unconventional resources on organic or greenfield lease acquisitions. Because that low cost of entry is critically important to providing through cycle value to the shareholders. You know, those, the PDP value that you would have to pay for in an established area or just established acreage prices, those things stay with you on your books forever. It raises the cost base of the company and is really antithesis to what we've been trying to do over the last few years by shifting to premium and now double premium drilling. Tim, would you like to please comment on the tax proposals? Sure. Paul, as far as the proposal, we're in the process of reviewing that, as is everyone else currently. Specifically looking at the minimum tax proposal, we do not see that as having any detriment to EOG. We are a full taxpayer already. As we model it currently, it will have no impact on EOG. Thank you. Our next question comes from Jeanine Wai from Barclays. Jeanine, please go ahead. Hi. Thanks for taking our questions. Maybe just following up on Paul's question there. Low-cost bolt-ons have always been part of your capital allocation strategy, and we noticed the cash flow statement had about $350 million of that in there. Any color on whether that was primarily blocking and tackling in your active areas, or is that more on the exploration front? Yeah, Jeanine, this is Billy Helms. That particular acquisition is really just an opportunity we found to bolt on some largely primarily acreage in some of our exploration plays. Very little, if no production on those plays. It just is another way that we can continue to add and grow at a low cost our exploration opportunity set that we see in the future of the company. Okay, great. Maybe just a quick one on marketing. You talked about you've got optionality for up to 250,000 barrels a day of Brent exposure. You're not electing that much right now. We're looking at your production levels out of the Permian and the Eagle Ford, and so what's the capacity to increase beyond that 250,000 or maybe to get to that 250,000? And if you were to take on some more exposure on that, is this really looking at things more on the contract side, or are you also open to securing more dock space on your own? Thank you. Oh, Jeanine, thanks for the question. A good question, too. It's timely. You know, the exports, especially for crude oil, has been important component of our marketing strategy. When you really look just from an industry standpoint, too, I mean, refiners in the U.S. are not expanding. I mean, if anything, it's degrading, right? I mean, we're seeing their market share. You're seeing refineries shutting down. You're seeing refineries that are being repurposed. We had a view going all the way back to 2018 that we wanted to have, you know, a significant export position that we could access from multiple plays. I know one of your questions there was just how do we think about the Delaware Basin or how do we think about the Eagle Ford? You're exactly right. That was all in our contracting, that we wanted to be able to have a large position that we could access from both of those plays. If you think about it today, we have that 250,000. Yes, that facility is expandable, but we have 5 million barrels of storage. I mean, we can segregate WTL, WTI. We can segregate our Eagle Ford. I mean, we're in a premier position as we think about from a low cost and being in early, with our tankage position and then also with the capacity that we have out of the Delaware Basin from a transport position and also from the Eagle Ford. What I would say is we can transact very quickly. We have tankage that's in place. If we feel the need that we needed to push more across, that's absolutely something that we could do. Great. Thank you. Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Neil, please go ahead. Hey, good morning, guys and team. Just one question for me. It's just, can you give us the lay of the land, of how the Dorado program is shaping up? How do you think about the net asset as we go into next year from a planning perspective, but, as we continue to see the gas curve has firmed up here, you know, how do you think Dorado can fit into the overall US gas picture? Thank you. Yeah, Neal, this is Ken. You know, at this time, we really have two drilling rigs active in the Dorado play. Just to give you a little bit of a background on it, since 2018, we've drilled and completed, you know, over 30 of our 1,250 premium locations, both in the Austin Chalk and the Eagle Ford. We've really made excellent progress on, you know, reducing well cost and enhancing our geologic understanding and increasing our well performance. We've increased our lateral length, and we're really operationally being able to execute. As far as how 2023 goes, it's a little early to talk about the 2023 program yet. Obviously, we'll remain disciplined with our investment there, you know, first to make sure that the market needs the gas and second to make sure we're operationally getting better. One thing to keep in mind is we really don't need a lot of wells there to grow production significantly, given the performance of the wells and their shallow decline rates. Thanks, team. In the interest of time, that is the end of the Q&A session today. I'll now hand you over to Mr. Yacob for closing remarks. Yes. We wanna thank everyone for participating on the call this morning, and thanks to our shareholders for their continued support. We especially want to recognize our employees for their performance this quarter. Our discussion today highlights their focus on making EOG a low-cost operator, generating high returns, and lowering our environmental footprint each and every year. Thank you. This concludes today's call. Thank you for joining. You may now disconnect your lines.