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, 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 includes 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 is 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. And 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 low refining 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 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 have made over the last several years provide 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 us 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% to 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, which 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 is 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 cost beat forecasted targets. So 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 upper 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 down-hole drilling motor program is providing solid performance improvements, generating a 13% year-over-year increase in the feet 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 have increased the amount of pumping hours per day by 24%. In addition, we continue to progress our self-sourced 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. 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 activities 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’re currently taking steps to secure services for next year, and we’ll 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, we 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 is 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, and 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 for many 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 mission 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 River 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, hydrating the specific landing zones. The basin has stacked potential similar to the Permian with two widespread well-known, very robust source rocks in the Mowry and Niobrara. Amongst 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 Powder River Basin 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 while 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 corded up acreage adjacent to our legacy acreage through a series of trades and small bolt-on transactions, utilizing reservoir data for multiple plays. We identified landing zones in the Mowry and Niobrara formations with favorable petrophysical and geomechanical properties and began testing. We drilled four 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 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 Mount Bellevue, Texas, and an underappreciated aspect of the Mowry and Niobrara wells is the 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 other 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 Mount Bellevue typical barrel. In addition, the quality of the Powder River Basin oil has an average API gravity of 44 to 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 Wyoming and Cushing, Oklahoma markets. Stepping back, I’d like to review our marketing strategy for the company as a whole and 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 Mount Bellevue. We also continue to see strong uplift in our natural gas price realizations due to our early mover advantage, securing 140,000 MMBtus per day linked to JKM through Cheniere LNG facility in Corpus Christi. Cheniere recently announced the final investment decision on Stage 3 in Corpus Christi. When Stage 3 goes in service, EOG will triple its exposure to JKM to 420,000 MMBtus 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. And 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, and 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. Our first question comes from Leo Mariani of MKM Partners. Leo, please proceed.

Hey guys, totally realize that it’s obviously 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. I guess it feels like a bit of a pivot from what you all had said in the past, which was kind of this 8% to 10% oil growth would kind of be optimal sort of operating speed for EOG as kind of something changed in terms of how you look at kind of optimizing the operations versus the growth of the company.

Yes, Leo, this is Ezra. I appreciate your question. 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. That’s really what we’ve tried to describe today is 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, and the associated inflationary pressures, oil growth will likely be similar to this year. And 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. And I just wanted to ask on the capital. Obviously, you’re one of the few companies that did not raise the CapEx budget thus far here in 2022. You described a lot of the ways that you’re able to kind of 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 big numbers, just talking a few on the margin. Just wanted to get a sense, is there 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?

Yes, Leo, this is Billy Helms. Yes, 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 going to 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. So 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, so we are going to see a slight increase in our well cost as we go through, especially the second half of the year, but we’re still confident we’re going to stay within our guidance and don’t expect to face additional costs that will increase our budget.

Okay. Thanks, guys.

Our next question comes from Arun Jayaram from JPMorgan Chase. Arun, please go ahead.

Hey, good morning. I appreciate the color on the Powder River Basin, but I guess my first question is just thinking about capital allocation between the basins as we think about next year. Today, Ezra, I think 22 of 24 of your rig lines are either in the Delaware or Eagle Ford. You have one 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. Just wondering if you can give us a sense of how your activity could shift as we think about next year and how many rig lines you may have in the Powder.

Yes, Arun, this is Billy. As far as capital allocation, as we see it today, there are a lot of factors that play into that, of course, and it’s early to say where we’re going to be. 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 will 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 that will continue to generate outstanding results. So that will still command capital. As we allocate capital based on returns, the encouragement we’re seeing from Dorado and the activity there is showing us the ability 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 come in with quite a bit of activity. The ratios, I would say, are going to stay similar. 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. But overall, the takeaway from that, I would think, would be that the flexibility we have with the multiple plays we have allows us 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?

Yes. This is Tim. As far as the bond, that matures in the first quarter of 2023. We have no plans to pay it off early. As far as the collateral they run off, kind of like the hedges that we’ve given you the timing of when those hedges are in our 10-Q. So it kind of runs off as that timing comes off. It all depends, of course, on where the strip goes, how that comes off. But right now, it’s based on the strip, and that would be how it would come off, 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.

Yes. Thanks. And if I could ask a question, one more question maybe on the PRB. You all highlight some good commodity price realizations that you’re all seeing there. Is that something that you think can persist going forward? And is it a function of what’s happening in the basin overall? Or is it specifically something EOG has 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. Yes, when you think about the price realizations, I think the broader message is just you can really see how competitive the Powder is with all our other plays. I mean, operationally, you heard Jeff 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. 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 a 44, 47, kind of over time. We really want to protect that quality. We’ve secured 500,000 barrels of storage in the field. We’ve got firm capacity to both Guernsey and the Cushing market. So having that multiple flexibility where we can show that kind of high demand barrel and the API quality that we have keeps it kind of segregated with that API quality. It’s really a value when we sell direct to our refiners. So just being able to have that value and have that quality and consistency is key, and so we draw a lot of that experience from what we’ve done in the Eagle Ford and also in the Powder – I mean, I’m sorry, in the Delaware Basin. But yes, that’s – the quality is what you’re seeing on the price realizations. And then, as you think about the NGLs, you’re seeing mostly ethane rejection that’s happening there. So most of that, you’re seeing the ethane that’s going to be going more towards like an MMBtu or selling that as a gas. And so that is a heavier barrel that you’re seeing that we kind of show. But again, we have the market flexibility. We can show that barrel in Conway. We can also show that barrel in Mont Belvieu. So we can kind of are that flexibility to, and look at those spreads. So getting kind of back to your question, I mean, really the quality and then the flexibility that we have with the multiple markets in an area that’s absolutely in demand.

Got it. Thanks for that. And as my follow-up, I want to ask a question on Trinidad. And it looks like you’re guiding down a fair amount for gas production in Trinidad. I know you’ve had some exploration success there, and I think you’re drilling a development or you have or you’re going to be drilling a development well this year. So can you give us a sense of like what to expect from Trinidad? And is it more of the relative pricing dynamic there versus Dorado in terms of like which play is going to get sort of more capital investment?

Yes, this is Billy Helms. For Trinidad, we have a long history of maintaining stable production with minimal investment, which generates significant cash flow for the company. This project has been very successful for many decades. We still see opportunities for exploration and are optimistic about future exploration success based on current observations. The slight reduction in gas production, particularly for the remainder of this year, is due to some maintenance projects on compressor stations and platforms in the field. This is primarily an operational issue that will mainly impact the third quarter. However, as we begin drilling some of these exploration wells, we are confident that our production base will continue.

Okay. Okay. So it should turn around back to sort of normal levels by early 2023. Is that right?

Yes, that’s right.

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 have you engaged in these earlier than normal discussions for services and consumables, et cetera. Are you still confident that the inflation that you experienced next year will not be any worse than the industry trends?

Yes, Scott, this is Billy Helms, again. On the inflation question, I think I would distinguish a little bit there. 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. 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. So now the contracting strategy has always been a long-term thing for EOG. We worked with our vendors, our partners on the service side. 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. We always started sometime 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, which determines the level of services that we secure for next year’s well cost. We typically like to think about securing about 50% to 60% of the well cost ahead of any given year. This year, we expect to be somewhat the same as we go into next year, but we’ll see as we get closer to the year-end, but that’s how we see the inflation. Obviously, we expect, with the tightness in the market, we’re going to 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. And then a follow-up here on the 60% distribution threshold really in light of the early hedge settlement payments you made this quarter, so if you include those payments which you guys are doing your reporting, then you guys are running ahead of the threshold. But if you assume those are more of a one-time hit to free cash, then you’re running a little bit behind that threshold. And I know you look at the threshold on an annual basis. So I guess the question is, what’s your appetite to approach the 60% payout for the year removing the impact of the $1.3 billion in early head settlement payments?

Yes, Scott, this is Ezra. Just a little bit of color on that. Obviously, the Board decides the dividend each quarter. They review our business needs, the macro environment, the cash position, so on and so forth. 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. 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. Neal, please go ahead.

My first question is for you or Tim regarding a different aspect of capital allocation. I’m trying to understand what you would need to see, both quantitatively and qualitatively, to consider looking at more buybacks. You’ve been buying back shares for years, and we noticed a notable decline about a month ago from the highs. So, when you think about buybacks and refer to them as opportunistic, what factors play into that?

Yes, Neal, this is Ezra. Thank you for the question. Basically, we evaluate a buyback just like any other investment decision. What we do is we look to see how it’s going to 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 programmatic system. Quite frankly, 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 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, these are all kind of short-term events that really don’t change the fundamental supply and demand picture.

I appreciate your perspective on that, Ezra. My follow-up question is for Billy, regarding vertical integration specifically. You mentioned self-sourced sand, but are there other oilfield service areas that you would consider more vertically integrated or are planning to explore? Additionally, I would like to know how much capacity you currently have for self-sourced sand.

Yes, Neal, 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. We’ve been able to 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 the year such that we’ll be able to continue to supply greater and greater amounts from our own self-sourced mines, so we’re excited about the growth in that. Other areas that we self-source, there are a number of them. I mentioned briefly in the prepared comments 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, and 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, 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 and 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. So those are maybe a couple of other things that would give you some color on what we’re doing.

That’s great details, Billy. Thank you guys for the time.

Thank you. Our next question comes from Doug Leggate from Bank of America. Doug, please go ahead.

Good morning, everyone. Thanks for letting me on. Ezra, Slide 5, your latest assessment of cash flow doesn’t give any numbers around it in terms of breakeven. 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, the assumptions behind that, if you don’t mind.

Yes, 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 kind of 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 going to like this, but it’s a follow-up from the share buyback question. Application in your stock is subjected obviously, but if I look at your share performance in absolute terms and in relative terms in particular for the last four or five years it’s – it’s really struggled to against the rest of the sector. One could interpret from your comments about dislocations and a version, perhaps the buybacks that you don’t see value in your stock. So if you could address that versus the transitory nature of a special dividend, why you wouldn’t want to step in to 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. So any thoughts around that would be appreciated?

Yes, Doug. The first thing I would say is that, that’s right, I think it’s stating the obvious that I feel that our stock is undervalued right now. But 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 return based on $40 oil and $2.50 natural gas. It’s a very, very high hurdle. So 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 cost, lowering the breakevens as we talked about has a very, very competitive portion of allocation. Now with regards on the transitory nature comparison with the transferring 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. Buying 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 we would call a significant market dislocation where I think you’d have an opportunity that would compete very favorably to create long-term shareholder value.

It’s a tricky one, I guess, a special dividend doesn’t reinvest, and if you think your stock is undervalued, then one could argue that the volatility is something you got to live with, but you think – I guess we’re never going to agree on this, but it seems to me the special dividend is, yes, it’s the lesser permanent input from the share price, I guess is what I was getting at. But anyway, I appreciate your answer, as 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 in, for example, in Eagle Ford, I think you gentlemen have said the asset is getting a little bit tired. So do you see opportunity to make maybe a more sizable bolt-on acquisition that to beef up the operation there? And secondly, just wondering if you guys have had a chance to review the new tender proposal on the tax law changes? And how that would 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. So on the A&D market there in the Eagle Ford, yes, let me clarify how we’re viewing the Eagle Ford right now. 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. So clearly our Eagle Ford position has reached a point where it’s not a main focus area for growth anymore, but what we see is a very, very long runway of exceptional returns on those wells as we reinvest them, assuming that we’re moving at the right pace, where our team has the ability to execute on lowering costs and 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, we’ve talked about 7,000 locations and being approximately halfway drilled through those locations. So 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 going to be the cost of acquisition. We primarily focus our exploration efforts and we always have for the 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. The PDP value that you would have to pay for in an established area or just established acreage prices 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. But specifically looking at the minimum tax proposal, we do not see that as having any detriment to EOG. We are a full taxpayer already, so 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?

Yes, 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. And then maybe just a quick one on marketing; you talked about – you’ve got the optionality for up to 250,000 barrels a day of Brent exposure. You’re not electing that much right now, but 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 securing to, or are you also open to securing more dock space on your own? Thank you.

Jeanine, thanks for the question. Good question too, as timely. The exports especially for crude oil has been an important component of our marketing strategy, but when you really look just from an industry standpoint too, I mean, refiners in the U.S. are not expanding. If anything, it’s degrading, right? I mean, we’re seeing our market share; you’re seeing refineries shutting down. You’re seeing refiners that are being repurposed. We had a view going all the way back to 2018 that we wanted to have 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? And 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. So if you think about it today, we have that 250,000 and 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. We are 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, and so 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 Ezra 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 is firmed up here? How do you think Dorado can fit into the overall U.S. gas picture? Thank you.

Yes. Neil, this is Ken. At this time we really have two drilling or executive in the Dorado play. Just to give you a little bit of a background on it, since 2018 we’ve drilled and completed over 30 of our 1,250 premium locations, both in the Austin Chalk and the Eagle Ford, and we’ve really made excellent progress on reducing well cost and enhancing our geologic understanding and increasing our well performance. We’ve increased our lateral length and we’re really operationally 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. 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 rate.

In the interest of time that is the end of the Q&A session today. So I’ll now hand you over to Mr. Yacob for closing remarks.

Yes. We want to thank everyone for participating in 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.