Good day, everyone, and welcome to the EOG Resources First Quarter 2023 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you and good morning. 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. Some of the reserve estimates on this conference call may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC’s reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; 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. Strong first quarter execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional results in 2023. Production, CapEx, cash operating costs and DD&A all beat targets, which underpinned our excellent financial performance during the first quarter. We earned $1.6 billion of adjusted net income and generated $1.1 billion of free cash flow. Free cash flow helped fund year-to-date cash return to shareholders of $1.4 billion through a combination of regular and special dividends, and share repurchases executed during the first quarter. Combined with our full year regular dividend, we have committed to return $2.8 billion to shareholders in 2023 or about 50% of our estimated 2023 free cash flow assuming an $80 oil price. We are well on our way to achieve our target minimum return of 60% of annual free cash flow to shareholders. Our first quarter results demonstrate the value of EOG’s multi-basin portfolio. We have decades of low cost, high return inventory that spans oil, combo and dry natural gas basins throughout the country. 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 beyond these core foundational assets, we continue to invest in our emerging Powder River Basin, Ohio Utica Combo and South Texas Dorado plays, which contribute to EOG’s financial performance today, while also laying the groundwork for years of future high return investment. Our portfolio provides flexibility to invest with discipline and develop each asset at a pace that allows it to get better. It provides optionality to actively manage our investments to minimize impacts from inflation. Diversity of our investment portfolio also translates to diverse sales market options, enabling us to pursue the highest netbacks. Our shift to premium drilling several years ago has helped to decouple EOG’s performance from short-term swings in the market. The result is an ability to deliver consistent, operational and financial performance that our shareholders have come to expect and that drives long-term value through the cycle. Recession risk and the near-term demand outlook for oil continues to drive volatility of prices month-to-month. However, our outlook remains positive, inventory levels currently near the five-year average are reducing as we progress through the year, global demand continues to increase and is forecast to reach record levels by year-end and new supply has moderated from pre-pandemic levels of growth. Longer term, with the reduced investment in upstream projects the last several years, we remain constructive on future pricing. For North American gas, near-term prices reflect high inventory levels due to this year’s warm winter and reduced LNG demand during repairs at Freeport. As such, we are currently evaluating options to delay some activity at Dorado. The medium- and long-term outlook for natural gas, however, continues to strengthen. Currently, U.S. LNG demand is at record levels, with an additional 7 Bcf a day capacity under construction or through FID with expected startup between 2024 to 2027 that should position the U.S. as a leader in the global LNG market. Our confidence in the outlook for our business is demonstrated by our capital allocation decisions in the first quarter. Disciplined reinvestment in our high return inventory continues to lower our breakeven and expand the free cash flow potential of EOG. We strengthened our balance sheet by retiring debt, paid out nearly 100% of free cash flow in regular and special dividends, and we utilized our repurchase authorization to buy back $310 million worth of stock late in the quarter during a significant market dislocation. I am confident EOG has the assets, the technology and the people to deliver both return on capital and return of capital for years to come. In a moment, Billy will discuss why we believe our foundational assets in the Delaware Basin and Eagle Ford will provide higher returns, margins and free cash flow in the years ahead, and why we remain excited about the progress we are making in our emerging assets, Powder River Basin, Ohio Utica Combo and South Texas Dorado. But first, here’s Tim to review our financial position.

Thanks, Ezra. EOG generated outstanding financial performance in the first quarter. We produced $1.6 billion of adjusted net income or $2.69 per share and $1.1 billion of free cash flow. Timing differences associated with working capital accounted for an additional $661 million of cash inflow in the quarter. Our outstanding financial results were driven by strong operating performance. Compared with the prior year, first quarter production volumes increased 2% for oil and 7% overall. We mitigated most of the inflationary headwinds to limit the increase to per unit cash operating costs to just 3% or $10.59 per BOE, which was more than offset by a 12% decline in the DD&A rate. Capital expenditures in the quarter of $1.5 billion came in $100 million below target. Our longstanding free cash flow priorities and cash return framework remain consistent. Our priorities are sustainable regular dividend growth, a pristine balance sheet, additional cash return options and low cost property bolt-ons. We are committed to return a minimum of 60% of the annual free cash flow to shareholders through our sustainable regular dividend, special dividends and opportunistic share repurchases. We believe the consistent application of our free cash flow priorities and transparent cash return framework positions the company to create long-term shareholder value through the cycle. In March, we strengthened the balance sheet by paying off a $1.25 billion bond at maturity with cash on hand leaving $3.8 billion of debt on the balance sheet. The next maturity is a $500 million bond due April 2025. Cash at the end of the quarter was $5 billion, yielding a net cash position of $1.2 billion, up $300 million from December 31. Yesterday, our Board declared a second regular dividend of $0.825 per share, the same as last quarter and a 10% increase from the prior year level. The $3.30 annual rate is a $1.9 billion annual commitment. On March 30, we also paid the $1 per share special dividend declared in February. EOG also repurchased $310 million of stock in the first quarter at an average price of $105 per share. For several days during the last two weeks of March, market volatility created a significant dislocation between the price of our stock and the value of the business. We were able to utilize our strong balance sheet to repurchase shares at highly accretive prices. We will continue to monitor the price and value of our stock and you should expect us to step into the market again when there are significant dislocations. We are off to a very strong start in 2023 to deliver on our full year cash return commitment of a minimum of 60% of annual free cash flow. Altogether, the full year regular dividend along with the first quarter special dividend and buyback, represents $2.8 billion of cash return, which is about 50% of the $5.5 billion of free cash flow we forecast for 2023 assuming an $80 oil price. We will continue to monitor oil and gas prices going forward and we remain committed to delivering on our cash return commitment and look forward to updating you over the rest of the year. Here’s Billy to discuss operations.

Thank you, Tim. EOG's operational performance is showing continuous improvement, with the first quarter delivering excellent results. Our volume, capital expenditures, and total cash operating costs for the quarter exceeded our forecasts. I want to express my gratitude to our employees for their hard work and exceptional execution, which has given us a strong start to 2023. Our capital and production plans for the full year remain the same. We anticipate a $6 billion capital program that will yield 3% growth in oil volume and 9% growth in total production. We have maintained activity levels from the fourth quarter of last year in both the Delaware Basin and Eagle Ford. Our core foundational plays are expanding, particularly in the Powder River Basin, Ohio Utica combo, and South Texas Dorado plays. Well productivity and cost performance across our portfolio are either meeting or exceeding expectations, with continued activity supporting ongoing innovation. As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford have performed exceptionally well, contributing significantly to our strong results in the first quarter. Consistent activity in these core plays is driving operational improvements and serves as a primary hedge against cost inflation. We are optimistic about the future of these assets. Even as they mature, we can apply technical insights, operational innovations, and previous investments to enhance our operating margins and capital efficiencies. In the Delaware Basin, we expect to see an increase in well performance this year, resulting in productivity and returns that exceed the premium hurdle rate. Last year, our Delaware Wolfcamp wells achieved an average six-month cumulative production of about 34 barrels of oil equivalent per foot, and we anticipate improvement this year. While the mix of oil, NGLs, and natural gas can influence overall performance, improvements are largely due to innovations such as our new completion design. We have tested 39 Wolfcamp wells that have shown an average first-year production increase of 22%, with a 20% improvement in estimated ultimate recovery compared to wells using our former completion design. Encouraged by these results, we plan to apply this new design to around 70 wells this year. This design continues to demonstrate potential as we increase the number of wells and test it across various targets and basins. Consistent activity in the Delaware Basin, coupled with a culture of continuous improvement, is yielding noticeable results. Drilling times are improving, contributing to leading peer performance through our drilling motor program and high-performing team. The footage drilled per motor run increased by 11% in the first quarter compared to last year. Similar advancements are occurring in our completion operations, particularly with the expansion of our super zipper technique. These initiatives, along with opportunities to co-develop multiple targets using our existing infrastructure, are expected to enhance efficiency and margins in the Delaware Basin for years to come. We first introduced the super zipper completion technique in the Eagle Ford in 2020. Since then, its use has expanded across the play, resulting in more than double the completion efficiency based on completed lateral feet per day. As shown in our quarterly investor slides, lateral completion rates have increased by 18% year-to-date compared to last year. In the first quarter, we also set a record in the Eagle Ford by drilling our longest well to date, achieving nearly 26,500 feet in measured depth and over 15,500 feet in lateral length. We anticipate continued improvements in completion efficiency as we extend laterals to over 3 miles where feasible. With over a decade of development in the Eagle Ford, we benefit from existing infrastructure supported by more than 3,700 producing wells. Leveraging these past investments reduces future capital needs and operating costs. Ongoing enhancements in completion activities and utilizing existing infrastructure have contributed to declining finding and development costs in the Eagle Ford. Last year, the Eagle Ford achieved its highest rate of return in the play's history. In the long term, we have more than a decade of drilling inventory in the Eagle Ford, allowing us to sustain our current production levels while achieving high returns and reducing breakevens. As previously stated, we are sustaining activity in our core plays while advancing our newer emerging plays. This year’s plan for Dorado includes completing eight additional wells compared to 2022 to maintain a consistent activity level for improved performance. Our drilling operations have seen a 29% improvement in footage drilled per day since 2021. Completion work is scheduled for a few wells in the second quarter, but we are considering delaying additional completions set for later this year in response to the current natural gas price environment. So far, operational advancements in Dorado's well performance are meeting or surpassing our initial expectations. Activity in the Utica combo play is just beginning, but we are already observing the benefits of sharing technology across our plays. For instance, recent drilling performance has improved by 20% to 30% compared to last year, aided by our proprietary drilling motor program and precision targeting. We expect similar improvements in our completion program when we start completing wells in the third quarter. Regarding inflation and industry service costs, as expected, the upward pressures we saw last year seem to have stabilized, leading us to believe that our average well costs will rise no more than 10% compared to last year. Early indicators suggest signs of moderation in service costs, which vary by basin. We anticipate that any decrease in service and tubular costs will take time to translate into lower well and operating costs, likely not until later this year or into 2024. As the year progresses, we will continue seeking ways to leverage our scale and the adaptability of our multi-basin portfolio to manage costs across all areas of operation. We are also committed to ongoing cost reductions through innovation, performance improvements, and efficient execution to counter inflation and further reduce our cost structure. Now I will turn it back to Ezra.

Thanks, Billy. In conclusion, I’d like to note the following important takeaways. First, strong execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional results in 2023. Thanks goes to our employees for delivering a great first quarter with their outstanding execution. Second, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a significant part of our first quarter results. Third, our first quarter performance demonstrates the value of EOG’s multi-basin portfolio. We have decades of low cost, high return inventory that spans oil combo and dry natural gas basins throughout the country. And fourth, our long-term outlook for both oil and gas remains positive, and our shift to premium drilling several years ago has helped decouple EOG’s performance from short-term swings in the market. The result is an ability to deliver consistent, operational and financial performance that our shareholders have come to expect and that drives long-term value through the cycle. Thanks for listening. We will now go to Q&A.

Thank you. Our first question is from Paul Cheng with Scotiabank. Paul, your line is now open.

Thank you. Good morning, everyone. I have two questions. The first one is likely for Billy. You mentioned the strong well productivity in the Permian. Could you provide more details regarding the testing sizes being conducted there and whether you are increasing those, especially in light of more co-development? Also, how many different landing zones are you targeting in your program? The second question relates to the recent inquiries from investors about the expansion in Dorado. In the last quarter's conference call, management indicated a focus on the long-term. I'm curious if there has been any change in your perspective regarding the pace of that development. Thank you.

Yeah. Paul, this is Billy. Let me give you a little highlight maybe of the Permian program and what we are seeing there. And then I will probably ask Jeff to give some more detailed color to help explain some of the improvements we are seeing. Overall, we are very pleased with the progress our Permian plans are showing. In general, our results are playing out just as we anticipated. In our plans, we had planned - all of our type curves are modeled and forecasted, and the results are meeting or exceeding our forecasted results including the co-development of different targets at the same time. But I’d like to go ahead and turn it over now to Jeff to maybe talk a little bit about the new completion design and the results that we are seeing and then some of the productivity improvements.

Yeah. Thanks, Billy. Paul, this is Jeff. Yeah. We’re extremely happy with our productivity out of the Delaware. And just to give you a little color, one of the big things that’s really improving that is our new completions design, or I should say, kind of our improved completion design. So, as Billy stated to date, we’ve tested around 39 wells in the Wolfcamp and we are seeing an uplift of about 20% or so in the well productivity and that’s in both the early and late life performance of that. I will also note that the uplift, we are not just seeing that in one phase. We’re seeing both in oil and gas, so kind of across the Board. So with these outstanding results, what we have done is we have really expanded this program and we’re planning on completing about 70 additional wells in the Wolfcamp this year. So going to be about a 2.5 times increase from last year and we definitely went ahead and taken this into account, both our drilling plans and guidance for 2023. So looking forward with this design, we’ve had a lot of success in our deeper formations. Our team really plans to continue to kind of test in some of the shallower formations to evaluate its benefits. One thing that we have observed with this design is that there’s varying performance uplift depending on the rock type and the depth of the target. And the design does come with a little bit of a cost increase, so we just want to be mindful about how quickly we’re testing it and be strategic at the pace that we’re going ahead and put these in the ground. Also, I’d like to point out that the design isn’t really new to EOG. It was actually first tested down in our Eagle Ford asset. And this is just an example of the technology transfer in the company of our multi-basin operations. It’s really helped us accelerate our learnings throughout the company. And then lastly, with the success that we have seen in the Delaware Basin, we’re actively testing it in all of our emerging places throughout the company and really look forward to evaluating those results throughout the year.

Paul, the other part of your question was about Dorado and what led to the change in pace we are considering. Initially, we developed a plan to remind everyone that we were not anticipating a significant increase in activity. We are only adding eight wells, so the plan was not designed for substantial growth in Dorado from the outset. However, we are always adaptable with our program, and that’s the advantage of having a diverse portfolio; we can adjust our activities based on market conditions or other influencing factors. Given that gas prices remain low as we progress through the year, it is reasonable to explore options regarding Dorado's operations. We are considering delaying some completions that were scheduled for later this year, and we will provide more details on that as the situation evolves.

Thank you, Mr. Cheng. The next question is from the line of Leo Mariani with ROTH Capital Partners. Leo, your line is now open.

Yeah. Hi. Just wanted to follow-up a little bit on the buyback versus the special dividend. Obviously, there was no new special dividend, I guess, announced this quarter instead, you got certainly lean on the buyback as you described in March. I just wanted to kind of confirm your thinking around this. I mean it still sounds like the buyback is going to be reserved only for kind of very opportunistic situations, where there is this dislocation. And generally speaking, it’s probably more reasonable to expect the special going forward with the buyback kind of maybe every once in a while, is that kind of how to think about it?

Yes, this is Ezra Yacob. Good morning. I believe you've captured it quite well. Our strategy remains unchanged. We aim to return at least 60% of our free cash flow annually. To date, our cash return commitment stands at $2.8 billion, which represents approximately 50% of what our free cash flow would be for the fiscal year, assuming an $80 oil price. To clarify, our cash return priorities start with the regular dividend as the first order of business. Any excess free cash flow will be distributed through special dividends—having issued them in seven of the last eight quarters—or through opportunistic buybacks. In the first quarter, we took advantage of market dislocations, mainly tied to the banking crisis, to repurchase about $300 million of our stock, aligning with our strategy. What's changed over the past 18 months since we authorized the buyback is the company's growing strength. Our core value proposition is focused on investing in high-return projects and acquiring lower-cost reserves, which lowers our breakeven points and improves our margins. As we implement this strategy and strengthen the company, our approach to dislocations evolves as well.

Okay. That’s helpful. And I just wanted to see if there’s any more of a robust update on the Utica. I think the last time you guys kind of rolled that out. I think you had four wells on production with a fair bit of history. Just trying to get a sense of the more wells producing at this point in time in the Utica and just any thoughts around some of the long-term performance of those prior wells have been on for, I guess, over a year at this point?

Yeah. Leo, this is Ken. We’re making excellent progress on our Utica program this year. We currently have a drilling rig actively operating in our northern area and we’re progressing nicely on our gathering and infrastructure projects. The four wells that you talked about that we drilled and completed in 2022 really do continue to deliver our expected performance and we plan to drill and complete about 15 wells across both our North and Southern areas this year and we will have those production results more towards the end of the year. Another thing to note is we also continue to add acreage and look for additional low-cost opportunities to add to our position.

Thank you, Leo. The next question is from the line of Scott Hanold with RBC. Scott, please go ahead.

Yeah. Thanks. Good morning and congrats on the quarter. Ezra, maybe if I could pivot back on the buyback conversation and if you can give us some color on, what were the key triggers on the decision to do buybacks? Was it relative valuation of EOG to peers, was it just the aggregate move or is there other things like intrinsic value assessments that kind of generated that process to really kick it off there?

Good morning, Scott. Yes. This is Ezra. Those are all accurate to the tune of how we kind of look at these opportunities. As we have talked about in the past, it kind of begins with the macro, first of all, right? What’s happening on both global and domestic supply and demand balances. As far as dislocations go, we do measure, we look at the intrinsic value of our business relative to different pricing scenarios, both short- and long-term. And we do evaluate trading multiples, not just at EOG versus the peers, but actually for the entire peer group and see what’s happening. And so one comparison that could be made is the dramatic sell-off that the industry saw last summer, which was associated with a pretty dramatic pullback in oil prices, that was really fundamentally supported by a change we felt in the macro outlook. There was a significant announcement there for roughly 300 million barrels of petroleum reserves that would be hitting the market on the supply side from across the globe. What we saw in the first quarter was not really supported by a big change in the forecast on the fundamentals. Potentially really just triggered from the banking crisis, potentially an increased fear on the demand side from increased recession, but we really feel like most of that has already been priced in to the market on the demand side. And so when we saw a pullback there in a dislocation with the market, really again associated in late March there with the banking crisis. We really didn’t hesitate and we have able to step into the market and do that $300 million share repurchase and we think we have really created a significant amount of value there for the shareholders.

That's great. Thanks for that. As a follow-up, I think one aspect that is often overlooked is the premium pricing you continue to achieve on your commodities. Looking ahead, do you see more opportunities to further enhance that?

Good morning, Scott. This is Lance. Thank you for your question. Our realizations remain strong, especially considering the multiple basins we operate in and our transportation position along with the capacity we've streamlined. It's crucial for us to maintain control all the way to the water. Looking ahead, our competitive position and pricing realizations, along with the potential to capture further premiums, put us in a great spot to seize additional opportunities quickly and leverage our scale effectively.

Thank you. The next question is from the line of Scott Gruber with Citigroup. Scott, please go ahead.

Yes. Good morning. I want to circle back on the Wolfcamp development strategy. After looking at slide 10 here in the deck, last year you layered in more Wolfcamp M wells. But this year, the percentage of Wolfcamp M will be slowing back down some. Is that impacted by where you will develop and deploy the new completion design or is that a reflection tend to be more selective with where you co-develop the Wolfcamp M, just what guidance shift in mix?

Yes, Scott, this is Jeff. Our co-development strategy is quite clear; we are focusing on adding high return targets to our well packages. The geology on our acreage varies significantly from one unit to another, so we need to carefully assess our strategy for each unit. Currently, as shown on slides 10 and 11 in our presentation, by incorporating deeper targets in the lower Upper Wolfcamp and the middle, we are achieving economic outcomes that exceed our premium hurdle rates, and we are maintaining one of the most efficient co-development paces in the basin. Overall, this approach enhances our total recovery per acre, optimizes the net present value of the resource, and reduces our barrel finding costs compared to the existing Delaware Basin levels.

Got it. And then maybe just one for some more color on the new completion design. You said it was initially developed and rolled out the Eagle Ford. Did it become a dominant design in the Eagle Ford and will it become the dominant design in the Permian and how quickly it can be rolled out to some of your new plays?

The design was first used in the Eagle Ford around 2016, but we didn't see the same improvements there as we do in the Permian. The differences in rock type and geological properties between the two areas account for that. However, it did help lower well costs and reduce completion time, so we still use it in the Eagle Ford and many of our emerging plays. In the Delaware, we plan to increase the rollout by 2.5 times what we achieved last year. There is a slight cost increase, so we need to be careful about how quickly we implement it. As with any aspect of our program, we want to make sure we learn as we go and continue to improve this technique.

Thank you. The next question is from the line of Derrick Whitfield with Stifel. Derrick, please go ahead.

Good morning, all, and thanks for taking my questions. With my first question, I wanted to focus on CapEx cadence throughout 2023. With Q1 coming in better than expected in Q2 projected to be heavier than expected. Could you comment on the one to two drivers, and separately, if not part of the answer, could you speak to cadence on non-D&C investments throughout 2023?

Yes, this is Billy Helms. The second quarter CapEx has increased compared to the first quarter primarily due to some non-drilling and completion capital, along with indirect infrastructure investments that were rescheduled from the latter part of the first quarter to the second quarter. This is why the first quarter was below our expected CapEx while the second quarter is a bit higher. We are still aligned with our original plan, where we intended to allocate approximately 52% of our CapEx to the first half of the year, keeping us on track for 48% in the latter half. That's how the program unfolds.

Great. And with my follow-up, I’d like to focus on your operational efficiency gains in the Eagle Ford. Is your gain principally driven by increased super zipper activity, and if so, are there practical limitations on the amount of completions you could pursue utilizing this approach?

Yeah. Derrick, this is Ken. I’d like to start off by really crediting our team there in San Antonio for driving down that finding cost that you talked about. Really by focusing on improving the efficiency of every portion of the process, we have been able to drive down costs over the past several years. And increasing our lateral lengths, while improving targeting and focusing on bit and motor performance in conjunction with the advent of super zipper completion operations have really allowed us to improve efficiencies and really drill and complete more lateral footage in a day compared to a few years ago. That’s really showing up on a lower cost basis. And one thing to note is we do have over 10 years of high-return drilling in this play that can sustain our current production levels and continue to expand our margins.

Thank you. The next question is from the line of Doug Leggate with Bank of America Merrill Lynch. Doug?

Good morning. This is John Abbott for Doug Leggate. Our first question is about Dorado. We understand that there may be a potential delay in activity this year. However, one of your goals this year was to begin achieving greater economies of scale. When do you think you will reach that size and scale, especially considering the additional LNG capacity that is coming online in 2026?

Yes, this is Billy Helms. We are increasing our activity in Dorado, primarily in drilling. We had also planned to bring in additional completions. On the drilling front, we are experiencing significant efficiency gains. The team has done an excellent job improving our drilling times, lowering well costs, and enhancing overall efficiency. We are very pleased with our progress, and the increased drilling activity is reflected in the results, providing us insights on how to further reduce well costs in the future. We have some planned completion activity in the second quarter, but we are also considering delaying the completion of any wells slated for the second half of the year. We are looking at ways to leverage learnings from our other programs and combine activities in Dorado by sharing equipment and personnel across our portfolio. Therefore, we do not feel the urgency to complete those wells immediately, but we are assessing options as they arise.

I guess…

LNG demand is interesting because it doesn't require many wells; the existing wells are very productive. We are well-positioned ahead of any future LNG capacity needs. Additionally, we can move gas from other areas, utilizing our multi-basin portfolio to serve the Gulf Coast. Therefore, the Dorado project should not be viewed solely in terms of the LNG market; it has the potential to incorporate gas from different players to the Gulf Coast through our marketing arrangements.

Thank you. The next question is from the line of Neal Dingmann with Truist. Neal, please go ahead.

Good morning. Thanks for the time. My first question, just on the Powder River. I am just wondering I heard too much on that right. I am just wondering how do you still feel this competes versus your other premium players? I know at one time, you suggested you had almost 1,700 locations and I am just wondering your thoughts around this.

Yeah. Neal, this is Jeff. We currently have excellent results in the Powder, and it features some of the lowest finding costs across our entire portfolio. We still have around 1,600 net undrilled premium locations between the full South Powder River Basin and the North. Looking at our program, everything is on track this year. The wells are performing as expected. In Q1, we completed approximately 15 gross wells, with two-thirds of those being Mowry, and we've been reaping the benefits of consistent activity in the Powder. We are operating two to three rigs consistently along with one full frac spread, which is significantly enhancing our efficiencies. We also have strong confidence in the play based on the overall performance with the Mowry. Additionally, we plan to gather data from the upper overlying formations, like the Niobrara, for future development. Furthermore, the infrastructure acquisition we made, which we noted in our 10-Q when we acquired Evolution, also boosts our confidence in the play. I’ll let Lance add a few comments on that.

Yeah. No. Thanks, Jeff. Yeah. Just to add to that, on our confidence when we think about the Powder River Basin, we did make a strategic investment there. That was about $135 million and we view that as a bolt-on acquisition and that’s really midstream footprint. There’s a plant and gathering system that just overlays our southern acreage. The plant is a first-class asset. It was completed in 2019 and when we think about this, it just really complements our existing gas gathering infrastructure build-out as we have connections in place. So we really look at that as value, because we can load that plant, fill the plant very quickly. And there’s also other benefits that we see long-term as well, as we think about just lowering cash operating costs, gathering, processing expense versus third parties, we will have control and redundancy, but then also to the confidence we can expand that very quickly. So…

Was that...

...when we think about that, we think about actually the gathering, processing and transportation expense. So it’s absolutely when we think about loading it with our equity gas into that facility and having control, we have definitely going to see better netbacks. But it’s more as we think about just controlling the cost and lowering the cost basis of the company that’s going to absolutely make the Powder River Basin and the Southern acres they are more competitive.

Thank you. The next question is from the line of Bob Brackett with Bernstein. Bob?

Good morning. Back to the Wolfcamp co-development. If you have hitting 2-plus targets in the Wolfcamp versus, say, cherry picking the best zone, all things being equal, you would expect wells to get worse, yet you have seeing wells get better. Is that attributable completely to the design change?

I would say this improvement is due to our co-development strategy. It's been a gradual process over time. Looking back to 2016, we initially had six unique targets in the Wolfcamp, and now we have grown to 18 unique targets. With this expansion, the spacing has evolved both vertically and laterally. Our teams have thoroughly tested these changes, considering actual spacing, interaction between zones, and depletion effects. We have developed the best co-development strategy to enhance overall production from these intervals while also improving the related economics.

Great. I guess the follow-up would be, so it sounds like the co-development strategy is driven by that desire to maximize the lack of communication between zones or is it more driven by just logistics of having that kit sit in one spot for a longer time?

No. It's really about maximizing the overall resource as you mentioned. We have optimized our communication to enhance recovery and truly maximize those economics.

Thank you. The next question is from the line of Arun Jayaram with JPMorgan. Arun, please go ahead.

Good morning. I wanted to revisit the new completion design. You mentioned testing this on 39 wells with plans to expand to 70 wells. My question is whether the 20% increase is in comparison to wells in the same area or relative to your type curve. Additionally, are the 70 wells expected this calendar year, and does that figure factor into your guidance, or would it represent an upside risk to your oil outlook?

Yeah. Arun, this is Billy. So the uplift we have seeing, part of that was actually baked into our guidance. We didn’t bake in the entire amount. So when we put together our plan, we understood that there were going to be some uplift. We did plan on 70 wells to be part of that calendar year program and we have baked in some of that into our production guidance, knowing that we would see some uplift. I think the uplift is surprising us a little bit more to the upside, but I would say that’s already factored into our guidance that we have issued. And then as far as the what we have doing there, we were finding that the target is critical. So the rock type is critical to why it works in some areas and so we have cautiously moving through our program to make sure we test as we go to understand which our targets lend themselves best to this design change and which ones don’t, because it does cost a little bit more and we want to be very disciplined on how we apply that across the fields we maximize as Jeff was saying, the economics of the play.

Okay. And just my follow-up is, any update on Beehive and Australia timing?

Yeah. Arun, on Beehive, we have still excited to be able to drill that well, but it’s going to be probably in the first half of next year before we have able to get that well drilled. And…

Thank you.

...just really due to some timing on permits and those kind of things.

The next question is from the line of Charles Meade with Johnson Rice. Charles, please go ahead.

Good morning, Ezra, Billy, Ken, and the entire EOG team. I have a couple of quick questions regarding some common themes you've discussed recently. Regarding the Dorado and the evaluation of the slowdown, can you provide some insight into your thoughts? Is this related to the natural gas price dropping below the 250 double premium, or is it more about the contango in the curve and the benefits of waiting a few months? I understand these issues may be interconnected, but I would appreciate your perspective on what specifically is prompting your review of the situation.

Certainly, this is Billy. It's not specifically triggered by a certain gas price, but rather the overall weakness in the current market conditions and the necessity to increase gas supply. In the near term, we comprehend the market softness, but over the medium and long term, we remain very optimistic about the future of gas. We are looking at the various flexibilities within the program and are considering options to effectively address this later in the year. We will continue to be disciplined with our investments to ensure we maximize the company's long-term value.

That's helpful. I have one more quick question about the Wolfcamp completion design. I gathered from your previous response that you're not planning a widespread change. However, I believe you have confirmed that there are 16 targets that are effective. Can you provide some insight into how many of these targets you plan to work on this quarter and potentially what the outlook is for reaching half or three-quarters of them?

Yeah. This is Jeff again. Yeah. That is correct. It’s not necessarily a one size fits all across. It really does have to do with the geology that we have applying it to. And when looking particularly there in the Permian, we primarily just applied it down in the deeper Wolfcamp targets. So that would basically be just kind of the up or down through the middle in a co-development standpoint. Now we are testing on those shallower targets, but there are quite a few different rock types. So right now, I’d say it’s area by area, and from a percentage basis, you kind of hate to put an actual percentage on it. But right now we have still evaluating that, and it will be a case-by-case basis.

Thank you. The next question is from the line of Neil Mehta with Goldman Sachs. Neil?

Yeah. Good morning, team. My question was on the natural gas liquids market where realizations, obviously, have been trending lower. I am just curious on your perspective on what gets NGLs to firm up relative to WTI and what are you seeing real time in the export markets? Thank you.

Yeah. Neil, good morning. It’s Lance. Yeah. I think what you have continuing to see absolutely the export positions that are getting built out. I think as you kind of have to think of those kind of as we think about them kind of more on ethane and more in propane. So continuing to see healthy propane exports. We continue to see the build out. That’s a company with that. You have continuing to see the demand as you think about the Far East demand that’s going to be the demand pool for those barrels. So continue to see that there could be some firming up there, kind of maybe more longer term, ethane, obviously, is going to flow a little bit more with gas prices and that’s kind of like what you have seeing today.

Yes. Neil, this is Ezra. As I stated kind of in the opening remarks, we still remain constructive on kind of the longer term gas story for the U.S. We think that the U.S., especially Dorado being a big piece of it has really captured low cost of gas supply that can really compete on the global scale with the amount of LNG that the U.S. is exporting right now, which is at record levels right now for the U.S. combined with the number of projects that have made it through a financial or a final investment decision and then the additional projects that are still being kind of planned and discussed, the U.S. will be long-term position to be really a global leader in the LNG market. Now gas is always difficult because it is highly volatile when it comes to things like the short-term pricing on weather. And it’s one reason you have heard this morning from both myself, Ken and Billy that the most important thing we look at when we develop Dorado is to really invest in that at the right pace for the long term. We want to make sure that we have not out running our learnings, that we appropriately invest to be able to keep our costs low and at the end of the day, really keep our margins wide. We want to put in the correct infrastructure to keep our low operating costs, because the margins are always pretty skinny on gas and the low-cost producer for gas is going to be able to be exposed to the global market here in the U.S. for the long-term.

Thank you. The next question is from the line of Josh Silverstein with UBS. Josh, please go ahead.

Yeah. Thanks. Good morning, guys. Maybe just sticking with gas first. You have an unusually wide gap on your differential even after reporting the first quarter results. Can you just talk about how you think that may shape over the course of the year, what you have looking for to come in towards the high end versus the low end there? Thanks.

Yes, Josh. This is Lance. When considering our guidance, we are just below the midpoint concerning our realization from a gas perspective. Our full-year guidance reflects that we expect to see significant contributions, particularly from our California exposure. As noted in our supplemental slide, we also have substantial exposure to the Gulf Coast and our JKM exposure. Therefore, I believe we will maintain our existing guidance.

Yes, Josh, this is Ezra. When we came out with that cash return guidance with a minimum of 60%, we really did just mean that, but it’s a minimum. In fact, last year we returned excess of this 60% free cash flow to our shareholders. And we started with that 60%, because we feel confident on that, especially when we roll in kind of almost a peer-leading regular dividend that we would be able to compete and deliver that through the cycles. So when we think about a specific target for cash on hand, I wouldn’t say that we have a real target. We have spoken about some indicators and things that we strategically think about as far as holding a cash balance. The first, of course, is we like to have a bit of cash on balance just to run the business to make us allow us to stay out of commercial paper, and historically, that’s around about $2 billion kind of depending at what point you are in the cycle. And then in addition to that, we do like to have cash on hand so that we can be strategic and counter cyclically invest in opportunities as they arise, whether that’s at times investing in casing or line pipe or last year we were able to step in and do an acquisition in one of our emerging players there in the Utica, where we actually purchased approximately 130,000 mineral rights. And then lastly, of course, just the stock repurchase, which we exercised here in the first quarter. We have talked about being able to utilize that opportunistically and really part of our strategy, the reason that you can actually step into a dislocated market and have the confidence to do a buyback is that you have got the strength of the balance sheet, which includes cash on hand. That’s really what we have going for and so I think that provides another compelling reason to carry potentially a higher cash balance than the company has historically done.

Thank you. That concludes our Q&A session for today. I will now turn the call back over to Mr. Yacob for any closing or additional remarks.

I just want to thank everyone for participating on the call this morning and I especially want to thank our employees for the outstanding results they delivered in this first quarter. Thank you.

That concludes the EOG Resources first quarter 2023 earnings results conference call. Thank you all for your participation. You may now disconnect your lines.