EOG Resources, Inc. (NYSE:EOG) Q1 2023 Earnings Call Transcript

EOG Resources, Inc. (NYSE:EOG) Q1 2023 Earnings Call Transcript May 5, 2023

Operator: 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.

Tim Driggers: 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.

Ezra Yacob: 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.

Tim Driggers: 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 boost location 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.

Billy Helms: Thanks, Tim. EOG’s operating performance continues to improve with the first quarter generating outstanding results. Our first quarter volume, capital expenditures and total per unit cash operating cost performance came in better than our forecasted targets. I’d like to thank our employees for their dedication and outstanding execution, giving us a great start to 2023. Our full year 2023 capital and production plans are unchanged. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We maintained the pace of activity from the fourth quarter of last year in the Delaware Basin and Eagle Ford. Our core foundational plays and continue to expand development in our emerging Powder River Basin, Ohio Utica combo and South Texas Dorado plays.

Well productivity and cost performance are meeting or beating expectations across our portfolio as each play sustains sufficient activity to support continued innovation. As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a big part of our overall strong first quarter results. Sustaining a consistent level of activity in these core plays is driving operational improvements and continues to be one of the primary hedges to offset areas of cost inflation. We are excited about the outlook for these assets in the years ahead. Even as these assets mature, we can apply technical learnings, operational innovation and leverage prior infrastructure investments to continue to improve the operating margin and capital efficiencies of these world-class assets.

In the Delaware Basin, we expect well performance will continue to improve this year, delivering productivity and returns well above the premium hurdle rate. Last year, our Delaware Wolfcamp wells delivered an average six-month cumulative production of about 34 barrels of oil equivalent per foot and are expected to improve this year. See slide 10 of our updated investor presentation for details. While well mix can impact the relative contribution of oil, NGLs and natural gas, overall performance is improving in large part due to continued innovations like our new completion design. We have now tested 39 wells in the Wolfcamp that are yielding an average increase of 22% in the first year production, with a 20% uplift in the estimated ultimate recovery compared to the similar wells and targets using our previous completion design.

With these encouraging results, we now expect to deploy this new design on about 70 wells this year. This new design is continuing to show promise, as we expand the number of wells and test the design across different targets and basins. Operationally, maintaining a consistent level of activity in the Delaware Basin, combined with our culture of continuous improvement is generating noticeable results. Drilling times continue to improve and are generating peer-leading performance aided by our drilling motor program and high-performing staff. The amount of footage drilled per motor run improved by 11% in the first quarter as compared to last year. Similar progress is being achieved with our completion operations with the expansion of our super zipper technique.

These efforts, combined with the opportunities that co-developed multiple targets in the stacked pay resource by using our existing surface footprint and an infrastructure are expected to drive significant efficiency gains and continue to improve our margins in the Delaware Basin for years to come. The first — we first introduced the super zipper completion technique in the Eagle Ford in 2020. Since then, we have expanded its use throughout the play and have more than doubled completions efficiency as measured by completed lateral feet per day. As indicated on page 12 of our quarterly investor slides, the amount of lateral completed per day year-to-date has increased by another 18% compared to last year. In the first quarter, we also set a record in the Eagle Ford, drilling our longest well to-date, reaching a measure depth of nearly 26,500 feet with a lateral length of over 15,500 feet.

We expect to continue to see completion efficiency improvements as we extend laterals in the Eagle Ford to 3-plus miles where feasible. As a core operating area that has been under development for more than a decade, the Eagle Ford also benefits from our existing infrastructure from over 3,700 producing wells. Leveraging existing investments made in strategic water, oil and gas infrastructure minimizes future CapEx needs and lowers operating costs. Ongoing improvements to completion operations and leveraging the benefit of existing infrastructure, enable our Eagle Ford finding and development costs to continue to decline. Last year, the Eagle Ford’s rate of return was the highest in the plays history. Longer term, we have over a decade of drilling inventory in the Eagle Ford, allowing us to maintain the current production base, while generating high returns and lowering breakevens.

As previously mentioned, we are maintaining activity in our core plays and progressing our newer emerging plays. This year’s plan in Dorado contemplates eight additional wells completed compared to 2022 in order to achieve a consistent level of activity to drive performance improvements. Our drilling operations are realizing a 29% improvement in the footage drilled per day since 2021. Completion operations will be conducted on a few wells in the second quarter. However, we are evaluating options to delay additional completions originally scheduled later this year due to the current natural gas price environment. To-date, operational progress towards improvements and Dorado’s well performance is meeting or exceeding our early expectations.

Activity in the Utica combo play is just commencing, yet we are already witnessing the compounding effects of sharing technology across our multiple plays. For example, drilling performance for recent wells is improving on the order of 20% to 30% compared to last year’s results with the benefit of our proprietary drilling motor program and precision targeting. We expect similar levels of improvement from our completion program once we begin completing wells in the third quarter. Now for a little color on inflation and industry service costs. As we had anticipated in building this year’s plan, the upward inflationary pressure that we witnessed last year appears to have plateaued, which still leaves us confident that our average well cost should increase no more than 10% compared to last year.

Early indicators are showing signs of service cost moderation, which is more prevalent in some basins and less than others. We would expect that any softening of service and tubular costs will be slow to manifest into lower well cost and cash operating costs until much later in the year or more likely in 2024. As the year unfolds, we will continue to look for opportunities to leverage our scale and the flexibility of our multi-basin portfolio to manage costs across all operating areas. We also remain highly focused on sustainable cost reductions through innovation, operational performance and execution improvements to mitigate inflation and further drive down our cost structure. Now I will turn it back to Ezra.

Ezra Yacob: 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.

Q&A Session

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

Paul Cheng: Thank you. Good morning, everyone. Two questions, please. I think the first one is probably for Billy. You talked about the Permian, the good well productivity. Just can you give us a little bit more detail in terms of the test size you have doing over there and whether you have increasing it, especially if you start to do more co-development and how many different landing zones or that you are targeting in your program? And second one that, just curious, I mean, I think, in the last, say, several months, a lot of investor have been asking why that go ahead with the expansion in the Dorado and I think last quarter in the conference call, management has said, you have looking for the long-term. So just curious that what may have trigger your — maybe there’s a slightly change in your view about the pace on that development? Thank you.

Billy Helms: Yeah. Paul, this is Billy. Let me give you a little highlight maybe of the Permian program and what we have seeing there. And then I will probably ask Jeff to give some more detailed color to help explain some of the improvements we have seeing. Overall, we have 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 have seeing and then some of the productivity improvements.

Jeff Leitzell: Yeah. Thanks, Billy. Paul, this is Jeff. Yeah. We have 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, our improved completion design. So as Billy stated to-date, we have tested around 39 wells in the Wolfcamp and we have 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 have not just seeing that in one phase. We have 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 have 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, 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 have testing it and be strategic at the pace that we have 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 have actively testing it in all of our emerging places throughout the company and really look forward to evaluating those results throughout the year.

Billy Helms: And then, Paul, the other part of your question was on Dorado and really what triggered the change of pace that we have thinking about. We put together a plan originally just to remind everybody that really, it was not a huge acceleration in activity planned for. We have only adding eight wells. So the plan never contemplated a huge amount of growth in the — in Dorado to start with. However, we always remain flexible on our program and with — that’s the benefit of having a multi-basin portfolio as we can move activity around based on market conditions or other factors as they present themselves. Naturally, with gas prices remaining weak and moving into the year, it’s only natural to think about options that we might be able to explore with Dorado activity. We are exploring the option to delay some completions that were scheduled for later in the year and we will give more color on that as that unfolds.

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

Leo Mariani: 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?

Ezra Yacob: Yes. Leo, this is Ezra Yacob. Good morning. I think that’s — I think you have summarized it pretty well. Our strategy hasn’t really changed. We are committed to returning at least 60% of our free cash flow on an annual basis. Year-to-date, as Tim had mentioned, our cash return commitment is $2.8 billion. It’s approximately 50% of our — what would be our fiscal year free cash flow at the assumed $80 oil price there. And just to recall, the cash return priorities for us, it really begins with the regular dividend as the first priority. The excess free cash flow, as you said, will either come back in the form of special dividends, which we have paid seven quarters of the last eight quarters, we have distributed a special dividend or opportunistic buybacks.

And what we saw in the first quarter when we executed a repurchase was, we really saw a dislocation dominantly associated with the banking crisis and we were able to step in to repurchase approximately $300 million of the stock. So, as you pointed out, really in line with our strategy. Now what I would say has changed over the last 18 months since putting the repurchase authorization in place is really the strength of our company. Our primary value proposition, of course, is investing in high return projects, adding lower cost reserves to our company’s profile, which thereby reduces our breakevens and expands our margins. And so as we continue to execute on this strategy and we continue to strengthen the company, the way we consider dislocations certainly evolves as well.

Leo Mariani: 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?

Ken Boedeker: Yeah. Leo, this is Ken. We have making excellent progress on our Utica program this year. We currently have a drilling rig actively operating in our northern area and we have 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.

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

Scott Hanold: 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?

Ezra Yacob: 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.

Scott Hanold: That’s great. Thanks for that. And as my follow-up, one of the things I think tends to get lost or is underappreciated is the premium pricing you all continue to get on your commodities across the Board. And can you just give us a sense of — as you kind of look forward, do you find more opportunities ahead where you can continue to raise the bar on that as well?

Lance Terveen: Hey, Scott. Good morning. This is Lance. Thanks for the question. Yeah. The — our realizations continue to be excellent, and I mean, when we think about it, it’s really just the capability that we have. When you think about the multi-basins that we have, but just our transport position and then the capacity that we have taken out. You hear us talk a lot about control and having control all the way to the water is exceptionally important. So I would just say, as you think about our position and the price realizations too and then extracting additional premiums, I think, our ability to just transact very quickly and with the supply, the scale that we have, I mean, we can definitely walk in with further opportunities.

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

Scott Gruber: 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?

Jeff Leitzell: Yeah. Scott, this is Jeff. Really with the — our co-development strategy, it’s pretty straightforward, and what we have trying to do is, we have just adding in high rate of return targets to our well packages. And really it’s driven by the geology, and obviously, the geology across our acreage, it changes very quickly. So kind of from development unit to development unit, we have really got to strategically dissect what our strategy is going to be there. But from what we have seeing right now, and you can see that on slide 10 and 11 in our deck, by adding in some of those deeper targets in the lower Wolfcamp, or I should say, the lower Upper Wolfcamp and then the middle, we have achieving economics well over our premium hurdle rates and we have some of the tightest co-develop pacing out there in the basin.

So ultimately, just this approach, I mean, it’s improving our total recovery per acre, helping optimize that NPV of the resource and it’s just adding those barrels finding costs below our current Delaware Basin levels.

Scott Gruber: 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?

Ezra Yacob: Yeah. Scott, great question. So, yeah, the design, as I talked about, it was first utilized in the Eagle Ford. It was back in — right around 2016 and we didn’t see the same uplift that we see in the Permian. It wasn’t quite as extensive, but it really has to do with the difference in rock type and their geological properties between the two plays. But it did provide the application, we are really beneficial as far as helping lower well costs and reduce our completion time. So, yes, it is something that we still do employ there in the Eagle Ford, and as I said, in a lot of our emerging plays. As far as in the Delaware and our rollout, our plan is to increase, as I said, the year-over-year number by 2.5 times what we did last year.

And I also did state, there’s just a slight cost increase, so we want to be cognizant of how quickly we roll it out and like anything in our program, we just don’t want to outrun our learnings and we want to make sure that we continue to evolve this technique as we learn.

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

Derrick Whitfield: 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?

Billy Helms: Yeah. Derek, this is Billy Helms. So, yeah, the second quarter CapEx has gotten to be a little bit higher than the first quarter and it’s mainly due to some non-drilling and completion capital, the indirect or infrastructure and those kind of things that we put in our program that it was recently scheduled to occur at the latter half of the first quarter, it turned out to be pushed into the second quarter. That’s the reason the first quarter under — was under our own CapEx and the second quarter is a little bit higher. And that really sticks to our original plan, we had always planned for about 52% of our CapEx to be spent in the first half of the year and so we have still on target for that in the 48% in the back half, so that’s kind of the way the program plays out.

Derrick Whitfield: 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?

Ken Boedeker: Yeah. Derek, 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.

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

John Abbott: Good morning. This is John Abbott on for Doug Leggate. Our questions — first our question are really on Dorado. We understand that you have going to potentially delay activity this year. But one of the goals that you set out this year was to try to just begin get greater economies of scale into play. When do you think you need to achieve that size and scale, noting that you have additional LNG capacity coming on, exposure in 2026?

Billy Helms: Yeah. John, this is Billy Helms. So for Dorado, yes, we are increasing activity there, mainly from a drilling side. Recently we had planned to also bring in additional completions. On the drilling side, I would add that, we are seeing a tremendous improvement in the efficiency gains there. The team there has done just an excellent job of being able to improve our drilling times, lower our well costs and just increase efficiencies overall. So we have very pleased with the progress we have made and so I think that increased activity we have seeing on the drilling side is playing out what we have seeing on the drilling results and giving us insights into how we can continue to lower well costs going forward. On the completion side, we have some planned activity here in the second quarter.

But beyond that, we have looking at ways we can — with the flexibility we have in our program to delay the completion of any wells that would be on in the second half. And really just thinking about how we can leverage some of the learnings from our other programs in play and combine that activity with the activity we have in Dorado by sharing equipment, people and those learnings across our portfolio. So we don’t really feel the need to jump in and complete those wells, but we are evaluating options as they roll out and we will see how those present themselves. And then as far as the activities for…

John Abbott: I guess…

Billy Helms: …LNG demand, I guess, the play — the unique thing about this play, it didn’t take a lot of wells. The wells are very prolific. So we have well ahead of any timing that we would need to add LNG capacity in the future. And then we also have the flexibility of moving gas from other operating areas, multi-basin portfolio to the Gulf Coast. So don’t think of the Dorado is just simply applying itself to the LNG market. It’s got the opportunity but looking at gas from other players to the Gulf Coast as well through our marketing arrangements.

John Abbott: That’s extremely helpful, which leads to the next question. Assuming there was not an issue with gas prices, how do you think about the optimal level of production for that play or activity long-term? I mean, how big does it came to get to? How do you think about that program — that — from an efficiency program longer term?

Ken Boedeker: Yeah. John, this is Ken.

John Abbott: You can…

Ken Boedeker: Yeah. John, this is Ken. I think the real thing in Dorado is it doesn’t take a lot of wells to generate significant volumes out of that play. So I don’t know the exact right pace. But what we want to do is we want to develop this at the right pace where we don’t outrun our learnings. We have making significant progress as we really get those operational synergies together that Billy talked about and so that pace of development is really going to be dictated by not outrunning our learnings.

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

Neal Dingmann: 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.

Jeff Leitzell: Yeah. Neal, this is Jeff. No. We have outstanding results there in the Powder right now and it’s some of the lowest finding costs that we have seeing there in the whole portfolio. So, yeah, we still have between kind of our full South Powder River Basin and then moving up to our North, about 1,600 net undrilled premium locations. So just looking at our program, everything is on pace this year. The wells are performing as we expected. Q1 we have completed about 15 gross wells, which two-thirds of those were Mowry and we have seeing a lot of benefits also by getting some consistent activity up there in the Powder. We have running a consistent two and — two to three rigs and one full frac spread with that, which is really allowing them to kind of push their efficiencies.

And then we also have a lot of confidence in the play just with the overall performance and stuff with the Mowry. And then from there, as we talked about, we want to go ahead and gather the data in the upper overlying formations like the Niobrara, so we can develop that later in the future. Also, additional confidence in the play, I think, would be really — should be said is that the infrastructure acquisition that we had. We had noted that in our 10-Q, we acquired Evolution. And I will go ahead and let maybe Lance say a couple of things on that.

Lance Terveen: 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…

Neal Dingmann: Was that…

Lance Terveen: … the last thing I just…

Neal Dingmann: Was that plant helped a deeps there as well? I am just wondering would you mention with that plant, would that boost the deeps there a little bit as well?

Lance Terveen: 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 been 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.

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

Bob Brackett: 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?

Ezra Yacob: No. I’d say it’s attributed to our co-development strategy. I mean it’s — really, it’s been a process over time. So if you look at back in 2016 in the Wolfcamp or I should say our strategy through the whole Permian, we had six unique targets and kind of fast forward here, we have up to 18 unique targets. Obviously, with that, the spacing has changed both in zone and from a vertical perspective. So our teams have methodically obviously tested this. They have taken into account the actual spacing, how they interact, the depletion to it, and we have come up obviously with the best co-development strategy really to maximize the overall production of those intervals and then obviously maximize the economics related to it.

Bob Brackett: 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?

Ezra Yacob: No. It’s really — it’s about maximizing the overall resource there, as you said. So we do have the optimal amount of communication that we have actually able to optimize the recovery and then like I said, really maximize those economics.

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

Arun Jayaram: Yeah. Good morning. I wanted to come back to the new completion design. You highlighted how you have tested this on 39 wells and you plan to go to 70 wells. And my question is, was the 20% uplift relative to wells in the same area or relative to the — to your type curve? And maybe the follow-up is, are the 70 wells contemplated for this calendar year and was that part of your guidance, did that include that or would that reflect an upside risk to your oil guide?

Billy Helms: 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.

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

Billy Helms: 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…

Operator: Thank you.

Billy Helms: …just really due to some timing on permits and those kind of things.

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

Charles Meade: Good morning, Ezra, Billy, Ken and the whole EOG team there. I think just a couple of quick ones for me touching on some of the common themes that you have already spoken on for a while. The Dorado, evaluating the slowdown, can you give some insight in your thinking? Is this about the natural gas price falling below your 250 double premium or is this about the contango you see in the curve and just the value of just waiting a few months or is it — I recognize those aren’t exclusive, but just some insight what really keep you guys to want to examine that?

Billy Helms: Yeah. Charles, this is Billy. Certainly, it really is not triggered on a specific gas price, but just the overall softness we see in the current market conditions and the need to simply bring more gas on in this current condition. As we talk near-term, we understand the near-term softness in the market but longer term, medium and longer term, we have still very bullish on the long-term outlook for gas. So we do look at the different flex — the flexibility we have in the program and we have evaluating options to be able to successfully push those back in the year. And we have just continue to remain disciplined on our investment to make sure we have maximizing the value to the company over the long-term.

Charles Meade: Okay. That’s helpful. And then just one more quick one on this Wolfcamp completion design. So I got the message, I think, in your last — your response to the last question, that this is not going to be an across the Board shift that you would want to make. But presumably you have confirmed, I think, you have talking about 16 targets it works and can you give us a sense as we work in a quarter of the targets and maybe upside to half or three quarters or what’s it look like to you guys right now?

Jeff Leitzell: 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.

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

Neil Mehta: 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.

Lance Terveen: 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.

Neil Mehta: Great. And then just curious on your guys’ perspective on the gas markets as well. You have talked a little bit about slowing down potentially in terms from a drilling perspective, but how do you see the balances moving from here in a weather normal way over the course of the year?

Ezra Yacob: 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.

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

Josh Silverstein: 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.

Lance Terveen: Yeah, Josh. Hey. This is Lance. I believe when we think about our guidance, I think, we were just below the midpoint of the guidance on our realization so from a gas standpoint. And then you have seen kind of our guidance for like the full year and we expect a lot of that’s going to be driven, obviously, we have the diversification that we have with our California exposure. We have — you can see on our supplemental slide, slide eight, you can obviously see the large exposure that we have into the Gulf Coast and then obviously, our JKM exposure as well. So I think we have going to hold with the existing guidance that we have.

Josh Silverstein: Got it. And then just as far as the shareholder return profile, I know you have been thinking about it from a percentage of free cash flow. But how would you think about it from managing like a cash balance standpoint? You have been over $5 billion now for the past few quarters, including paying down the debt maturity in the first quarter. Is $5 billion, $6 billion the right level of cash for EOG? What level of cash would you not want to get over, because it feels like there are certain periods where you could return over 100% of cash or free cash flow to shareholders if you really want to? Thanks.

Ezra Yacob: 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.

Operator: 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.

Ezra Yacob: 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.

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