EOG Resources Q1 2023 Earnings Call Transcript

Quartr
Provided by Quartr
May 5, 2023

There are 15 speakers on the call.

Operator

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.

Speaker 1

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.

Speaker 1

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 Leitzel, EVP, Exploration and Production Lance Terveen, Senior VP, Marketing and David Strike, VP, Investor Relations.

Speaker 2

Across our multi basin portfolio has positioned the company to deliver exceptional results in 2023. Production, CapEx, cash operating costs and DD and A all beat targets which underpinned our excellent financial performance during the Q1. We earned $1,600,000,000 of adjusted net income and generated $1,100,000,000 of free cash flow. Free cash flow helped fund year to date cash return to shareholders of $1,400,000,000 through a combination of regular and special dividends and share repurchases executed during the Q1. Combined with our full year regular dividend, we have committed to return $2,800,000,000 to shareholders in 2023 or about 50% of our estimated 2023 free cash flow assuming an $80 oil price.

Speaker 2

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.

Speaker 2

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.

Speaker 2

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 5 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.

Speaker 2

Longer term, with the reduced investment in upstream projects to 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.

Speaker 2

S. LNG demand is at record levels. With an additional 7 Bcf a day capacity under construction or through FID with expected start up between 2024 to 2027 that should position the U. S. As a leader in the global LNG market.

Speaker 2

Our confidence in the outlook for our business is demonstrated by our capital allocation decisions in the Q1. Disciplined reinvestment in our high return inventory continues to lower our breakevens 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 $310,000,000 worth of stock late in the quarter during a significant market dislocation. I'm 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.

Speaker 2

But first, here's Tim to review our financial position.

Speaker 1

Thanks, Ezra. EOG generated outstanding financial performance in the Q1. We produced $1,600,000,000 of adjusted net income or 2.69 percent per share and $1,100,000,000 of free cash flow. Timing differences associated with working capital accounted for an additional $661,000,000 of cash inflow in the quarter. Our outstanding financial results were driven by strong operating performance.

Speaker 1

Compared with the prior year, 1st quarter Volumes increased 2% for oil and 7% overall. We mitigated most of the inflationary headwinds which was more than offset by a 12% decline in the DD and A rate. Capital expenditures in the quarter of $1,500,000,000 came in $100,000,000

Operator

at a low target.

Speaker 1

Our long standing 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 In March, we strengthened the balance sheet by paying off A $1,250,000,000 bond at maturity with cash on hand, leaving $3,800,000,000 of debt on the balance sheet. The next maturity is a $500,000,000 bond due April 2025.

Speaker 1

Cash at the end of the quarter was $5,000,000,000 yielding a net cash position of $1,200,000,000 up $300,000,000 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 $1,900,000,000 annual commitment. On March 30, we also paid the $1 per Share special dividend declared in February. EOG also repurchased $310,000,000 of stock in the Q1 at an average price of $105 per share.

Speaker 1

For several days during the last 2 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 Q1 special dividend and buybacks represents $2,800,000,000 of cash return, which is about 50% of the $5,500,000,000 of free cash flow we forecast for 2023 assuming an $80 oil price.

Speaker 1

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.

Speaker 3

Thanks, Tim. EOG's operating performance continues to improve with the Q1 generating outstanding results. Our Q1 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.

Speaker 3

We forecast a $6,000,000,000 capital program To deliver 3% oil volume growth and 9% total production growth, we maintain the pace of activity from the Q4 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 Place. Well productivity and cost performance are meeting or beating expectations across our portfolio as each play sustained sufficient activity to support continued innovation. As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well And we're a big part of our overall strong Q1 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.

Speaker 3

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 6 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.

Speaker 3

We have now tested 39 wells in the Wolfcamp that are yielding an average increase of 22% in the 1st year production With a 20% uplift in 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.

Speaker 3

The amount of footage drilled per motor run improved by 11% in the Q1 as compared to last year. Similar progress is being achieved with our completion operations With the expansion of our SuperZipper technique, these efforts combined with the opportunity to co develop multiple targets In the STACK pay resource, by using our existing surface footprint and infrastructure, are expected to drive significant efficiency gains and continue to improve our margins in the Delaware Basin for years to come. We first introduced the SuperZipper 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.

Speaker 3

In the Q1, we also set a record in the Eagle Ford, Drilling our longest well to date, reaching a measured 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 It 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 play's history.

Speaker 3

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 8 additional wells completed compared to 2022 In order to achieve a consistent level of activity to drive performance improvements, our drilling operations Originally scheduled later this year due to the current natural gas price environment. To date, operational progress towards improvements Andorado's well performance is meeting or exceeding our early expectations. Activity in the Utica combo play It's just commencing, yet we are already witnessing the compounding effects of sharing technology across our multiple plays.

Speaker 3

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 Q3. Now for a little color on inflation and industry service cost. As we had anticipated in building this year's plan, the upward inflationary pressure that we witnessed last year appears to have plateaued, It 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.

Speaker 3

We would expect that any softening of service and tubular cost will be slow to manifest into lower well cost and cash operating cost 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 cost 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'll turn it back to Ezra.

Speaker 2

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 Q1 with their outstanding execution. 2nd, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a significant part of our first Quarter results.

Speaker 2

3rd, our Q1 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 4th, 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 Thanks for listening. We'll now go to Q and A.

Operator

Thank you. The question and answer session will be conducted electronically. Please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time Our first question is from the line of Paul Cheng with Scotiabank.

Operator

Paul, your line is now open.

Speaker 4

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.

Speaker 4

Just can you give us a little bit more detail in terms of The test size you are doing over there and whether you are increasing it, especially if you start to do more co development And how many different lending zones 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 investors have been asking why that go ahead with And I think last quarter in the conference call management has said, you're looking For the long term, so just curious that what may have triggered your maybe there's a slightly change in your view about the pace on that development. Thank you.

Speaker 3

Yes, Paul, this is Billy. Let me give you a little Some of the improvements we're seeing. Overall, we're 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.

Speaker 3

But I'd like to go ahead and turn it over now to Jeff and maybe talk a little bit about the new completion design and the results We're seeing and then some of the productivity improvements.

Speaker 5

Yes. Thanks, Billy. Paul, this is Jeff. Yes, 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 completions design.

Speaker 5

So As Billy stated today, we've tested around 39 wells in the Wolfcamp and we're 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'll also note that the uplift, we're 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've done is we've really expanded this program and we're planning on completing about 70 additional wells in the Wolfcamp this year.

Speaker 5

So that's going to be about a 2.5 times increase from last year and we definitely went ahead and taken this into account in 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 Testing 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.

Speaker 5

So we just want to be mindful about how quickly we're testing it and be strategic at the pace Sit down in our Eagle Ford asset and this is just an example of the technology transfer in the company of our multi basing operations. It's really helped us accelerate our learnings throughout the company. And then lastly, with the success that we've seen in the Delaware Basin, we're actively testing it in all of our emerging plays throughout the company and really look forward to evaluate

Speaker 3

And then Paul, the other part of your question was on Dorado and really what triggered the Change of pace that we're thinking about, we put together a plan originally just to remind everybody that really it was not a huge acceleration And activity planned for we're only adding 8 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 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 We'll be able to explore with Dorado activity, and we are exploring the option to delay some completions that were scheduled for later in the year, And we'll give more color on that as that unfolds.

Operator

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

Speaker 6

Yes. 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 guys certainly lean on the buyback as you described in March.

Speaker 6

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?

Speaker 2

Yes. Leo, this is Ezra Yacob. Good morning. I think you've summarized it pretty well. Our strategy hasn't really Changed.

Speaker 2

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 $2,800,000,000 That'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've paid 7 of the last 8 quarters. We've distributed a special dividend or opportunistic buybacks.

Speaker 2

And what we saw in the Q1 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 $300,000,000 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 It's 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.

Speaker 6

Okay. That's helpful. And I just wanted to see if there's any more of a robust update on the Utica. I Last time you guys kind of rolled that out, I think you had 4 wells on production with a fair bit of history. Just trying to get a sense, are there 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 that have been on

Speaker 1

Yes, Leo, this is Ken. We're making excellent progress on our Utica program this year. We currently have a drilling rig actively operating on our Northern area and we're progressing nicely on our gathering and infrastructure projects. The 4 wells that you talked about that we drilled and completed in 2022 really do continue to deliver our expected performance. We plan to drill and complete about 15 wells across both our North and Southern areas this year, and we'll have those production results more towards the end of the year.

Speaker 1

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.

Speaker 7

Yes, thanks. Good morning and congrats on the quarter. Ezra,

Speaker 3

maybe if

Speaker 7

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 movers, is there other things like intrinsic value assessments that kind of generated that process to really kick it off there?

Speaker 2

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've talked about in the past, it kind of begins with the macro, first of all, right, what's happening on both 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.

Speaker 2

There was a significant announcement there for Roughly 300,000,000 barrels of petroleum reserves that would be hitting the market on the supply side from across the globe. What we saw in the Q1 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 and a dislocation with the market, Really again associated in late March there with the banking crisis, we really didn't hesitate and were able to step into the market And due to that $300,000,000 share repurchase, and we think we've really created a significant amount of value there for the shareholders.

Speaker 7

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?

Speaker 8

Hey, Scott. Good morning. This is Lance. Thanks for the question. Yes, our realizations continue to be Excellent.

Speaker 8

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've taken out, you hear us talk a lot about control and having control all the way to water is exceptionally important. So I would just say, as you think about our position and then 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.

Speaker 9

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 sliding back down some. Is that impacted by where you'll develop and deploy the new completion design? Or is that a reflection of trying to be more selective with Where you co develop the Wolfcamp M?

Speaker 9

Just what kind of shift in mix?

Speaker 5

Yes, Scott, this is Jeff. Really what the our co development strategy, it's pretty straightforward. And what we're trying to do is, We're 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've really got to strategically dissect what our strategy is going to be But from what we're 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're achieving economics well over our premium hurdle rates And we have some of the tightest co development spacing out there in the basin.

Speaker 5

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

Speaker 9

Got it. And then just looking for some more color on the new completion design. You said it was initially developed and rolled down to Eagle Ford. Did it become the dominant design in the Eagle Ford? And will it become the dominant design in the Permian?

Speaker 9

And, yes, how quickly can it be rolled out to some of the new players?

Speaker 5

Yes, Scott. Great question. So yes, 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.

Speaker 5

It wasn't quite as extensive, but that really has to do with the difference in rock type and their geological properties between the two plays, but it did provide the application, proved really beneficial as far as helping lower well costs and reduce our 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. And then 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

Operator

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

Speaker 10

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 and Q2 projected to be heavier than expected, could you comment on the 1 to 2 drivers? And separately, if not part of the answer, Could you speak to cadence on non D and C investments throughout 2023?

Speaker 3

Yes, Derek, this is Billy Helms. So yes, the 2nd quarter CapEx has guided to be a little bit higher than the Q1, and it's mainly due to some Non Drilling and Completion Capital, the indirects or infrastructure and those kind of things that we put in our program It was originally scheduled to occur at the latter half of the first quarter. It turned out to be pushed into the second quarter. Thus, that's the reason the Q1 was under on CapEx and the Q2 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.

Speaker 3

And so we're still on target for that And the 48% in the back half, so that's kind of the way the program plays out.

Speaker 10

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

Speaker 1

Yes, 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've 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 Superzipper 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. Naturally showing up on our 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?

Speaker 10

Good morning. This is John Abbott on for Doug Leggett. Our first our questions are really on Dorado. We understand that you're 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 a greater economies upscale into play. When do you think you need to achieve that size and

Speaker 3

Yes, John, this is Billy Helms. So for Dorado, yes, we are Increasing activity there, mainly from the drilling side. Originally, 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 Being able to improve our drilling times, lower our well costs and just increase efficiencies overall.

Speaker 3

So we're very pleased with the progress we've made. And so I think that increased activity we're seeing on the drilling side is playing out what we're seeing on the drilling results and Given 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 Q2, but beyond that, we're 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 and plays and combine that activity with the activity we have in Toronto 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'll see how those present themselves. And then as far as activities for LNG demand, I guess the play the unique thing about this play, It doesn't take a lot of wells.

Speaker 3

The wells are very prolific. So we're 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 as just simply applying itself to the LNG market. It's got the opportunity, but looking at gas from other plays to the Gulf Coast as well through our marketing arrangements.

Speaker 10

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 production for that play or activity long term. I mean, how big does it kind of get to? How do you think about

Speaker 1

Yes, John, this is Ken. I think the real thing in Dorado is, is it doesn't take a lot of wells to generate significant volumes out of that place. 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're 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. Neil, please go ahead.

Speaker 10

Good morning. Thanks for the time. My first question just on the Powder River. I'm just wondering, I heard too much on that, right? I'm just wondering how do you still feel this competes versus your other premium plays?

Speaker 10

And I know at one time you suggested you had almost 1700 locations and I'm just wondering your thoughts around this.

Speaker 5

Yes, Neal, this is Jeff. No, we have outstanding There are some of the lowest finding costs that we're seeing there in the whole portfolio. So, yes, we still have between kind of our full South Powder River Basin and then moving up to our north, about 1600 net undrilled premium locations. So just looking at our program, everything's on pace this year. The wells are performing as we Q1, we've completed about 15 gross wells, which 2 thirds of those were Maori.

Speaker 5

And we're seeing a lot of benefits also by getting We're running a consistent 2 to 3 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 Maori 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. And then 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'll go ahead and let maybe Lance So say a couple of things on that.

Speaker 8

Yes. No, thanks, Jeff. Yes, 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 $135,000,000 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 plants are 1st class asset.

Speaker 8

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, And there's also other benefits that we see long term as well as we think about just lowering cash operating costs, gathering processing

Speaker 3

And

Speaker 11

so And the last thing

Operator

I just

Speaker 10

wanted to Will that plant help the dips there as well? I'm just wondering, would you mention that plant, would that boost the dips there a little bit as well?

Speaker 8

When we think about that, we think about actually the gathering, processing, transportation expense. So it's absolutely when we think about Loading it with our equity gas into that facility and having to control, we're 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 Southern Acres there more competitive.

Operator

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

Speaker 1

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

Speaker 5

No, I'd say it's attributed to our co development strategy. I mean, 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, Spacing has changed both in zone and from a vertical perspective. So our teams have methodically obviously tested this. They've taken into account the actual

Speaker 1

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?

Speaker 5

No, it's really, it's about maximizing the overall resource there as you said. So we do have the optimal amount of communication,

Operator

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

Speaker 12

Yes, good morning. I wanted to come back to the new completion design. You highlighted how you've 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?

Speaker 12

And was that part of your guidance? Did that include that or would that reflect an upside risk to your oil guide?

Speaker 3

Yes, Arun, this is Billy. So the uplift we're seeing, A 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 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've issued.

Speaker 3

And then as far as what we're doing there, we're finding that The target is critical. So the rock type is critical to why it works in some areas. And so we're Cautiously moving through our program to make sure we test as we go to understand which 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 field so we maximize As Jeff was saying, the economics are the play.

Speaker 12

Okay. And just my follow-up is any update On Beehive in Australia timing?

Speaker 3

Yes, Arun, on Beehive, we're 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're able to get that well drilled. And that's 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.

Speaker 13

Good morning, Andrew, Billy, Kennen 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've 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 2.50 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 keyed you guys to want to examine that?

Speaker 3

Yes, 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're talking near term, We understand the near term softness in the market, but longer term medium and longer term, we're still very bullish on the long term outlook for gas. So we do look at the different the flexibility we have in the program and we're evaluating options to be able To successfully push those back in the year and we're just going to continue to remain disciplined on our investment to make sure we're maximizing the Value to the company over the long term.

Speaker 13

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'd want to make. But Presumably, you've confirmed, I think you're talking about 16 targets of works.

Speaker 13

And can you give us a sense, does it 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?

Speaker 5

Yes, this is Jeff again. Yes, that is correct. It's not necessarily a one size fits all across. It really does have to do with the geology that we're applying it And when looking particularly there in the Permian, we primarily just applied it down in the deeper Wolfcamp targets. So, that would It would be just kind of the upper down through the middle in a co development standpoint.

Speaker 5

Now we are testing on those shallower targets, but there are quite a few different rock types. Right now, I 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're 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?

Speaker 6

Yes. Good morning, team.

Speaker 14

My question was on the natural gas liquids market where realizations obviously have been trending lower. Yes. I'm 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.

Speaker 8

Yes, Neal. Good morning. This is Lance. Yes. I think what you're continuing to see absolutely the export positions that are getting built out.

Speaker 8

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 on propane. So continuing to see healthy propane exports, we continue to see the build out that's a company with that. You're 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, it's going to float a little bit more with gas prices and that's kind of like what you're seeing today.

Speaker 14

Great. And then, just curious on your guys' perspective On the gas markets as well, you've talked a little bit about slowing down potentially in terms from a drilling perspective, but how do you see

Speaker 2

Yes, Neil. Good morning. 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.

Speaker 2

S, especially, Dorado being a big piece of it, has really captured Low cost to 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.

Speaker 2

S. Will be long term positioned to be really a global leader in the LNG market. Now gas is always because it is highly volatile when it comes to things like the short term pricing on weather. And it's one reason you've heard this morning From both myself, Ken and Billy, 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're not outrunning 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.

Speaker 2

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.

Speaker 11

Yes. Thanks. Good morning, guys. Just sticking with gas first. You have an unusually wide gap on your differentials Even after reporting the Q1 results, can you just talk about how you think that may shape over the course of the year?

Speaker 11

What you're looking forward to come in towards The high end versus the low end there. Thanks.

Speaker 8

Yes, Josh. Hey, good morning. 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've seen kind of our guidance for like the full year and we Expect a lot of that's going to be driven.

Speaker 8

Obviously, we have the diversification that we have with our California exposure. We have you can see on Our supplemental slide, Slide 8, 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're going to hold with existing guidance that we have.

Speaker 10

Got it.

Speaker 11

And then just as far as the shareholder return profile, I know You've been thinking about it from a percentage of free cash flow, but how would you think about it from managing a cash balance standpoint? You've Over $5,000,000,000 now for the past few quarters, including paying down the debt maturity in the Q1. Is $5,000,000,000 $6,000,000,000 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 to or free cash flow to shareholders if you really want to.

Speaker 11

Thanks.

Speaker 2

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, that it's a minimum. In fact, last year, we returned excess of the 60% free cash to our shareholders. And we started with that 60% because we feel confident on that, especially when we roll in kind of an almost A peer leading regular dividend that we'd be able to compete and deliver that through the cycles.

Speaker 2

So when we think about a Specific target for cash on hand, I want to 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 run about $2,000,000,000 kind of depending on 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 due an acquisition in one of our emerging plays there in the Utica, where we actually purchased approximately 130,000 Mineral rights.

Speaker 2

And then lastly, of course, just the stock repurchase, which we exercised here in the Q1. We've 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've got the strength of the balance sheet, which includes cash on hand. That's really what we're going for. And so I think that provides another compelling reason to carry potentially a higher cash balance than the company's historically done.

Operator

Thank you. That concludes our Q and A session for today. I'll now turn the call back over to Mr. Jacob for any closing or additional remarks.

Speaker 2

I just want to thank everyone for participating in the call this morning. And I especially want to thank our employees for the outstanding results They delivered in this Q1. Thank you.

Operator

That concludes the EOG Resources Q1 2023 earnings results conference call. Thank you all for your participation. You may now disconnect your

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EOG Resources Q1 2023
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