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EOG Resources (EOG 2.87%)
Q1 2023 Earnings Call
May 05, 2023, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


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'd like to turn the call over to chief financial officer of EOG Resources, Mr. Tim Driggers.

Please go ahead, sir.

Tim Driggers -- Chief Financial Officer

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.

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Here's Ezra.

Ezra Yacob -- President

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 net backs.

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. 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 progressed 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 start-up 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 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 million 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. But first, here's Tim to review our financial position.

Tim Driggers -- Chief Financial Officer

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 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're 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 cents per share, the same as last quarter and a 10% increase from the prior-year level. The $3.30 annual rate is a $1.9 billion annual commitment.

On March 30, we also paid the $1 per share special dividend declared in February. EOG also repurchased $310 million of stock in the first quarter at an average price of $105 per share. For several days during the last two weeks of March, market volatility created a significant dislocation between the price of our stock and the value of the business. We were able to utilize our strong balance sheet to repurchase shares at highly accretive prices.

We will continue to monitor the price and value of our stock, and you should expect us to step into the market again when there are significant dislocations. We're 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 buybacks, 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 -- Chief Operating Officer

Thanks, Tim. EOGs 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 maintain 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 place 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 we're 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 estimated ultimate recovery compared to the similar wells and targets using our previous completion design. With these encouraging results, we are -- 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 super-zipper technique. These efforts, combined with the opportunity to co-develop multiple targets in this stack pay resource by using our existing service footprint and 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 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 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 play's 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. 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 toward 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 began 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 costs 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'll turn it back to Ezra.

Ezra Yacob -- President

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'll now go to Q&A.

Questions & Answers:


Operator

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

Paul Cheng -- Scotiabank -- Analyst

Thank you. Good morning, everyone. Two questions, please. I think the first one is probably for Billy.

You talk about the Permian, the good well productivity. 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 landing zone 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 investors have been asking why go ahead with the expansion in the rentals. And I think last quarter in the conference call, management has said you're looking for the long term, so just curious what may have trigger your -- maybe that's a slightly change in your view about the pace on that development. Thank you.

Billy Helms -- Chief Operating Officer

Yeah, Paul, this is Billy. Let me give you a little -- highlights maybe of the Permian program and what we're seeing there, and then I'll probably ask Jeff to give some more detailed color, so help explain 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 planned all of our top 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 and maybe talk a little bit about the new completion design, the results that we're seeing, and then some of the productivity improvements.

Jeff Leitzell -- Executive Vice President, Exploration and Production

Yeah. Thanks, Billy. Paul, this is Jeff. Yeah, we're extremely happy with our productivity out of the Delaware.

And just to give you a little color, one of the big things that's really improving that is our new completions design or, I should say, kind of our improved completion design. So, as Billy stated, to date, you know, 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. So, that's going to be about a 2.5 times increase from last year. And we've definitely went ahead and taken this into account in both our drilling plans and guidance for 2023. So -- so, looking forward with this design, we've had a lot of success in our deeper formations.

Our team really plans to continue to kind of test in some of the shallower formations to evaluate its benefits. One thing that we have observed with this design is that there's varying performance uplift depending on the rock type and the depth of the target. And the design does come with a little bit of a cost increase, so we just want to be mindful about how quickly we're testing it and be strategic at the pace that we're going ahead and putting these in the ground. Also, I'd like to point out that, you know, 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 learning throughout the company. And then, lastly, with the success that we've seen in the Delaware Basin, you know, we're actively testing it in all of our emerging plays throughout the company and really look forward to evaluating those results throughout the year.

Billy Helms -- Chief Operating Officer

And then, Paul, the other part of your question was on Dorado and -- and really what triggered the change of pace that we're thinking about. You know, we -- we put together a plan originally just to remind everybody that really it was not a huge acceleration in activity plan for we're 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 in our program, and what that's a benefit of having a multi-basin portfolio is we can move activity around based on market conditions or other factors as they present themselves.

Naturally, with gas prices remaining weak and -- and moving into the year, it's only natural to think about options that we might 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 -- we'll give more color on that as that unfolds.

Operator

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

Leo Mariani -- ROTH Capital Partners -- Analyst

Hi. I 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. I just wanted to kind of confirm, you know, your thinking around this.

I mean it -- it still sounds like the buyback is going to be reserved only for kind of very opportunistic situations where there is this dislocation. And, you know, generally speaking, it's probably more reasonable to expect, you know, the special going forward where the -- the buyback kind of maybe every once in a while, is that kind of how to think about it?

Ezra Yacob -- President

Yes, Leo, this is -- this is Ezra Yacob. Good morning. I think that -- I think you've summarized it pretty well. You know, 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. That's approximately a 50% of our -- you know, what would be our fiscal year free cash flow at the assumed $80 oil price there. And just to recall, you know, the cash return priority is, 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 seven of the last eight quarters we've distributed a special dividend, or opportunistic buybacks. And, you know, 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. You know, our primary value proposition, of course, is investing in high-return projects, adding lower-cost reserves to our company's profile, which, you know, 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 -- ROTH Capital Partners -- Analyst

OK, 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 are there more wells producing at this point in time in the Utica.

And just any thoughts around, you know, some of the long-term performance of those prior wells that have been on, you know, I guess, for over a year at this point?

Ken Boedeker -- Executive Vice President, Exploration and Production

Yeah, 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 four wells that you talked about that we drilled and completed in 2022 really do continue to deliver our -- our expected performance.

And 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 toward the end of the year. Another thing to note is -- 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 -- RBC Capital Markets -- Analyst

Yeah, thanks. Good morning and congrats on the quarter. You know, Ezra, maybe if I could pivot back on -- 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 -- the, you know, aggregate move? Or is there other things like intrinsic value assessments that -- that kind of generated that process to really kick it off there?

Ezra Yacob -- President

Good morning, Scott. Yes, this is Ezra. Those are all accurate to the tune of how we kind of look at these opportunities. You know, as we've 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, you know, that could be made is, you know, the dramatic sell-off that 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 -- was not really supported by a big change in the forecast on -- 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 into 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 we're able to step into the market and do that $300 million share repurchase. And we think we've really created a significant amount of value there for the shareholders.

Scott Hanold -- RBC Capital Markets -- Analyst

That's great. Thanks for that. 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 -- Senior Vice President, Marketing

Hey, Scott. Good morning. This is Lance. Thanks for the question.

Yeah, our realizations continue to be, you know, 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've taken out. You hear us talk a lot about control, and having control all the way to the water is -- is exceptionally important. So, I would just say, as you think about our position and the price realizations too and then extract in 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 -- Citi -- Analyst

Yeah, 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? And just kind of what's the shift mix?

Jeff Leitzell -- Executive Vice President, Exploration and Production

Yes, Scott, this is Jeff. Really what the -- you know, our co-development strategy, you know, 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, you know, our acreage, it changes, you know, very quickly.

So, kind of from development unit to development unit, you know, we've really got to strategically dissect what our, you know, strategy is going to be there. But from what we're seeing right now and you can see that on Slide 10 and 11 in, our deck, you know, by adding in some of those deeper targets in the lower Wolfcamp -- or I should say the lower upper Wolfcamp and then the middle, you know, we're achieving economics well over our premium hurdle rates. And, you know, we have some of the tightest co-development spaces out there in the basin. So, ultimately, just this approach, I mean it's improving our total recovery per acre.

It's helping optimize that NPV of the resource, and it's just adding those barrels, finding costs below our current Delaware Basin levels.

Scott Gruber -- Citi -- Analyst

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

Jeff Leitzell -- Executive Vice President, Exploration and Production

Yes, Scott, great question. So, yeah, the design, as I talked about, it was first utilized in Eagle Ford, it was back in right around 2016. And we -- we didn't see the same uplift that we see in the Permian. It wasn't quite as extensive, but that really has to do with the difference in rock type and the geological properties between the two plays.

But it did provide a -- you know, the application proof, really beneficial as far as helping lower our well cost 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. And then, as far as in the Delaware and our rollout, you know, 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, you know, we just don't want to outrun our learnings and we want to make sure that, you know, 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 -- Stifel Financial Corp. -- Analyst

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 -- Chief Operating Officer

Yeah, Derrick, this is Billy Helms. So, yeah, the second-quarter capex has got to be a little bit higher than the first quarter, and that's mainly due to some nondrilling and completion capital, the indirect or infrastructure and those kind of things that we put in our program that 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 first quarter was under on capex and the second quarter is a little bit higher. You know, 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're still on target for that and the 48% in the back half. So, that's kind of the way the program plays out.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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 perceive utilizing this approach?

Ken Boedeker -- Executive Vice President, Exploration and Production

Yeah, Derrick, this is Ken. I'd like to start off by really crediting our team there in San Antonio for -- for driving down that finding costs 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 links 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, you know, really drill and complete more lateral footage in a day compared to a few years ago.

And that's really showing up in 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?

John Abbott -- Bank of America Merrill Lynch -- Analyst

Good morning. This is John Abbott on for Doug Leggate. Our first -- our questions are really on Dorado. You know, 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, again, 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 -- Chief Operating Officer

Yeah, John, this is Billy Helms. So, for Dorado, you know, 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 -- in the efficiency gains there.

The team there has done just an excellent job being able to improve our drilling times, lower our well cost, and just increase efficiencies overall. So, we're very pleased with the progress we've made. And so, I think that 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 second quarter, but beyond that, we're looking at ways we can with the flexibility we have in our program to -- to delay the completion of any wells that would be beyond in the second half.

And really just thinking about how we can leverage some of the learnings from our other programs in place and combine that activity -- with the activity we have in Dorado by sharing equipment, people, and those learnings across our portfolio. So, you know, we don't really feel the need to jump in and complete those wells, but we -- we are evaluating options as they roll out and we'll -- we'll see how those present themselves. And then, as far as the activities for, I guess, the LNG demand, I guess, you know, the play -- you know, the unique thing about this play, it doesn't take a lot of wells. 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 Dorado as just simply applying itself to the LNG market. It's got the opportunity, but we can get gas from other places to the Gulf Coast as well through our marketing arrangements.

John Abbott -- Bank of America Merrill Lynch -- Analyst

That's extremely helpful, which leads to the next question. You know, 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 that from an efficiency program longer term? [Inaudible]

Ken Boedeker -- Executive Vice President, Exploration and Production

Yeah, John, this is Ken. I think the -- yeah, 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 play. So, I don't know the exact right pace, but what we want to do is we want to develop this at the -- 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. Neal, please go ahead.

Neal Dingmann -- Truist Securities -- Analyst

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

Jeff Leitzell -- Executive Vice President, Exploration and Production

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're seeing there in -- 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's on pace this year. The wells are performing as we expected. Q1, we've completed about 15 gross wells which two-thirds of those were Bowery. And, you know, we're seeing a lot of benefits also by getting some consistent activity up there in the Powder.

We're running a consistent 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, you know, a lot of confidence in the play, you know, just with just -- just with the overall performance and stuff as with the Bowery. And then, from there, as we talked about, we want to go ahead and gather the data you know, in the upper overlying formations like the Niobrara, so we can develop that later in the future. And then, also, you know, 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 say a couple of things on that.

Lance Terveen -- Senior Vice President, Marketing

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 it's really a midstream footprint. There's a plant and gathering system that just overlays our southern acreage.

The plants are 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 and 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'll have control in redundancy, but then also to the confidence we can expand that very quickly. So, well, the last thing I just [Inaudible].

Neal Dingmann -- Truist Securities -- Analyst

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

Lance Terveen -- Senior Vice President, Marketing

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 net backs. But it's more of 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 acreage there more competitive.

Operator

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

Bob Brackett -- AllianceBernstein -- Analyst

Good morning. Back to the Wolfcamp co-development. If you're hitting two-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?

Jeff Leitzell -- Executive Vice President, Exploration and Production

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, you know, we're up to 18 unique targets. And obviously, with that, the spacing has changed both in zone and from a vertical perspective.

So, our teams have methodically obviously tested this, you know. They've taken into account, you know, the actual spacing, how they interact the depletion to it. And we've 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 -- AllianceBernstein -- Analyst

Great. 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?

Jeff Leitzell -- Executive Vice President, Exploration and Production

No, it's really -- it's about maximizing, you know, the overall resource there, as you said, you know, so we do have the optimal amount of communication that we're actually able to, you know, 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 J.P. Morgan. Arun, please go ahead.

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

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

Billy Helms -- Chief Operating Officer

Yeah, hi. Arun, this is Billy. So, the -- 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 -- I would say that's already factored into our guidance that we've issued. And then, as far as the -- you know, what we're doing there, you know, we're finding that 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 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 that we maximize, as just as Jeff was saying, the economics of the play.

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

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

Billy Helms -- Chief Operating Officer

Yeah, Arun, on Beehive, we're still excited to be able to drill that well, but it's -- 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.

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've already spoken on for a while. The Dorado, the -- evaluating the slowdown, can you give some insight in your thinking? Is this -- is this about the -- the natural gas price falling below your 250 double premium? Or is this -- 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?

Billy Helms -- Chief Operating Officer

Yeah, Charles, this is Billy. Certainly, you know, 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, you know, to simply bring more gas on in this current condition. You know, as -- as we talk near term, we understand the near-term softness in the market. But longer term -- or medium and longer term, we're still very bullish on the long-term outlook for -- for gas.

So, you know, we do look at the different -- the flexibility we have in the program, and we're evaluating options to be able to -- 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.

Charles Meade

OK, that's helpful. And then, just one -- one more quick one on this -- on this Wolfcamp completion design. So, I -- I got the message. I think in your last -- in your response to the last question that this is not this -- 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 in the works. Can you give us a sense as does it work in a quarter of the targets and maybe upside to -- to half or three quarters? Or what's it -- what's it look like to you guys right now?

Jeff Leitzell -- Executive Vice President, Exploration and Production

Yeah, this is Jeff again. Yeah, that is correct. You know, it's not necessarily a one-size-fits-all across. It really does have to do with the geology that we're, you know, 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, you know, right now, I say it's area by area.

And, you know, from a percentage basis you kind of hate to, you know, put an actual percentage on it, but, you know, 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?

Neil Mehta -- Goldman Sachs -- Analyst

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

Lance Terveen -- Senior Vice President, Marketing

Yeah, Neil, Good morning. It's Lance. Yeah, I think what you're -- you're continuing to see absolutely the -- the export, you know, positions that are getting built out. I think as you -- you kind of have to think of those kind of as we think about them as kind of more on ethane and more on propane, so continuing to see healthy propane exports.

We continue to see the buildout that's accompanied 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, continuing to see that there could be some firming up there kind of maybe more longer term. Ethane, obviously, is going to float a little bit more with gas prices.

And that's kind of like what you're seeing today.

Neil Mehta -- Goldman Sachs -- Analyst

Great. And then, just curious on your guys perspective on -- 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 the balances moving from here in a weather-normal way over the course of the year?

Ezra Yacob -- President

Yes, Neil, good morning. This is Ezra. As I stated in the opening remarks, you know, we still remain constructive on -- 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 a 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 -- which is at record levels right now for the -- 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 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've 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'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. We want to put in the correct infrastructure to keep our -- 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 -- UBS -- Analyst

Yeah, thanks. Good morning, guys. Just sticking with gas first. You have an unusually wide gap on your differentials 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're looking for to come in toward the -- the high end versus the low end there? Thanks.

Lance Terveen -- Senior Vice President, Marketing

Yeah, 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 -- our guidance for, like, the full year, and we expect a lot of that's going to be driven, obviously, we have the diversification, you know, that we have with our California exposure. We have, you know, 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 the existing guidance that we have.

Josh Silverstein -- UBS -- Analyst

Got it. 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 been over $5 billion now for the past few quarters, including paying down the debt maturity in the first quarter. You know, is -- 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 to -- or free cash flow to shareholders if you really wanted to. Thanks.

Ezra Yacob -- President

Yes, Josh, this is Ezra. You know, 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 flow to our shareholders. And we started with that 60% because we feel confident on that, especially when we roll in, you know, kind of almost a peer-leading regular dividend that we'd be able to -- to compete and deliver that through the cycles.

So, when we think about a specific target for -- for cash on hand, I want to say that we have real target. You know, 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 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 countercyclically invest in opportunities as they arise, whether that's, you know, at times investing in casing or line pipe or, last year, you know, we were able to step in and do an acquisition in one of our emerging plays there in the Utica where we actually purchased approximately 130,000 mineral rights. And then, lastly, of course, just the -- the stock repurchase which we exercised here in the first quarter. You know, we've talked about being able to utilize that opportunistically. And really part of our strategy, the reason that that you can -- 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 -- that's really what we're going for. And so, I think that provides another compelling reason to carry a potentially a higher cash balance than -- than the company's historically done.

Operator

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

Ezra Yacob -- President

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 first quarter. Thank you.

Operator

[Operator signoff]

Duration: 0 minutes

Call participants:

Tim Driggers -- Chief Financial Officer

Ezra Yacob -- President

Billy Helms -- Chief Operating Officer

Paul Cheng -- Scotiabank -- Analyst

Jeff Leitzell -- Executive Vice President, Exploration and Production

Leo Mariani -- ROTH Capital Partners -- Analyst

Ken Boedeker -- Executive Vice President, Exploration and Production

Scott Hanold -- RBC Capital Markets -- Analyst

Lance Terveen -- Senior Vice President, Marketing

Scott Gruber -- Citi -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

John Abbott -- Bank of America Merrill Lynch -- Analyst

Neal Dingmann -- Truist Securities -- Analyst

Bob Brackett -- AllianceBernstein -- Analyst

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

Charles Meade

Neil Mehta -- Goldman Sachs -- Analyst

Josh Silverstein -- UBS -- Analyst

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