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F500-2021-185-EOG Resources

Founded in 1999 after a split from Enron Oil &amp; Gas, the Houston company specializes in procuring, producing, and marketing petroleum and other natural gases.

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The oil and natural gas company has operations in the U.S, Trinidad &amp; Tobago, and China.

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EOG Resources is an independent oil and gas company that explores for, develops, produces, and markets crude oil, natural gas liquids, and natural gas, with operations primarily in the U.S. and in Trinidad and Tobago. EOG is known as an industry trendsetter in the onshore U.S. shale industry, specifically in the Permian Basin, South Texas’s Eagle Ford Shale, and, most recently, Ohio’s Utica Shale. Formerly known as Enron Oil &amp; Gas, the company was spun off in 1999, prior to its parent Enron’s downfall.

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Q3 2024

EOG Resources (EOG): Company Profile, Stock Price, News, Rankings

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EOG Resources

eog resources

Good day, everyone, and welcome to EOG Resources Third Quarter 2024 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 Investor Relations Vice President of EOG Resources, Mr. Pierce Hammond. Please go ahead, sir.

Good morning, and thank you for joining us for the EOG Resources Third Quarter 20 24 earnings conference call. An updated investor presentation has been posted to the Investor Relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, 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 may also contain certain historical and forward looking non GAAP financial measures. Definitions and reconciliation schedules for these non GAAP measures and related discussion can be found on the Investor Relations section of EOG's website. In addition, some of the reserve estimates on this conference call may include estimated potential reserves as well as estimated resource potential, not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Esri Yacob, Chairman and CEO Jeff Leitzel, Chief Operating Officer Ann Janssen, Chief Financial Officer Keith Trasko, Senior Vice President, Exploration and Production and Lance Treveen, Senior Vice President, Marketing and Midstream. Here's Ezra.

Thanks, Piers. Good morning, everyone, and thank you for joining us. Since the end of 2020, EOG has generated more than $22,000,000,000 of free cash flow and more than $25,000,000,000 in adjusted net income. We've increased our regular dividend rate 160% and including both regular and special dividends paid or committed to pay more than $13,000,000,000 directly to shareholders and $3,200,000,000 indirectly through share repurchases all while reducing debt 35%. EOG has a history of delivering consistently strong financial and operational results and the Q3 is simply more of the same.

Led by our employees' commitment to operational excellence and capital discipline, we outperformed on oil, natural gas and NGL volumes for the quarter as well as beating expectations on per unit cash operating costs. We generated $1,600,000,000 of adjusted net income and $1,500,000,000 of free cash flow and returned $1,300,000,000 of that free cash flow back to our shareholders through a mix of our regular dividend and opportunistic share repurchases. In addition to announcing Q3 results, yesterday, we demonstrated confidence in our ability to generate strong free cash flow in the future as well as our continued commitment to return a significant portion of cash to our shareholders by increasing the regular dividend 7% and boosting our share repurchase authorization by $5,000,000,000 Cash return to shareholders begins with our focus on the regular dividend, which has never been reduced or suspended in the 27 years since we've been paying 1, and it reflects our confidence in the increasing capital efficiency of our business going forward. And we continue to improve our capital efficiency by leveraging technology and innovation across both our foundational and emerging assets. That is one of the key advantages of operating in multiple basins.

We are able to drive improvements to operational performance through technology transfer between those basins. We are drilling further and faster than at any time in our history, completing wells with fewer people and less equipment due to efficient operations. And we continue to capture additional value through our marketing strategy. EOG's performance is sustainable because it's driven by our culture, empowering each employee to be a business person first, focusing on returns and seeking ways to improve the business every day. Our culture is our competitive advantage and combined with our focus on sustainable value creation through the cycles gives us confidence in our ongoing performance as we finish 2024 and position ourselves for 2025.

In a moment, Jeff will provide some early commentary on our 2025 capital program, but our investment strategy always begins with capital discipline, balancing short and long term free cash flow generation, return on capital employed and return of capital to shareholders. We also consider the macro environment in which we are operating and currently the overall macro environment remains dynamic. Oil inventory levels are below the 5 year average with both supply and demand showing moderate growth year over year. We expect to finish 2024 with strong demand slowing into a seasonally lower Q1 and then increasing throughout the rest of 2025. Domestically, while efficiency gains continue across the industry, we anticipate another year of slower U.

S. Liquids growth grounded in the lower number of active drilling rigs and drilled but uncompleted wells. Regarding North American natural gas, inventory levels have moved closer to the 5 year average throughout the year due to a combination of producer discipline and increased demand driven primarily by power generation. We remain optimistic on the long term outlook for gas demand beginning in and increasing throughout 2025 from additional LNG projects coming online and ongoing increases in power generation. Finally, last month, we released our annual sustainability report for 2023, highlighting our leading environmental performance and commitment to safe operations.

We achieved a GHG intensity rate below our 2025 target for the 2nd year in a row and achieved a methane emissions percentage at or below our 2025 target for the 3rd consecutive year. Our in house methane monitoring solution has progressed beyond the pilot phase and is integrated into our standard operating procedures. And our carbon capture and storage pilot project is operational and we stand ready to deploy our learnings to future operations. Our consistent sustainability performance is a result of our empowered and collaborative workforce and our continued investment in innovation and technology to achieve not only leading environmental performance, but also strong and consistent safety performance throughout our operations. This year's report highlights our innovative culture that drives EOG's mission to be among the highest return, lowest cost and lowest emissions producers playing a significant role in the long term future of energy.

Now here's Anne with details on our financial performance.

Thanks, Ezra. EOG continues to create long term shareholder value. During the Q3, we earned $1,600,000,000 of adjusted net income and generated $1,500,000,000 of free cash flow on $1,500,000,000 of capital expenditures. 3rd quarter capital expenditures were in line with forecast and we still expect our full year capital expenditures to be about $6,200,000,000 Cash on the balance sheet at quarter end is temporarily higher due to the postponement of certain tax payments until the Q1 of next year from disaster relief granted for severe weather events in Texas, including Hurricane Beryl. Our ongoing marketing strategy to diversify and expand our access to premium markets also delivered exceptional results during the Q3 with peer leading U.

S. Price realizations of $76.95 per barrel of oil and $1.84 per Mcf for natural gas. Finally, we paid a $0.91 per share dividend and repurchased $758,000,000 of shares during the quarter. Year to date, we have generated $4,100,000,000 of free cash flow, which helped fund $3,800,000,000 of cash returned to shareholders. Of that $3,800,000,000 dollars 1 $600,000,000 was paid in regular dividends and was complemented by $2,200,000,000 in share repurchases through the Q3.

Taking into account our full year regular dividend, we have committed to return $4,300,000,000 to shareholders in 2024 and we are on track to exceed not only our minimum cash return commitment of 70% of annual free cash flow, but also last year's cash return of 85%. EOG's commitment to high return investments is delivering high returns to our shareholders. Yesterday, we were pleased to announce a 7% increase to what is already a top tier regular dividend, not only for our industry, but the broader market. This increase reflects our confidence in the fundamental strength of our business, which continues to get better through consistent execution of EOG's value proposition. Efficiencies and technology applied throughout our multi basin portfolio continue to sustainably improve EOG's capital efficiency.

A growing sustainable regular dividend remains the foundation of our cash return commitment we believe is the best indicator of the company's confidence in its future performance. In addition to the dividend increase, the Board approved a $5,000,000,000 increase in our share repurchase authorization to supplement the $1,800,000,000 remaining on the authorization as of quarter end. The total $6,800,000,000 buyback capacity retains our flexibility to deliver on our cash return commitment to shareholders. Over the last several quarters, we have favored buybacks to complement our regular dividend and we will continue to monitor the market for opportunities to step in and repurchase shares for the remainder of the year. EOG's balance sheet underpins the financial strength of the company and remains a strategic priority.

To optimize EOG's capital structure going forward, we intend to position our balance sheet such that our total debt to EBITDA ratio equals less than 1x at $45 WTI. We believe this is an efficient and prudent long term capital structure for a cyclical industry that will support our commitment to deliver shareholder value. As a result, we anticipate refinancing upcoming debt maturities, increasing our debt balance to $5,000,000,000 to $6,000,000,000 range in the next 12 to 18 months and maintaining our cash balance at levels similar to what we have carried for the last 2 years. By managing our debt levels toward this more efficient capital structure, we are increasing our capacity to return cash to shareholders. Now here's Jeff to review operating results.

Thanks, Anne. We delivered another outstanding quarter thanks to our employees and their consistent execution across our multi basin portfolio. Their focus on continued improvement through innovation, technology advancements and operational control is why our 3rd quarter volumes and per unit cash operating costs beat expectations. Oil volumes beat our forecast primarily due to better than expected productivity from new wells, driven by continuous improvement to our completion designs. Year over year, we have increased our maximum pumping rate capacity by approximately 15% per frac fleet on average.

The benefit is twofold, faster pump times and better well performance. Higher pumping rates provides our team with the flexibility to tailor each high intensity completion design around the unique geological characteristics of every target. This in turn has helped to maximize the stimulated rock volume in the reservoir resulting in improved well performance. Efficiency improvements due to faster pump times combined with stronger well performance have more than offset the additional costs for these increased pumping rates. As a result of 3rd quarter volume performance beats, we are once again raising full year guidance.

Our oil production midpoint has increased by 800 barrels per day, natural gas liquids by 2,800 barrels per day and natural gas by 24,000,000 standard cubic feet per day. We also beat per unit cash operating cost targets during the Q3. The primary drivers were lower lease operating expense due to less workover expense and fuel savings. We now expect our full year per unit cash operating cost to be lower than forecasted and have reduced guidance accordingly. Our capital expenditures in the Q3 were in line with our forecast with only minor differences primarily due to timing of operations.

In addition, well cost deflation driven primarily by efficiencies is playing out as we had forecasted at the start of the year, resulting in a 3% to 5% year over year decrease in well costs. As a result, our expectations for full year CapEx remained unchanged at $6,200,000,000 at the midpoint. The efficiency gains we continue to realize this year demonstrate the value of our multi basin portfolio in decentralized structure. Ideas born in one operating area are replicated across multiple basins through technology transfer. Two examples of innovation expanding through our portfolio and driving efficiencies this year are extended laterals and our in house motor program.

Average lateral lengths for our domestic drilling program continue to increase. In the Delaware Basin, we now expect to drill more than 73 mile laterals this year compared to our original forecast of 50. We've also set a new lateral length record in the Eagle Ford, not only for EOG, but for all of Texas. Our Aspen A-1H well was drilled in our western acreage and has a lateral length of over 22,000 feet. As we highlighted last quarter, longer laterals allow for more time focused on drilling down hole and less time moving equipment on surface, decreasing overall downtime in days to drill.

In addition, longer laterals help unlock new potential from acreage that might not otherwise meet our economic thresholds. EOG's in house motor program also continues to pay dividends. In the Delaware Basin, we are testing the limits of our drilling motors in the shallower Leonard Shale and Bone Spring formations. While drilling the production hole section, we attempt to drill as much of the vertical curve and lateral portions of the wellbore with 1 motor run. Historically, this operation requires a minimum of 3 motor runs and 2 trips, which is a pause in drilling to pull a motor out of the wellbore and replace it with a new one.

As a result, we have eliminated over one full trip per well in the shallower Delaware Basin targets. Given that each trip can cost $150,000 or more, the cost savings and efficiency gains from using better designed higher quality motors continues to add significant value to our drilling program. This is just one of several examples of the value the EOG motor program has created. Looking company wide, since the start of 2023, we have increased our drilled footage per motor run by over 20% versus 3rd party rental options. As we continue to test, learn and redesign our drilling motors, we see substantial upside to our future drilling performance as we expand motor innovation throughout our multi basin portfolio.

In Ohio, we've made significant progress this year transitioning the 225,000 net acres of the volatile oil window in the Utica play from delineation into development. We now have 5 packages online and producing for more than 100 days, 3 of which have been producing well over 180 days. Both oil and liquids performance continues to meet or exceed expectations, demonstrating the premium quality of this play. We are also capturing sustainable operational efficiencies through multi well pad development and continuous operations. On the drilling side, the Utica provides an ideal operational environment to make significant gains quickly.

We have decreased drilling days to drill 3 mile laterals 29% year over year and have already achieved a record of drilling more than 2 miles in a single day. We also have made significant gains on the completion side, achieving a nearly 13% increase in completed lateral feet per day compared to last year. Over the next few years, activity in the Utica will continue to be primarily focused in the volatile oil window where we anticipate our well costs will average less than $6.50 per effective treated lateral foot with finding cost and development cost in the range of $6 to $8 per barrel of oil equivalent. For 2025, we anticipate a 50% increase in Utica activity as we continue to leverage consistent operations to achieve additional economies of scale. Our large contiguous acreage position lends itself to developing a long life repeatable low cost play competitive with the premier unconventional plays across North America.

Previewing 2025 company wide, with the outstanding performance we have delivered this year, we do not see a need to significantly adjust activity next year. We do, however, expect very minor shifts in activity between basins with a continued increase in activity in the Utica and another year of actively managing our Dorado investment with a 1 rig program. This will allow us to continue to capture some economies of scale across our emerging assets and advance our technological understanding of these plays, while delivering the operational and financial performance that our shareholders appreciate. Now here's Ezra to wrap up.

Thanks, Jeff. EOG recently celebrated our 25th anniversary as an independently traded public company. And while many things have changed across our industry, EOG's fundamental strategy and commitment to creating share value for our shareholders has remained consistent. 1st, our commitment to capital discipline begins with reinvestment at a pace to support continuous improvement across our assets, delivering returns through the cycle, generating free cash flow and maintaining a pristine balance sheet to support a sustainable growing regular dividend. 2nd, our strong operational execution begins with being a first mover in exploration to maintain a low cost, high quality multi basin inventory.

We leverage in house technical expertise, proprietary information technology and self sourced materials to help drive well performance and cost control and we focus on a balanced approach to product, geographic and pricing diversification to drive margin expansion. 3rd, we are committed to safe operations, leading environmental performance and stakeholder engagement. Our sustainability report highlights progress on our emissions reduction pathway as well as overall environmental stewardship. And finally, our culture is our competitive advantage. A decentralized non bureaucratic organization places value creation in the field at the asset level and in the hands of each of our employees.

We take pride in our collaborative multidisciplinary teams that drive innovation, utilizing our technology and real time data collection to drive decision making. Thanks for listening. Now we will go to Q and A.

Thank you. The question and answer session will be conducted electronically. And our first question today will come from Steve Richardson with Evercore ISI. Please go ahead.

Hi, good morning. I was wondering if you could start, Ezra, with the optimization of the balance sheet. This is a new wrinkle from the company. And I wonder if you could just talk about this incremental gross debt that you're looking at adding. The timeframe, should we think about that $2,000,000,000 coming concurrent when you would look to refi the existing maturities?

And then also the knock on of that is, how do you look at redeploying that cash, assuming into the buyback? And does this mean that you'll be taking shareholder returns above kind of sustainably above that minimum commitment for the next couple of quarters? Maybe just talk about the timeframe around that, please?

Yes, Steve. Good morning. Thanks for the question. The decision is aimed at really just making our capital structure more efficient. We're moving to a level of debt that's more appropriate for a company of our size and strength, still being respectful that we're in a cyclical industry.

Ultimately, the move is designed to allow us to move more equity into the debt side. We've always talked about we've been pretty consistent that the goal of our company has never been to get to a 0 absolute debt. And so really, the timing right now looks pretty good as we have a couple of bonds coming into maturity in the next 12 to 18 months. The market is looking a little more favorable than it has in the last few quarters. And so as we step into this, as we talked about, as Anne mentioned, our debt target will be to keep our total debt to EBITDA at less than 1 times leverage ratio at a $45 WTI, which if you calculate that out, is approximately a $5,000,000,000 to $6,000,000,000 range.

And so you're right, that will free up some additional cash. And really what I would look for is, yes, in the near term that does imply that we'll definitely be in a position to exceed the 70% commitment and quite frankly be closer to 100% and at times more than 100% of return of free cash flow to the shareholders. But I want to put a more specific time target on it other than kind of the next 12 month timeframe, the next 12 to 18 months is we look to be opportunistic in the market, not only with share repurchases, but also the timing of reaching out on these bonds.

That's great. Really strong choice capital allocation. Thanks. If I could maybe just follow-up on natural gas. You have arguably the lowest cost dry gas asset in the market and with the Verde pipeline finishing, you've got some real opportunities here.

Appreciate the comments on a 1 rig program for 2025. But you mentioned off the top, Ezra, how optimistic the natural gas demand outlook looks. So how should we think about the contango of the gas curve and what signal you're looking for to apply more capital there arguably that you are at the low end of the cost curve in North America?

Yes, Steve, that's another great question on Dorado. We've highlighted last quarter that cash operating costs are right around that dollar already for the asset. And so we do consider it to be one of the lowest cost natural gas projects in all of the U. S. And very well positioned.

Verde is online, which we're very excited about. But the North American gas inventory, as you said, is it's currently about 5% above the 5 year average still. And we'll see what happens with winter, but either way, whether it's warm or cold, industry does appear to have not only some curtailed volumes, but there is also some gas ducts that will likely come online pretty quickly. And so what we see and this is somewhat in line with where we've been for the last 2 years is that 2025 is really going to be an inflection point for North American gas demand with LNG beginning to come online and then coming online really 2025, 2026, 2027. And when we think about that, it's as we calculated about 10 to 12 Bcf a day of LNG that's under construction and should come online in that timeframe.

And then above and beyond that, we actually see another almost 10 to 12 Bcf a day in demand growth between now and the end of the decade, that's really associated with power demand. A little bit of industrials, some Mexico exports, but really it's power demand driven not only by, new power demand from AI and electrification, but also coal power retirements. And so our goal with Dorado is to continue to invest at a pace where we can capture some of the economies of scale as Jeff talked about, which in the last 2 years has really been a 1 rig program. And as the market starts to open up for us, we'd like to increase that. The next kind of critical point in these unconventional plays is to get to a continuous completion spread.

But we're very excited about where we can go and the asset that we've captured there.

And our next question today will come from Arun Jayaram with JPMorgan Securities LLC. Please go ahead.

Yes, good morning. Ezra, I was wondering if we could talk about puts and takes in terms of 2025 capital. Jeff mentioned that you expect to run relatively flattish activity, but with the movements between some basins. I was wondering if you could kind of characterize how capital would move. You're going to be a little bit more active at Dorado, we think in the Utica.

I think your strategic infrastructure spend is going to go down on a year over year basis and there's obviously some of the efficiency gains that Jeff was highlighting?

Yes, Arun, this is Jeff. Yes, thanks for the question. So yes, as you talked about and we talked about in our opening comments, the plan right now, which it's still early, is to maintain relatively flat activity next year. And those minor shifts, I mean, they're going to be fairly small. I mean, a few wells here and there and pretty immaterial across the portfolio, which will lead to the modest increase in activity we talked about in the Utica.

What I'd first say is just about our current program and the activity levels we're at. We're extremely happy with the progress we've made and the improvements we've seen across the whole portfolio by really focusing on that. And where we're at now is we want to focus on the emerging plays and really getting them to that critical activity level to maximize our efficiencies, which the first step in that is getting it to 1 full drilling rig. And then really the next hurdle is going to be getting those plays to 1 full frac fleet. So in the Utica, as we've touched on, we should be there next year.

We're looking at about a 50% increase in activity. We'll be up to 2 full rigs and 1 full frac fleet by year end. So we'll reach those critical points. And then in Dorado, which you talk about, we really anticipate maintaining just the one full rig that we've been running. We've been seeing outstanding performance and efficiencies from that consistent operations.

But we'll continue to manage the investments in our completion activity just as we watch the natural gas market and move through the winter. So I think by doing all this, this really allows us to continue to progress each one of those emerging plays, but we'll still be able to deliver another year of strong results from the portfolio. And then just real quick on infrastructure, you did hit on it. Over the last few years, we've had a little bit of additional infrastructure spend that was strategic with the Janus gas plant and the Verde pipeline. This year, it was around $400,000,000 And looking forward to 2025, really we just we're going to be finishing up that Janus plant and a few little things from a facilities aspect on the Verde pipeline.

So we expect the strategic spend there next year to be somewhere around $100,000,000 And then as those continue to roll off and we look in the future, we'll start moving back towards that 15% to kind of 20% indirect level.

Got it. That's helpful. Maybe just a follow-up to Steve's question on the optimization of the balance sheet. You mentioned Ezra that this could maybe drive higher cash returns to investors. How much does the potential to do A and D or bolt ons, countercyclical A and D, how does that progress in terms of your thinking in terms of going to $5,000,000,000 to $6,000,000,000 of gross debt?

Yes, Arun, this is Ezra. Yes, I mean, I think you're right. While we're going to be making our capital structure more efficient, we'll be very well positioned still to have what we consider industry's leading balance sheet, quite frankly. And that does going to preserve it's going to preserve the financial strength of the business for us. That will give us the ability to still maintain the ability to continue to invest in countercyclic low cost property bolt ons, other things that we've done in the past along those same lines.

And what I would say is the ability to return more than 100% of annual free cash flow in the near term and deliver more cash to shareholders over time, it's really just an effect of again shifting some of the equity into the debt side. Where we're starting at today is such a position of strength with a cash positive position that even leveraging up on this debt side, it still puts us in a great position to be able to continue to execute on a lot of our priorities, like I said, including low cost property bolt ons to be able to be in a position to opportunistically step into larger share repurchases if the opportunity presents itself. And so we really see this as a very shareholder friendly maneuver that we're doing. And like I said, the timing of it is really just what we kind of see in the market and the fact that we do have some of the bonds maturing.

And our next question today will come from Scott Hanold with RBC Capital Markets. Please go ahead.

Thanks. And I'm going to hit on the balance sheet optimization. And Ezra, you just sort of answered part of my question there with regards to like the why now. It's definitely unique to the sector. And just kind of curious, was this a decision you've been contemplating for some time?

Kind of what was the catalyst to move on it now? And also with respect to that, how much value creation from shifting to a lower cost capital structure like moving from equity to debt, some of that value, how much of a value improvement do you expect to see from that?

Yes, Scott, this is Ezra again. So on the strategic portion and then maybe I'll hand it over to Ann to get in a little bit more of the mechanics. But yes, I think this is really in line with where management and Board has been thinking for a long time. As I started off the Q and A session with Steve, I mentioned that I think we've been pretty consistent talking about the goal of the company has never been to go to an absolute zero debt level. But really we like to be positioned to create long term shareholder value and having different measures, different abilities to do that.

One thing that we love about having that pristine balance sheet that I should have just mentioned when speaking with Arun is also the peer leading regular dividend that we have. And this gives us confidence in being able to continue to grow that and maintain that dividend. As I said in the opening remarks, it's been 27 years that we've been paying that dividend without ever needing to suspend it or cut it and that's something we're very proud about. So we really look at the entire priority of our cash flows when we're thinking about this. And the trigger again that's caused it right now is just where we're at in the macro environment, and not from the commodity side, but really from the financial side.

If you recall, Scott, the last bond that we retired was about a $1,200,000,000 bond, back in Q1 of 2023. And that was the right decision at the time for us. But one of the reasons is not only were interest rates climbing at that time, but as we all recall, there was a what turned out to be a rather somewhat small banking crisis that at the time felt like it could maybe possibly balloon into something larger. So we refinanced that or I'm sorry, we paid that off with cash on hand. And essentially since then, interest rates have always been climbing up until the recent last couple of quarters where things have kind of plateaued and we're starting to see them bend over a little bit.

So those are really the things that have kind of given us the confidence to kind of go ahead and make this decision now. As far as moving the equity onto the debt side and the impact for us, I'll hand that off to Anne.

Yes. The way we look at it is the optimal capital structure is one where the balance sheet has more debt than what we have today. So basically, we're looking at putting on a level of debt that is more appropriate for our company of our size and strength in this point in the cyclical industry. So if you want to look at those parameters, as we mentioned, 1st, we want to be less than 1x total debt to EBITDA leverage ratio, at approximate bottom cycle prices around $45 I mean, if you compute that out, that gives us a yield to total debt level of about $5,000,000,000 to 6 $1,000,000,000 Conversely,

you look at the cash side of the business, as we look at the appropriate level of cash, we think that's currently about the level we've held for the last 2 years. We need about a minimum of 2,000,000,000

a daily basis. And then that additional cash allows us to backstop the regular dividend as well as support additional cash return and take advantage of those countercyclical opportunities. So again, echoing Ezra's comments, our main objective is just to create long term value for our shareholders. And we think setting up the balance sheet the way we are will better position us to have an appropriate level of cash to run the business, continue to make those investments as they present themselves and backs up our regular dividend through the cycle.

Understood. My follow-up is a little bit on the election. The outcome certainly have created a lot of volatility in the markets. And as you look at what this means for the energy industry and specifically for EOG, what are some of your initial kind of takeaways and the potential tailwinds at play?

Yes, Scott. We've still got obviously the Presidential and the Senate is getting close to you can kind of see who's going to control those two portions of our Congress and then we'll see where the House finishes up after that. I think for us, what we really prepare for is kind of this next couple of months. Whenever there's a change of administration, this is the time period when we really start to focus in, maybe take some steps to prepare just in case things can slow down. So we're feeling very good with where we're at right now.

As far as going forward on the industry, I think the industry has come a long ways as far as our relationship with not only at the federal level, but really at the local level, working alongside policymakers, regulators and such. And I think the industry is in a very good spot to continue the performance that we've had over the last few years. When I I know I can speak a little more directly for EOG, from the areas that we operate, even the new areas like in Ohio with our Utica play, we've really developed an outstanding relationship, I think. Many across industry, policymakers, really just stakeholders in general see that there is a long that oil and natural gas are going to play a part of the long term energy solution. And that working with industry is really the best way to kind of achieve the goals of low cost, reliable and lower emissions type of energy sources.

And our next question today will come from Leo Mariani with ROTH. Please go ahead.

Hey, guys. Why don't you just touch base a little bit here on the Utica again. So just curious, you guys talked about $6 to $8 a BOE. I think that was exclusive to the volatile oil window. Do you think there's room to kind of continue to get cost down over time?

I know you guys have talked about a long term goal of $5 a BOE finding cost, but I think that may have included some of the gassier windows as well. So where are you at in the cost cycle in the Utica? And do you think there's still significant room to take that down?

Yes, Leo, this is Keith. The final cost range, yes, you're right. It is specific to the volatile oil window and the 225,000 net acres we have there. The range represents the expectations for the next 2 to 3 years of development. That's the same for the well cost range.

If you back out the science on some of our early wells, we've hit the upper end of this range multiple times and we'll continue to drive it down with the economies of scale. Versus the $5 finding costs we previously disclosed, that reflects the entire 445,000 acre field. That includes the up dip oil window and the down dip condensate window. It also incorporates full field development. So we still see line of sight to that, but what we're doing here is giving more guidance in the near term.

Overall, we've made great progress in the play. The well productivity and well cost continue to demonstrate the premium quality, and it really highlights our organic exploration strategy.

Okay. Appreciate that. Wanted to see if there was any update on the PRB. I feel like it's been a little time since we've kind of heard on that. How are you kind of viewing that play in terms of how it stacks up against others?

And I think you're doing a little bit less on the well side this year than you did. Last year, you talked about adding a little bit of activity in the Utica for 2025. Just kind of any update in terms of how the PRB is performing and how you're kind of thinking about future activity levels there?

Yes, Leo, this is Jeff. So, yes, the Powder is progressing nicely. As we've talked about for the past handful of years, we've really been focused on the Maori formation, which is the deeper formation and really kind of lining out our geologic model and what our development plans are there and we had really good success with it. So, we've shifted over since we've gotten all that overlying geologic data in the Niobrara to where we're really doing a split program this year of about 25 wells split between the Maori and the Niobrara. And what I would say is we've applied the new geologic models and we're continuing to refine our completion techniques up there.

And through the 1st part of the year, we brought on some of those Niobrara wells. And I mean, the results are very early right now, but they're very encouraging. We are seeing an uptick of greater than probably about 10% increase in productivity versus 2023 in the Niobrara. So moving forward right now, I think we're in a very comfortable spot. We still have a little to learn there in the Niobrara on kind of just our development patterns and when to offset in depletion in space.

And so I think we're probably going to be pretty consistent with our program as we move into 2025 as we continue to refine those models.

And our next question today will come from Clay Akermes with Bank of America. Please go ahead.

Hey, good morning guys. Thanks for getting me on. My first question is on the gas guide. So we've seen it go up every single quarter of this year and we think that that's the Permian. I appreciate that the Janus plant is coming online, but I'm wondering if that gas outperformance pulls forward any of your additional midstream development timelines?

Yes, Kayleigh. This is Jeff. And no, our plans are pretty secure as far as that goes. And really there shouldn't be any advancement. I mean all of any of the kind of midstream or I should say strategic infrastructure projects that we've talked about, I mean they're on time and they're on pace to come online when we expected.

With the Janus Gas Plant, as we've talked about, the plan is to complete that next year. So as we talked about, we'll have a little bit of strategic infrastructure dollars associated with that, about $100,000,000 But other than that, no, there'll be really no acceleration in any of those projects.

Got it. For my follow-up, I'd like to go back to Dorado. I appreciate that it's got very low cash costs. I think in the past, we've talked about $1 and that falling by $0.50 to $0.60 because of Verde. And sort of given its position on the coast, I imagine that it's going to be quite a resilient play.

My question is, are you going to optimize production around that cash cost figure? Or do you think that there was a return threshold to consider that would cause you to maybe curtail production or maybe decelerate?

Yes, Clay. This is Ezra. The way we look at Dorado quite frankly is similar to the way that we invest any of our basins and it starts with the returns profile. Are we investing at the right pace to optimize the returns and the ultimate NPV of that asset? And quite frankly, what we found in Dorado, especially with its location there close to the demand center, coupled with some of the strategic decisions we've been able to make on the marketing side is that this dry gas play from an economics perspective really competes with many of our oil plays.

And so that's really what governs how quickly that we invest into that play. On the lower level as we've talked about with any of these unconventional resources or these emerging assets, we like to try and get to these critical points of where you capture the economies of scale. So the first is consistent rigs. The second point would be a consistent completion spread where you're not mobilizing in and out of base on a lot of crews and things like that. It gives you the ability to really know the crew that you're working with and the equipment and you can really start to leverage the learnings.

On the upper end of it, you can definitely outrun your pace of investment there and your ability to learn on each well and make each well a little bit better, whether it's finding cost or well performance. And then layered on top of that obviously is the macro environment. Now we've done a great job with Dorado by strategically allowing that gas to reach multiple markets. It's got multiple outlets and it's well positioned along the Gulf Coast like we said. And so that does, bring to it an inherent opportunity to continue to deliver that gas.

And we think that it will be a significant portion of the future supply that should grow into the North American growing gas demand.

And our next question today will come from Neal Dingmann with Truist. Please go ahead.

Thanks for the time guys. I'm hoping I could ask another one on the Utica specifically. Love to hear your latest thoughts on how you're thinking about the prospectivity more on the West side of the play, either in that black oil or volatile oil in the play. And then just one other question on this play. What's the latest on just the decline?

I know it's still early, but I'm just wondering, are these wells declining more like typical oil wells or like a Marcellus gas well?

Yes. This is Keith. On the prospectivity overall, we are still focused mainly on the volatile oil window and trying to dial down spacing there. We will eventually jump up to the west side or also to the condensate window at some point. We're still in the data gathering phase there.

On the decline side, I'd say we're not seeing anything out of the ordinary. It's a combo play and we see the declines like a typical tight shale well similar to the Eagle Ford.

Got it. Okay. Okay. And then maybe just a segment or follow-up just on overall inventory. I'm just wondering, I understand you no longer put out the well count in your slides like you previously had in the appendix.

I'm just wondering, I was hoping you could give a sense or maybe a ballpark how many years you're thinking about of running room specifically in the Dell, Eagle Ford and Bakken at the current rig paces?

Yes, Neal, this is Ezra. What we do disclose is our resource potential as far as resource. And we've continued to show that we've got about 10,000,000,000 barrels of equivalents of the premium resource across the multi basin portfolio. The ones that you're highlighting are it's an interesting collection because you've got a mix of kind of those are our foundational plays, but they're all a different kind of legacy aspects. So in the Bakken, we run basically a 1 rig program and we're at a point where we feel that we can continue to do that and generate similar returns for a number of years to come.

In the Eagle Ford, many things have changed in the Eagle Ford and I think everyone's seen that we've slowed down our pace of investment, kind of, just for lack of a better data point, say pre COVID until post COVID, where these days we put to sales maybe 120 wells to sales every year or something like that. And again, the slowing down of that investment, it's less about the inventory that we have remaining and it's more about what I was speaking with Clay about as far as investing in each of these plays at the right pace. Slowing down there in the Eagle Ford, we've actually increased the returns and expanded the margin profile. And that's really the thing that we focus on. And then in the last one that I would mention is the Delaware Basin, of course.

To be honest with the Delaware Basin, I think it's difficult. Industry has done a lot of drilling there over the past decade. But with the technology advancements, I think industry continues to unlock, especially on the Delaware Basin side, unlock additional targets every year. And so to be quite honest, it's a little bit difficult to quantify just how much inventory would be left in such a robust resource as the Delaware Basin. You're talking about literally a mile's worth of oil and gas saturated reservoirs in that basin.

And so we feel very good about the premium resource that we have in place. We've got a very high quality, very deep bench of assets across multiple basins. And really at the pace that we're operating in the last couple of years and where the macro environment looks right now, inventory is a lack of inventory is not really something that we really ever makes our radar. What we continue to look for is improving the quality of that inventory through our organic exploration effort, which is one of the things that's driven the success there in the Utica.

And our next question today will come from Charles Meade with Johnson Rice. Please go ahead.

Good morning, Dan. Good to you and your whole team there. I wanted to go back to your prepared comments. You spoke a bit about the commodity macro and you gave a thought on the U. S.

EOG Resources (EOG) Q3 2024 Earnings Call Transcript

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