EOG Resources, Inc. (NYSE:EOG) Q3 2023 Earnings Call Transcript

EOG Resources, Inc. (NYSE:EOG) Q3 2023 Earnings Call Transcript November 3, 2023

Operator: Good day everyone, and welcome to EOG Resources Third Quarter 2023 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Tim Driggers: Good morning, and thanks for joining us. This conference call includes forward-looking statements, factors that could cause our actual results to differ materially from those and 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 reconciliations for these non-GAAP measures can be found on the EOG’s website. In addition, 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 SECs reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; Billy Helms, President and Chief Operating Officer; Jeff Leitzel, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; and Piers Hammond, VP Investor Relations. Here’s Ezra.

Ezra Yacob: Thanks, Tim. Good morning, everyone. Over the past five years, EOG has increased production 33%, decrease per unit operating costs 17% generated over $20 billion of free cash flow and over $20 billion in net income. We’ve increased our regular dividend rate nearly 350% and including both regular and special dividends paid and committed to have returned about $13 billion directly to shareholders, all while reducing total debt by more than 40%. At the core of our historical and future success of EOG’s employees who embrace and embody the EOG culture. And our third quarter results continue to reflect our employees outstanding execution, strong performance and our foundational Delaware basin and Eagle Ford assets, as well as continued progress across our emerging plays have delivered production volumes, capital expenditures, and per unit operating costs better than expectations, and enabled us to raise our full year oil production guidance and reduce our full year cash operating costs guidance.

In addition to announcing third quarter results yesterday, we demonstrated our confidence in the outlook for our business by increasing the regular dividend 10%, announcing a $1.50 per share special dividend and raising our cash return commitment to shareholders beginning in 2024, to a minimum of 70% of annual free cash flow. Our annualized regular dividend is now $3.64 per share, which represents the highest regular dividend yield amongst our peers and is competitive with the broader market. This dividend increase reflects two things. First, the progress we continue to make on our cost structure by leveraging technology and innovation sustainably improves EOGs capital efficiency. Furthermore, we expect the advantages of operating in multiple basins will drive additional improvements to EOGs cost structure and returns and reduce the break-even oil price to fund the dividend in the years ahead.

Today we estimate that we can maintain our current level of production and fund the $2.1 billion regular dividend commitment at an oil price as low as $45 WTI. Second, this dividend increase reflects our confidence in EOGs expanding portfolio of premium plays to grow the company’s future income and future free cash flow. This quarter we’ve highlighted recent well performance results in the newest addition to our premium portfolio of assets, the Utica combo play. Over the last several years, our success in organic exploration continues to add low-cost reserves and consistently drive down our DD&A rate enabling EOG to create value through industry cycles. Beyond our regular dividend, which we’ve never cut or suspended, we raised our cash return commitment to shareholders to a minimum of 70% of annual free cash flow beginning in 2024.

Alongside our portfolio of premium assets, and our cash flow margins EOGs balance sheet continues to strengthen allowing us to supplement the dividend with a larger commitment of future free cash flow through special dividends and share repurchases. In addition to the $1.50 per share special dividend declared yesterday, we executed additional opportunistic share repurchases for the third consecutive quarter. For 2023, we estimate our committed cash return will be about 75% of free cash flow. EOG continues to consistently execute lower our cost structure through innovation efficiencies, and organically grow the quality of our portfolio to improve capital efficiency and free cash flow potential. Our transparent cash return strategy is anchored to a sustainable growing regular dividend and backstopped by an impeccable balance sheet.

EOG is in a better position than ever to deliver value for our shareholders through industry cycles and play a leading role in the long-term future of energy. Here’s Tim to review our financial position.

Tim Driggers: Thanks, Ezra. EOG delivered superb operating and financial performance in the third quarter. Oil production increased 4% year over year, while total production was up 9% year-over-year per unit cash operating costs declined by 5% from the prior year period. The DD&A rate fell by 9% year-over-year driven by the addition of reserves at lower finding costs compared to our production base. Capital Expenditures came in at $1.52 billion, $140 million below our target, mostly due to the timing of non-well related expenditures, such as infrastructure projects. Year-to-date, CapEx of $4.5 billion is 75% of the full year guidance. We earned adjusted net income of $3.44 per share in the third quarter, and generated free cash flow of $1.5 billion.

We announced a $1.50 per share special dividend and during the third quarter we spent $61 million on share repurchases, bringing total 2023 share repurchases through the third quarter to $671 million, at an average price of $108 per share. In total, we’re on track to return $4.1 billion of cash to shareholders this year, in the form of regular dividends, special dividends and repurchases. This equates to about 75% of our estimated 2023 free cash flow higher than our 2023 minimum commitment of 60% of annual free cash flow return to shareholders. Overall, it was a strong quarter driven by solid operational execution and improving capital efficiency. Here’s Billy to review operations.

Billy Helms: Thanks, Tim. EOGs operational performance continues to improve and this quarter is another example. We exceeded our third quarter forecast across the board on volumes per unit operating cost and CapEx. Thanks goes to our employees for consistently delivering the EOG value proposition quarter-after-quarter. Third quarter volumes exceeded guidance largely due to accelerated timing of activity within the quarter driven primarily by improved efficiencies, as well as some benefits from better well productivity. Efficiencies in our completion efforts have reduced the time to bring wells to sales. For example, in our Eagle Ford play, the completed lateral fleet per day has increased 19% year-over-year. The team has also reduced non-productive time by 31%, which is the added benefit of lowering total well cost.

In addition, our new completion design continues to drive performance improvements in the Delaware basin, with targeted laterals realizing a 20% increase in productivity. Well productivity improvements is the primary reason we were able to increase the full year oil guidance by 1500 barrels of oil per day. Last quarter, we reduced our full year guidance for total unit cash operating cost, mostly due to lower release operating expense and reduced transportation cost. Our third quarter performance continued that trend. Our production teams are optimizing both production and cost through our many technology applications that allow for real-time decisions to maximize production and reduce interruptions of third-party downtime. These cross functional efforts by our production, marketing and information systems teams continue to pay dividends.

Once again, we are lowering our guidance for full year cash operating costs by approximately 2% this quarter, bringing our total reduction since the start of the year to 3% or nearly $0.30 per BOE. Capital Expenditures in the third quarter were lower than expected due to timing of infrastructure projects, as well as variances in activity across our multi-basin portfolio. We expect to maintain our current levels of activity for the remainder of the year, and our full year capital guidance is unchanged. For 2024, we are currently evaluating this year’s results as we develop our plans for each of our plays. As a reminder, we invest to generate returns and growth is a byproduct of the investments in our highly economic multi-basin portfolio. We are very pleased that the levels of activity across our portfolio are at a pace that allows for continuous learning and improvements, and thus we’d expect to maintain similar levels of activity through 2024.

With the strong results we’re achieving in our emerging plays, we anticipate a few additional wills in both the Utica and Dorado. As we typically do each year, we will remain focused on managing costs through the cycle by contracting for about 50% of services and leveraging our scale and consistent activity levels to build and maintain strong partnerships with service providers. As a result, we’re able to take a longer-term view to sustainably lower well cost over time. This year is shaping up to be another solid year performance for EOG. And I remain excited about the opportunities we see through the remainder of the year and into 2024. Now here’s Jeff to talk about the updates on the Utica play.

Jeff Leitzell: Thanks, Billy. In addition to sharing new well results, I’d like to review a few unique characteristics of our Utica asset to provide distinct advantages including our low cost of entry, our mineral rights position, held by production status, geologic operating environment, and downstream infrastructure status. This year we added 25,000 net acres and have now accumulated 430,000 net acres predominantly in the volatile oil window across 140-mile trend running north to south. Our leasehold cost of entry remains less than 600 per net acre. We’ve also acquired 100% of the mineral rights across 135,000 acres of our leasehold. Mineral rights significantly enhance the value of this play by adding 25% to our production and reserve streams for no additional well cost or operating expense.

Furthermore, over 90% of the Utica acreage is held by production and requires only a handful of wells to be drilled every year to maintain. The result is more control over our development to allow us to invest in an appropriate pace to capture and incorporate technical learnings and continually improve the play. Another unique advantage of the Utica is its geologic operating environment. Due to the place favorable geologic properties, the opportunity to drive down cost through efficiencies is significant. The target zone is both shallow and consistent, which lends itself easily to drilling 3-mile laterals, and we anticipate testing even longer laterals as we continue to delineate and collect more data. Consistent geology also allows for precise targeting of the very best most productive rock.

We’re able to regularly drill 99 plus percent in zone within a narrow 10-foot window. As a result, this play provides an excellent geologic environment for significant efficiency improvements and low-cost operations. On Slide 11 of this quarter’s investor presentation, we highlighted our strong and consistent well result to span our acreage position from the north and to the south. Our initial 4-well Timberwolf package was drilled at 1000-foot spacing and has been performing well above type curve. These 3-mile laterals each deliver an initial 30-day production averaging 2150 barrels of oil equivalent and an 85% liquid cut. With a large amount of liquids in the product mix all of the wells we have drilled today support double premium potential across our acreage position.

The Utica also has the advantage of abundant midstream infrastructure, the existing processing fractionation and residue build out eliminates the need for significant new build commitments, which was a well-recognized advantage when we evaluated the play. In the north, we have placed into service, a pipeline that runs east of our acreage into the market center. In the south, we have an established reliable third-party building out a new pipeline that is expected to be in service late this year. With these trunk lines in place investment will be limited to in-field gathering as we prepare for a modest increase in activity next year. Our current plans for 2024 are to run approximately one full drilling rig that will continue to test optimal well spacing and improve operational efficiencies.

Our Utica asset is another textbook example of our differentiated approach to build a diverse portfolio of premium assets predominantly through low-cost organic exploration, which adds reserves at lower finding and development costs and lowers the overall cost basis of the company. The end result is continuous improvement to EOGs company-wide capital efficiency. Our track record of successful exploration and strong operational execution has positioned the company to create shareholder value through the industry cycles. Here’s Lance with a marketing update.

Lance Terveen: Thanks Jeff. In our South Texas Dorado play, we recently completed two projects to service future gas flows from this premium, dry natural gas play and natural gas treatment facility and the first phase of a 36-inch pipeline. The facility was recently placed in the service to treat gas from the Dorado play prior to transportation through our 36-inch natural gas pipeline to sales near [indiscernible], Texas. Both projects were delivered on time and under budget, a testament to our operational team and foresight to procure a pipe counter-cyclically, along with other long lead time materials. The second phase of the natural gas pipeline will kick off construction in early 2024 and is expected to be complete late next year.

Phase 2 of the pipeline will terminate in the Agua Dulce, which provides access to three other pipelines with connectivity to the growing demand along the Gulf Coast and Mexico, and potential premium pricing relative to Henry Hub. Our pipeline will be instrumental in expanding our gas sales options for the 21 TCF of net resource potential we’ve captured in Dorado, and perhaps more importantly, save $0.20 to $0.30 per MCF in transportation costs over the life of the asset versus third-party alternatives. Now here’s is Ezra to wrap up.

Ezra Yacob: Thanks, Lance. EOG continues to deliver on our value proposition and our approach remains differentiated for several reasons. First, our premium return standard investments are governed by one of the highest hurdle rates in the industry 30% direct after-tax rate of return using $40 oil, and $2.50 natural gas pricing. Second is organic exploration, by prioritizing organic exploration we add inventory and reserves at lower finding and development costs. Third, our assets are unique. By remaining focused on the first two returns and organic exploration, we have built one of the largest highest return lowest cost and most diverse portfolios of assets in the business. We operate in 16 plays across nine basins and have a mass resources of 10 billion barrels of equivalents with an average finding and development cost of just $5 per barrel.

At our current production level, that’s equivalent to about 30 years of low cost, high margin inventory, and our assets continue to grow. Fourth is technology. We have never considered as a manufacturing process. We leverage both infield technology and information technology to improve well productivity and efficiencies. Our goal is to lower costs and expand our margins to constantly improve our existing assets and new discoveries. Thanks for listening. Now we will go to Q&A.

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Q&A Session

Operator: Thank you. [Operator Instructions] And our first question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Scott Hanold: Thanks. Good morning. Congrats on the strong quarter. Ezra, I think it was pretty notable, the way you all took a step up in your fixed dividend payments. I mean, you’ve got a history of doing that, but it was a good step up this quarter, in addition to boosting the shareholder return program to 70%. So, can you talk about some of the more significant factors like, why make those pretty pronounced moves now? Is there something in the business model, you guys get more confidence at this point to make those moves?

Ezra Yacob: Yes, Scott, thanks for the question. The decision to raise minimum cash return to 70%. Overall, it just demonstrates our commitment our shareholders. It reflects our continual improvements since the initial commitment was made nearly two years ago. And really to your question on the business model change, it’s really just our ability to deliver that shareholder value. It’s grounded in the fact that our strong cash return generation capacity continues to improve the strength of our industry leading balance sheet continues to improve and our commitment again to just being disciplined with our reinvestment across the entire portfolio. So we’re in a position now where we feel very confident that and proud that we can increase that minimum commitment to 70%. And we look forward to being able to deliver that to the shareholders.

Scott Hanold: So when you look at those breakeven points to do that, sort of this base business, is that breakeven point then lowered from, say, where you were a year or 2 ago to where it is now?

Ezra Yacob: Yes. That’s right, Scott. As we continue to invest in these higher-return, lower-cost reserves and bring them into the base business, we continue to do some strategic infrastructure spending to lower the overall cost of the company going forward. That continues to expand the free cash flow potential of the company. And that, in addition to strengthening the balance sheet, everyone knows we retired a $1.25 billion bond earlier this year, and we’ve been able to be not only net zero but actually put a little bit of cash on the balance sheet. All of those things are what gives us confidence in the base business going forward and the fact that we can continue to increase this minimum cash return to our shareholders from the 60% up to the 70%.

Operator: The next question comes from Leo Mariani of ROTH MKM. Please go ahead.

Leo Mariani: You guys spoke about sort of similar ’24 activity versus 2023, but also kind of said that there might be a handful of more wells in the Utica, in the Dorado. So I just kind of wanted to get a sense there. I mean, do you see this as kind of a give-and-take proposition, where if you do a little bit more in some place, you might have kind of a few less wells and some other plays? And just trying to get a sense of how maybe costs are trending overall in wells today.

Billy Helms: Yes, Leo. This is Billy. Yes, as far as 2024, certainly, it’s too early to get into many specifics about the plan. But I would say that our plan will be based on a couple of different factors. One would be the macro environment, kind of what that looks like going into next year. The other one is really governed by what’s the optimum level of activity across each of our plays that supports the objective of having continuous improvement. And so on that, on our core plays say, our foundational plays, the Eagle Ford and the Delaware Basin, we’re very pleased with the activity levels we currently have there. And we’d expect to maintain similar levels of activity in those plays. We see the advantage of that is we are seeing continued improvement in each one of those plays, as we’ve talked about already on this call, And then, for our emerging plays, the Utica and the Dorado, for instance, we’re very pleased with the results we’re seeing to date.

And so as we move into next year, we certainly want to continue that learning, and you may see a few additional wells in those plays on top of what we’ve done this year. As far as the cost trends, that’s one reason we like to maintain these levels of activity. It allows us to improve our cost basis, improve operationally on how we’re executing these wells, and we’re seeing the benefits of that play out. So I’ll maybe leave it at that and see what your follow-up is.

Leo Mariani: Okay. No, that’s helpful. So maybe just to kind of jump over to the Utica. Obviously, you brought a new package of wells online here. I know it’s sort of early days, but when you look at these wells, do you tell yourself that you’ve already been able to see some improvement over the last year? Just trying to get a sense, are these wells a little better than they were, say, a year ago? And then on the cost side, in the Utica, are you starting to see maybe the cost come down a little bit here? Or maybe it’s kind of early. I think you’ve had a target of sort of sub-$5 F&D, just not really sure kind of where you’re at today.

Jeff Leitzell: Yes. Thanks, Leo. No, we’re really excited about the latest package that we brought on. That’s our Timberwolf package that we highlighted on Slide 11. It’s in a 1,000-foot space test. And of note there, as we’ve talked about our new completion design down there in the Permian and the Wolfcamp, we were able to go ahead and implement that on that. And as you can see from the initial results that we talked about, the 30-day IPs on that or 2,150 BOE per day over that 30-day period. So really excited about how that’s turning out from the spacing test. We have an additional package. We actually highlighted in our slide deck, Xavier. We’re going to tighten the spacing on that to 800 foot, and we should have results coming on here fairly shortly.

So we’re very excited with the results. And with that application of new completion design, it’s going to be tough to tell if that’s really what the big mover is, but we’re extremely excited about the results that we’re seeing so far. And from a cost standpoint, we really haven’t disclosed specific costs in the Utica. We’re still in the early stages, as we talked about in learning in this play. We’ve got a lot of room for operational efficiency gains. We’ve got some infrastructure, small infrastructure to develop that we can install like water gathering, reuse and sand to drive down costs. And then as we said, with the well results we’re seeing, we feel really confident in supporting that sub-$5 F&D cost.

Operator: The next question comes from Arun Jayaram of JPMorgan Securities. Please go ahead.

Arun Jayaram: Ezra, I wanted to get your thoughts maybe at a high level in 2024. On the third quarter call of last year, you provided some soft [Technical Difficulty]. I was wondering if you could maybe give us some thoughts on overall, how you see the year kind of playing out. If I look at consensus forecast, it’s for about $6.1 billion of CapEx with [Technical Difficulty]. So I want to get your thoughts if you could give us some soft guidance around next year.

Billy Helms: Yes, Arun. This is Billy. Let me try to weigh in on that for you. And I apologize if I missed some of your question, you were breaking up a little bit there. As far as 2024, as I said earlier, it’s a little bit early to give specifics on the plan, but I would say just look at our activity levels we’re seeing today. And I would expect to see similar levels of activity on our core foundational plays going into next year, give you some hint as to what activity levels we might have. I would expect a few additional wells next year in our emerging plays, such as the Utica and maybe Dorado. And then, as far as service costs, let me just weigh in a little bit on that while we’re talking about that. We certainly understand service costs have moderated in the industry as industry activity has dropped throughout the year.

The magnitude of those declines certainly varies between the services and in which basins we’re operating in. We remain focused on just continuous improvement that we see in our efficiency gains throughout our operations. So we tend to use the latest technology in the highest-performing crews, which includes super-spec rigs and frac fleets. That equipment continues, as you know, to be in high demand with service pricing proving to be more resilient. We have seen drops in tubular and casing costs for next year that will tend to reduce overall well cost. But again, the magnitude of that effect on overall well cost is yet to be quantified. So as we go into next year, certainly, we expect to maintain our activity levels that we see in our core plays, a few extra wells, some softening on well cost.