EOG Resources, Inc. (NYSE:EOG) Q4 2022 Earnings Call Transcript

EOG Resources, Inc. (NYSE:EOG) Q4 2022 Earnings Call Transcript February 24, 2023

Operator: Good day, everyone, and welcome to EOG Resources Fourth Quarter Full Year 2022 Earnings Results Conference Call. As a reminder, the call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call 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 can cause 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 GAAP measures can be found on EOG’s website. Some of the reserve estimates on this conference call may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC’s reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; Billy Helms, President and Chief Operating Officer; Ken Boedeker, EVP, Exploration and Production; Jeff Leitzell, EVP, Exploration and Production; Lance Terveen, Senior VP, Marketing; and David Streit, VP, Investor Relations. Here’s Ezra.

Ezra Yacob: Thanks, Tim. Good morning, everyone. EOG’s growing portfolio of high-return assets delivered outstanding results in 2022. We earned record return on capital employed of 34% and record adjusted net income of $8.1 billion, generated a record $7.6 billion of free cash flow which funded record cash return to shareholders of $5.1 billion. We increased our regular dividend rate 10% and paid four special dividends, paying out 67% of free cash flow, beating our commitment to return a minimum of 60% of annual free cash flow to shareholders. And we strengthened what was already one of the best balance sheets in the industry, reducing net debt by nearly $800 million. We continue to deliver on our free cash flow priorities this year by declaring an additional special dividend of $1 per share yesterday.

Outshining our financial results were achievements made by our operating teams working in a challenging inflationary environment. Credit goes to the innovative and entrepreneurial teams working collaboratively across our multi-basin portfolio. Together, we leveraged the flexibility provided by our decentralized structure to deliver exceptional operational performance. Production volumes, CapEx and per unit operating costs were within guidance set at the start of the year. We offset persistent inflationary pressures that exceeded 20% during the year to limit well cost increases to just 7%. Our exploration teams uncovered a new premium play, the Ohio Utica combo, and advanced two emerging plays, the South Texas Toronto and Southern Powder River Basin.

We’ve progressed several exploration prospects including the Northern Powder River Basin. We expanded our LNG agreement, currently estimated to take effect in 2026 to 720,000 MMBtu per day, which will provide JKM-linked pricing optionality for 420,000 MMBtu per day. Last year, the revenue uplift from our current 140,000 MMBtu per day LNG exposure was more than $600 million net to EOG. Preliminary results indicate that we reduced our GHG intensity and methane emissions percentage, achieving our 2025 targets. And we initiated an expanded deployment of our new continuous methane leak detection system called iSense. Led by the tremendous performance in our Delaware Basin and Eagle Ford plays, our operating performance and financial results in 2022 are a reflection of our asset portfolio and the unique organizational structure in place to support it.

Seven teams in North America and one international team operates 16 plays across nine basins. Our decentralized structure empowers each operating team to make decisions in real time at the asset level to maximize value. This differentiates EOG and enables us to consistently execute our strategy and produce outstanding results year after year. Our multi-basin portfolio provides numerous high-return investment opportunities and we remain focused on disciplined investment across each of our assets. In addition to our premium well strategy, in which wells must generate a minimum of 30% direct after-tax rate of return at a flat $40 oil and $2.50 natural gas price for the life of the well, we invest at a pace that allows each asset to improve year-over-year, lowering the cost and expanding the margins generated by each asset.

Disciplined investment means more than just expanding margins at the top of the cycle. It means delivering value for the life of the resource and through the commodity price cycle. It’s not only developing lower-cost reserves, but also investing strategically to lower the operating cost of these resources, which positions EOG to generate full cycle returns competitive with the broad market. Looking ahead to 2023, EOG is in a better position than ever to deliver value for our shareholders and play a significant role in the long-term future of energy. Our ability to reinvest in the business, deliver disciplined growth, lower our emissions intensity, earn high returns, raise the regular dividend and returned significant cash to shareholders, all while maintaining what we believe is the best balance sheet in the industry is due to our differentiated strategy executed consistently year after year.

Now, here’s Tim to review our financial position.

Tim Driggers: Thanks, Ezra. When we established our premium strategy back in 2016, our goal is to reset the cost base of the business to earn economic returns at the bottom of the price cycle. The impact premium has had on the cost basis of the Company and our financial performance has been dramatic. Since 2014, prior to establishing our premium strategy, our DD&A rate has declined 42% and cash operating cost by 23%. Also, in 2014, and under similar oil prices as last year, we earned 15% ROCE. With our lower cost structure, ROCE increased to a record 34% in 2022. We have also reduced net debt last year by $800 million to further strengthen the balance sheet. We view a strong balance sheet as a competitive advantage in a cyclical industry.

Our current balance sheet is among the strongest in the energy industry and ranks near the top 20th percentile of the S&P 500 in terms of leverage and liquidity, measured as net debt to EBITDA and cash as a percentage of market cap. We have a $1.25 billion bond maturing in March and intend to pay that off with cash on hand. Our 2023 plan is positioned to generate another year of strong returns. We expect to grow oil volumes by 3% and total production on a BOE basis by 9%. At $80 WTI and $3.25 Henry Hub, we expect to generate about $5.5 billion of free cash flow for nearly 8% yield at the current stock price and produce an ROCE approaching 30%. This attractive financial outlook, along with our strong balance sheet, is what gave us the confidence to declare a $1 per share special dividend to start the year on top of our regular dividend of $0.825 per share.

As a reminder, our commitment to return a minimum of 60% of free cash flow considers the full year, not a single quarter in isolation. The special dividend reflects the confidence in our plan and our constructive outlook on oil and gas prices. We will continue to evaluate the amount of cash return as we go through the year with an eye on, once again, meeting or exceeding our full year minimum cash return commitment of 60% of free cash flow. Here’s Billy to discuss operations.

Billy Helms: Thanks, Tim. I would like to first thank each of our employees for their accomplishments and execution last year. 2022 was a challenging year, and the commitment and dedication of our employees remain steadfast as they delivered outstanding results. Last year can be characterized as a year of heightened inflation where we witnessed increasing commodity prices, accompanied by higher levels of activity across the industry. The result was a much tighter market for services, labor and supplies. We were able to offset most of this inflation through efficiency gains and capital management across our portfolio to limit well cost increases to just 7%. For the full year, oil production was above the midpoint of guidance, while capital expenditures were $4.6 billion, were only 2% above the original guidance midpoint set at the beginning of the year.

Our operating teams working throughout the Company leveraged efficiencies to help offset inflation. This is most evident in our core development plays, which sustain sufficient activities to support continued experimentation and innovation. In the Delaware Basin, we expanded use of our Super Zipper completion technique to increase treated lateral feet per day by 24%. In our Eagle Ford play, the completions team increased completed lateral feet per day by 14% and the amount of sand pump per day per fleet by 27%. Our decentralized operations teams are continually striving to improve performance and share learnings across our portfolio to limit well cost increases. These learnings are then deployed in our emerging opportunity plays. For instance, in the Southern Powder River Basin, Mowry play, the drilling team decreased drilling time by 10% with improved bid and drilling motor performance.

In our South Texas Dorado gas play, the operations team reduced drilling time by 12%. Through technical and operational advancements, they promise to continue to drive improvements in 2023. Beyond cost reductions, a new completion design implemented last year in the Delaware Basin is realizing positive improvements in well performance in certain target reservoirs. This new design was tested in 26 wells last year and is yielding as much as an 18% uplift and estimated ultimate recovery. We’re also making great progress towards our long-term ESG goals. Our wellhead gas capture rate exceeded 99.9% of the gross gas produced. And preliminary results indicate that we lowered GHG intensity and methane emissions percentages in 2022. We now have approximately 95% of our Delaware Basin production covered by iSense, our continuous methane monitoring technology.

Now turning to the 2023 plan. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We expect total volumes on a Boe basis to grow each quarter through the year. First quarter will show more growth in gas versus oil due to the well mix and timing of several Dorado gas wells that were completed late in the fourth quarter of last year. The plan can be summarized in the following four points. First, drilling rig and frac fleet activity in our core development programs, specifically the Delaware Basin and the Eagle Ford, will be relatively consistent with the fourth quarter of last year. The longer-term outlook for the Eagle Ford is to maintain the current production base where we have over a decade of continued opportunities to generate high returns and cash flow.

After a decade of stellar operational improvements in the Eagle Ford, it has become a highly efficient, high-margin play with existing infrastructure and access to favorable markets. In the Powder River Basin, the plan builds off last year’s positive well results and infrastructure installation with an additional 20 Mowry completions. We expect to complete a few additional wells in our emerging Utica play in Ohio as we continue to delineate our acreage position and drill a few wells in the Bakken and DJ Basins. In Dorado, our plan is to achieve an activity level that creates economies of scale and develop a continuous program to allow for innovation that drives improved well performance and cost reductions. This results in a moderate increase in activity, completing about 10 additional wells versus last year.

In Trinidad, a drilling rig is now scheduled to arrive in the third quarter, which is about a six-month delay. So, international volumes decreased 60 million cubic feet per day or 10,000 Boes per day versus our earlier estimates. Overall, we increased activity in our emerging plays. The average EOG rig count for the year is expected to increase by about two rigs and one additional frac fleet. Second, we have line of sight to efficiencies that we expect will limit additional inflation pressure on well cost to just 10% versus last year. Year-over-year increases in tubular costs as well as day rates for drilling rigs and frac fleets are the main drivers of the increase. As part of our contracting strategy, we stagger our agreements to secure a base line of services and secure consistent execution.

For this year, we have locked in about 55% of our well cost, which is a similar level to previous years. Approximately 45% of our drilling rigs and 65% of our frac fleets needed for the year are covered under term agreements with multiple providers. By maintaining this consistent base of services, we expect to find additional opportunities to drive performance improvements and eliminate downtime, thus potentially providing an opportunity to offset some additional inflation. Third, our 2023 capital program includes additional infrastructure investment. Typically, funding for facilities and other infrastructure projects comprises 15% to 20% of the CapEx budget. And this year, we expect that number to be closer to 20%. In Dorado, we commenced construction late last year on a new 36-inch gas pipeline from the field to the Aqua Dolce sales point near Corpus Christi, Texas.

This pipeline will help ensure a long-term takeaway, fully capture the value chain from the wellhead to the market center, help support expanded LNG export price exposures due to come online around 2026 and broaden our direct interstate pipeline capacity to reach markets along the entire Gulf Coast corridor. We’re also undertaking smaller infrastructure projects in other areas, like the Utica to lower the long-term unit operating cost. Fourth, we plan — the plan includes capital that represents the next steps towards our vision of being among the lowest emissions producers of oil and natural gas. Our first CCS project has begun injection and we will continue to explore opportunities to enhance our leadership position in environmentally prudent operations.

These projects offer healthy returns while also providing reductions in long-life unit operating cost and lower emissions. EOG remains focused on running the business for the long term, generating high returns through disciplined growth, improving our resource base through organic exploration, improving our environmental footprint and investing in projects that will lower the future cost basis of the Company. I am excited about 2023 and the opportunity it brings for our employees to further improve the Company. Now here’s Ken to review year-end reserves and provide an inventory update.

Ken Boedeker: Thanks, Billy. Our 2022 proved reserve replacement was 244% for finding and development cost of just $5.13 per barrel of oil equivalent, excluding revisions due to commodity price changes. Our proved reserve base increased by 490 million barrels of oil equivalent and now totals over 4.2 billion barrels of oil equivalent. This represents a 13% increase in reserves year-over-year and was achieved organically. In 2022, we also reduced our finding and development costs by 8% compared to the previous year. In fact, over the past five years, we have reduced finding and development costs by nearly 40%. Our permanent shift to premium drilling, combined with our culture of continuous improvement focused on efficiencies driven by innovation, are why our corporate finding costs and DD&A rate continue to decline.

We continue to focus on maximizing the long-term value of our acreage. For example, last year, we continued co-development of up to four Wolfcamp targets. The pursuit of secondary targets with wells developed in packages alongside traditional development benches generally have minimal production impact on the primary zone, however, carry a favorable investment profile because they require no additional leasehold investment, are drilled and completed on existing pads and produced into existing facilities and gathering systems. The goal is to deliver low risk, high returns that maximize the cash return potential of our assets. Looking out beyond our current proved reserves, we’ve identified over 10 billion-barrel equivalents of future resource potential in our existing premium plays with an expected finding cost — finding and development costs less than our current DD&A rate.

When we invest in finding and development costs less than our DD&A rate, we drive the cost basis of the Company down. When we invested high returns, combined with a low finding and development cost, it shows up in the financials as increased return on capital employed. Thanks to the benefits of our decentralized structure and multi-basin organic exploration strategy, our resource base is growing faster than we do it. More importantly, it is getting better. We have over 10 years of double-premium drilling at the current pace, and we are focused on improving the quality of our resource every year through operational innovation, technical improvements and expiration. Now let me turn the call back to Ezra.

Ezra Yacob: Thanks, Ken. In conclusion, I’d like to note the following important takeaways. EOG Resources offers a unique value proposition. First, it begins with our multi-basin portfolio of high-return investment opportunities anchored by the industry’s most stringent investment hurdle rate or premium price deck. Second, our disciplined growth strategy optimizes investment to support continuous improvement across our portfolio. Our employees utilize technology and innovation to increase efficiencies and allow EOG to remain a low-cost operator. Third, we are focused on generating both near- and long-term free cash flow to fund a sustainably growing regular dividend, support our commitment to return additional free cash flow to shareholders and maintain a pristine balance sheet to provide optionality through the cycles.

Fourth, we are focused on safe operations and improving our environmental footprint across each of our assets, utilizing both existing and internally developed technologies. And finally, it’s the EOG employees that make it happen. Our culture is at the core of our value proposition and is our ultimate competitive advantage. Thanks for listening. Now we’ll go to Q&A.

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Q&A Session

Operator: Our first question today comes from Paul Cheng from Scotiabank. Your line is now open.

Paul Cheng: Two questions, please. First, Ezra, with Dorado, how is your investment program changed in many of the changing landscape in the natural gas price? I would imagine, at this point, there’s more economic to drill for the oil play than the gas play? How that changed your outlook for the next several years on that play? Second question is on the CapEx. Maybe that it seems like you are investing for the future. So what is the sustaining CapEx requirement to maintain a flat production at this point for your program? And also, if we’re looking at, say, for the remainder of this year, is there any area that you think we will start to see some softening in the cost and which may not be reflected in your current budget?

Ezra Yacob: Thank you, Paul. This is Ezra. Those are both great questions. So let me start with the first one here on natural gas and what’s it looking like right now. You’re correct, we’ve been watching the recent volatility in natural gas, late 2022 and currently associated with the LNG outages and the warm winter that we’re experiencing. Our gas growth this next year on the plan, you’ll see is about — at the midpoint is about 240 million cubic feet per day. About 50% of that is coming out of the — as you mentioned, the associated gas from the Delaware Basin and the other half of it is basically coming out of our Dorado play. Our strategy at Dorado, I’d say, hasn’t significantly changed yet. And at this point, we don’t really see that it would, barring anything dramatic.

And the reason for that is that Dorado always has been kind of a longer-term strategy for us. We’ve always focused on having moderate investment there to grow into the growing demand center along the Gulf Coast. It’s never really been about chasing seasonal demand or aggressively ramping up activities in that play. The U.S., just this year, will have about two Bcf a day of LNG export back online after the disruption’s clear. We’ve got an additional five Bcf a day coming online in kind of the ’24, ’25 time frame and then potentially another eight Bcf a day still working through financing. And we see this line of sight demand growth is also reflected with the strip price where you see currently, it’s moved into contango. So our long-term strategy at Dorado really remains the same.

It’s investment at a pace where the asset improves each year giving us an ability to drive down both upfront well costs and long-term operating costs, where we can consistently deliver the low cost of supply. This year, as Billy stated, we’ll be moving towards a one completion crew program to really capture those efficiencies at Dorado. The first part of your second question, I believe, is on sustaining CapEx. And what I’d say is the sustaining CapEx is a number that we don’t necessarily focus on here as an organic growth company. And the reason for that is, even during 2020, we didn’t maintain a maintenance capital type of program. We’re very dynamic, and we’ll grow and we see the ability to invest in our business and the market supports it.

And when we don’t need to, we can pull back at that time as well. So maintenance CapEx is not necessarily a number that we look at. Now as far as breakevens on our capital program this year, it definitely is up a little bit year-over-year. As Billy mentioned, there’s some inflation in there. But also, we’re obviously seeing the opportunity to invest in our multi-basin portfolio and increase the CapEx. So, our CapEx program this year is at $44 WTI price with a $3.25 gas price. And I’ll maybe hand it over to Billy to give a little bit of color on inflation and where we see it going this year.

Billy Helms: Yes, certainly. On the inflation front, I think it’s safe to say that everybody has seen commodity prices falling. We’ve seen inflation rates have peaked and come down. And so we’re seeing a lot of the service costs, at least, have plateaued going into this year. And so, as I mentioned on the call, we’ve got about 55% of our wealth costs secured through existing contracts with our event. And that leaves us the opportunity to capture any upside that we might see in lower rates going into the year. So we’re sitting in a fairly good position. I think we’re going to be poised and waiting to see what happens and take advantage of opportunities as they present themselves. But I think inflation, at least, is showing that we’ve plateaued. We baked in about a 10% inflation into our plan. And as we see opportunities, we’ll continue to look for ways to improve that.

Paul Cheng: Billy, do you see any particular area have the opportunity of softening?

Billy Helms: I think what we’ve seen is one of the biggest drivers this last year on inflation was certainly tubulars casing cost. And I think we’ve seen different things and different parts of that make up. I think the ERW products is mostly the surface and intermediate casings, those have rolled over and are softening a little bit more than the production casing, which is your seamless products, which are still largely exposed to imports. And so you’re seeing some opportunities on casing, but I think there’s still yet to come on most of that. On the service side, I think we haven’t really seen anything manifested yet, but I think we’ve all seen rig counts have largely been flat since September, and they’re down off their peak of — in November of probably 20 to 25 rigs.

And with the drop in gas prices, I think everybody is expecting maybe we’ll see some more softening on the rig activity level. So that may lead to some opportunities to capture some markets. The one advantage that we have, and I’ll go ahead and throw this out, we may expand on it later, but the benefit we have is operating in multiple basins. And so we see certainly more service tightness and labor constraints in areas with the most activity, which would be the Permian. But we have the opportunity to shift activity to our other basins to enable those to take advantage of more available equipment, more available capacity to add services at favorable rates. So that’s the advantage that we have as a company.

Operator: Our next question today comes from Arun Jayaram from JPMorgan. Your line is now open.

Arun Jayaram: Ezra, you have a net cash, a balance sheet and if we run through, call it, the $80 case, 55 — or $5.5 billion in free cash, if you return 60% of that, you’re looking at a balance sheet that would be, call it, $3 billion of net cash at year-end. So I wanted to get your views on uses of that cash that you have on the balance sheet and where your heads at in terms of thoughts of increasing cash return to shareholders versus looking at inorganic opportunities, including bolt-ons or M&A? And how do you prioritize some of those opportunities as we think about 2023?

Ezra Yacob: It’s Ezra. That’s a great question. I love talking about our balance sheet and the strength of it. It’s something we take a lot of pride in. And the reason for that is because it gives us a lot of optionality at different times, whether it’s to look at — in 2020, we purchased — strategically purchased a lot of casing. In 2021, we were able to purchase a decent amount of line pipe. And just last year, we were able to make a small acquisition in the Utica play, including purchasing some minerals there. So we’re still not looking for any large, expensive, corporate M&As. We do continue to seek out opportunities where it makes sense to do bolt-ons, things that would be accretive, things that could move right into our existing infrastructure and extend some of our lateral lengths.

In general, for our net cash position, I would say we don’t have a specific target. We do like to have the optionality. The one thing you didn’t mention is that we will be retiring a bond here in this first quarter at $1.2 billion. And then, in addition to that, I’d point out that last year, we did move beyond our minimum commitment of that 60% return of free cash flow to our shareholders. Last year, we returned approximately 67%. And so I think you can see — you can take that as a data point that when appropriate and at the right time and obviously, it’s evaluated at the Board level, depending on where we’re at within the cycle, where we’re at within the year and what our cash position looks like, we have proved that we’re willing to move above and beyond the 60% minimum threshold.

Arun Jayaram: Great. My follow-up is Ezra, just given the size of the Company, you’re approaching 1 million Boes per day in terms of overall output, and most of your activity is short cycle oriented. And I wanted to get your thoughts on exploring longer cycle opportunities. You’ve seen some of your peers invest in areas such as Alaska and LNG. And I wanted to get your thoughts on EOG looking at the long cycle and perhaps an update on where we stand for — to drill Beehive in Australia?

Ezra Yacob: Yes, Arun, we can start — yes, maybe with some of our longer cycle stuff. We can start with Trinidad. As Billy mentioned, there has been a bit of a rig delay on our Trinidad drilling program. So that will start about midyear this year. We did set a platform there based — this past year based on one of the discoveries that we made in 2020. We should start construction on another platform there named Momento later this year, also based on some of the work that we did in that drilling campaign that ended in 2020. So that’s on the Trinidad side. In Beehive in Australia, it’s our prospect on the Northwest shelf. That prospect has actually slid a little bit. It’s now time to be spud in 2024. And then with some of the other projects that you had mentioned, as you can see, and it goes in line with what we were just talking about with the ability of our balance sheet to be strategic and opportunistic.

And typically, we do these things counter-cyclically like our agreement on the LNG side, or the ability to put in some infrastructure like we are currently in Dorado to go ahead and lower our operating costs and expand our margins. Those are the type of opportunities that we really look for, things that are in concert with our core business, which is drilling and developing premium oil and natural gas wells.

Operator: Our next question today comes from Doug Leggate from Bank of America. Your line is now open.