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.

Doug Leggate: So Tim, I don’t know if this one’s for you or for Ezra, but your comments about being able to offset some of the inflation have been a fairly consistent part of your message over the last year. So, I think folks were a little surprised by the CapEx number. So I wonder if you could walk us through the moving parts of whether it be activity led or more specifically, infrastructure related to some of the newer places? There are disproportionate amount of takeaway spending has maybe lifting the CapEx issue. I’m just curious on the breakdown.

Billy Helms: Yes, Doug, this is Billy Helms. Let me take a stab at that. So first, there’s probably three buckets you can probably put the increase in. First of all, is inflation in our well cost. That’s probably a good piece of it, 1/3 of it. It’s about — we’re anticipating about a 10% well cost inflation in our program versus last year. And yes, that’s maybe 10% over and above last year. But still last year, we achieved only a 7% well cost increase in spite of probably, arguably, 15% or 20% inflation. So I think our teams have done a great job on offsetting inflation with efficiency gains. We’re expecting more of that this year, but we’ve baked in about a 10% cost increase. The second part of that is going to be infrastructure.

We’ve talked about already our Dorado gas pipeline. That’s been initiated. And we’re also building out some infrastructure in some of our emerging plays, like the Utica to start the testing of those plays. And then we’ve also included some capital for our ESG projects that we’re advancing. So those are kind of the buckets that we look at. And then obviously, we have some additional wells on top of that in these various plays. So as we pick up the two additional rigs and one extra frac fleet, of course, that’s going to accompany some additional well count. So those are the three main buckets that I would characterize the increase in the capital versus last year.

Doug Leggate: Okay. I appreciate the color, Billy. Thanks for picking that one up. My follow-up is probably for Ezra. And Ezra, forgive me for this one, but I want to take you back to pre-COVID when EOG was growing quickly and frankly, a market didn’t need the oil. But you could make the case that today. We’ve got a market that doesn’t need the gas. And I understand your point about maybe trying to take markets, some others are cutting back. But the fact is we still have a largely stranded market in the U.S. Why is this the right time to accelerate your gas production given what is a potentially very constructive outlook longer term?

Ezra Yacob: Yes, Doug, that’s a good question. Yes, I think the difference is between 2019 or pre-COVID with the oil versus what we’re doing in Dorado right now. So like I said, the Dorado volumes are anticipated to support. It’s basically the output of a single completion spread program this year. And the benefits that we see of running a consistent program there to learn about this asset, continue to drive down costs, support putting in some infrastructure, things like water takeaway and in-basin gathering, that outweighs the near-term volatility in the gas price because what we see is in a very not-too-distant future, we see a pretty dramatic increase in the offtake and the demand coming on along the Gulf Coast. Now we are backstopped and supported, obviously, with investing on the return side in these premium wells.

So we measure the investment on here at a $2.50 natural gas price. And while at today’s prices, that’s below, we run that $2.50 all the way through the life of the asset. The rest of the gas that we’re growing this year is, honestly, as we — as I said at the top of the Q&A is really associated gas coming out of the Delaware Basin, where the returns there are dominantly driven obviously on the oil and liquids side. And we’re really running a maintenance program or a flat activity level program to Q4 across the Delaware Basin.

Operator: Our next question today comes from Leo Mariani from MKM Partners. Your line is now open.

Leo Mariani: I was hoping you could update us a little bit on maybe some new well results, if there are any from some of the emerging plays. Most interested in hearing about any recent Utica well performance or any Utica wells that may have come on? And then similar, just in the PRB, did get a sense if you’ve seen improving wells there as well. You’ve talked a lot about cutting costs in PRB, but just curious as to whether or not some of those wells have seen improvements as you guys have gotten more experience?

Ken Boedeker: Yes, Leo, this is Ken. I’ll take the Utica portion of that. The four wells we drilled and completed in ’22, really continue to deliver our expected performance. And just to give you a flavor on that, we anticipate starting our drilling program for ’23 at the end of the first quarter here. One other thing, I would note in the Utica, not on the well side, but on the acreage side is we have added about 10,000 acres of low-cost acreage store position, and we’ll continue to look for additional opportunities to add to that position. So we’re really excited about the Utica plan for 2023. I’m going to go ahead and give it over to Jeff now for the Powder.

Jeff Leitzell: Yes, Leo, this is Jeff. Yes, just a quick update. In 2022, we continue to delineate our acreage there in the Southern Powder River Basin. We completed about 31 net wells across the four primary targets. And all of those, we had excellent results. And we’ve been shifting our primary focus there, as we’ve talked about previously to the Mowry. So in 2023, we’re going to ramp up the activity a little bit there. We’re going to run kind of a consistent two- to three-rig program with one frac fleet. So that will be about 55 net wells. And the majority of those, as we talked about, will be in the Mowry. It’s about a 75% increase year-over-year there in the Mowry. And then we’ll continue to focus on optimizing that Mowry program there in our Southern Powder River Basin core area.

We’ll collect a lot of valuable data, and then we’ll look to utilize it in the future on our overlying Niobrara formation and then the North Powder River Basin position that we announced earlier on.

Leo Mariani: Okay. That’s helpful. And then just wanted to jump over to the Eagle Ford. If I look at the Eagle Ford, production has kind of been steadily dropping in the last few years. You guys have picked up activity pretty significantly in ’23. It looks like roughly 50% more net completions this year versus last. In your prepared comments, you signaled basically trying to kind of keep Eagle Ford flattish for a number of years sort of going forward. Just wanted to get any additional color around that? Eagle Ford had kind of been in decline in favor of other plays, primarily Delaware. And now the plan is to kind of flatten it out. Are you kind of seeing new things there in terms of well productivity or lower costs that have got more encouraged about the play? Just wanted to get a sense because it seems like maybe it’s risen slightly in the pecking order here.

Ezra Yacob: Yes, Leo, this is Ezra. That’s a great pickup. It’s a good question because that’s exactly what’s happened is that it is raising up with respect to the returns and the way they compete for capital. Over the last couple of years, kind of coming out of the pandemic, we’ve reduced our — there. And the result of that, we’ve been trying to right-size the investment. The result has been really back to back years of the highest drilling — rate of return drilling programs that we’ve seen in the history of developing that asset. As everybody knows, it’s a very high-margin oil play where we’ve got a lot of infrastructure and a tremendous amount of industry knowledge there. Simply, the asset now is commanding a lot more capital investment this year.

We are looking to invest to maintain flat production, as you said. The production has decreased a bit over the last couple of years. And one advantage that we are seeing in the Eagle Ford, and Billy touched on this, and maybe I’ll let him add a little more color on it, is really how the inflation and service availability has manifested itself across these different basins and why the Eagle Ford’s a bit more attractive.

Billy Helms: Sure. As I mentioned earlier in some of the questions, obviously, you see more levels of inflation and more constraints on services in certain fields versus the other, the Permian being the most active play. Certainly, there’s a more constraints there on services and labor and those kind of things. So it allows us the opportunity to pick up activity in basins that are seeing less stress, you might say, and Eagle Ford certainly being one of those. On top of that, our team there in Eagle Ford has done just a tremendous job continuing to push innovation and striving for efficiencies such that we continue to make better and better returns in that play with time. And we’ve kind of reached a point, as Ezra mentioned there, that we want to maintain the constant level of production going forward in that play because we do see more than a decade of running room of continuing to maintain that production level with the opportunities we have in front of us.

So we think it’s just a good level of production to maintain going forward.

Operator: Our next question today comes from Neal Dingmann from Truist. Your line is now open.

Neal Dingmann: My first question is on your play detail, specifically, was looking at some other side. I see a couple of years ago, you all suggested you had approximately about 11,000 premium undrilled locations with about, I think, it was nearly 55% of these in the Delaware. Of that Del, about 40% of these will be in Wolfcamp plays. I’m just wondering if that really, number one, total premium locations is still — I forget what the last number you threw around the premium locations? And wonder if you’d still consider the majority of these in the Wolfcamp portion of the Del?

Ken Boedeker: Yes, Neal, this is Ken. I’ll take a shot at that. We — what we talked about earlier, and the way we really look at it, is we have 10 years of double-premium inventory at our current activity level. So locations really aren’t a concern for us. What we’re really trying to talk about and show is the value proposition of our 10-plus billion Boe resource base that has a finding cost less than our current DD&A rate. Investing in this inventory will use to DD&A and improve earnings and return on capital employed. Our well counts are really constantly changing as our development plans evolve, acreages swapped and laterals are extended. And all those changes improve our finding costs and returns and modify our location count. So what we’re really focused on now is lowering our cost basis as we invest at high returns.

Neal Dingmann: No, that makes sense. Then maybe Ken just follow up on that. I guess my follow-up is on play details, maybe specifically the Bakken. You all suggested, I think even a couple of years ago, it wasn’t a ton of locations, as you said, maybe I don’t know if you’d consider a ton of value there. So I’m just wondering how many — how you’d kind of look at that play today? And would you all consider — you certainly don’t need it financially, but would you consider monetizing it given it appears to be one of your more mature areas?

Ken Boedeker: Sure, Neal. The Bakken creates significant returns, and it is one of our highest percentage plays that we have in the Company. So where it’s appropriate and when it’s appropriate for development, which is we’re going to be putting some money into it this year, we’ll try to run about a one-rig program there the foreseeable future.

Operator: Our next question comes from Scott Gruber from Citigroup. Your line is now open.

Scott Gruber: So I saw in your supplemental debt that you mentioned that continuous pumping operations are helping to drive completion efficiency in the Delaware. I believe that’s one of the benefits you’re seeing for running your frac fleet. Is that accurate? And just a bit more detail on how continuous fracking is having completion efficiency above and beyond doing zippers?

Billy Helms: Yes, Scott, this is Billy. Yes, we’re thrilled with the — our efficiencies driven through our completion teams. The continuous pumping operation, you’re right, is tied to mostly our electric frac fleets. Just a reminder, we’ve — we’re probably running 60% or 70% of our frac fleets today are electric. And we’ve been in that business really since about 2015. So, we’ve been operating more electric frac fleets probably than most of our peers or most of the industry for a long period of time. And through that, we’ve gained a tremendous amount of knowledge of how to continue to drive efficiencies in that operation. It really has started more in our San Antonio group in the Eagle Ford play, and that’s why we’re so excited about continuing our investment there.

And certainly, we’re transferring that information and that those techniques across the Company, including the Delaware Basin. But basically, the continuous pumping operation allows us to minimize any amount of downtime, so we can increase the amount of footage we complete every day, which drives the well cost down over time and allows us to approach some really highly efficient completion strategies. And so, part of that is also leading to improved completion designs, which is allowing us to make better well performance. So overall, it’s just one thing that builds on another, and we’re excited about the future and where that takes us.

Scott Gruber: Got it. And then you also mentioned taking advantage of any softening in — frac rates if they do manifest this year. How is your contract coverage for both currently following the period of tightness? Would you be able to capture any deflation before year-end? Or would that really benefit more at ’24 just given contract coverage?

Billy Helms: Our contracts are really staggered, and they don’t all roll off at any one given time. Certainly, our well cost is up this year as I mentioned earlier, because some of those contracts have rolled off last year and renewed on those higher day rates and pumping charges this year. But in general, we have about 45% of our drilling rigs secured under term agreements and about 65% of our frac fleets. So that leaves us ample opportunity to capture opportunities if they do present themselves as time moves on.

Operator: Our next question comes from Jeanine Wai from Barclays. Please go ahead.

Jeanine Wai: My first question, maybe following up on Leo’s question, on the Eagle Ford. In terms of the step-up in activity in the Eagle Ford this year, can you talk about how capital efficiency compared between the overall Delaware and South Texas Eagle Ford? I guess when you pull the well data, the difference in the well performance looks like the Eagle Ford is about 30% lower on a cumulative oil per foot basis over the past couple of years, but that’s only one side of the equation, and we realize that. And I think your 3Q disclosure indicated that the Eagle Ford well cost is almost 30% lower on a per foot basis than in the Delaware. So I guess just putting it all together for us, can you just provide some color on how capital efficiency and returns compare between the Eagle Ford and the Delaware?

Billy Helms: Yes. Jeanine, this is Billy. Happy to give you some color on that. The Delaware Basin is certainly one of our most capital-efficient plays, quickly followed by the Eagle Ford. The advantage we have in the Eagle Ford is, as I mentioned earlier, the tremendous efficiencies that have been driven in that play. You’re right the cum per foot is probably a little bit lower in the Eagle Ford but the well cost is also significantly less. And so we can put a lot more wells to sales in a lot shorter time frame than we can in the Delaware Basin. And then going back to that also, we didn’t really feel that we wanted to ramp up activity anymore in the Delaware Basin, but instead leverage on our multi-basin portfolio to increase activity in areas where equipment and crews are more available to leverage into our operation.

And so that’s what we’ve chosen to do. But I think the Eagle Ford is still one of our most capital-efficient plays we have in the Company, and we’re excited about that opportunity to keep sustaining volume going forward.

Jeanine Wai: Okay. Great. Maybe moving to base declines. Can you provide an update on your current base declines given the 3% oil and the 9% Boe growth this year? Do you anticipate that your oil and corporate declines will remain flat or at least — or maybe even decrease this year?

Billy Helms: Yes, Jeanine, this is Billy again. The base declines have been fairly consistent, I would say, year-to-year. And we don’t see a measurable change really in our base declines going forward. I think last year was a pretty good year as compared to this year, and I expect the declines would be similar.

Operator: Our next question comes from Derrick Whitfield from Stifel. Your line is now open.

Derrick Whitfield: With my first question, I’d like to lean into the new completion design you’ve implemented in Delaware that achieved an 18% AUR uplift. Could you perhaps elaborate on the nature of the enhancement and if it would to be across and outside of the basin?

Billy Helms: Yes, Derrick, this is Billy Helms again. On the new completion design, certainly, we’re always experimenting with new ideas and trying to innovate as to ways we can improve well performance over time. And we’re excited about some of the new advancements and techniques we’re experimenting with the Delaware Basin. And to be honest, that’s just more color on why we like to get to a consistent program and where we can innovate and experiment and make these improvements. So I’m not going to go into detail about what this new completion design looks like. But certainly, as we continue to advance it, we will translate it to — import that technology to other basins, and we’re already doing so. We were excited about the 18% uplift we’ve seen, but it’s only been done on 26 wells so far in the Delaware Basin.

So you can see it’s still early on. The amount of the improvement is tremendous though, and we fully expect to be able to transfer that knowledge to other plays.

Derrick Whitfield: Perfect. And as my follow-up, perhaps shifting over to the Eagle Ford. We noticed the legacy wet gas position was seemingly reengaged in your supplement update. If I recall, that initial position was in the order of 26,000 acres. Could you perhaps comment on what has brought it back to life and the amount of activity you’re expecting over the next couple of years?

Ken Boedeker: Yes, Derrick, this is Ken. Yes. Really, what’s brought back to life is our people in our San Antonio division, have reviewed it and realized that they could invest at high returns in that area. So we’ve actually looked at three different zones within that area and drilled three wells last year that had significant returns, and we’ll see additional activity this year. I don’t know that we’ve given an exact well count, but it will definitely be stepped up. And really, it’s just a matter of having legacy acreage and our people understanding where we think we can make those kind of returns.

Operator: Our next question comes from Charles Meade from Johnson Rice. Your line is now open.

Charles Meade: I want to follow up on Derrick’s question, which was a great question. I’d just like to push a little bit further on that Delaware Basin completion design. I understand you don’t want to talk about what it is. But as I mentioned, some of the possibilities, I’m curious, is this something that you apply to whatever your maybe fringier intervals that’s something that’s bringing that — bringing kind of a lesser interval up to the — your double-premium threshold? Or alternatively, is this something that you’re doing already on — or is this a new design kind of a meat and potatoes interval that could maybe herald a broader shift hire in your whole Delaware Basin capital efficiency?

Billy Helms: Yes. Charles, this is Billy Helms. Yes. The new design is — really starts with an understanding of the rock we’re applying it to. I think we’ve talked in the past about how all of our designs are tailor made to every wellbore and whatever the geology is telling us is the right application for that. So is it something that we could apply to all zones? I would say probably not, but it’s certainly more attractive than other zones. But it is also being done in the core of the play. It’s not just applying to the fringe intervals or the fringe of the plays, but some of our core plays or target intervals and we’re seeing dramatic improvements. Now it’s going to be — continue to be tailored based on what the geology tells us is the right application, and we’ll tweak it and be able to transfer that knowledge as we see it develop.

Charles Meade: That’s helpful color. And for my follow-up, and I recognize this is a simplification for a company like you guys and your number of rigs and the number of plays. But overall, you indicated that you’re going to increase your — you’re going to add three new rig lines in ’23. Can you give us a sense where you are in that process? Or when we should expect those in aggregate, the rig count to tick up over the course of ’23?

Billy Helms: Sure, Charles. The rigs are pretty much in operation today. We started kind of picking up rigs at the end of the fourth quarter going into this year. And as we mentioned, the fourth quarter run rates in the Delaware Basin and the Eagle Ford will be pretty consistent throughout the year. And so, we’ve also started drilling in some of the other plays, some of the new emerging plays, such as the Powder River Basin and Dorado. So those are kind of ongoing. We’ll be picking up rigs at different times and some of the other plays, like the Bakken or the DJ or the Utica. And those will kind of come and go. Those aren’t going to be really, yet full rig lines. They’ll kind of ebb and flow based on the timing of each individual play. But the base program is pretty much going to be set, and I’d say the rig count is not going to fluctuate much beyond where it is today.

Operator: There are no further questions at this time. I will now hand back over to Mr. Yacob for closing remarks.

Ezra Yacob: I’d just like to thank everyone for participating in the call this morning and especially thank our employees for the outstanding results delivered in 2022. Thank you.

Operator: That concludes today’s EOG Resources Fourth Quarter and Full Year 2022 results. You may now disconnect your lines.