EOG Resources, Inc.

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 in our forward-looking statements have been outlined in the earnings release and outlined in EOG's release. This conference call also contains certain non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures can be found on EOG's website. Some of the reserve estimates on this conference call may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Jacob, Chairman and CEO, Billy Helms, President and Chief Operating Officer, Ken Baedeker, EVP Exploration and Production, Jeff Leitzel, EVP Exploration and Production, Lance Turveen, Senior VP Marketing, and David Streit, VP Investor Relations. Here's Ezra.

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 Dorado and Southern Powder River Basin. We 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 and expanded deployment of our new continuous methane leak detection system called iSense. Led by the tremendous performance in our Delaware Basin and Eagleford 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 operate 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 the OG 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. Discipline 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 return 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.

Thanks, Ezra. When we established our premium strategy back in 2016, our goal was 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 costs 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 82.5 cents 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.

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 remains 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 of $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 sustained sufficient activities to support continued experimentation and innovation. In the Delaware Basin, we expanded the use of our super zipper completion technique to increase treated lateral feet per day by 24 percent. In our Eagleford play, the completions team increased completed lateral feet per day by 14 percent and the amount of sand pumped per day per fleet by 27 percent. Our decentralized operations team 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 Maori 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 that 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 percent uplift in 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 planning, 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 frack 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 Mallory completions. We expect to complete a few additional wells in our emerging Utica play in Ohio as we continue to delineate our acres 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 frag 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 cost 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 baseline 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 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 percent of the CapEx budget, and this year we expect that number to be closer to 20 percent. In Dorado, we commenced construction late last year on a new 36-inch gas pipeline from the field to the Aqua Dulce sales point near Corpus Christi, Texas. This pipeline will help ensure 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 costs. Fourth, 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 costs 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.

Thanks, Billy. Our 2022 approved reserve replacement was 244% for a finding and development cost of just $5.13 per barrel of oil equivalent, excluding revisions due to commodity price changes. Our approved 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 Wolf Camp 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 paths, 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 and development cost less than our current DD&A rate. When we invest at a finding and development cost less than our DD&A rate, we drive the cost basis of the company down. When we invest at 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 drill 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 exploration. Now, let me turn the call back to Ezra.

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, our 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. 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.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touchtone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up. We will take as many questions as time permits. Once again, please press star 1 on your touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the pound key We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question today comes from Paul Cheng from Scotiabank. Your line is now open.

Thank you. Good morning, everyone. Two questions, please. First, with Dorado. How has your investment program changed in light of the changing landscape in the natural gas price? I would imagine at this point it's more economic to drill for the oily plate than the gas plate. How does that change your outlook for the next several years on that plate? Second question is on the capped eggs. Maybe it seems like you are investing for the future. Yes, the sustaining CapEx requirement to maintain a track production at this point for your program. And also, if we're looking at, say, for the remaining of this year, is there any area that you think we will start to see some stop coming in the course and which may not be reflected in your current budget? Thank you.

Thank you, Paul. This is Ezra. Good morning. Those are both great questions. Let me start with the first one here on natural gas and what they're 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's coming out of the, as you mentioned, the associated gas from the Delaware Basin. And the other half of it's basically coming out of our Dorado play. You know, 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. You know, the U.S., just this year, we'll have about two BCF a day of LNG export back online after the disruption is clear. We've got an additional five BCF a day coming online in kind of the 24-25 timeframe, and then potentially another eight BCF a day still working through financing. And, you know, we see this line of sight demand growth is also reflected with 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. given 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, you know, 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, you know, what I'd say is the sustaining CapEx is a number that we don't necessarily focus on here as an organic, you know, 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 when 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 break evens 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 a $44 WTI price with a $325 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.

Yeah, certainly. On the inflation front, I think it's safe to say that everybody's seen – you know, 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, you know, as I mentioned on the call, we've got about 55% of our wealth costs secured through existing contracts with our vendors. 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've baked in about a 10% inflation into our plan. And as we see opportunities, we'll continue to look for ways to improve that.

Hey, Billy, do you see any particular area have the opportunity of softening?

You know, I think what we've seen is one of the biggest drivers this last year on inflation was certainly tubulars casing costs, and I think we've seen different things and different parts of that make up. I think the ERW products, which are 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's 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 and 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.

Our next question today comes from Arun Jayaram from JP Morgan. Your line is now open.

Yeah, good morning. You know, Ezra, you have a net cash balance sheet, and if we run through, call it the $80 case, you know, $55 or $5.5 billion in free cash, if you return, you know, 60% of that, you know, you're looking at a balance sheet that would be call it $3 billion in 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 head's 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?

Yes, good morning, Arun. It's Ezra. That's a great question. I love talking about our balance sheet and the strength of it, something that 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, you know, in 2020, we 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 he 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.

Great. My follow-up is, Ezra, just given the size of the company, you're approaching a 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. I'm seeing some of your peers invest in areas such as Alaska and LNG. I wanted to get your thoughts on EOG, looking at the long cycle, and perhaps an update on where we stand to drill beehive in Australia.

Yes, Arun. We can start 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 mid-year this year. We did set a platform. uh, there based, uh, this past year based on the, the, one of the discoveries that we made in, in 2020. We should start construction on another platform there named Mento, uh, later this year, also based on, uh, some of the work that we did in that drilling campaign that ended in, in 2020. Uh, so that's on the Trinidad side. In Beehive in Australia, it's our prospect on the Northwest shelf. That prospect is, has actually slid a little bit. Uh, it's now time to be spud in, uh, 2024. And then with some of the other projects that you had mentioned, you know, 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 countercyclically, 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.

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

Thanks. Good morning, everybody. 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 issues have been a fairly consistent part of your messaging over the last year. So I think folks were maybe a little surprised by the CapEx number. So I wonder if you could walk us through the moving parts, whether it be activity-led or more specifically infrastructure related to some of the newer plays. Is there a disproportionate amount of takeaway spending that's maybe lifting the CapEx issue? I'm just curious on the breakdown. Thank you.

Yeah, 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, a third of it. 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 backed 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. We've also included some capital for our ESG projects that we're advancing. Those are the buckets that we look at. Obviously, we have some additional wells on top of that in these various plays. As we pick up the two additional rigs and one extra frack lead, 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.

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 going quickly and, frankly, a market that didn't need the oil. Well, 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 from others that 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?

Yes, Doug, that's a good question. Yeah, I think the difference is between, you know, 2019 or pre-COVID with the oil versus what we're doing in Drada right now. Like I said, you know, the Drada 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 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 liquid side. And we're really running a maintenance program or a flat activity level program to Q4 across the Delaware Basin.

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

Hi. 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, you know, similar just in the PRB, just trying to get a sense of 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.

Yeah, 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 to our 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 powders.

Yeah, Leo, this is Jeff. Yeah, just a quick update. In 2022, you know, we continued to delineate our acreage there in the southern Powder River Basin. We completed about 31 net wells across four primary targets. You know, in all of those, we had excellent results. And we've been shifting our primary focus there, as we've talked about previously, to the Maori. 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 frack fleet. So that will be about 55 net wells, and the majority of those, as we talked about, will be in the Maori. It's about a 75% increase year over year there in the Maori. And then we'll continue to focus on optimizing that Maori 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 Niagara formation and then the north Powder River Basin position that we announced earlier on.

Okay, that's helpful. And I just wanted to jump over to the Eagle Ford. If I look at the Eagle Ford, you know, production's kind of been steadily dropping, you know, the last few years. You guys have picked up activity pretty significantly in 23. Looks like roughly 50% more net completions this year, you know, versus last. In your prepared comments, you signaled basically trying to kind of keep Eagle Ford flattish, you know, for a number of years, you know, 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 you 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.

Yes, Leo, this is Ezra. That's a great pickup. It's a good question because that's exactly what's happening is that it is raising up with respect to the returns and the way that it competes for capital. Over the last couple of years, kind of coming out of the pandemic, we've reduced our investment there. And the result of that, we've been trying to right-size the investment. And the result has been really back-to-back years of the highest 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 Eagleford, 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 Eagleford's a bit more attractive.

Sure. As I mentioned earlier in some of the questions, you know, obviously you see more levels of inflation and more constraints on services in certain fields versus the other, the Permian being the most active place. 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 the 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 a 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.

Our next question today comes from Neil Dingman from Truist. Your line is now open.

Morning, Ezra. Thanks for the time. My first question is on your play details. Specifically, I was looking at some older slides, and I see a couple years ago you all suggested you had approximately about 11,500 premium on drill locations with about, I think it was nearly 55% of these in the Delaware, and of that Dell, about 40% of these Dell being Wolf Camp 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 Wolf Camp portion of the Dell.

Yeah, Neil, this is Ken. I'll take a shot at that. You know, 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, The 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. You know, investing in this inventory will reduce DD&A and improve earnings and return on capital employed. Our well accounts are really constantly changing as our development plans evolved. 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.

No, that makes sense. And maybe, Ken, just follow up on that. I guess my follow-up is on play details, maybe specifically the Bakken. You all suggested, you know, I think even a couple of years ago, there 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 you know would you all consider i mean you certainly don't need it financially but would you consider monetizing to give it appears to be one of your more mature areas sure neil um you know the bach can create significant returns and it is one of our our highest oil percentage plays that we have in the company so

You know, 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 for the foreseeable future.

Thank you.

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

Yes, good morning. So I saw in your supplemental deck 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 from running your e-frac police. Is that accurate? And just a bit more detail on how continuous fracking is aiding completion efficiency above and beyond doing zippers.

Yeah, Scott, this is Billy. Yeah, we're thrilled with the advances in our efficiencies driven through our completion teams. The continuous pumping operation, you're right, is tied to mostly our electric frack fleets. Just a reminder, we're probably running 60 or 70 percent of our frack fleets today are electric, and we've been in that business really since about 2015, so we've been operating more electric frack 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 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.

Got it. And then you also mentioned taking advantage of, you know, any softening of rig and frack rates if they do manifest this year. How's your contract coverage for both currently following a period of tightness? You know, would you be able to capture any deflation before year-end, or would that really – benefit in more than 24 just given contract coverage?

You know, 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 were renewed on the 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 frack fleets. So that leaves us ample opportunity to capture opportunities if they do present themselves as time moves on.

Our next question comes from Janine Way from Barclays. Please go ahead.

Hi, good morning, everyone. Thanks for taking our questions. Our first question, let's see, maybe following up on Leo's question on the Eagleford, in terms of the step-up in activity in the Eagleford this year, can you talk about how capital efficiency compares between the overall Delaware and South Texas Eagleford? I guess when you pull the well data, the difference in the well performance looks like the Eagleford is about 30% lower in 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. I think your 3Q disclosure indicated that the Eagleford well cost is almost 30% lower on a per foot basis than in the Delaware. I guess just putting it all together for us, can you just provide some color on how capital efficiency and returns compare between the Eagleford and the Delaware?

Yeah, Janine, 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 Eagleford. The advantage we have in the Eagleford is, as I mentioned earlier, the tremendous efficiencies that have been driven in that play. You're right, the cume per foot is probably a little bit lower in the Eagleford, but the well cost is also significantly less. And so we can put a lot more wells to sales in a lot shorter timeframe than we can in the Delaware Basin. And 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 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 that Eagleford is still one of our most capital efficient plays we have in the company. And we're excited about that opportunity to keep a sustaining volume going forward.

OK, great. Thank you for that detail. Maybe moving to base declines. Can you provide an update on your current base declines? Given the 3% oil and the 9% VOE growth this year, do you anticipate that your oil and corporate declines will remain flat or maybe even decrease this year? Thank you.

Yeah, Janine. 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.

uh last year was a pretty good year as compared to this year and i expect the declines would be similar great thank you our next question comes from derek whitfield from stifle your line is now open john good morning all and thanks for taking my questions with my uh first question i'd like to lean into the new completion design you've implemented in the delaware that achieved an 18% EUR uplift. Could you perhaps elaborate on the nature of the enhancement and its applicability across and outside of the basin?

Yeah, Derek, 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. We're excited about some of the new advancements and techniques we're experimenting with in the Delaware Basin. And to be honest, that's just more color on why we like to get to a consistent program 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 percent 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 places.

Terrific. And as my follow-up, perhaps shifting over to the Eagleford, 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?

Yeah, Derek, this is Ken. Yeah, really what's brought it back to life is our people in our San Antonio division have reviewed it, and realized that they could invest in high returns in that area. So we've actually looked at three differing 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.

That's great. Thank you.

Our next question comes from Charles Mead from Johnson Rice. Your line is now open.

Good morning, Ezra and Billy and the rest of the EOG team there. I want to follow up on Derek's question, which I thought was a great question. I'd just like to push a little bit further on that. on that Delaware Basin completion design. I understand you don't want to talk about what it is, but as I imagine some of the possibilities, I'm curious, is this something that you applied to one of your maybe fringier intervals, that's something that's bringing a lesser interval up to your double premium threshold, or Well, alternatively, is this something that you're doing already, or is this a new design on kind of a meat and potatoes interval that could maybe, you know, herald a broader shift higher in your whole Delaware Basin capital efficiency?

Yeah, Charles, this is Billy Helms. Yeah, the new design really starts with a – 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 in 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, core target intervals, and we're seeing dramatic improvements. Now, it's going to continue to be tailored based on what the geologist tells us is the right application, and we'll tweak it and be able to transfer that knowledge as we see it develop.

That's helpful, Koba. Thank you, Billy. And for my follow-up, and I recognize this is a simplification with for a company like you guys and your number of rigs and number of plays, but overall, you indicated that you're gonna increase your, you're gonna add three new rig lines in 23. Can you give us a sense of where you are in that process or when we should expect those, in aggregate, the rig counts to pick up over the course of 23?

Sure, Charles. The rigs are, are pretty much in operation today. You know, we started kind of picking up rigs at the end of the fourth quarter going into this year. And as we mentioned, you know, the fourth quarter run rates in the Delaware Basin and the Eagleford 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 in 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.

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

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.