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.

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.

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 by 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 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 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.

Thank you, Tim. I want to start by expressing my gratitude to all our employees for their achievements and performance last year. 2022 posed many challenges, but our employees’ unwavering commitment and dedication led to impressive results. The year was marked by increased inflation and rising commodity prices, resulting in a tighter market for services, labor, and supplies. We managed to mitigate most of the inflation impacts through efficiency improvements and careful capital management, limiting well cost increases to 7%. Overall, our oil production exceeded the midpoint of our guidance, and capital expenditures totaled $4.6 billion, slightly above the original guidance midpoint by 2%. Our operational teams across the Company effectively utilized efficiencies to offset inflation, especially in our core development areas, which maintained sufficient activity levels to foster ongoing experimentation and innovation. In the Delaware Basin, we were able to enhance our Super Zipper completion technique, raising treated lateral feet per day by 24%. In our Eagle Ford play, the completions team improved completed lateral feet per day by 14% and the sand pumped per fleet by 27%. Our decentralized operations teams consistently strive to enhance performance and disseminate knowledge across our portfolio to limit well cost increases. These insights are applied in our emerging opportunities. For example, in the Southern Powder River Basin Mowry play, the drilling team shortened drilling time by 10% through better bid and drilling motor performance. In our South Texas Dorado gas play, drilling time was reduced by 12%. With ongoing technical and operational advancements, we expect to continue driving improvements in 2023. Additionally, a new completion design introduced last year in the Delaware Basin has shown positive enhancements in well performance across specific target reservoirs. This design was tested in 26 wells last year and has the potential to yield an 18% uplift in estimated ultimate recovery. We are also making significant strides toward our long-term ESG objectives, achieving a wellhead gas capture rate exceeding 99.9% of the gross gas produced, and early results suggest reductions in GHG intensity and methane emissions in 2022. Around 95% of our Delaware Basin production is now monitored by iSense, our continuous methane monitoring technology. Looking ahead to 2023, we anticipate a $6 billion capital program aimed at achieving 3% oil volume growth and 9% total production growth. We expect total volumes on a Boe basis to increase each quarter this year. The first quarter will show more gas growth compared to oil due to the well mix and the timing of several Dorado gas wells that were completed late last year. Our plan can be summarized in four key points. First, we expect drilling rig and frac fleet activity in our core development programs, particularly in the Delaware Basin and the Eagle Ford, to remain steady compared to the fourth quarter of last year. The Eagle Ford has become a highly efficient, high-margin area with existing infrastructure, enabling over a decade of opportunities for high returns and cash flow. In the Powder River Basin, we will build on last year’s positive well results and infrastructure installations, planning for an additional 20 Mowry completions. We also plan to complete more wells in our emerging Utica play in Ohio while continuing to drill in the Bakken and DJ Basins. In Dorado, we aim to reach an activity level that fosters economies of scale and supports a continuous program for innovation that improves well performance and reduces costs, resulting in about 10 additional well completions compared to last year. A drilling rig is expected to arrive in Trinidad in the third quarter, which has been delayed by about six months, reducing our international volume estimates by 60 million cubic feet per day or 10,000 BoEs per day. Overall, we will increase activity in our emerging plays, with the average EOG rig count for the year expected to rise by about two rigs and one additional frac fleet. Second, we foresee efficiencies that should limit additional inflation pressure on well costs to approximately 10% relative to last year. The main factors contributing to this increase are year-over-year rises in tubular costs along with day rates for drilling rigs and frac fleets. To manage this, we stagger our contracts to secure a consistent baseline of services and ensure reliable execution. This year, we have locked in about 55% of our well costs, similar to prior years. Around 45% of our drilling rigs and 65% of our frac fleets required for the year are covered under term agreements with various providers. By maintaining this stable service base, we anticipate opportunities to achieve performance improvements and minimize downtime, potentially offsetting some additional inflation pressures. Third, our 2023 capital program incorporates further infrastructure investments, typically comprising 15% to 20% of the CapEx budget, but we expect this proportion to be closer to 20% this year. In Dorado, we began 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 aims to ensure long-term takeaway capacity, fully capture the value chain from the wellhead to the market, support expanded LNG export opportunities set to come online around 2026, and enhance our pipeline capacity along the Gulf Coast corridor. We are also undertaking smaller infrastructure initiatives in other regions, such as in the Utica, to drive down long-term unit operating costs. Fourth, the plan includes capital investment that advances our goal of being among the lowest emissions producers of oil and natural gas. Our first CCS project has commenced injection, and we will keep exploring ways to enhance our leadership in environmentally responsible operations. These projects yield strong returns while contributing to reductions in operating costs and emissions. EOG is focused on long-term business management, generating high returns through disciplined growth, improving our resource portfolio through organic exploration, enhancing our environmental impact, and investing in initiatives that will reduce future costs for the Company. I’m optimistic about 2023 and the opportunities it presents for our employees to further advance the Company. Now, I’ll hand it over to Ken to discuss year-end reserves and provide an inventory update.

Thanks, Billy. In 2022, our proved reserve replacement was 244% with finding and development costs of just $5.13 per barrel of oil equivalent, not accounting for revisions due to commodity price changes. Our proved reserve base grew by 490 million barrels of oil equivalent, now totaling over 4.2 billion barrels of oil equivalent, marking a 13% year-over-year increase achieved organically. We also reduced our finding and development costs by 8% compared to the prior year, and over the last five years, we've cut these costs by nearly 40%. Our ongoing transition to premium drilling and our commitment to continuous improvement focused on efficiency and innovation are key reasons why our corporate finding costs and DD&A rates keep decreasing. We are dedicated to maximizing the long-term value of our acreage. For instance, last year we co-developed up to four Wolfcamp targets. Pursuing secondary targets alongside traditional development has minimal production impact on the primary zone while offering a favorable investment profile since it does not require additional leasehold investment and utilizes existing pads and facilities. Our aim is to achieve low-risk, high returns that enhance the cash return potential of our assets. Looking beyond our current proved reserves, we’ve identified over 10 billion-barrel equivalents of future resource potential in our existing premium plays, with expected finding and development costs lower than our current DD&A rate. By investing in finding and development costs less than our DD&A rate, we reduce the Company's cost basis. High returns coupled with low finding and development costs reflect positively in our financials as increased return on capital employed. Thanks to our decentralized structure and multi-basin organic exploration strategy, our resource base is expanding faster than our growth rate, and more importantly, its quality is improving. We have over 10 years of double-premium drilling at our current pace, and we remain focused on enhancing the quality of our resources every year through operational innovation and technical advancements. Now, let me hand 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 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.

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

Two questions, please. First, Ezra, with Dorado, how has your investment program changed in 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 for the gas play? How has 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 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, which may not be reflected in your current budget?

Thank you, Paul. This is Ezra. Those are both great questions. Let me start with the first one regarding natural gas and its current situation. You're correct that we've been monitoring the recent fluctuations in natural gas since late 2022, which are tied to the LNG outages and the warm winter we're experiencing. Our gas growth plan for next year shows a midpoint of about 240 million cubic feet per day, with roughly half coming from associated gas in the Delaware Basin and the other half from our Dorado play. Our strategy at Dorado remains consistent and we don't anticipate any significant changes unless something dramatic occurs. Dorado has always been a longer-term strategy for us, focusing on moderate investments to meet growing demand along the Gulf Coast rather than chasing seasonal demand or rapidly increasing activities in that area. This year, the U.S. will see about two Bcf a day of LNG exports coming back online after the disruptions. An additional five Bcf a day is expected to come online around 2024-2025, with the potential for another eight Bcf a day still in the financing process. This anticipated demand growth is also reflected in the strip price, which has currently moved into contango. Therefore, our long-term strategy for Dorado remains unchanged, focusing on investments that improve the asset each year and allow us to reduce upfront well costs and long-term operating expenses, ensuring we maintain a low cost of supply. As Billy mentioned, we will implement a one completion crew program this year to enhance efficiencies at Dorado. Regarding your second question about sustaining CapEx, I would say that's not a figure we prioritize as an organic growth company. Even during 2020, we didn't adhere to a maintenance capital program. We are adaptable and will grow when the market supports it, and we can scale back when necessary. Therefore, maintenance CapEx isn't a primary focus for us. In terms of breakeven points for our capital program this year, it has increased slightly compared to last year, primarily due to inflation, but we're also looking to invest more in our multi-basin portfolio. Our CapEx program this year is based on a $44 WTI price and a $3.25 gas price. I'll turn it over to Billy to provide additional insights on inflation and our outlook for this year.

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 well 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 baked in about a 10% inflation into our plan. And as we see opportunities, we'll continue to look for ways to improve that.

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

One of the main contributors to inflation over the past year has undoubtedly been the cost of tubulars casing. We've observed various factors affecting this market. The ERW products mainly consist of surface and intermediate casings, which have started to soften more than production casing, specifically seamless products that remain heavily influenced by imports. There are some emerging opportunities in the casing market, but I anticipate there is more to come. On the service side, tangible effects haven't emerged yet; however, it's worth noting that rig counts have remained largely stable since September and are down from their peak in November, which was likely around 20 to 25 rigs. With the decline in gas prices, there is a general expectation of further softening in rig activity levels, potentially opening up opportunities for market capture. A significant advantage we possess is our ability to operate across multiple basins. We are experiencing tighter service and labor constraints in more active regions like the Permian. However, we can redirect our activities to other basins to take advantage of the increased availability of equipment and capacity, allowing us to provide services at more competitive rates. This flexibility is a key strength for our company.

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

Ezra, you have a net cash balance sheet and if we run through, call it, the $80 case, $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?

It's Ezra. That's a great question. I enjoy discussing our balance sheet and its strength, which is something we take a lot of pride in. The reason for that is it provides us with a lot of options at various times. For instance, in 2020, we made strategic purchases of casing. In 2021, we acquired a significant amount of line pipe. Just last year, we made a small acquisition in the Utica play, including some mineral purchases. We are not currently looking for any large, expensive corporate mergers and acquisitions. Instead, we continue to seek opportunities that make sense, such as bolt-ons that would be accretive and could integrate seamlessly into our existing infrastructure to extend our lateral lengths. Regarding our net cash position, we don't have a specific target; we appreciate having that flexibility. One point not mentioned is that we will be retiring a bond in the first quarter for $1.2 billion. Additionally, last year we exceeded our minimum commitment of 60% return of free cash flow to our shareholders, returning approximately 67%. You can see this as evidence that when the time is right, evaluated at the Board level, considering our position in the cycle, the year, and our cash situation, we are willing to exceed the 60% minimum threshold.

Great. My follow-up is Ezra, considering the size of the Company as you near 1 million BOEs per day in overall output, and with most of your activities being short cycle oriented, I wanted to hear your thoughts on pursuing longer cycle opportunities. Some of your peers have invested in regions like Alaska and LNG. Where does EOG stand on exploring long cycle options, and could you provide an update on the Beehive drilling project in Australia?

Yes, we can begin with some of our longer cycle projects, starting with Trinidad. There has been a delay in our drilling program there, so it will commence around mid-year this year. We established a platform based on one of our discoveries from 2020. Later this year, we aim to start construction on another platform called Momento, also following the results of our previous drilling campaign that concluded in 2020. Regarding Beehive in Australia, our Northwest shelf prospect has experienced a slight delay; it is now scheduled to be spud in 2024. In line with the projects you mentioned, our balance sheet allows us to be strategic and opportunistic. We typically pursue these initiatives counter-cyclically, like our agreement on the LNG side or the infrastructure developments we are currently implementing in Dorado to reduce operating costs and enhance our margins. We seek opportunities that align with our core focus, which is drilling and developing high-quality oil and natural gas wells.

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

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 disproportionately high amounts of takeaway spending has maybe lifted the CapEx issue. I'm just curious about the breakdown.

Yes, Doug, this is Billy Helms. Let me address that. There are probably three main factors contributing to the increase. First, inflation in our well costs accounts for about one-third of the increase. We expect around a 10% increase in well costs this year compared to last year. Last year, we managed only a 7% increase despite facing a potential 15% to 20% inflation, which indicates our teams have done well in offsetting inflation through efficiency improvements. We're anticipating more efficiency this year, but we have accounted for a 10% cost rise. The second factor involves infrastructure investments. We've initiated our Dorado gas pipeline and are also expanding infrastructure in our emerging plays, like the Utica, as we begin testing those areas. We've also allocated some capital for our ESG projects. Lastly, we are adding more wells in these areas. With the addition of two more rigs and an extra frac fleet, this will naturally lead to an increase in well counts. These are the three primary factors I would highlight regarding the increase in capital compared to 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 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?

Yes, that's a good question. I think the difference between 2019, or pre-COVID, with oil and what we're currently doing in Dorado is significant. The Dorado volumes are expected to support the output of a single completion spread program this year. The advantages of running a consistent program there include gaining insights about this asset, continuing to reduce costs, and supporting the development of infrastructure such as water takeaway and in-basin gathering. These benefits outweigh the short-term volatility in gas prices because we anticipate a substantial increase in demand along the Gulf Coast in the near future. Our strategy is backed by investing in premium wells. We evaluate investments based on a $2.50 natural gas price. Although current prices are lower, we project that $2.50 throughout the asset's lifespan. The additional gas production this year primarily comes from associated gas in the Delaware Basin, where returns are largely driven by oil and liquids. We are maintaining a steady activity level program in the Delaware Basin through the fourth quarter.

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

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?

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 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 Powder.

Yes, Leo, this is Jeff. Yes, just a quick update. In 2022, we continued to delineate our acreage 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 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.

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.

Yes, Leo, this is Ezra. That's a good observation. It's a relevant question because what's happening is that returns and capital competition are on the rise. Over the past couple of years, especially coming out of the pandemic, we've scaled back our investments. The outcome of that has been two consecutive years with the highest returns in drilling programs that we've experienced in the history of this asset. As you know, it's a highly profitable oil play with significant infrastructure and extensive industry knowledge. Currently, this asset is attracting much more capital investment this year. We aim to invest to keep production stable, as you mentioned. Although production has dipped slightly over the last couple of years, one advantage we're witnessing in the Eagle Ford, which Billy mentioned, is the impact of inflation and service availability across various basins, making the Eagle Ford more appealing.

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 constraint 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.

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

My first question is about your play detail. A couple of years ago, you indicated you had around 11,000 premium undrilled locations, with about 55% of these in the Delaware. Of that amount, approximately 40% are in Wolfcamp plays. I'm curious whether the total number of premium locations is still the same. Also, do you still view the majority of these as being in the Wolfcamp section of Delaware?

Yes, Neal, this is Ken. I'll address that. As we discussed earlier, we have a decade's worth of double-premium inventory based on our current activity levels. Therefore, the number of locations isn't a major concern for us. What we want to highlight is the value proposition of our substantial resource base, exceeding 10 billion BOE, which has a finding cost lower than our existing depreciation, depletion, and amortization rate. Investing in this inventory will reduce our DD&A and enhance our earnings and return on capital employed. Our well counts are continually changing as our development plans evolve, including acreage swaps and lateral extensions. These adjustments improve our finding costs and returns while altering our location count. Our main focus now is to reduce our cost basis while investing at high returns.

No, that makes sense. Ken, could you provide some follow-up on that? My next question is about the details of the Bakken play. A couple of years ago, you mentioned there weren't many locations and perhaps not much value there. I'm curious about your current perspective on that play. Would you consider monetizing it, especially since it seems to be one of your more mature areas, even though you are not financially dependent on it?

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 in the foreseeable future.

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

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?

Yes, Scott, this is Billy. Yes, we're thrilled with the 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'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 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 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?

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.

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

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 compares 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?

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 that the cumulative oil 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 timeframe 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 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.

Okay. Great. Could you provide an update on your current base declines, considering the 3% oil and 9% BOE growth this year? Do you expect your oil and corporate declines to remain stable or possibly decrease this year?

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.

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

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 apply across and outside of the basin?

Yes, Derrick, this is Billy Helms again. Regarding the new completion design, we are always looking for new ideas and ways to enhance well performance over time. We are excited about the advancements and techniques we are testing in the Delaware Basin. This is why we aim for a consistent program that allows us to innovate and make improvements. While I won't go into specifics about the new completion design, as we continue to refine it, we will apply that technology to other basins, and we are already in the process of doing so. We are pleased with the 18% uplift we've observed, although this has only been applied to 26 wells in the Delaware Basin so far, so it's still early days. The improvement is significant, and we fully expect to share that knowledge with other plays.

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?

Yes, Derrick, this is Ken. Yes. 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 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.

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

I want to follow up on Derrick's excellent question regarding the Delaware Basin completion design. I realize you may not want to discuss the specifics, but I'm interested in whether this approach is being used for your lessening intervals, potentially raising them to meet your double-premium threshold. Alternatively, is this a new design for a standard interval that could signal a broader improvement in your overall capital efficiency in the Delaware Basin?

Yes, this is Billy Helms. The new design really starts with an understanding of the rock we're applying it to. We've discussed before how all our designs are customized for each wellbore based on the geology's requirements. While it may not be suitable for all zones, it is definitely more beneficial in certain areas. Additionally, we're implementing it in the core of the play, not just on the outskirts or less productive zones, and we're noticing significant improvements. However, it will continue to be adjusted according to geological insights, and we will refine it as we observe developments.

That's helpful information. For my follow-up, I understand this is a simplification given your number of rigs and plays. Overall, you mentioned that you plan to add three new rig lines in 2023. Can you update us on your progress in that area? When can we expect the rig count to increase throughout 2023?

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.

There are no further questions at this time. I will now hand back over to Mr. Yacob 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.

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