EOG Resources, Inc. (EOG) Q4 2020 Earnings Report, Transcript and Summary

Good day, and welcome to the EOG Resources fourth-quarter and full-year 2020 earnings conference call. [Operator instructions] Please note that this event is being recorded. I'd now like to turn the conference over to Tim Driggers, chief financial officer. Please go ahead, sir.

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth-quarter and full-year 2020 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. Definitions, as well as reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. Some of the reserve estimates on this conference call or in the accompanying investor presentation slides may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings release issued yesterday. Participating on the call this morning are; Bill Thomas, chairman and CEO; Billy Helms, chief operating officer; Ezra Yacob, president; Ken Boedeker, EVP, exploration and production; Lance Terveen, senior VP marketing; and David Streit, VP, investor and public relations. Here's Bill Thomas

Thanks, Tim, and good morning, everyone. Last year was historic, and we were tested like never before. In a challenging environment, I am proud to say our EOG employees who personify our unique culture responded exceptionally without a beat. I'd like to thank our employees for delivering such outstanding performance. We generated $1.6 billion of free cash flow, earned adjusted net income of $850 million and ended the year with $3.3 billion of cash on the balance sheet. We increased our sustainable dividend rate by 30% and shored up what was already an industry-leading balance sheet to a low 11% net debt-to-cap ratio. We lowered our finding and development cost, improved our capital efficiency and earned a direct after-tax rate of return of more than 50%, with an all-in after-tax rate of return of 25% based on our premium price deck of $40 oil and $2.50 natural gas. Such extraordinary results in a $39 oil price environment were made possible by our shift five years ago to our premium strategy, which established an investment hurdle rate of 30% direct after-tax rate of return using flat $40 oil and $2.50 natural gas prices. Using such a stringent hurdle rate shields the company from cyclic oil and gas prices. 2020 was a true test of that shield, and that is a testament to the power of our premium strategy. Beyond delivering stellar financial results last year, we continued to invest in long-term value of the company. Through our low-cost organic efforts, we added 1,500 net premium locations to our inventory, including 1,250 from the newest addition to our portfolio, Dorado, a South Texas natural gas play with 21 Tcf of net resource potential at a breakeven price of less than $1.25 per Mcf. We believe Dorado is one of the lowest cost and lowest emissions natural gas fields in the U.S. and expands EOG's portfolio of assets that we believe will play a significant role in the long-term global energy solution. We also completed two pilots of infield technology to reduce emissions, a hybrid solar and natural gas-powered compressor station that reduces combustion emissions and a closed-loop gas capture system to reduce force flaring as a result of downstream market interruptions. Reducing flaring is an industrywide priority, and we plan to publish our closed-loop gas capture technology for others to replicate. We entered the next phase of the cycle a much improved company. With the countless, creative and innovative ideas we implemented in 2020, we're in the process of making significant improvements to EOG's future performance. Looking forward, the following six steps summarize the foundation for our 2021 plan and outlook for the next three years. Number one, maintain fourth-quarter 2020 production. There is no reason to consider growth until the market rebalances. Signs of an earlier recovery will not change our $3.9 billion 2021 capital plan. Number two, shift to a double-premium drilling program. Our focus on increasing returns never waivers, and this year is no exception. We're raising the investment standard again. Double-premium wells earn 60% direct after-tax rate of return at $40 oil and $2.50 natural gas and make up the top half of our 23-year drilling inventory. Shifting to double premium will make another step-change in our future performance by delivering higher returns, lower decline rates and more free cash flow potential. We have more than 10 years of double-premium inventory and are optimistic we will replace double-premium locations faster than we drill them. Number three, accelerate new exploration projects. Last year, our exploration program focused on technical evaluations across numerous new prospects. We're excited to resume a more robust leasing and testing effort this year. We're evaluating a large number of double-premium oil plays in the U.S. and internationally with the potential to deliver low finding costs and development costs and low production decline rates. The focus of our exploration program is to continue to improve the quality of our inventory and EOG's total shareholder value. Number four, raise the bar again on our ESG performance and ambitions. After achieving significant improvements in safety, emissions and water performance in 2020, we have announced our ambition to reach net zero Scope 1 and Scope 2 GHG emissions by 2040. As one of the steps along the way, we expect to eliminate routine flaring by 2025. We believe this is possible using creative applications of current and future technology. We're currently implementing internally developed technology with a goal of measuring granular real-time emissions data for all facilities in the company. This will encourage innovation and development of unique solutions to achieve our net zero ambition. Number five, resume moderate production growth only when the market is balanced. Assuming a balanced market by year-end, we are positioned to grow oil 8% to 10% in 2022 and 2023. We forecast that our shifting well mix toward double premium will lower our base decline rate to less than 25% within five years from 34% last year. This optimal growth rate delivers the most long-term total value by delivering higher returns, lower decline rates and more free cash flow over the long term. And number six, generate significant free cash flow. All cash allocation decisions are focused on enhancing total long-term shareholder value. Our top priorities for free cash flow are to sustainably grow the dividend and reduce debt. Beyond these priorities, when excess cash materializes, we will evaluate other options opportunistically, such as supplemental dividends, share repurchases and low-cost property additions. With our deep inventory of double-premium locations, moderating decline rates and sustainable cost reductions, EOG's free cash flow potential is improving significantly. Before I turn it over to Billy, I want to address our thoughts on federal acreage. From the statements made by the current administration, we believe that our current existing federal leases and corresponding federal drilling inventory can be fully developed. EOG is well prepared to manage through any regulatory changes that could impact the pace of development on federal acreage. The combination of our large number of federal permits in hand, our flexibility to pivot within our deep inventory of double-premium locations and our ability to add new inventory through organic exploration gives us the confidence that the future performance of the company will not be affected. Now here's Billy.

Thanks, Bill. Let me start by expressing my warmest appreciation to all of our employees. I am truly amazed by their talent, commitment and resiliency as demonstrated by the dramatic improvements achieved in 2020. Within weeks of publishing our initial 2020 capital plan, we quickly cut capital by scaling back activity by nearly half. To protect the company's financial strength, our employees responded with urgency and purpose, finding new ways to sustainably reduce our well cost structure further. What stands out the most to me is how the EOG culture of innovation and multidisciplinary collaboration and teamwork increased at a time when everyone was working remotely to protect themselves, their families and their communities. The results of that innovation and teamwork can be seen clearly in our 2020 operational performance. We significantly improved our capital efficiency by reducing total well cost 15% and per unit cash operating cost 4%. With respect to our year-end reserves and excluding the low impact of low commodity prices, we reduced finding and development costs 15% to a low of $6.98 per barrel of oil equivalent and replaced nearly 160% of our 2020 production. The speed with which we spread technical innovations directed at lowering cost and improving well performance throughout the company has increased. We believe the communication challenge presented by remote work and the teamwork required between individual operational areas to execute our significantly revised plan last year inspired what we believe will be a permanent improvement in how we integrate new learnings and innovations companywide. Our operational execution fired on all cylinders during 2020, reaching our stretch goal to reduce well costs 15% last year with about three-quarters of that coming from sustainable efficiency improvements. We expect to maintain this momentum and reduce well cost another 5% this year. We also expect to carry sustainable operating cost reductions into 2021. Our reductions to LOE during 2020 remarkably outpaced the volume reductions and shut-in production as a result of exceptionally low commodity pricing. We reduced LOE 22% on a total-dollar basis versus 8% decline in production volumes. Shutting in volumes afforded us the opportunity to take a closer look at our maintenance and workover programs and streamline our lease upkeep practices, resulting in sustainable cost reductions. We finished the year with fourth-quarter oil production at a little over 440,000 barrels of oil per day and having spent $3.5 billion of capital, exactly what we forecasted back in May when we revised our plan in response to the downturn in oil prices. We increased our rig count from a low of five rigs last summer and are now running about 24 rigs to support a 2021 program that will maintain essentially flat oil volumes. The rig count is currently at the high point, and it will drift down throughout the year to an average of about 22 rigs. Looking back to when we introduced the premium strategy in 2016, our per unit cash operating costs have declined by 18%, and our per foot well costs are down about 40%. This operational excellence has enabled EOG to raise the bar further and target double premium as our new investment standard. With such significant progress the past five years and the momentum we are carrying, I'm convinced we are only just getting started at being one of the lowest-cost energy suppliers. We also made significant strides in our ESG performance in 2020. First, on the safety side, our total recordable incident rate, the primary safety metric, improved more than 25%. Safety is always our first priority, and we continue to focus on ways to enhance our safety culture even further. On the environmental side, we increased the percent of reused water used in our operation to about 45% of our supply and significantly reduced total barrels of freshwater used. And we increased our already-strong wellhead gas capture rate from 98.8% in 2019 to an astounding 99.6% in 2020. Our ambitions for the future are a reflection of that performance. We have set a goal to raise the wellhead gas capture rate to 99.8% in 2021 and achieve zero routine flaring by 2025. We're literally fighting for the last remaining 0.1 percentage point now. Longer term, we have set an ambition to be net zero in Scope 1 and Scope 2 GHG emissions by 2040. Ultimately, it is our highly creative and passionate employees that gives me confidence in this aspiration. In the past five years, we have achieved a number of technical innovations and operational advancements that have enabled us to generate significant reductions in methane and overall GHG intensity rates to date. Our approach to emissions reductions remains operationally focused, investing with returns in mind and seeking achievable and scalable results. Our investments in projects such as closed-loop gas capture and solar-powered compression pay off in two ways; they lower emissions and function as learning mechanisms for future innovation. We know that to be part of the long-term energy solution, we not only have to be low cost; we have to do it with one of the lowest environmental footprints. Our newly formed Sustainable Power Group is working to identify low emissions power generation solutions and accelerate innovations to support our missions, goals and ambitions. I'm excited about all the innovation occurring in the company, and that gives me confidence we can achieve our goals and ambitions. Finally, I want to take a minute to express my sincere gratitude for the tireless efforts of our production and marketing teams in the wake of the severe winter weather event last week. The teams worked in difficult conditions without any safety incidents to manage the production interruptions caused by extensive freezing weather and delivered as much critical production to our downstream customers as possible. All of our production is now back online, and we expect our average daily production in the first quarter to be reduced by about 4%. Beginning with the onset of the storm, the production staff also worked in close coordination with our marketing team who communicated with our downstream customers to redirect natural gas production in Texas to local distribution companies that deliver natural gas to heat homes and to utilities for electric power generation. These efforts supported by critical -- these efforts supported critical human needs throughout the Dallas, Fort Worth, San Antonio, Austin, Houston and other Central and East Texas communities. Further, in line with our core values at EOG, we sold these redirected gas shipments at prices consistent with those received prior to the winter weather event rather than high and volatile daily spot prices. Through it all, the EOG culture of interdisciplinary teamwork and nonbureaucratic decision-making, technology leadership and commitment to do the right thing shone through, and I couldn't be more proud of everyone involved. Here's Ezra for an update on our exploration efforts.

Thanks, Billy. Our organic exploration focus has always been the driver behind successfully replacing what we drill every year with better inventory. Our current effort is built around adding plays with shallower decline rates that also meet our double-premium hurdle rate, ultimately offering higher capital efficiency than our existing inventory. Dorado, the South Texas natural gas play we announced late last year, is the most recent example of EOG creating shareholder value through low-cost organic exploration. Early entry and capture of a high-quality reservoir across a contiguous acreage position with access to low-cost services and proximity to multiple markets is the recipe for a high-return investment opportunity and is exactly the type of prospect we're looking for. Our strong financial position, combined with our proprietary database of unconventional plays, has positioned us to capitalize countercyclically and capture exploration opportunities with little to no competition. We are focused on oil, and we are in the process of drilling and testing high-potential prospects. We are optimistic we can prove up a number of them and capture additional acreage at competitive pricing that will further improve the quality of what we believe is already one of the best portfolios of assets in the industry. Our vision is to develop double-premium oil plays in each operating area, including international. This is highly efficient and allows us to allocate capital across a wide array of plays to optimize returns and capital efficiency. This decentralized multi-basin approach is a hallmark of EOG, one that leverages our competitive advantages in exploration, technology and low-cost operations, all benefiting from knowledge transfer between the basins. The results, if we are successful, will flow through our financials with higher return on capital employed, lower operating costs, higher capital efficiency, shallower declines and even more free cash flow. When we look back at this time several years from now, I'm confident we will recognize 2021 as a step-change in EOG's performance and financial profile, much like we look back on our shift to premium drilling in 2016. Here's Tim to review our financial position.

Thanks, Ezra. EOG's financial performance in 2020 demonstrates the resiliency of our business model and portfolio of high-return assets. In response to the lower oil prices caused by the price war and pandemic, we elected to utilize our operational flexibility to quickly cut activity. Levered by the sustainable cost deductions that Billy discussed, we reduced capex in 2020 by 44% to $3.5 billion. The result was $1.6 billion of free cash flow, a great performance in what we certainly hope will prove to be the bottom of the cycle year. The board of directors voted to increase the dividend by 10% to an annual rate of $1.65 per share. EOG's dividend has grown at a compounded annual rate of 20% over the last 21 years. This reflects the continued improvement in the profitability and cost structure of the company and our confidence in EOG's long-term resiliency. I'm pleased to say we have never cut the dividend and never issued equity to support it. We analyze numerous stress down-cycle scenarios to evaluate the size of the dividend and to ensure it can be sustained over the long run. The regular dividend represents our first priority for returning cash -- free cash flow to shareholders. Beyond that, we have set a target to reduce debt outstanding by $2 billion from the level at the end of last year. We have made a down payment on that goal, paying off with cash on hand a $750 million bond that matured in February 1. There are no additional debt maturities until 2023 when a $1.25 billion bond is scheduled to mature. Beyond that, we have no plans to further reduce debt. Our goal is to maintain about $2 billion of cash on the balance sheet on average through cycles. This is not a hard-and-fast rule. The actual amount of cash on the balance sheet at the end of each quarter will vary depending on business conditions at the time, but this should give you some rough idea of what to expect going forward. EOG is firmly committed to generating significant free cash flow. Our top priorities for free cash flow remain -- is to remain sustainable dividend growth and debt reduction. As cash materializes and we have more visibility into the future, we will opportunistically consider other options, such as a supplemental dividend during the up-cycles or share repurchases during market lows, along with low-cost property additions with potential to improve EOG's performance. Now let me turn the call back to Bill.

Thanks, Tim. In conclusion, I would like to note the following important takeaways. First, due to market conditions, EOG will not accelerate production in 2021. Second, after this year, once the market rebalances, developing our current drilling inventory at a moderate growth rate of 8% to 10% optimizes returns and free cash flow potential over time. Third, our shift to double-premium investment metrics paves the way for another step-change in EOG's returns and future performance. Fourth, our domestic and international exploration portfolio is stronger in both quality and quantity than it's ever been. This year, we are accelerating the testing and leasing efforts on many of those prospects that have the potential to significantly enhance total shareholder value of the company. Our exploration projects have the potential for higher returns, lower costs and lower decline rates than our current inventory. And finally, we are passionate and excited about the innovation and technology that continues to manifest itself in EOG. It gives us confidence that we will continue to lower well costs and operating costs and reduce our environmental footprint. Our goal for EOG is to be one of the lowest-cost, highest-return and lowest-emissions producers playing a significant role in the long-term future of energy. Thanks for listening. Now we'll go to Q&A.

[Operator instructions] And our first question today will come from Arun Jayaram with JPMorgan. Please go ahead.

Bill, my first one is for you. In 2021, you're gonna hold, call it, a maintenance program. And based on your '22 and '23 outlooks, you could have some growth, call it, 8% to 10%. I guess, my question is, given typical shale cycle times, would you have to spend any incremental capital in 2021 to prepare you to meet that 8% to 10% growth in '22?

Hi Arun. I'm going to ask Billy to comment on that.

Yeah, Arun, no, we don't anticipate that we would have to spend any additional capital this year to be able to accommodate growth in the future. And beyond this year, I would add that we'll only add activity once we see a more balanced market, as Bill described.

Tim, I got one for you. In the guide, we did note a step-change lower in the tax deferral with the company's current tax mix now above 90%. Can you talk about the drivers of the higher cash tax mix in 2021? And as we would have thought some of your IDCs would have led to a lower cash tax rate. And can you just talk about, is this a one-year phenomena or indicative of the go-forward tax rate?

Arun, this is Tim. Yeah, so as we become more and more profitable, obviously, it has lowered the price that we have to make a taxable income. So that's the first thing. We are an extremely profitable company now. And if you go back and look to the -- to 2020, for sure, in the $39 oil, there wasn't much tax profit there. So in the $50 environment, we have significant taxable income, and we have no net operating losses left to offset that with. So it's a simple math of being a very profitable company and paying taxes. So beyond that, I could clarify it more offline, if you'd like, but that's the general answer.

Your next question will come from Jeanine Wai with Barclays.

Hi, good morning, everyone. Thanks for taking our questions. So sorry, Tim, not to keep pushing you on Arun's question right now. But in terms of '22 and '23 on the deferred tax, how that might trend, is it possible that the deferred guidance might improve a little bit next year as you get back to growth to 8% to 10% because you'll be spending more money? The strip is backward dated, which, I guess, is lower cash, so good news, bad news for this. As well as you've got a lot of gains on the nat gas side for this year that maybe may not material next -- materialize next year. So maybe just furthering on Arun's question, is it possible that 0% to 15% could be something different in '22 and '23 as you get back to growth?

That's exactly right. As we spend more capital in the growth mode obviously we'll have more IDCs to deduct to lower our cash taxes. So it a backward dated environment where we got lower oil prices then yes, it would lower that deferred ratio.

Thank you for the clarification. My second question is just on cash returns. So given the high-class problem of your forecasted free cash flow and you formally set the total debt target to $3.7 billion with no plans to further reduce debt, what's the minimum operating cash balance that you're comfortable? And I guess, it's a backdoor way of asking like does your new formalized debt target, does that imply that you plan on paying out 100% of excess free cash flow in a year after dividend and after whatever you may allocate toward low-cost property acquisitions? Or am I just getting ahead of myself here?

Yeah Jeanine, I'll let Tim talk about the cash need to operate the company.

So what we have said is that of around $2 billion is the number we feel comfortable with through the cycles. That doesn't mean it's a hard-and-fast rule that we will have $2 billion on the balance sheet. Some quarters, it will be more; some quarters, it will be less, especially during the quarter based on how money comes in and out of the company. So that's the level that we're comfortable with for now.

Yeah. And Jeanine, the second part of the question is, I think it's important to know that our board is very, very committed to returning cash to shareholders. And we -- I think we've demonstrated that certainly, over the last 20 years, a 20% compounded annual increase in the dividend, the last four years, 146% increase. And then, last year, even in a down year, we increased the dividend and sustained it by 30%. So we're very committed to giving cash back. At the same time, we think it's important to be flexible and opportunistic, which means we want to be able to give the cash back in the way that it creates the most return, the most total shareholder return. And so that will be different in different situations. In an up-cycle, it certainly could be we want to continue to work on the regular dividend. That's the primary way we want to give cash back. And so we are gonna continue to work that really, really hard. And then, on top of that, we'll consider other things opportunistically. As the company continues to improve and get better and improve our free cash flow potential, which we think we're gonna be able to do very consistently over time, we'll consider other options. As Tim mentioned, potentially, a supplemental dividend; potentially, in certain situations, stock buybacks. And then, we are always looking at opportunistic low-cost, high-return bolt-on property acquisitions. And we did a number of those last year. Some of those were in our exploration plays. Some of those in -- really in the Delaware Basin, where we're actually drilling bolt-on acquisitions. So we're always looking to improve the drilling potential of the company through those kind of things, too. So we've got a lot of great options. We're very excited about having a lot of free cash flow and continuing to build on that. That's not a problem. That's a great opportunity. And we're just looking for the right way to redistribute that and generate the highest returns for the shareholders.

And our next question will come from Bob Brackett. Please go ahead.

Hey, good morning. I was comparing the net expected well completions for this year by play versus last year. And am I over-interpreting it? But I see a decrease in the nonfederal areas, call it, the Texas Eagle Ford. I see a rise in the PRB in the Delaware. Is that program predicated on federal lease concerns or desires? Or am I over-interpreting?

I am going to ask Billy to answer that one.

Bob, no, I would say, we've -- in the past 10 years, a lot of our growth previously came from the Eagle Ford, and that is a more mature play at this point. And going forward, they still have quite a bit of inventory, and a lot of that is still double premium. But we see a lot of the growth coming from the Delaware Basin and the Powder River Basin, as you mentioned. Part of that is that in the last couple of years, even last year, we built out some infrastructure on federal land. And just as a natural progression of our development program, we start moving activity into those areas. That's true both in the Delaware and the Powder River Basin. But that's kind of where we see activity moving. And that will also help in the decline rate that Bill and Ezra we talked about earlier in the call.

Our next question will come from Scott Gruber with Citigroup. Please go ahead.

I want to continue on Jeanine's line of questioning. Thinking more about this year, you'll have about $2.5 billion of cash on the balance sheet post bond repayment, and you mentioned retaining $2 billion over the long term. But you also have the '23 maturity, and then you'll generate $1.5 billion of free cash at $50 this year and even more, another $1 billion or so at $60. So just how do you think about use of cash this year, especially if capex is not going to flex? How do you think about building cash for the '23 maturity? Is that above and beyond the $2 billion you mentioned? And how do you balance that against returning cash this year if the strip is right?

Sure. So we've already committed to spending $1.7 billion of the free cash flow through the payment of the bond that matured and then our regular dividend. So that's the first thing. And then, at the end of each quarter, we will review with the board what our cash position is, and we will look at, sight into the future and see what the condition as an industry look like and make decisions based on where we are at that point in time. So there's no hard-and-fast rule on what that answer will be. It's a long-term outlook, not a short-term outlook. So that's the way we're building this model.

Is the $2 billion kind of how you're thinking about the right cash balance for this year or does it, this is a little bit higher given the '23 maturity? How does that come into consideration?

No, the $2 billion is -- two pieces to the $2 billion; one is normal operating conditions and one is a surplus for abnormal operating conditions. So they're both built into that number, and that's the number that Tim Driggers feel comfortable with. So that's how that number was derived. Having lived through a lot of these cycles and knowing the size of our company, I know what I feel comfortable with to not be stressed in a stressful situation on the cash side. So that's how we derive that number.

And our next question will come from Leo Mariani with KeyBanc. Please go ahead.

Just wanted to delve a little bit into the capex here in 2021. Certainly noticing from the slides that you guys are spending an extra $500 million kind of above maintenance. I wanted to get a sense of how much of that is devoted to some of these new exploration plays that you guys were discussing here. And then, ultimately, it sounds like there's quite a bit of testing happening with the drill bit in '21 versus last year. Do you guys see this year as really having a potential as kind of a breakout year for exploration success for EOG, given the higher spend.

Yeah, Leo, let me start that, and then I wanna ask Ezra to give some color on it. But the important thing to consider on our exploration program is that we're investing in plays that we believe will make a significant step-change in the performance of the company. And when I talk about that, that's in addition to the double-premium change we are making this year. It's above and beyond that. We're really looking for plays that are really the new technology we see for the future of horizontal drilling for the most part. These are much, much better rock and have the potential to be much better than -- and deliver results like lower decline rates to help us to generate even more free cash flow and higher returns than ever before. So we're investing in very significant potential -- future potential for the company. The breakdown on the half of the $500 million is $300 million in exploration and $100 million in international and $100 million in ESG projects. And I'm gonna let Ezra comment just in general on our exploration efforts and give a little bit more color.

Thank you for the question, Leo. So as Bill highlighted, we pulled back in 2020 a little bit on our exploration budget, commensurate with reducing the capital spend across the board. And so we are excited this year to be able to return 2020 levels to kind of a pre-pandemic level or more of a historic balance level for the exploration side. And while I can't promise specifics on timing or anything like that, I can give you a little bit of color on how the process goes. And obviously, we like to capture leasehold, and we prefer not to talk in too great a detail about our exploration plays until we get the leasehold captured. And especially what we think is not only the Tier 1 areas, the sweet spot of these plays, but also in a contiguous position. And then, as you can see from the last few announcements, Dorado, the Powder River Basin and the Wolfcamp M and Third Bone Spring, we like to have a handful of wells tested, not only testing the geologic concepts and the producibility of the play but also just testing the repeatability on it. And so those things are different from each of these plays, each of the rock types, giving us the confidence and the transparency to start talking about those publicly. As Bill said, and you highlighted, we are leasing and testing across multiple plays this year. We're very excited about the potential that they'll dramatically increase the quality of the already-robust inventory that we have. And as we shifted from premium in 2016 to focus on double premium this year, we really think these exploration plays have the potential to deliver another significant step-change for EOG's performance in the future. And we're -- last thing I'd highlight is we are doing this at a time when much of the industry has really pulled back on any new exploration at all. And that leaves us in kind of a countercyclic opportunity here where we are excited that we've been able to put together these prospects and get them drilled and tested and provide a little additional color for you, guys, when we have the information.

I really appreciate that. Just for my follow-up question, I just wanted to ask a little bit about kind of production cadence here on the oil side in 2021. Obviously, the goal is to kind of keep things roughly flat with the 4Q '20 levels of 442,000. You're kind of, obviously, starting at a lower point in 1Q because of a lot of the storm downtime. Does that imply that we're gonna see a bit of a gradual ramp on those volumes to kind of get to the average as we work our way into midyear and second-half '21 for the U.S. oil volumes?

Sure, Leo, no, the production each quarter will be about the same, targeting around that 440,000 barrels a day, which really was our target here in the first quarter. Obviously, the storm affected basically a one week of production, and that came largely in the Delaware Basin and Eagle Ford areas. All that production is back on now. And that downtime is gonna result in about a 4% decrease in the first-quarter production. And we've stated we've not -- we are not gonna grow production in an oversupplied market. So basically, once we kind of get this production -- now that the production is back on, we'll maintain this rate at around the 440,000 barrels a day in each of the remaining three quarters.

And our next question will come from Neal Dingmann with Truist Securities.

Bill, just a quick or easy question for you, or Tim, just wondering about hedging these days, your thoughts. You did pretty well with it in '20, when you had some on, you took off, realized the gains on that. So I'm just wondering, with the improvement we've seen in oil prices here, although we're in kind of, obviously, steep backwardization, how are you all thinking about that?

Yeah. Neal, we remain opportunistic on our hedging. Obviously, the price has moved up very dramatically here in the first quarter of the year, faster than really we had thought. We added a few hedges there at the beginning of the year, just to lock in above 50 and 55. But we're currently watching the market and watching it move up, and we'll be opportunistic and add hedges as we feel that they will be beneficial. And we have no hedges in natural gas at this time.

Okay. And then, just you guys have been successful on your organic exploration you've talked about. I'm just kind of curious, with the plan this year, as you have -- I guess, my question is, do you have a set plan on sort of regardless what happens to either pricing or the success of these plays throughout this year and into the '22 what you would do activity and sort of spending-wise on that? Is it pretty set? Or is that -- could that still ebb and flow.

We'll let Ezra talk about this.

Yes, Neal, thanks for the question. We have kind of a base plan setup for our exploration, but what I would say is much of it's going to be dependent on what we see -- how we get these leases put together and what we see on the early results of these plays. So we remain fairly flexible on how quickly we think we could start to allocate capital to these. What I would say, just a little more color, is all of our domestic exploration plays, as we've highlighted in the past, are in areas of preexisting oil and gas operations. So they're not frontier basins or anything like that. There is some form of infrastructure, albeit maybe legacy. And so we would be able to get these things kind of produced and up and moving once we have the results on the repeatability of the plays and have the acreage tied up.

And our next question will come from Brian Singer with Goldman Sachs. Please go ahead.

My first question is a two-part question with regards to the decline rate impact from the shift to double-premium locations. What characterizes either the underlying geology or what you're doing in your completion techniques to achieve these lower decline rates? Or is it just a shift away from the Eagle Ford? And then, if this represents a new capital-efficient shift for the company, why would it not push down maintenance capital below the $3.4 billion?

Sure, Brian, good morning. So as far as the decline rate shift, that's coming mostly from focusing our areas on better rock, to be honest, that as we mature the Eagle Ford Play, as we mentioned earlier, and more of our capital is going toward the Delaware Basin and even the Powder River Basin, in general, those are plays that had essentially better rock and capability of a lower decline. So that's a large part of that. And then, on the new -- with the shift in the capital efficiency and the maintenance capital, I would remind you, the $3.4 billion, when we set that, I guess, a year or so ago, that was at a production rate of about 420,000 barrels a day. And that was also pre-Dorado. So we are maintaining the $3.4 billion at a higher oil production rate of 440,000 barrels a day, and we've also added in the capital on Dorado because that is part of our announced plays going forward.

Great. Thanks. And my follow-up actually does involve Dorado because you mentioned that a couple of times in your prepared remarks as a potential global energy solution. And I wonder how you monetize that. Is there an LNG contract or partnership with a global player? Or are you taking a more bullish view on medium- or longer-term U.S. natural gas prices?

Brian I am going to ask Lance to talk about the L&G potential for Dorado?

Hey, Brian, good morning. This is Lance. Yeah, I mean, I think as we've talked about in the past, that's what makes it so exciting about the Dorado play. It's just -- when you think about the proximity to the market, I mean, we're so close to the proximity to both -- all our domestic customers, but then also the LNG markets as well. So I think the biggest thing, again, is just the proximity. It's the location. It all -- it's very complementary with what we've done in the past in a lot of our plays, moving gas downstream to, obviously, try to capture the highest prices. So we'll just continue to stay very opportunistic there, but the big thing I want to focus on is just the proximity and what's in place today.

And our next question will come from Doug Leggate with Bank of America. Please go ahead.

Good morning, it's Doug Leggate, actually, from Bank of America. I'm afraid that I'm just going to focus on one issue, Bill, and you have to forgive me, it's on the growth plan post 2021. And I want to kind of just set this up a little bit. And then, my question really is why 8%, 10% is the right number and how you define a balanced market? Now I know I've gone through some of this before, but I just want to set it up here a little bit. Basically, just about everybody has dropped their breakeven price. And I think Saudi would argue that their optimal production rate is a lot higher than where it is today. So when you talk about an optimal plan, you talk about a $53 average oil price in the last four years, but we know that Saudi was subsidizing that. So I'm back to the same question I had a number of years ago, which is why when you represent 0.5% of global supply, it's OK to grow at 10% or 5% of global demand because that puts you back to being part of the problem? Hopefully, you see where I'm going with this because if everyone else said the same thing. The U.S. is 500,000 to 1 million barrels a day. And your price war comment, my last comment, I want to just offer a little different perspective on that. Saudi put 2 million barrels of a day on the market in April, put it on a ship and sent it to the U.S. That was a price war. It wasn't a Russia price war. It's an E&P U.S. subsidized growth price war. And so my question for you is, why is 10% OK? How do you define a balanced market? And will you revisit this at some point in the future because it puts us back in the same place you were a few years ago?

Yeah, Doug, yeah, thank you for the question. It's -- first of all, we've been really clear. We're not gonna push oil in an oversupplied market. We're very, very cognizant of the fragile recovery that we're in, and it's important that we don't put any more pressure on that and allow the market to recover. And we are going to watch that the rest of this year. Obviously, we're not gonna -- we've made a commitment. We're not going to be increasing production this year, and we'll watch it next year before we set our plan. So we're not -- we are not interested in growing oil in an oversupplied market, period. And when the market is right and we begin growth again, the reason that 8% to 10% is the right number because it really optimizes all the metrics in the company, returns and free cash flow potential over time. We got a great chart that we put together in Slide No. 10, and it really shows that the operating efficiency, the operating cost, the earnings and cash flow per share growth, the return on capital employed, the three-year cumulative free cash flow and the long-term free cash flow, all are at an optimal level at an 8% to 10% growth rate. If we go slower, some of those are not optimal; they're worse. If we grow faster than that, at the same thing, some of those are not optimal; they're worse. So the 8% to 10% really optimizes a balanced growth rate, a moderate growth rate, where the company can continue to get better very fast and optimize our returns, our earnings potential, our cash flow potential and our long-term free cash flow..

Maybe as a quick follow-up then, Bill, on the same topic. So I understand the point about optimal, but optimal is because of what the strategy you decide to adopt. So for example, you don't need to spend $0.5 million or $1 billion on exploration. If you do, you could high grade. You never rightsize the company with a slow growth rate. And you still describe taking 5% of global demand as moderate. So I guess, my question is, between 2017 and 2019, Saudi have 2 million barrels a day held up to market before COVID. Is your definition of a balanced market that the lowest cost producer is still subsidizing the business by bringing back any production? Because that, by definition, is subsidizing your business. So optimal -- I'm just having a tough time understanding why you're not learning any lessons from growing nine times in 10 years with very little cumulative free cash flow, and your share price response, obviously, was terrible. So why is 5% global demand growth for a company with 0.5% global supply okay?

Yeah. I think there's two elements that we look at really closely, obviously, to determine whether the market is relatively balanced or not. One of them is the inventories. We want to see them get down to the five-year average or lower and keep hitting lower. Then the other is spare capacity, worldwide spare capacity. So we're watching spare capacity, and as it's -- at the moment, it's still 10 million barrels a day, and we need to have some work. So we want to get spare capacity down in the world to kind of a historic normal level. And so we'll be watching both of those. And we are very definitely committed to not overpressuring the market and working with the market we have to work with and staying disciplined and not trying to push oil or grow oil into an oversupplied market. We're making that commitment. We've always done that. We did it in 2015 and 2016. We didn't grow. We, obviously, shut in production last year, and we're staying -- we're maintaining that exit rate this year. So we're very disciplined and we're very cognizant of that. Beyond that, when the market is available, we want to run a company to generate the highest total return for the shareholder value. That is our job. We want to generate value, business value, really core business value. And that's what we're about, and that's what we're going to stay focused on.

And our next question will come from Charles Meade with Johnson Rice. Please go ahead.

I wanted to ask a question about your double-premium inventory and really the rate of change there. If you took that definition of double premium and applied that to your '19 program and your '20 program, what percentage of that '19 program or '20 program would have fit -- would have qualified for that double-premium bucket? And what's it gonna be in '21?

Yeah, Charles, Yeah, the double premium, we've been building more double premium every year as we get our cost down and improve our well productivity. Last year, it was about 50%. In 2019, it was less than that. So last year, it was about 50%. And this year, our goal is to get it up to 75%, maybe even higher percent as that. And then, next year, it will even be higher than that. So we're focused on improving the wells, not only with the cost, but there's a slide, Slide No. 7, I think it is. It shows that these double-premium wells are much, much more productive. In fact, over the first two years, they cumed 39% more oil than the wells we've been drilling in the last several years. So they're better wells. Obviously, we're lowering our costs at the same time. And I think that's really a differentiator for EOG. As the industry data shows, most of the industry well productivity is flattening out. Where at EOG, the well productivity is continuing to increase. So we're not through. We're gonna get better every year. We figure out how to target better rock. Our completion technology continues to increase. Obviously, our well costs are going down significantly. And all that is sustainable. And that's on really the EOG culture and our methodology of not really getting into a maintenance mode and just doing routine every well the same. We are in the learning process. We gather tremendous amount of data and technology. We're learning the geologies. We drill the wells. We're learning the pay quality. And we're figuring out just continuously on a real-time basis how to get better in every aspect of the company. And so we're excited about our future and continuing to increase returns and capital efficiency and free cash flow potential as we go forward.

Thank you, Bill, that's helpful insight into your thinking process. And perhaps, picking up that one thread on better rock, am I interpreting that the right way that -- is that essentially the shift from these -- the resource shale plays more toward these combo-clastic kind of plays? And is that a -- is that just kind of a coincidence? Or is that more of a fundamental arrow for you guys?

Well it's not a coincidence. I am going to let Ezra talk about that.

Yeah. Charles, thanks. That's perfect. You kind of hit the nail on the head. As you move away from these, the actual true shale plays themselves are some of the tightest rock. And so as we've moved into not only different basins and different formations but especially targeting the specific landing zones. As we've developed some of our petrophysical, some of our geologic models to really understand the specific landing zones in rocks like the Austin Chalk per se, you fundamentally have higher porosity and permeability, just better all around rock quality that adds to not only the returns but also, as Bill was highlighting, to the shallower decline profile.

And our next question will come from Paul Cheng with Scotiabank. Please go ahead.

Two questions, please. Last year, you signed a gas supply agreement. That seems to be well timed, given the sharp rise in the JKM prices. Can you tell us that what is that volume for this year? And how quickly you would ramp to 440 million cubic feet per day? How many years that we get there? And also that since it's linked to both JKM and Henry Hub, can you tell us that what percent is on JKM and what percent is in Henry Hub? That's the first question. Second question, I think this is probably for Bill. Some of your competitors have decided to formalize the excess cash return framework that once that they have excess free cash after capex and paid dividend, they will pay that out. Just curious that why from EOG standpoint, you don't think that will be a maybe workable program for you because I think the market would love cash return, but that they also love transparency and sort of understanding that under what circumstances they can get what. So just curious that, why that we do not believe that will fit into the EOG model? Thank you.

Yeah Paul, I am going to ask Lance to talk about the JKM.

Hey, yeah, thanks for your question, especially related to LNG. Yeah, I'd say it was fairly bearish last year, right, related to JKM and just global LNG pricing with the warm weather and, obviously, the oversupply. And things have changed, haven't they, quite drastically to where, on a go forward, it looks very constructive, definitely, as you look at global prices. So yes, just as a reminder there, Paul, we've got 140 million a day that goes into that agreement that we have with Cheniere. Like you said, we're excited for the benefit there that we've seen, especially in a go forward. We kind of had that view going into before and finalizing our agreement. We're definitely constructive kind of long-term related to global prices. And obviously, having exposure to JKM and being very correlated with oil too and having the upside, that's where we kind of wanted to be positioned from an LNG pricing standpoint. So yes, we've been very pleased here in the first quarter with that pricing and constructive from a long-term standpoint as well. And yes, your second question was -- there was just kind of how it ramps up, and you're right. It's the 140 million is the JKM, and there's an additional 300 million that will be tied to Henry Hub.

And for the JKM, is that the one to one or that is a factor?

Paul, could you ask that one more time please sir.

For the link to the JKM, is it a direct price you get the JKM? Or you say factors? Is there an S-curve or anything like that?

I am not going to go into the specifics contractually, but it's very familiar from what you've heard from Cheniere as well in their IPO model. And so that's how we've structured that.

And this will conclude our question-and-answer session. I'd like to turn the conference back over to Bill Thomas for any closing remarks.

2020 was a year with many challenges, and I'm so very proud of the employees of EOG. They responded with an exceptional performance in an exceptional year. We entered 2021 and this next up-cycle with lower cost and more potential than ever in the history of the company. Our organization and culture are focused on improving returns, playing a significant role in the future of energy and delivering substantial long-term shareholder value. So thanks for listening, and thanks for your support.

The conference has now concluded. Thank you for attending today's presentation and at this time, you may now disconnect your lines.