Welcome to the Q2 2022 ConocoPhillips Earnings Conference Call. My name is Richard, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. I will now turn the call over to Mark Keener, Vice President, Investor Relations. Mr. Keener, you may begin.

Thank you, Richard, and welcome to everyone joining us for our second quarter earnings call. First, let me introduce the members of the ConocoPhillips leadership team taking part in today's call. We have Ryan Lance, Chairman and CEO; Bill Bullock, EVP and Chief Financial Officer; Dominic Macklon, EVP of Strategy, Sustainability and Technology; Nick Olds, EVP of Global Operations; Jack Harper, EVP of Lower 48; and Tim Leach, adviser to the CEO. On the call, Ryan and Bill will provide some opening comments, after which the team is available to take your questions. Before I turn it over to them, just a few quick reminders. In conjunction with this morning's press release, we posted supplemental materials that include second quarter earnings results and highlights, earnings and cash flow summaries, price realizations and sensitivities for estimating earnings and cash flow, and updated guidance for the third quarter and full year. During the call, we'll make forward-looking statements based on current expectations. Of course, actual results may differ due to the factors noted in today's release and in our periodic SEC filings. And finally, we'll make reference to some non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in this morning's release and on our website. With that, I'll turn it over to Ryan.

Well, thank you, Mark. And Mark has elected to retire, so I want to start off by really thanking him for more than 30 years of dedicated service to our company and wish him well in retirement. And at the same time, I'd like to warmly welcome Phil Gresh, who will be joining our team next month as Vice President of Investor Relations. Now before I get into the results for the quarter, I'd also like to touch on a few things that continue to be top of mind for us. The ongoing tragic invasion in Ukraine and the residual implications from COVID have significantly impacted supply chains around the world, with shock waves driving both product shortages and elevated levels of volatility, including large swings in commodity prices. The combination of these factors has brought into sharp focus the critical importance of U.S. and global energy security and reliability. By fulfilling our triple mandate of responsibly and reliably meeting energy transition pathway demand, delivering competitive returns on and of capital, and progressing towards achieving our net zero operational emissions ambition, we're playing a key role in providing secure, dependable energy solutions that are clearly needed around the globe. The guiding principles of our triple mandate were key to our recent actions and announcements regarding global LNG supply capacity, as the use of natural gas in place of coal and refining products represents an opportunity for significant reductions in greenhouse gas emissions around the world. We believe this reality is going to drive increasingly strong global LNG demand and related opportunities well into the future. As recently announced, we entered into an HOA with Sempra for a possible investment in the Port Arthur LNG project that's currently underway. The potential investment is designed to leverage our company's considerable strength as one of the largest gas producers and marketers in North America, while expanding our global LNG business. This potential investment is expected to be project financed and, if executed, would afford us the opportunity to participate in additional strategically located LNG projects, as well as to jointly pursue related emissions reduction opportunities. That announcement followed our recently completed 10% ownership increase in APLNG, as well as our selection to participate in Qatar's North Field East project, adding to our long positive relationship with Qatar Energy. Our recent decision to join the OGMP 2.0 initiative is also in service to achieving our triple mandate, as reducing greenhouse gas emissions, including methane, is an imperative for our company and our sector. Applying the rigorous OGMP 2.0 reporting standard, which incorporates third-party verification will be a vital step on our path to net zero operational emissions. Now before I turn the call over to Bill to cover the second quarter performance, let's discuss for a moment on the equally important returns element of our triple mandate. Looking at returns on capital, we generated a trailing 12-month ROCE of 24% in the quarter, 5 points higher than the 19% we delivered last quarter. Turning next to our returns of capital. Once again, we've increased our targeted 2022 distributions to shareholders, taking the total full year expected returns to $15 billion. This represents a 50% increase from the target announced last quarter, with the $15 billion to be distributed across our three tiers of ordinary dividends, share repurchases, and VROC. At current strip prices, this represents a return to shareholders of slightly more than 50% of our projected CFO for the year. Our commitment to achieving our triple mandate is unwavering and delivering competitive returns on and of capital to our shareholders through the cycles is a key component of that commitment. Now let me turn it over to Bill to cover our overall performance for the quarter.

Well, thanks, Ryan. And as you noted, we generated a return on capital employed of 24% on a trailing 12-month basis. On a cash adjusted basis, that improves to 27%. Turning to earnings per share, we generated $3.91 per share in adjusted earnings in the quarter. This was driven by strong realized prices and production of almost 1.7 million barrels of oil equivalent per day. As we previously mentioned, production volumes in the second quarter were reduced by scheduled turnaround, as well as some unplanned weather and other minor impacts. Lower 48 production averaged 977,000 barrels of oil equivalent per day for the quarter, including 634,000 from the Permian, 233,000 from Eagle Ford, and 91,000 from the Bakken. Operations across the rest of our global portfolio also ran well, leading us to generate $7.8 billion in cash from operations in the quarter, excluding working capital. This includes roughly $750 million in distributions from APLNG, and we continue to project full year distributions of $2.3 billion, with roughly $300 million expected in the third quarter. We also invested $2 billion back into the business in the second quarter, resulting in free cash flow of $5.9 billion. That more than covered the total $3.3 billion we returned to shareholders in the quarter, as well as the $1.9 billion used to reduce total debt. These actions taken in combination with the $600 million in disposition proceeds and the repurchase of approximately $300 million in long-term investments, resulted in ending cash of $8.5 billion as of June 30. Turning to the second half, we provided a third quarter production guidance range of 1.7 million to 1.76 million barrels of oil equivalent per day, and reduced our full year production from 1.76 million to 1.74 million per day. That's primarily related to risking of projected production from Libya in the second half of the year, as well as some modest updates across the portfolio. Now in conjunction with these changes, we reduced DD&A guidance from $7.7 billion to $7.6 billion for the year. We also increased full year 2022 adjusted operating cost guidance to $7.5 billion from the prior $7.3 billion. Now this is reflecting commodity-related price impacts. We reduced guidance for the corporate segment loss from $1 billion to $900 million, primarily due to lower interest expense resulting from our recent debt reduction and higher interest earned on cash balances, along with some restructuring efforts. Operating capital guidance for the year remains unchanged at $7.8 billion. So to sum it up, we have delivered another strong quarter across all aspects of our triple mandate. Our diverse global asset portfolio continues to run well. We returned $3.3 billion to our shareholders in the second quarter, ended the quarter with $8.5 billion of cash and short-term investments, and increased our full year return of capital target to $15 billion. We continue to strengthen our fortress balance sheet, and we have reduced total debt by $3 billion year-to-date. And we further enhanced our low-cost energy transition-oriented portfolio by expanding our current and future presence in the growing global LNG market and by joining the OGMP 2.0 initiative. Now with that, let's go to Q&A.

Our first question comes from Mr. Neil Mehta from Goldman Sachs.

Mark, you will definitely be missed, and congratulations to Phil. If you're on the line, I look forward to working with you in your new role. The first question is for you, Ryan. There was a significant announcement about the incremental return of capital. The questions we've received from investors this morning, given the variable aspect of it, are whether this should be viewed as dependent on oil prices or if we should see it as a financial commitment from Conoco that you can rely on, assuming reasonable market volatility.

Yes, Neil, if your question is specifically about 2022, you can expect this return to be passed back to the shareholders in that year. We assessed the market considering the volatility you mentioned and are confident that we can raise the distributions to $15 billion through the three channels we've utilized previously. So you can rely on that for 2022.

And Ryan, I love your perspective on some of the long-term growth projects that the company is leaning into here. The announcement in Qatar, potential investment in U.S. Gulf Coast and then making progress on Alaska, how does that fit into the long-term Conoco strategy? And do you think that the company is taking a little bit more of a growth orientation here relative to just a free cash flow orientation?

I wouldn't describe it as a focus solely on growth. Our long-term goal is to develop our company. We prioritize actions that align with our cost of supply framework. We acknowledge market volatility and aim to avoid investments that exceed a $40 cost of supply. This approach is essential for generating free cash flow and returns on capital, and everything we do supports this goal. Since the Ukrainian invasion, we believe gas serves as a transitional fuel as we shift toward lower carbon alternatives. We have significant capacity in both LNG and natural gas, particularly in North America, and we aim to enhance this with more LNG liquefaction capacity. We've been exploring this for a while, and the opportunity arose with Sempra. We also want to participate in expansion projects in Qatar, which offers some of the most competitively priced gas globally, suitable for both Asia and Europe. Our investments align with our cost of supply considerations, and we are focused on growing the company over the long term. We believe we are at the beginning of a favorable cycle in the commodities market, given our analysis of current supply-demand dynamics. When projects align with our criteria, they make sense for our company and leverage our strengths. While we can't always control the pace of these opportunities, we are eager to participate in favorable deals like the one with Sempra on Gulf Coast liquefaction.

Our next question on line comes from Mr. Stephen Richardson from Evercore ISI.

Great. I'd like to also thank Mark for all the help and wish him the best. He will definitely be missed. The first question, I guess, is just following up on those comments, Ryan, on Sempra. I was wondering if you could just maybe talk a little bit about, do you think about the returns here relative to the backward integration into your existing U.S. gas production? Do you think about it much more on a merchant basis? And also just curious if you could talk about why this project relative to the other opportunities and variables you looked at in terms of more Gulf Coast gas?

Yes, Stephen. I think let me take the last one first a little bit. This was a permitted, shovel-ready project. We like the location; we know that area pretty well and we like the expansion opportunities that come with it and the optionality that it creates on the site, scale, and scope, which is why we chose Sempra over some of the other opportunities that kind of presented themselves on the Gulf Coast. And also the action link that it has to the West Coast LNG that they have with their Mexican opportunities that are going on there. So it was a really good fit. We know Sempra pretty well. We've worked with them in the past. A good fit culturally to the company and consistent sort of culture in terms of how we think about the business, the markets, and where natural gas is going globally. More to your first part, yes, we think about this in a very integrated fashion. So it's not only liquefaction, but it's moving it into the market, and that it's a recognition that with the transactions we've done over the last year and the core assets inside the portfolio in the Lower 48, both Canada and the Lower 48, we recognize we've got a large potential natural gas position. And we want to create value for that position in a very integrated fashion. So it's the integrated nature of the project. Not any one element, but they all tie together. The ability to supply gas to the liquefaction facility, the taking of the 5 million tonnes of commitment moving it into the markets that we know really well and getting into that fully integrated chain is what interested us the most.

I would like to follow up on the recent discussions in Washington regarding the resolution of some of the permitting challenges faced by the industry, especially related to NEPA. Could you talk about what would need to happen to elevate the Willow project? It's the project that comes to mind when we think of NEPA, so any insights on that would be appreciated.

Yes, NEPA needs reform, Stephen. It can take 10 years or more to complete. This issue affects not only our industry but all industries; even wind and solar developers express similar frustrations. The lengthy coordination among various government agencies under NEPA is time-consuming. Improving coordination, setting response time deadlines, and establishing reasonable public comment periods without unnecessary extensions are essential. This administration and past ones have struggled with this. The NEPA process urgently requires reform to enhance efficiency and ensure that coordinating groups facilitate progress through the necessary agencies. I understand they are considering this, possibly as part of a companion bill to the Schumer-Manchin bill, leaving us uncertain about its completion, but reform is critically needed. Regarding Willow specifically, we have been engaged in this process for a long time and are nearing the final stages. The supplemental EIS statement from the Department of Interior is currently open for public comment. The public has had ample opportunity to express their views on this project, and we believe we understand the prevailing opinions. It is now time to make a decision to proceed. We anticipate the record of decision will arrive later this year, allowing us to advance the project. We believe we have addressed all the concerns raised by the federal judge and are prepared to move forward.

Our next question on line comes from Jeanine Wai from Barclays.

We'd also like to show our congratulations to Mark on your retirement, and thanks so much for your time, and you'll be very missed. Our first question maybe dovetails on Neil's question on cash returns. Just maybe digging in a little bit more. Does the increase primarily reflect a stronger-than-expected commodity price environment? Or are there other factors that are kind of driving the increase? I mean, I guess we had anticipated some kind of increase given we saw a really strong free cash flow outlook, but we thought it would be kind of walked up over time. So the $5 billion increase, it exceeded our expectations. I think it exceeded the market's expectations. So any color on how you're thinking about future potential there would be great.

Jeanine, we assess many factors and have a solid understanding of the supply-demand dynamics and macro trends. The market is quite volatile, so we aimed to ensure we could deliver in 2022, even considering the backward nature of the forward curve. However, we maintain a positive outlook on commodity prices. Additionally, we are focused on our balance sheet, which is very strong. We plan to rebuild our cash reserves after our recent transaction, which has proven beneficial for the company. We're pleased with its progress. We still want to increase our cash reserves to prepare for market volatility and future conditions, but we have a constructive view on commodity prices over the next few years. As a result, we believe our progress allows us to potentially increase shareholder distributions beyond market expectations over recent months.

Our second question, maybe moving to CapEx and inflation. It continues to be a pretty tough operating environment out there between inflation and a tight supply chain. Can you maybe discuss how your costs are trending versus your expectations? And we kind of thought Conoco would true up the CapEx budget for the recently announced participation in the North Field LNG project. But you reiterated the CapEx budget this morning. So if you're able to clarify for us if there's anything in the '22 budget for that participation, that would be very helpful.

Yes. Maybe I'll say a few high-level words. Obviously, inflation is still with us. It's staying with us. It's different around all different pieces of the world. Maybe I can ask Bill to chime in on some of that. And then Nick, maybe you can address Jeanine's question specifically on the timing of North Field East.

Yes, sure, Ryan. So Jeanine, we continue to expect our overall company inflation to be in the 7% to 8% range, and that's what's reflected in our capital guidance of $7.8 billion, just like we talked about in the first quarter call. Like everyone else, with our higher activity levels in Permian, that's where we're experiencing the most inflation, what we're watching, and we're continuing to keep an eye on that.

Jeanine, this is Nick. Yes, this is in relation to the North Field expansion. So obviously, we got the 25% equity in half a train. So to put that in perspective, Qatar Energy communicated that the total project, that's 4 trains of 8 million tons per ounce, so a total of 32 million is $29 billion for that. Our effective working interest is 3.125%. So if you take that, that gives us an estimated incremental CapEx of approximately $900 million for the NFE project. Now related to timing, as Ryan mentioned, this project has been going on for a couple of years with drilling and putting in platforms. So we'll have an initial catch-up payment for our share of the project costs, either late this year or early next, and that's not determined at this point in time. And with respect to start-up of first LNG, as Qatar Energy has communicated, that is in 2026. Again, this would be incremental to any guidance.

Yes. So Jeanine, that would be additional. If a catch-up payment were to occur this year, it would be in addition to the $7.8 billion that we projected.

Our next question on line comes from Mr. Roger Read from Wells Fargo.

And Mark, congratulations. You seem far too young man to retire, but you got to do what you got to do, right? Anyway, the question I'd like to get on. It kind of comes back to the overall LNG and tying it together your existing operations, and obviously, the two new seems, I guess, one for sure and one likely investment. You're a big gas trader in the U.S., to some extent globally. I was just curious as does that create a new integrated sort of business we should think about down the road? And what would be the opportunities there? Probably gets a little bit back to Stephen's question about the return structure of the transaction overall with Sempra.

Let me start by saying that I believe Bill can provide some insight on the commercial aspects of what we're doing in this area. You're correct, Roger. We view this in a very integrated way. We're marketing 7 to 8 Bcf of gas daily in North America. Thus, the potential to supply gas to a multi-train project in Port Arthur, Texas is appealing to us. Our commitment to take on 5 million tons means we have substantial experience in positioning it in the market. Bill can elaborate on this. We have commercial teams in both London and Singapore and are familiar with the European and Asian markets. We'll determine the best way to manage the 5 million tons, possibly supplemented by spot transactions. This integrated approach, from supply to selling gas to customers, is what drew our interest in this opportunity. Bill, do you have any additional comments on the commercial side?

Yes. Sure, Ryan. Roger, as Ryan highlighted, is this integrated nature that's most exciting about it. We are one of the largest marketers in North America, certainly a top five marketer. I think lately, we're pushing number two. So we're very comfortable with supply, and we move orders of magnitude above our physical production. So the optionality that being able to supply LNG regas facilities is pretty interesting to us. It's also interesting to us in terms of ensuring strong flow assurance for our own production. And then we've got a history of well over 40 years of marketing LNG through Asia. We started the trade into Japan with our Kenai facility. We've been in the LNG business for quite a long time. As Ryan mentioned, we've got offices in London, Singapore, and Japan. We've been moving spot volumes in the market here off of APLNG. And so it's a part of the market we know quite well and pretty excited about this integrated nature of being able to create value across that chain.

And the other part, Roger, I would say, Jack could chime in too here, but just the gas resource that we have as a result of the transactions over the last couple of years, we've got a very large, high-quality gas resource that we hope to be pivoting to over time to even supply a lot of this gas.

Yes, for sure. The other question, just coming back, you talked earlier about potential positives like a NEPA reorg and all that sort of thing. I was just wondering in the IRA bill with some of the issues on a methane tax, Conoco has certainly been ahead of the game on overall emissions reductions and everything. But is there anything in that or any of the other aspects of the bill, 15% minimum tax things like that, we should think of as headwinds?

Well, I think, generally speaking, the Schumer-Manchin bill, I'm not sure if it's a good time ever to the increasing taxes and increasing government spending, just as a general economic policy, and that's a large part of what this bill goes to. Now specific to our industry, at least the agreement recognizes that natural gas and oil are an important part of the energy transition and they're going to be here for decades. So that's a positive. I think the methane fee to your point, it's got some books in it. We'll have to see how it develops over time and comes out with the extra regulation coming out of the EPA. Our general view is if you're going to regulate it, why do you have to put a fee on top of that? We'll have to see how that's structured. It generally won't, as we understand it today, maybe impact companies like ConocoPhillips that have been very proactive in the emissions space. And you saw our OGMP 2.0 agreement to join that, specifically targeting methane itself. So at least the agreement incentivizes some carbon capture by addressing the 45Q. So it's uncertain right now. The earlier comment, I think, from Stephen on NEPA reform, too, there's supposed to be a companion bill that comes with this that addresses a lot of that, and that leaves a lot of uncertainty in the process. So kind of mixed views at this point in time, Roger.

Our next question on the line comes from Mr. Doug Leggate from Bank of America.

And Mark, let me offer my congratulations to you as well. I'm not sure Mr. Gresh will be as much fun to travel with, but good luck in your retirement. I guess, Bill, maybe I could start with you. Last quarter, you talked about the U.S. business moving into full cash tax. I wonder if you could just give us an update as to whether we're there yet. And when you wrap it all together with the rest of the portfolio, including the recent Norwegian changes, how should we think about the cash tax outlook for Conoco going forward?

Yes, sure. Happy to, Doug. We moved into a U.S. tax paying position in the second quarter. And of course, the amounts and timing through 2022 can vary depending on price and other market conditions. But the majority of our U.S. taxes in the second quarter were paid in cash with very minimal offsets from NOLs. And looking at the limitations on NOLs, we'd expect to be our tax payments through 2023 to be reduced only slightly, but not eliminated. So at a high level, we're in a cash tax paying position. Our effective tax rate for the second quarter was about 32%. Moving forward, I expect our effective tax rate to stay in the mid-30s assuming production lines with our guidance and forward curves.

So basically, if there is an E&P, there's no impact from you guys, it sounds like?

Yes. If you're talking about the 15% corporate minimum tax proposed in IRA, we don't expect that to have any material impact on the company because we exceed a 15% minimum tax across our jurisdictions.

My follow-up is I wonder if I could try and tackle the CapEx question from a slightly different angle. When you wrap all of the moving parts together, cash tax is changing, obviously, a little bit of inflation on the operating costs. And then, of course, the overall capital budget an issue that going back to when Matt was around, we used to get a lot was the idea of what the sustaining capital breakeven was for the portfolio. So I wonder if I could ask you to, as you look to 2023, what does that look like? And obviously, gas prices have moved around as well. But if you could give us an update as to how you see that covering your sustaining capital as opposed to the total capital. And I'll leave it there.

Thank you, Doug. This is Dominic. There are several factors at play, and we will update our plans as we complete our annual planning cycle. For this year, our breakeven point is still estimated to be around $30 per barrel for capital breakeven, with sustaining capital expected to be about $6 billion. We are seeing some inflationary pressures, but we believe that under less volatile macroeconomic conditions with lower inflation, sustaining capital will remain around $6 billion. Additionally, we anticipate that longer-term, low-cost supply projects will temporarily increase this amount, and we plan to provide more details on this by the end of the year.

Our next question on line comes from Mr. John Royall from JPMorgan.

So just a question on your cadence of production in the Permian. I know you talked about it being back half weighted in the prior quarter and looks like a modest tick down in 2Q. So can you just speak to the cadence for the back half and expectations for 3Q versus 4Q? And then maybe just a broad update on your drilling program there.

Yes, this is Jack. Generally, production in both the Lower 48 and the Permian is expected to be weighted towards the second half of the year, with a low single-digit growth year-over-year on a pro forma basis. However, on an entry-exit basis, we anticipate the Lower 48 to grow in the mid- to high single digits, while the Permian is expected to be at the upper end of that range. Regarding our activity expectations, the good news is that we plan to maintain a steady pace in the second half of the year, and we are currently operating the number of rigs we intend to run for the remainder of the year.

Yes. And then if you could just give some color on crude realizations, looks really strong in the quarter when you look at your side there. Very strong across the board, but North Sea was particularly strong. So just anything going on there broadly or regionally to point out?

Yes, sure. If you look at our realizations overall, and we provided a summary of that in the supplemental information, total realizations for the quarter were about 78% of Brent. That's really driven by four factors as we look at it, John. First is, that's the narrowing of the Brent, WTI spread. Brent increased about 12%. WTI was about 15%. Henry Hub was up significantly more compared relative to Brent, it was up 44%. So that's impacting the total realizations. And then on the crude side, in particular, we had better realizations coming out of Alaska for the quarter. That's really last returning to more of its normal type realizations. In the first quarter, you may recall we had an impact for our HollyFrontier refinery downtime in the first quarter that was impacting our prices. And then we saw better realizations out of Norway. That's really driven by cargo timing across the quarters. So that's really what's impacting our crude realizations across the company.

Our next question on line comes from Mr. Paul Cheng from Scotiabank.

Let me extend my congratulations to Mark and thank him for his assistance over the years. I have two quick questions. Ryan, many of your competitors have been making significant bolt-on acquisitions in areas like Bakken, Eagle Ford, and Permian. As you review your portfolio, do you identify substantial opportunities to enhance or solidify your position in those areas through bolt-on acquisitions, or do you believe the value proposition is not particularly appealing? Also, regarding the split in the first half between dividends and buybacks, which is about one-third dividends and two-thirds buybacks, can we use that as a reliable indicator going forward for your distributions?

Yes, Paul. We're actively engaged in the market. Currently, our main focus is on the Lower 48, and Jack can also provide insights on our core developments. We've highlighted this in some of our presentation slides. A significant part of our attention is on swapping and trading acreage, especially following a large transaction we completed earlier this year. This strategy enables us to avoid drilling just one mile and instead allows us to explore opportunities for two and three-mile laterals. We've examined the bolt-on opportunities you mentioned, particularly in the Bakken and the Eagle Ford. Our company maintains a high standard, adhering to our cost supply cutoffs of $40 and $50. Consequently, any acquisition we consider must have costs below $50, and any potential future exploitation of the asset needs to be below $40 to fit within our portfolio. Our margins are quite stringent. We monitor all these potential acquisitions and are currently engaged in a few, mostly pertaining to swaps in the Permian. Jack, would you like to add anything?

Yes. I would just add that since the Concho deal closed at the beginning of last year, the team has done 15 of these swaps and trades in the Permian this quarter, about 25,000 acres. And we have about that same number of deals in various stages currently. And the significance about that amount of acreage is that's at least a year's worth of Permian drilling activity, all of those extended lateral lengths.

Thanks, Jack. And on to your second part, Paul, I think the thing to remember this year is there's a little bit of the buyback pace that was influenced by the swap that we had with Cenovus swapping out of the shares that we own there into the shares of ConocoPhillips. But we're going to watch the market. Obviously, we're going to watch where our share prices are trading and how much we put to the cash side of it versus the share buyback. I'd say somewhere in that two-third, one-third, so 60%, 40% is probably something that you should expect for the year this year. And then we'll relook at that, revisit that next year as we go through our planning process. And that includes the typical fourth quarter increase to the ordinary dividend. We'll take that under advisement with the Board and be thinking about that cash return portion as we think about the market and think about where the company is positioned. But I think roughly what you see this year is probably something closer to a 60-40 split between buybacks and cash.

Our next question comes from Mr. Bob Brackett from Bernstein Research.

Please add my voice to the chorus praising Mark as well. I'll come back to the Willow question. It's my understanding that the 45-day comment period ends at the end of this month. Can you talk about what the path towards FID following that looks like? What are the various steps? And can you talk about the various alternatives proposed in the supplemental as you think about the cost benefit of those?

Yes, Bob, this is Nick. You're right, the 45-day comment period has commenced. And again, just backing up, that's a key milestone for the BLM to publish the draft SEIS on July 8. Now to your question on project schedule, we wouldn't take FID until we get the final SEIS and a supportive record of decision by the BLM. And so that would allow us to move forward with Willow construction. Now related to FID, we would probably see that at the earliest later this year, and most likely early next. Now we are planning as far as scheduled to commence a 2022, 2023 winter construction season assuming we had a very favorable record of decision. Now that will allow us, Bob, to do civil construction and start putting roads in place for the project. I'll come to the alternatives here in a second. We do continue to work on detailed engineering to refine cost and schedule, as well as the final development modifications. And the reason I raised the developed modifications is in the current SEIS, there's a new alternative, Alternative E, that is responsive to the Alaska District Court order. And that is to minimize or reduce the surface impact on the Teshekpuk Lake Special Area. So that alternative, we think is a good path forward. It reduces the surface infrastructure and still maintains the estimated recoverable resources that we communicated in the market update of about 600 million barrels. Still looking, Bob, at 180,000 barrels a day gross before royalty for the project. Again, we're committed to Willow, and it remains competitive in the portfolio. We continue to see very strong stakeholder support, including the Alaska Congressional Delegation, the trades and unions. So the key thing is really looking forward to that final SEIS and a supportive record of decision.

Our next question in line comes from Mr. Neal Dingmann from Truist Securities.

My first question is about value creation. Specifically, you have an impressive plan indicating that more than 30% of cash from operations will be returned to shareholders. I'm curious about your expectations for future trading value for shareholders. Do you focus on per share growth metrics, or how do you define it?

We consider various ways to enhance shareholder value. It begins with our commitment to return at least 30% of cash from operations to shareholders, not just free cash flow. Historically, we've returned over 40% as commodity prices have increased, and our focus on lowering supply costs has guided our approach. Our goal is to reduce capital intensity while effectively managing our capital within the scope of our commitments. During our planning, we assess macroeconomic factors to determine an appropriate capital investment level after setting aside 30% of our cash for shareholders. We believe this offers a better value proposition than merely concentrating on growth or capital return. Our aim is to develop the company sustainably while ensuring shareholders receive their fair share of cash upfront. After addressing capital needs, we acknowledge the importance of maintaining a strong balance sheet, which is a vital asset for the company. We aim to retain some cash due to the volatility in commodity markets and our growth and development ambitions. We're not tied to a specific growth target but prioritize maximizing returns on and of capital. Our plans will adapt to ensure we achieve these objectives, leading to production targets and a sequencing of projects that support long-term company growth and development.

Yes, I love that financial flexibility, Ryan. I mean, a lot of even the bigger ones don't have it right now. And then lastly, maybe just a question for Jack on domestic OFS inflation. Jack, is it prudent to lock in other than rigs? Are you thinking about locking in maybe some other long-term contracts? I guess where I'm going with this is, I heard some folks out there are lock-in pipe even though they can't technically lock in the price, whatever it is, 6 months, 9 months from now. And so I'm just thinking, as you see the tightness out there right now, what are you guys doing to mitigate that?

Sure. We value flexibility in general in the program. We do have some modest amount of our rigs and frac spreads contracted. But what we're doing to mitigate that are several things. I mentioned those swaps and trades earlier. By the end of this year, we will have been able to drill 80 3-mile wells in the Permian over the last two years. We're drilling those wells faster. We're employing some frac technology in various places. And we're also keeping our programs steady, which we really have always valued, keeping a steady program and also keeping competition amongst our vendors, and we have all those things in place right now. So we're doing all we can, but there is still inflation out there.

Our next question on line comes from Mr. Leo Mariani from MKM Partners.

I was hoping to get a little bit more color around your longer-term LNG plans. Obviously, you guys have entered into a number of facilities, which will, I guess, come online in a handful of years. But some of the prepared comments, you guys referred to reassessing some of your domestic maybe just North America and overall gas potential as potential feedstock for some of these. So any just color around that? I mean, as you look to start-up date, is it possible you could be drilling more for gas here in the U.S. in a couple of years in ready debt feedstock for delivering into some of these facilities? And it sounds like that might be an economically advantageous thing for you to do.

Yes, I think we're also considering future developments in our Lower 48 Canadian portfolios. We have a substantial amount of gas resources, mostly associated with our oil production. We're evaluating the pipeline additions and capacity expansions to the Gulf Coast, California, and Mexico. As Bill mentioned earlier, we are one of the top three gas marketers in North America, which gives us insights into market trends and how we can supply gas to these regions. We want to take advantage of price differences between domestic Henry Hub and European and Asian markets, ensuring we aren't limited to a single market in North America for our gas sales. Our approach is thoroughly integrated and well-informed, enabling us to capitalize on arbitrage opportunities as they arise between various global regions.

And then just a quick question on the Eagle Ford for you folks. I certainly noticed there was a pretty healthy jump in production in the Eagle Ford this quarter. Had kind of been declining a little bit in the last handful of quarters. Is that kind of maybe now firmly back in growth mode? I know you guys have alluded to the past to kind of ramping that up in the next couple of years. And maybe this quarter, it was just better than expected, maybe you had a number of chunky pads come online all at once that kind of drove it. But just thoughts on Eagle Ford growth, is that going to continue to be sharply growing asset through the end of the year into next year?

This is Jack again. Good question. Yes, first of all, I'm very proud of the work the team is doing down in the Eagle Ford in all aspects of the business. But in the second quarter, specifically, there were some disproportionately weighted completions in the Eagle Ford. We're also having great success continuing that refrac program there. And in general, the Eagle Ford is growing towards its plateaued production, but it's not there yet. So it will be a continued source of Lower 48 production growth.

Our next question comes from Raphaël DuBois from Societe Generale.

The first one is related to Qatar NFE. It will be very helpful if you could maybe give us a bit more color so that we can model what you will learn through this deal. For instance, can you maybe clarify whether the gas to be sold will be oil-linked or will it be linked to a gas price hub? Any premium maybe to expect from the fact it will be a low carbon footprint? Or maybe can you compare the profitability of NFE with your two other LNG participations? That would be very helpful.

I can certainly start.

Let me start, and I'll kick it to Bill a little bit. I think a lot of that is still work to be done. I think Raphaël, in terms of the marketing of the gas will probably follow very similar approaches to what Qatar has done in the past. But Bill can supply a little bit of view. I think the focus of the project right now is the construction in EPC.

Yes, I think that's right, Ryan. And I would just reflect on Cutter Gas and Cutter Energy has been very, very successful. They're one of the largest gas LNG marketers in the world. They've been very successful about placing those volumes and the project will continue to have those places through that format. So I think it watch this space, but just reflect that Cutter Gas, Cutter Energy have been very, very effective at placing gas over time into valued markets.

And maybe another question. At full year results, you give us your thoughts on the increase in U.S. supply we should expect. And if memory is right, you mentioned 900,000 barrels per day. I was wondering if you could maybe refresh that thought 8 months into the year? And maybe give us your initial thoughts for the next couple of years.

Yes, Raphaël, I believe we are still looking at around 900,000 barrels a day. That figure represents a range from entry to exit for 2022. Going into 2023, we anticipate a similar, possibly slightly lower number, assuming commodity prices remain at their current levels and considering the inflationary pressures we are observing in the Lower 48. There are also constraints on the supply chain, labor, and other critical spending areas primarily in the Permian. So yes, those are the entry to exit rates we expect for this year and the next.

Thank you. We have no further questions at this time. I will now turn the call back over to Mark Keener for closing remarks.

Thanks, Richard, and thanks to all who joined today's call. And finally, thank you all for the kind sentiments. They are appreciated. And with that, I'll pass it back to you to wrap this up, Richard. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.