Welcome to the Third Quarter 2023 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. I will now turn the call over to Phil Gresh, Vice President, Investor Relations. Sir, you may begin.

Yes. Thank you, and welcome to everyone, to our third quarter 2023 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; and Tim Leach, Adviser to the CEO; Bill Bullock, Executive Vice President and Chief Financial Officer; Dominic Macklon, Executive Vice President of Strategy, Sustainability and Technology; Nick Olds, Executive Vice President of Lower 48; Andy O'Brien, Senior Vice President of Global Operations; Kirk Johnson, Senior Vice President, Lower 48, Assets and Operations; and Will Giraud, Senior Vice President, Corporate Planning and Development. Brian and Bill will kick it off with opening remarks, after which the team will be available for your questions. A few quick reminders. First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. Second, during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release, and in our periodic SEC filings. We will make reference to some non-GAAP financial measures. Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website. And before I turn it over, I just want to flag for today, we'll do one question per caller. So with that, let me turn it over to Ryan.

Thank you, Phil, and thank you to everyone for joining our third quarter 2023 earnings conference call. It was another solid quarter for ConocoPhillips, as the team continued to deliver strong underlying performance across the portfolio, and we have achieved several additional project milestones in our international portfolio in early October. Now before I get into the details, I wanted to address the topical news in the industry, which has been the M&A headlines in recent weeks. This is not a surprise to us. We have long said that we expect to see further industry consolidation. ConocoPhillips remains steadfast in our returns-focused value proposition and cost of supply principles, which creates a high bar for M&A. And as a reminder, we've been actively high grading our own portfolio over the past several years. And as a recent example, we are pleased to have closed on the acquisition of the remaining 50% of Surmont in early October. An opportunity came along to acquire this asset at a very attractive price that fit our financial framework, an asset we can make better through our full ownership and an acquisition that makes our 10-year plan even better. Surmont is a long-life, low-declining, and low-capital intensity asset that we know well. We achieved first steam from Pad 267 in the third quarter, and production is expected to start up in the first quarter of 2024. This is our first new pad addition since 2016, and as we said at our recent analyst meeting, we can leverage existing infrastructure to add additional pads with very limited capital requirements in the years ahead. Now moving to global LNG. We've also continued to progress our strategy, securing 1.5 mtpa regas capacity at the Gate LNG terminal in the Netherlands. This will take our total European regas capacity to 4.3 mtpa. We have now effectively secured destinations for nearly half of our Port Arthur LNG offtake commitment in the first six months since we sanctioned the project. Now elsewhere in the international portfolio, we started up our second central processing facility, CPF2 in the Montney. And in Norway, we just announced that we have started up three project developments ahead of schedule in October. This includes the company-operated Tommeliten Alpha A, subsea tieback project at Ekofisk, which is nearly six months earlier than originally planned as well as two non-operated projects. Finally, in China, our partner started at Bohai Phase 4b ahead of schedule in October. So as you can see, our diversified international portfolio continues to be a strong differentiator for our company. Shifting to results. We have record global and Lower 48 production in the third quarter, and we raised our full-year production guidance to account for the closing of the Surmont acquisition, all this while achieving continued capital efficiency improvements as our full-year capital guidance remains unchanged. We also continued to deliver on our returns to our shareholders. We increased our quarterly ordinary dividend by 14%, consistent with our long-term objective to deliver top quartile increases relative to the S&P 500. We have distributed $8.5 billion in dividends and buybacks year-to-date, and we remain on track for our $11 billion full-year target. And we did this while funding the shorter and longer-term organic capital growth opportunities that we see across the entire portfolio. The team continues to execute well. Our deep, durable, and diversified asset base continues to get better and better, and we are well positioned to generate competitive returns and cash flow for decades to come. Now let me turn the call over to Bill to cover our third quarter performance in more detail.

Thanks, Ryan. In the third quarter, we generated $2.16 per share in adjusted earnings. We produced 1,806,000 barrels of oil equivalent per day, representing 3% underlying growth year-over-year. Planned turnarounds were successfully completed in Norway and Alaska, and Lower 48 production averaged 1,083,000 barrels a day equivalent per day, including 722,000 from the Permian, 232,000 from the Eagle Ford, and 111,000 from the Bakken. Lower 48 underlying production grew 8% year-on-year with new wells online and strong well performance relative to our expectations. Moving to cash flows, third-quarter CFO was $5.5 billion, including APLNG distributions of $442 million. Third-quarter capital expenditures were $2.5 billion, which included $360 million for longer cycle projects. And through the end of the third quarter, we have now funded $875 million for Port Arthur LNG, out of our planned $1.1 billion for the year. Regarding returns of capital, we delivered $2.6 billion to shareholders in the third quarter. This was via $1.3 billion in share buybacks and $1.3 billion in ordinary dividends and VROC payments. And today, as Ryan said, we announced an increase to our ordinary dividend of 14% to $0.58 per share. We ended the quarter with cash and short-term investments of $9.7 billion, which included proceeds from the $2.7 billion of long-term debt that we issued to fund the Surmont acquisition, which closed in early October. Before shifting to guidance, I do want to take a quick moment to update about our VROC. Beginning in 2024, we will be aligning both the announcement timing and subsequent payment of our VROC with our ordinary dividend. Therefore, you can expect us to provide details on our first-quarter VROC payment on the fourth-quarter call in February. Now turning to guidance, which now reflects additional 50% of Surmont starting in early October, we forecast fourth-quarter production to be in a range of 1.86 million to 1.9 million barrels of oil equivalent per day. Full-year production guidance is now roughly 1.82 million barrels of oil equivalent today. Now, to put this production guidance in the context, we expect underlying growth for both the fourth quarter and the full year to be roughly 4% year-over-year, which includes Lower 48 production growth of roughly 7%. And this is very consistent with our full-year guidance and our long-term plan we laid out at our Analyst and Investor Meeting. For APLNG, we expect distributions of $300 million in the fourth quarter and $1.9 billion for the full year. And while APLNG distributions can vary quarter-to-quarter, a normalized run rate to think about moving forward is around $400 million per quarter at current price levels. Shifting to adjusted operating costs, we raised our full-year guidance by $300 million to $8.6 billion. This was driven by our increased working interest in Surmont, increased Lower 48 non-operated activity and inflationary impacts on the Lower 48. We've also raised our DD&A guidance by $100 million to $8.3 billion, which is also primarily due to Surmont. And full-year adjusted corporate net loss guidance remains unchanged at roughly $800 million, and the second half run rate is a good starting point for 2024. Finally, our full-year capital spending guidance range is also unchanged. So to wrap up, we had another solid operational quarter. We continued to deliver on our strategic initiatives across our diverse portfolio, and we remain highly competitive on our shareholder distributions. That concludes our prepared remarks. I'll now turn it back over to the operator to start the Q&A.

Our first question comes from Neil Mehta with Goldman Sachs.

There's been a lot of variability in Lower 48 results from some of your competitors, and you guys have been very steady tracking at the 7% growth rate. Just love your perspective and walking through the basins and particularly the Permian, what is working, what's not for you guys? And how do you feel about the plan as you move into 2024?

Yes, Neil, this is Nick. You're right. I mean, overall, if you look at our performance across all of our basins, it's been strong, and in line with prior year performance across, again, all those Lower 48 assets. I'd also mention that it's been in line with our type curve expectations. I'll call out, for example, Delaware well performance is showing top quartile on volumes produced, not only on a barrel of oil basis, but also on a BOE basis per foot. So we're seeing very encouraging results there. I think the key point, too, is the strong performance reinforces our strong focus on returns, capital-efficient environment that we've set there.

And I would add, Neil, it speaks again to the quality and the depth of the inventory in the company. We've got, we're prosecuting some of the best acreage in the basin and doing it in such a way that's focused on capital efficiency and returns, as Nick described.

Our next question comes from the line of John Royall with JPMorgan.

You've had a handful of international project start-ups that you touched on in the release. If you could give us some more color on these projects, that would be helpful. And maybe if you could tie that into a growth outlook for the international business in '24 as well, that would be helpful.

Andy here. It’s a bit early to discuss full-year guidance for 2024. As you noted, we've received some positive updates regarding our Alaskan international projects, showing significant progress across the portfolio. It’s encouraging to see many projects reaching major milestones either on or ahead of schedule and budget. In Norway, we achieved first production ahead of schedule on three out of our four subsea tiebacks, and we anticipate the fourth will come online as planned in the second quarter of 2024. Collectively, these four projects are expected to contribute around 20,000 barrels per day of production next year, which should more than compensate for the typical decline we expect in 2024. In China, our partner-operated Bohai Phase 4b also reached first production ahead of schedule from its first platform. This project will involve two platforms connected to a central processing facility, with the second platform expected to begin operations in the first quarter. This sets us up for the opportunity to drill new wells in Bohai for the next four to five years. Additionally, we’ve hit significant milestones in Canada with CPF2 in the Montney and Pad 267 in Surmont. CPF2 started up successfully in September, contributing approximately 100 million cubic feet per day of gas processing and around 30,000 barrels of condensate above handling capacity. We averaged about 20,000 barrels of production in the Montney during Q3, and we plan to substantially increase that next year. For Surmont Pad 267, we initiated first steam production in September, with the first half expected in early 2024. Once online, we anticipate Surmont will grow by about 5,000 to 10,000 barrels per day next year, including a month-long turnaround every five years. I’m very proud of our progress and execution across these projects. This demonstrates how we leverage our existing infrastructure to capitalize on low-cost supply opportunities. I hope this gives you a sense of the momentum we’re building as we move into next year.

Our next question comes from the line of Steve Richardson with Evercore ISI.

Bill, I was wondering if maybe you could help us on a little bit of broad strokes on 2024, CapEx thoughts. I think in the past, you've talked about kind of flattish CapEx around $11 billion, with admitting, there's a lot of moving parts in an M&A environment. Maybe you could just talk a little bit about that as you're thinking forward.

Yes, it's Dominic. Stephen, what we can say is very much aligned with the AIM framework we discussed regarding CapEx. To summarize the various elements, we expect that if Willow is approved, the spending on that project will increase. Additionally, there's about $100 million more for the additional 50% of the Surmont term that we are incorporating. However, these increases will largely be balanced by reduced spending on our LNG projects and the conclusion of project capital in Norway. The main point is that this aligns closely with the framework we outlined at AIM, and of course, it includes the additional 50% for Surmont.

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

Although Phil has moved to the opposing side with one question, I would like to make a comment and then ask my question. My comment is that your stock has increased nearly 5% this morning. It seems that your dividend decision is gaining appreciation in the market, and congratulations on that move. We hope to see more of it. Now, my question is related to a query raised earlier about performance in the Permian. I would like to reframe it; one of your major competitors faced challenges with their non-operated portfolio this quarter. Given that a significant part of your production comes from non-operated sources, is there a noticeable difference between your operated and non-operated performance that has contributed to your consistent year-over-year production growth?

I can't help but respond to your comment, Doug, and then I'll let Nick address a question about the Lower 48. This aligns perfectly with our expectation of achieving top quartile targeted dividend growth as a company compared to the S&P 500. That's our plan, and we are committed to executing it. Now, I'll let Nick discuss your question regarding the Permian.

Yes, Doug, that's a great question. Looking at the Q2 to Q3 performance this year, we experienced a 2% increase, indicating sequential growth. As Bill mentioned earlier, we're seeing a 7% increase year-over-year. This includes both our operated and non-operated portfolios, both of which are performing well. Specifically, the increase from Q2 to Q3 was largely driven by our operated Permian program and OBO. We are seeing growth in the assets operated by others, along with some improvement in the Bakken as well. These operated by others assets are very competitive; we evaluate every opportunity and benchmark them accordingly, and they perform well within our cost supply framework. To remind you, approximately 30% of our production from the Permian comes from operated by others. Looking back to our Analyst Investor Day, we have two-thirds of our inventories in the Delaware and one-third in the Midland Basin, contributing to the overall 5% in the Lower 48. Ultimately, both segments are competing effectively, and we will continue to assess every opportunity to ensure we are investing wisely and maximizing capital efficiency.

Our next question comes from the line of Lloyd Byrne with Jefferies.

Ryan, you mentioned it in your prepared remarks, but I'm hoping you could comment further on international gas integration strategy. And I recognize it's early, but by our numbers, there seems like a lot of option value there. So maybe just thought process behind it and maybe any targets you might have to help us think about the future there.

Yes, I can let Bill provide you with more details on that, Lloyd. We are excited about the opportunity to increase regasification capacity in the Netherlands at the Gate LNG, which complements our operations in Germany. We are also exploring additional options as we work to manage Port Arthur volumes and other global volumes into that market. We believe it will be a strong market for many decades, which is why we are pursuing this strategy. Bill can address your specific questions on the details.

I'm happy to provide more details on that. We are very focused on market development, and as we've mentioned, we aim to proceed in a step-by-step manner regarding supply generation. Recently, we announced developments at Port Arthur LNG and continued strong progress at German LNG, which has a regas capacity of 2.8 million tonnes per annum. Out of this, 2 million tonnes are dedicated to supporting our LNG from Qatar, leaving 0.8 million tonnes for Germany. Additionally, we have added 1.5 million tonnes of regas capacity at Gate, bringing the total to 2.3 million tonnes, which is roughly half of the capacity at Port Arthur. Importantly, we are seeing significant interest and demand for LNG. We are working to develop a diversified portfolio that includes sales to Europe and Asia, possibly incorporating some FOB sales at our facility and a variety of term lengths. I am pleased with our progress; within six months of final investment decision on Port Arthur, we have placed about half of its capacity. To analyze our returns, consider the existing capacity into Germany and the TTF: start with the Henry Hub price, add liquefaction, shipping, and regas costs, and compare that against anticipated European gas prices. This will give you a foundational cash flow for volumes into Europe before considering additional optionality. A similar analysis can be applied for Asia. We agree that these developments are valuable additions to our portfolio, and we are excited about the progress we are making.

Our next question comes from the line of Devin McDermott with Morgan Stanley.

So I want to echo the earlier comment on the dividend raise and ask a question on the shareholder return. So it's good to see the 14% increase. I was wondering if this large change in the dividend is more tied to incremental cash flow on Surmont, or there's been a broader change in how you're thinking about the target payout, or dividend breakeven as you look out at the business over the next few years? And just as part of that. Maybe you can give us an update on your broader thinking on shareholder return strategy and the breakdown of dividend VROC and buybacks in the context of dividends increase.

Yes, I don't believe anything has changed in our framework, which we outlined fairly thoroughly in our last analyst meeting. Based on our mid-cycle price expectations, you can anticipate that we will return at least 30% of our cash flow to our shareholders. Additionally, when prices exceed our mid-cycle targets, which they currently are, you can expect an even greater return of cash. Over the past 5 to 6 years, we have returned about 40% to 45% of our cash back to shareholders, through a combination of dividend payments and share repurchases. Our approach remains consistent. We aim to provide an affordable and reliable dividend that grows competitively with the top quartile of the S&P 500 over time. We also plan to repurchase some of our shares throughout the cycle and have introduced a third component, VROC, to offer additional returns to our shareholders when prices are above our mid-cycle targets. This strategy has served the company well. For this year, we expect cash flow to be close to $22 billion, and we plan to return half of that to our shareholders, which sets a solid foundation for next year.

Our next question comes from the line of Nitin Kumar with Mizuho.

I guess just sticking with the theme of M&A and I appreciate, Ryan, you touched on it in your comments. But one of your peers out there has talked about improving recoveries in the Permian to the tune of 20% or higher than everybody else. You operate across the entire Permian Basin. I'm curious, are you deploying or seeing others deploy technologies that you think can improve recovery rates that significantly?

Yes. I'll let Nick respond to that specifically. I want to make a general comment. As we discuss this topic, it's important to note that many people in the industry sometimes confuse inflation with recovery and recovery rates. We need to be cautious in our discussions, especially regarding unconventional resources. We're doing everything we can to enhance the recovery from the wells, acreage, blocks, and layers in our portfolio. However, we must avoid conflating this with recovery factor or recovery rate. I can have Nick elaborate on the specific measures we're taking to ensure we achieve maximum recovery from our assets.

Thanks, Ryan. Yes, our asset teams are very focused on optimizing the recovery of our wells and development projects throughout all of our Lower 48 assets. It's essential that we maximize recovery while also improving capital, which aligns with our returns-focused strategy and cost supply framework that guides our decision-making. We are enhancing recovery through three primary areas, and I will outline what we are examining and implementing within our assets. First, we make development decisions, which is our initial focus. The second area is optimizing the reservoir. The third is exploring enhanced oil recovery, which is more of a long-term approach. In the Permian, as we noted at the Analyst Investor Day, we have two decades of inventory at current rig activity levels. Our emphasis is on development decisions and reservoir optimization to boost recovery. For instance, lateral length is crucial; the longer the lateral, the greater the recovery per well. Transitioning from a one-mile lateral to a two- or three-mile lateral significantly increases recovery and enhances capital efficiency by 30% to 40%. Currently, 80% of our Permian well inventory is 1.5 miles or longer, with 60% being two miles or more, and we are progressively executing on three-mile laterals. In well completion, we are conducting noteworthy work in the Bakken using multi-variable analysis to optimize completion design, which has yielded very favorable recent results in terms of recovery and capital efficiency. Additionally, we are implementing co-development in the Midland Basin, which helps minimize parent-child impacts while enhancing both recovery and capital efficiency. Our efforts over the past four years in both the Midland and Delaware Basins have demonstrated improved performance. For reservoir optimization, particularly in Eagle Ford, we are utilizing techniques to refrack aging wells, resulting in a 60% increase in expected ultimate recovery, which is highly competitive within our cost supply framework. In the Bakken, we are deploying infill wells and upcoming edge wells to further enhance overall recovery, which also aligns with competitive cost of supply. Regarding enhanced oil recovery, we have conducted numerous pilot studies primarily in the Eagle Ford involving gas injection and huff-and-puff methods, which have shown technical success in injectivity and oil response. However, these projects do not currently compete with our extensive drill inventory. We will continue to study and analyze these initiatives for future consideration. Overall, through longer laterals, refined completion designs, and infill wells, we are actively improving recovery across our assets.

Our next question comes from the line of Roger Read with Wells Fargo.

There has been some discussion about Alaska regarding regulatory and legislative matters, especially as we approach the winter season. I would like to know more about the situation with Willow and other projects there.

This is Andy. I'll address the legal aspects first and then provide an update on our project. Regarding the legal situation, there are ongoing lawsuits contesting the federal government's approval of the project. As I mentioned previously, we anticipate a ruling on this in November. The preliminary rulings in April were favorable, and the upcoming ruling will cover the entire legal challenge. While I may be repeating myself, I'm pleased with how the Bureau of Land Management and other agencies have handled the process and fulfilled the requirements for approval. We are confident and look forward to the court rulings in November as we prepare for the 2024 season. You also referred to the Department of Interior's proposed regulations for managing and protecting the National Petroleum Reserve in Alaska that were introduced in September. We don't expect these draft rules to affect Willow or hinder our exploration program, nor do they impact the 10-year plan previously outlined at AIM. However, we are concerned that if the rules are finalized as they are currently written, they could hinder future developments beyond Willow in the National Petroleum Reserve in Alaska. We plan to provide feedback to the Department of Interior to align the proposed rules with the existing statute. It's important to note that the statute acknowledges the primary purpose of the National Petroleum Reserve is to enhance domestic oil supply. On the project front, Willow aligns perfectly with our expertise. There are no first-of-a-kind risks involved; it's comprised of three drill sites and one new processing facility. Our strong track record ensures timely and budget-compliant delivery. Currently, our work is progressing smoothly, and our 2023 capital is fully included in the overall company guidance provided today. We have started the initial phase of module fabrication on the Gulf Coast. On the North Slope, we've successfully opened the gravel mine and are gearing up for the construction season in 2024. More than half of the project's scope is already secured with firm contracts, which include clauses allowing us to exit if we do not finalize investment decisions. Of the contracts issued to date, 75% are structured as lump sum or unit rate contracts, providing us with price certainty and reducing our exposure to inflation. As we continue contract negotiations, our capital estimate for first production remains unchanged at $7 billion to $7.5 billion as previously communicated. This should give you a solid update on both the legal and project status.

Our next question comes from the line of Ryan Todd with Piper Sandler.

Ryan, you've been actively managing the portfolio over the past few years across various regions and types of assets. Some of this has been opportunistic, particularly with the timing of projects like Surmont and APLNG. Looking ahead, do you see more opportunities for managing the portfolio? Are there significant chances for divesting certain assets that we should anticipate as you continue your development efforts? Are there any areas where you wish to adjust or enhance your exposure in order to maintain long-term competitiveness?

Yes, Ryan. As we highlighted at the Analyst Meeting earlier this year, we are quite satisfied with the progress we've made over the past 4 to 5 years, which we believe has resulted in a strong 10-year plan. I am very pleased with the development of our portfolio, which is global and diverse. It encompasses a good mix of short-, medium-, and long-term investment opportunities. All these investments lead to 20 billion barrels with a cost of supply of less than $40. We have clear visibility into what we believe is a solid plan. We are diligent in assessing our portfolio, and if something doesn't perform, we actively seek opportunities to exit. Currently, I wouldn’t say we have anything significant in our portfolio that falls into that category. We always aim to be opportunistic, which aligns with the APLNG and Surmont ROFR we hold. You never know when partners might make unexpected changes, which can provide a valuable opportunity to acquire an asset we are familiar with and can improve. Ultimately, this enhances our 10-year plan. We are consistently looking to identify such opportunities since they can arise unexpectedly, and we are very opportunistic about them. Just to reiterate, our framework remains in place. Any opportunity must meet our financial criteria, must show potential for improvement, and should contribute positively to our compelling 10-year plan, which is a stringent requirement within the company.

Our next question comes from the line of Paul Cheng with Scotiabank.

Can you hear me?

Yes, we sure can, Paul.

If I can revisit the Permian, what is your current average lateral length? How much do you believe you can increase or extend it over the next few years? Is that one of the main factors you think could enhance your results in your Permian operations? Additionally, have you tested this, as I assume there will eventually be an economy of scale as you extend further? Have you conducted any experiments to determine what that limit might be? Is it 4 miles, or potentially longer or shorter than that?

Yes. Thanks, Paul. I can let Nick kind of weigh in on some of that. We're not, yes, I think lateral length is just one of the things that we're working on. Nick described a bunch more on an earlier question around completion efficiency and how we're attacking the spacing and the stacking. So I think it's all of those things that we're trying to attack, and they're different depending on where you're at in the Bakken, the Eagle Ford or the Permian. But we have deep experience in all three of those basins and using all that knowledge to make sure we're maximizing the recovery and minimizing the cost of supply, and maximizing the efficiency that we're getting out of it, specifically on lateral lengths, I can let Nick weigh in on that.

Yes, Paul. To reiterate, we have a significant deep and broad inventory of long laterals across our assets. As I mentioned earlier, 80% of our Permian inventory is 1.5 miles or longer, with 60% exceeding 2 miles. We are increasingly seeing 3-mile laterals, and the results from these are encouraging from both our 2022 and 2023 programs. Our teams are actively identifying core opportunities, not just in the Permian but also in the Bakken, where we've concluded some trades that will enable us to drill 3-mile laterals in the future. This enhances our portfolio of long laterals across all four assets. Regarding the potential for longer lateral lengths, such as four miles, while there may be benefits in terms of reducing supply costs, we also have to consider the operational risks involved, including the drilling phase and future workovers. Nevertheless, the performance of the 3-mile laterals has been excellent, and we possess a robust inventory of long laterals as previously stated.

Our next question comes from the line of Josh Silverstein with UBS.

Ryan, I appreciate the comments before on the return to capital thoughts for next year. I was curious with the added debt from the Surmont transaction, how you might think of additional shareholder returns versus this year or that want to build cash, or pay down the debt there.

Yes, I think we're in that planning process as we kind of think about next year and all those moving pieces. So I say it looks to me like at this 10 seconds, commodity prices are kind of very similar to where we were coming out at the end of last year coming into the beginning of 2023. So I think that framework around total return as a starting point is pretty good for 2024. We'll just have to see what commodity prices are as we go forward. And we have a plan, and Bill can address that, to kind of pay off the debt as it comes due over the next few years. That gets us down to our original target of $15 billion in gross debt, and we can continue to do that. And I think if we had a very large upcycle to the price commodity price, we might look at adding more cash to the balance sheet as well. So I think all three of those are in play as we think about, what we do over the course of each quarter as we go into next year.

Our next question comes from the line of Sam Margolin with Wolfe Research.

I guess I wanted to ask for an update maybe on the Venezuela process. It's come up in prior calls and the process is advancing. And I guess, specifically, I want to ask about a scenario where the assets that aren't strategic to you get returned or surrendered to creditors, and what might be the path forward from there because it's a large claim, and it's material. And it seems like it will be a good outcome for you, but might require some actions in the aftermath.

Yes. Sure, Andrew. It's Tim. But yes, we're in a process with the Venezuelans right now. They also have a considerable amount of money through both our ICSID and our ICC claims, approaching over $8 billion. They own some, on the full judgment on the ICC, they still owe us $1.4 billion, $1.5 billion. So we're pursuing that pretty aggressively. I think we're watching the progress closely. Clearly, the U.S. government has provided a lifting of some, if not all, of the sanctions here, waiting on results of what the Venezuelans do on the other end for free and fair elections. So that may create a bit of an opening. But this is a long process, but we're pretty committed to doing everything we can to make sure we get our money out of Venezuelans that they owe us. And that's what we're focused on.

Our next question comes from the line of Neal Dingmann with Truist Securities.

My question, you get on this a little bit, just on M&A specifically, why I appreciate your earlier comments about any assets needing in the 10-year plan. I'm just wondering, is there a preference for when you're seeing things shorter longer-term cycle assets? And just also curious on how you view valuations of some of the recent public deals.

Well, certainly, the way we look at it, Neal, is we like a global, we like a diverse portfolio. We like it to be balanced. I think we're mostly focused on what's the cost of supply to make sure it fits our framework around that, and that any asset that you bring into the company, make sure it competes for capital on an ongoing basis against a pretty rich, deep, durable, long life and a lot of inventory sitting in the company today. So as I said, it's a pretty high bar. I don't know quite how to comment on the recent deals that have been done. Those are transactions. Those are really good companies that were bought. Clearly, they have good assets. we're pretty familiar with them. We've watched them for a long period of time, and they're good companies with good assets. Transactions were in a part of the cycle that's a little frothy and probably at a higher mid-cycle price than we would ascribe to them, I guess. Maybe that's all I should probably say.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

I was curious about whether the consolidation leading to larger peers in the Permian affects the competitiveness of development and positioning. Specifically, how does it impact services and midstream capacity as you aim for a 7% growth CAGR over the next decade and beyond?

I don't see any significant issues there at all, Scott. There are many operators already present in the Permian Basin, and it appears that the service side of the business is managing all the activity we have in that area. While there have been times of tightness in certain categories, we believe that for the most part, it won't pose a major concern for us moving forward. Being one of the larger operators in the basin allows us to attract the attention of service companies because they recognize that we have a sustainable program. They understand that we are not going to shift our plans abruptly, which makes us the type of customer they prefer to work with. Therefore, we don’t foresee any risk associated with the ongoing consolidation trend in the Permian, and it is likely to persist. No questions. More probably needs to happen.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

I wonder if you can provide your current thoughts on adding activity in the Lower 48. I know you said that you can grow production without adding, but others are looking at the current service prices and commodity prices and seeing this is a good time to add. So I just want to hear your most recent thoughts on that.

Well, I think that will be part of the process we're going through right now, Kevin. I think we're trying to think about what 2024 looks like, but our starting point is, we're seeing the efficiencies and we're seeing growth coming out of our assets. So we started to a place that says, let's just think about flat scope, and then we'll think about these other drivers like commodity price or service capability to your point and make a decision as we go into next year about what the scope and the resulting capital will look like.

Our last question will come from the line of Leo Mariani with ROTH MKM.

Could you share your observations regarding the trends in Lower 48 service costs? A few months ago, there were strong expectations that costs would decrease, but with commodity prices rebounding, I’d appreciate your insights on the current leading edge costs.

Yes, Leo, it's Dominic. As we discussed last quarter, we're definitely observing some deflation in the Lower 48. Looking at our capital expenditures this quarter, that trend is reflected in the lower spending compared to the previous quarter. However, we still anticipate that our overall company capital inflation will average in the mid-single digits this year compared to last year, which is included in our guidance. As we approach year-end, we are considering how the market is currently balanced. There is some deflation occurring, yet we have noticed a recent increase in oil and gas prices. We are closely examining how these trends will continue into next year. As I mentioned earlier, our overall capital expectations for next year align with what we outlined at AIM, plus our additional interest in Surmont. We're monitoring this situation closely, and it provides a good idea of our current thinking.

We have no further questions at this time. Thank you, ladies and gentlemen. This concludes today's conference call. Thank you for participating. You may now disconnect.