Phil Gresh - Vice President, Investor Relations Ryan Lance - Chairman and CEO Bill Bullock - Executive Vice President and Chief Financial Officer Andy O’Brien - SVP of Strategy, Commercial Sustainability and Technology Nick Olds - Executive Vice President of Lower 48 Kirk Johnson - Senior Vice President of Global Operations

Welcome to the Third Quarter 2024 ConocoPhillips Earnings Conference Call. My name is Liz 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. [Operator Instructions] I will now turn the call over to Phil Gresh, Vice President, Investor Relations. Sir, you may begin.

Thank you, Liz, and welcome everyone to our third quarter 2024 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; Bill Bullock, Executive Vice President and Chief Financial Officer; Andy O’Brien, Senior Vice President of Strategy, Commercial Sustainability and Technology; Nick Olds, Executive Vice President of Lower 48; and Kirk Johnson, Senior Vice President of Global Operations. Ryan and Bill will kick of the call with some opening remarks after which the team will be available for your questions. Along with today’s release, we published a supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. 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 measure can be found in today’s release and on our website. As we move to the Q&A afterwards, as reminder we will take one question per caller. With that, I will turn the call over to Ryan.

Thanks, Phil, and thank you to everyone for joining our third quarter 2024 earnings conference call. Let me start with a few comments about our results and the outlook for the rest of the year, and then I will provide an update on the Marathon Oil acquisition. Starting with the results, the company demonstrated strong execution in the third quarter. We exceeded the high end of our production guidance for the quarter and raised our full year production outlook largely driven by lower 48 performance. On return of capital, we remain on track to distribute at least $9 billion into shareholders this year. We have officially incorporated our VROC into the ordinary dividend to the ordinary dividend and consistent with our long-term track record, we are confident that we can grow our ordinary dividend at a top quartile rate relative to the S&P 500. On buybacks, our planned fourth quarter share repurchases will approach $2 billion and we have increased our existing share repurchase authorization by up to $20 billion. Shifting to our planned acquisition of Marathon Oil, we're still on track to close this quarter. In the meantime, integration planning is progressing well. The team is now fully mapped out how we plan to achieve the initial guidance of at least $500 million of synergies, primarily from the overhead and operating cost reduction categories that we have previously talked about. And we now expect to at least double the initial $500 million target driven by capital optimization. While we are still finalizing our 2025 budget and will provide formal guidance in February, we are confident that the combined company can grow at a low-single-digit rate again in 2025 with pro-form a CapEx of less than $13 billion. So to wrap up, we're pleased with our operational execution and we look forward to closing the Marathon Oil acquisition later this quarter. Now let me turn the call over to Bill, to cover our third quarter performance and 2024 guidance in more detail.

Well, thanks, Ryan. In the Q3, we generated $1.78 per share in adjusted earnings. We produced 1,917,000 barrels of oil equivalent per day, representing 3% underlying growth year-over-year. And that's despite having an estimated impact of 85,000 barrels per day of turnarounds during the quarter, including approximately 55,000 barrels for Surmont's once every five year turnaround. Lower 48 achieved record production of 1,147,000 barrels of oil equivalent per day, which represents 6% underlying growth year-over-year. Now by basin, we produced 781,000 in the Permian, 246,000 in the Eagle Ford and 107,000 in the Bakken. Moving to cash flows, third quarter CFO was over $4.7 billion which included over $400 million of APLNG distributions. Operating working capital was a $1 billion tailwind in the quarter, Capital expenditures were $2.9 billion and we returned $2.1 billion to shareholders, including $1.2 billion in buybacks and $900 million in ordinary dividends and VROC payments. We ended the quarter with cash and short-term investments of $7.1 billion and $101 billion in long-term liquid investments. Now turning to guidance. For the fourth quarter, we expect production to be in a range of 1.99 million to 2.03 million barrels per day. For the full year, we now expect production to be 1.94 million to 1.95 million barrels per day, up 10,000 barrels per day from prior guidance. On cash flows, we're increasing full year guidance for APLNG distributions by $100 million to $1.5 billion, and we expect over $200 million of distributions in the fourth quarter. All other guidance items are unchanged. And as a reminder, guidance excludes the impact of pending acquisitions. So in conclusion, we continue to deliver on our strategic initiatives, we remain focused on executing our plan for 2024. We are committed to staying highly competitive on our shareholder distributions and are progressing toward closing the Marathon transaction. That concludes our prepared remarks. I'll turn it back over. I'll turn it back over to the operator to start the Q&A.

[Operator Instructions] Our first question comes from Neil Mehta with Goldman Sachs.

I wanted to spend some time on the synergies, because the comment on the call about the doubling of the synergies is notable. Can you just unpack that? Where are you seeing it? Should we think about it as an OpEx item, as capital items and when we could actually see it in the numbers? Is this something, how long does it take to be realized? Andy O'Brien: Neil, this is Andy. I can take that question. So just to unpack it and maybe go back to what we said on the second quarter call was that we stood up a team, who've been working the bottoms up integration and synergy capture detail. Now that team has already fully mapped out how we're going to achieve $500 million that we initially guided to on a run rate basis within a year of closing. We've also now finished designing the organization. We've identified non-labor duplication and process efficiencies to optimize costs. Also, you might remember during the acquisition announcement call I mentioned there'd be additional upside from reworking the combined drilling and refrac programs at the asset level. We've now completed that detailed modeling across all three basins. So versus 2024 capital spend, we plan to reduce the combined ConocoPhillips and Marathon program by at least $500 million in 2025. Now, these reductions come primarily from Eagle Ford and Bakken. We're confident in our ability to achieve an optimal plateau level at lower levels of activities versus a standalone companies or simply put, we need fewer rigs and fewer frack crews to achieve the same outcome. So when you combine all of that with the original announced synergies of $500 million, we now have clear line of sight of doubling that to $1 billion. Now, in terms of the timing of those synergies, so you can effectively think of the CapEx is happening immediately when we get into 2025 in the reduction in the capital budget. And as I said, earlier that the OpEx and G&A so that's going to ramp over time. But we'll be there on a run rate within the 12 months of closing.

Yes, Neil, I would probably add that recognize this is all done pre-close, so we haven't closed the transaction and haven't really got into a complete look under the hood. So I would, I'm guessing or expecting that we'll have additional OpEx opportunities, we'll have additional capital opportunities, additional commercial opportunities is we're able to dive in post-close and look a little bit closer at the contracts and some of those things that we have going on. So, stay tuned in this space.

Our next question comes from Doug Leggate with Wolf Research.

A - Andy O'Brien: Doug, Andy here. Maybe I'll take you back to sort of what we said back in our AIM presentation and build it from there. So in AIM, we said the long-term average free cash flow breakeven, excluding the dividends within the mid-30s. And also that's a little higher in the early years as we invest in Willow.Now with the Marathon transaction, plus the increased synergies we've announced today, that's going to further lower the number by a couple of dollars. So to the low 30s.And then of course, you need to add the dividend on top of that and that's about $10. So having such a low free cash flow breakeven is really one of the key reasons why we're able to increase the ordinary dividend by 34%. And very importantly, that's how we can continue our commitment to the S&P 500 top quartile growth. So, hopefully that unpacks, Doug, the sort of strength that we have there.

And hopefully, you'll enjoy the 34% raise to the ordinary dividend, Doug.

Q - Stephen Richardson: A - Ryan Lance: A - Andy O'Brien: Sure. Thanks, Ryan. As Ryan said, we're saying our expectation is less than 13 in ’25. And just to put that in context, that compares to 13.5 for the combined ConocoPhillips and Marathon guidance for ‘24. And the primary driver of that reduction is really what I just covered in the Marathon synergies comment across the Lower 48. It's also important to say without lower CapEx number that we absolutely can continue to have growth in the low single-digits and that's going to be fairly balanced across the Lower 48 and ANI.

So I wanted to build on some of the comments so far on 2025, but shift over to shareholder returns, I think at the time of the Marathon transaction, you talked about an over $11 billion target and commodity prices have been very volatile since then but you're also messaging more capital-efficient program and better synergies through -- as per the prior few questions. I was wondering if you can kind of put this all together and how you're thinking about pro-forma shareholder returns once the transaction closes and some of the moving pieces around that number.

Devin, yes, a lot of moving pieces, as you might imagine coming through that. I'll probably start the answer by just reflecting a little bit about how we've done in 2024. So I think it informs kind of how we think about this and how we might approach 2025. I think it's a little bit early to give an indication of what '25 is because some of the pieces of moving parts that Steve just addressed, we got, again, backwardation in the oil curve, Contango in the gas curve and a lot of volatility happening in the commodity price. So as we get through the course of the year and into next year, we'll all be kind of trying to assess what our CFO is. But if you look at our past history, six, seven years now, we've provided about 45% of our CFO has gone back to the shareholder in form of distributions through both the dividend channel and share buybacks. So we'll certainly plan to continue to offer our shareholders a pretty compelling value proposition for the company. But if you look at -- as we got into 2024, early 2024, we were thinking arguably an $80 kind of price deck. It's been softer than that. But look, we paid off some debt. We've stuck to our $9 billion distribution target. We had a little bit of disposition monies come in. We've paid off some debt this year. We got a strong balance sheet. We've got cash on the balance sheet. And look, we're made for the kind of volatility that we're seeing in the market today. So those are the pieces that we're going to take into consideration as we go into 2025. We've got a lot of levers. We've got a lot of ways to think about the business. We got the synergy. And look, the operations are running really well, both in the international space under Kirk's leadership and the Lower 48 under Nick's leadership. So that's resulted in the extra production that we're getting out of the year and the efficiency that we're driving through the system. So we're going to put all those levers, all those pieces and parts together when we get to the end of the year, take an assessment of the commodity price market, what we think the market will give us in 2025 and come up with a distribution target for next year post the Marathon close. So we've got a lot of moving pieces in it but the shareholders should expect to get a significant portion of our cash flow coming back off the top and probably something that exceeds our floor of 30% that we talk about. It's going to be something probably significantly higher than that.

Our next question comes from Arun Jayaram with JPMorgan.

I wanted to get your thoughts on just capital allocation to the Marathon properties. I know you're probably thinking about capital allocation to the Lower 48 as a whole. But I wanted to get maybe some insights on just the Marathon properties because if we look at their activity trends, they ran about 11 rigs to 12 rigs on their properties in the first half, and they've downshifted to five or six in the back half. So how do you plan to manage those properties on a go-forward basis?

Yes, I can let Andy jump in, Arun, but that was one of the bit of the surprises that we saw when we got into the data room. And it's really one of the attractive features that we saw with the Marathon properties, some good low cost of supply resources they compete in the portfolio. And look, with the scale that we have in our company and combining with Marathon, we can run these assets differently. And I'll tell you our Lower 48 team is chomping at the bit to get a hold of these assets because we won't have an execution plan that looks like what you just described, where you ramp up early in the year and you back off later in the year. With the scale that we bring to the combination, we can just -- we found that running at a consistent pace is much better than trying to ramp up and ramp down, which you have to do when you either don't have scale or the capacity to do those things. And we're just going to run the assets differently. And I can let Nick provide a little bit more detail on the competitiveness within the portfolio.

Yes. Arun, just kind of building on what Ryan just mentioned, we've looked at running level-loaded and steady state since mid-2022. Clearly, we have shown you that through that approach that we've improved operating efficiencies on the drilling side as well as the frac side. And so as Ryan mentioned, we're going to apply that methodology and that strategy on the Marathon acreage. We're actually really excited to bring that in. As you've seen before, traditionally, they have been really kind of heavy on the front end the first half with frac and drilling activity, and then they level off, as Ryan mentioned, in the second half. So we're going to run at steady state level loaded. We've seen even this year to kind of give you a proof point, we're delivering with flat activity, 10% more activity than 2023. So that means more feet per day, it means more wells. And for the folks on the phone, you're clearly seeing that in the bottom line production performance for Lower 48. The Marathon assets, as we've talked about in the acquisition case, very competitive and cost of supply across all the basins. We've got 2,000 wells and the bulk of that's in Eagle Ford. We know those assets well and look forward to capture it. So overall, we'll see activity rationalization on the rig and frac front. As Andy mentioned, we'll go through and really determine the optimum plateau, look at incremental cost of supply to run these assets going forward and still get modest production growth.

Our next question comes from Lloyd Byrne with Jefferies.

Can you guys just comment a little bit on the differentials that you're seeing in gas, maybe Waha and what you expect from Matterhorn? And then take that one step further and any additional regas progress or targets that you guys have going forward internationally? Andy O'Brien: Yes, I'll talk about where we are with that. So as you saw, Henry Hub prices did improve in Q3. However, as expected, Lower 48 gas realizations continue to be depressed as a result of the Permian pipeline constraints. So our Lower 48 gas realization as a percentage of Henry Hub dropped from 17% in Q2 to 8% in Q3. As I said, this was primarily driven by the Permian Waha pricing which declined a negative $0.25 in MMBtu. Now we have seen some improvement in October with the ramp-up of Matterhorn. However, this has been somewhat offset by some pipeline maintenance elsewhere in the Permian. Now it's difficult to forecast exactly how the fourth quarter is going to play out. But the forward curve is suggesting that we should see some improvement. And then specifically to your comment or your question on Matterhorn, we expect Matterhorn to be about 2 Bcf a day in November. And then with compression, that should increase capacity to 2.5 Bcf later in 2025. I think the second part of your question was more on the LNG side and the progress we've been making there. Nothing specifically new to announce on the LNG side in terms of new regas. But the one thing that we have, I've mentioned is there has been some deals that we've done in Europe. We executed three agreements during the third quarter to support the expected increase of gas that we're going to have into Europe from LNG. And in aggregate, those three agreements represent about 1.8 MTPA of our capacity. So these new agreements will give us then the ability to place volumes sort of more efficiently into multiple markets in Europe. So that gives you an update on where we are on the progress we've made this quarter.

Our next question comes from Betty Jiang with Barclays.

I want to ask about asset sales and how you think about the use of proceeds. There's a headline yesterday about sale of non-core Permian assets, so wondering about that. But perhaps more broadly, as you look at the optimization of the portfolio today, what are the areas where you think there could be more value for others versus where they sit internally? Andy O'Brien: As you know, we've been actively high-grading our portfolio over the last several years. And the Marathon transaction provides us an opportunity to continue that process. As you say, we've announced a target around $2 billion of non-core asset dispositions over the next several years, and we're very confident of achieving that. Now we're not going to comment on the specifics of where they are, our A&D activity in advance due to the commercial sensitivity but activities are well underway on multiple disposition candidates at this stage.

Our next question comes from Bob Brackett with Bernstein.

We've been hearing a lot of questions around this idea of a wave of global LNG hitting the shores in '25 or '26 or '27. It's easy to put an LNG project into a spreadsheet, perhaps harder to bring it online. Any thoughts around should we expect a surge of liquefaction capacity? Obviously, you've got a front row seat to that.

Yes, Bob, I think we've all been kind of looking at it, you're right. The spreadsheet presumes a lot of FIDs get taken and it's pretty tough to take FIDs in the space and things kind of shift to the right. But look, we -- if there's a little bit of a supply overhang coming later this decade, coming in the '27, '28 time frame, we can see some of that if these projects progress as designed. We've already seen some that are even in construction today that are moving to the right, let alone whether or not they're going to take FID. So that's going to be something that continues to just be pretty volatile in the marketplace. But yes, we would expect a little bit of extra supply coming on later this decade. But we're making these investments for 20, 30, 40 years, and we're pretty bullish on where the LNG demand growth is going over the next decade and beyond. And that's what we're focused on is the opportunity to get access to those premium gas markets in Europe and in Asia. And to do that, you have to be a full value chain. You have to be in the regas side. You have to be -- ships to move it around and you have to be in the regas -- or the liquefaction shipping and the regas side as well. And Andy just talked about some of what we're doing to expand on the marketing end of it and linking all that together. So we feel it's the right move for the company, right thing long term to do for the company. But there will be periods of time when it's oversupplied just like there will be period of times when it's undersupplied and the price will spike. And that's what we've seen over the last 30, 40 years in this business, and we expect that will continue over the next 30, 40 years.

Our next question comes from Ryan Todd with Piper Sandler.

Maybe can you talk about how you think about the supply-demand balance for crude oil over the next couple of years? I know you guys always have a view on this. And how much, if at all, does this factor into your outlook for activity levels and your willingness to grow production going forward?

Yes, Ryan. I think we'll -- as we do every year at the end of the year, we'll do our bottoms-up assessment of where we think supply and demand is. Look, we -- as we look out into 2024, coming into the year, we were thinking more like 1.2 million, 1.3 million barrels a day of demand growth. It looks like with primarily China slowdown and some of the other places around the world, that demand growth is going to be closer to around 1 million barrels a day, so a bit softer than what we have said. There's still spare capacity sitting within the OPEC+ group. And anybody's bet whether or not they decide to continue to delay pulling any excess supply back into the market, we'll do that assessment. But look, I think we're pretty constructive in the market going forward over the next few years, constructive being above what we would call an equilibrium mid-cycle price and still be probably above that. So pretty constructive in terms of the market going forward. But look, we're not going to -- we'll make our assessment, see where our cash flows are at. We know where our capital program is going to go be, and we've got lots of levers inside the company to make sure that we're competitive on our distributions back to our shareholder, which we've demonstrated over the last six to seven years. And you can judge us by the past and that's how we think about the business. We're going to be maximizing returns on our investment. We're going to be investing in the company for some growth and the long-term growth and development of the company. And I recognize we're spending some money on some pre-productive capital. But we're doing that for the long-term health of the company, thinking about the next 10 years and beyond. And these are really good projects that compete on a cost of supply basis and that we want to make investments in for the long-term health of the company. So we factor all that together but we've got a lot of flexibility. We're built for the volatility that we see in the market with our balance sheet, cash and the other things that we can do as a company.

Our next question comes from Roger Read with Wells Fargo.

Maybe to follow-up on the pre-productive capital and just ask you about Willow. You mentioned spending goes up in '25. What are -- given the compressed time of the year for working there, what are some of the milestones we should be thinking about this drilling season and then what you would be setting up for in the winter of '25, '26?

Roger, this is Kirk. Certainly, we would describe our third quarter progress as really being on trend with prior quarters. Our project team really just continued to make some strong progress through Q3, and that's really across all fronts: engineering, procurement, fabrication, all of those are on track. And certainly, you heard from me in the last call that we were able to transition a bit earlier from fabrication of the operations center into fabricating the process modules. And that ultimately enabled us to sealift those modules into Alaska certainly not just on time but a little bit early, and that played out quite well for us. Most importantly, the team is really sharpening the pencil right now on preparing for our 2025 winter construction season, which is what you're alluding to. And we do recognize that the scope here next year is going to be larger than this past winter season that was really quite successful for us. In 2025, we'll resume those critical activities that, of course, you have to do from ice roads and so that consists of gravel placement for roads and pads. We'll resume pipeline installations. And then we'll also start to begin placing camps out at Willow. And then lastly and very importantly, again, now that we have those operations center modules, they're up on the North Slope of Alaska. Once we have ice roads constructed, we'll begin moving those modules into the winter or into the rural development area. So again, the teams are hard at work. They're doing some great work in their planning and refining the logistics required for this next year, recognizing it's going to be a bigger winter season for us. And it's a bit early for us to guide on capital for Willow. We'll be ready to say more once we're ready to guide on total company.

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

I think this one is for Bill. Last quarter, you guided us to a bit of a working capital draw in 3Q and we saw a bit of a pretty big tailwind. Can you give us a little bit of color on what occurred there and what do you project for 4Q? And if you also could add into that, any expectations for other outflows that would be, say, related to Marathon like severance and other costs?

Yes, sure. You're right. Last quarter, I indicated that we were expecting about $0.5 billion working capital headwind during the quarter. Well, as it turned out, we had two items. The first was the IRS provided a deferral opportunity that allowed us to push the second quarter tax payments and remaining tax payments for the year out into 2025. And the second item was pretty normal. That's your normal movements on accounts receivable and accounts payable with falling prices. That's the explanation for the reversal on working capital expectations. Now looking towards the fourth quarter, it is a bit difficult to forecast where we expect to be for the fourth quarter with the pending Marathon acquisition. As you know, there's NOLs and some other tax attributes that will come to us with the Marathon acquisition. And we'll be providing an update to that further after closing.

Our next question comes from Neal Dingmann with Truist.

My question is on your strong third quarter '24 well performance, specifically in the Lower 48. Ryan I was just wondering, is there a particular area or maybe a key operational driver you'd point to for this upside such, I don't know, maybe the improved logistics, several fracs or the like?

Yes, I can let Nick chime in. It's just really good performance across the whole Lower 48 teams running on all eight cylinders. So Nick can provide a bit of detail on that.

Yes, Neal, you're right. We had obviously a very strong quarter. A number of attributes for 3Q. We had strong base production come in from 2Q into 3Q, obviously, the buildoff of -- and as I've already mentioned, we continue to focus in on those driving the operating efficiencies. So we've seen more feet per day, more stages per day. In fact, in 3Q, in the Delaware Basin, we had a best ever feet per day for that entire quarter within the program. And that's a testament of using technologies like the Drilling Intelligence Group, where we can do 24/7 monitoring of wells. We can troubleshoot. We can optimize the forward plans and then share learnings across all the rigs. And so that lifts all boats there. And as I mentioned earlier, just to reiterate, we're at flat activity level compared to 2023. But for this year, we got 10% -- greater than 10% more scope so same activity level. On a little more granularity, we had two production records in the assets. We had Permian as well as Eagle Ford. On the Eagle Ford front, we had a large turnaround. That went very successful. We're ahead of schedule and below budget so we had less downtime, Neal, in that. And then as we typically and historically see with Eagle Ford, we get flush production as we start that asset back up coming out of maintenance. And so you get to see -- you do see flush production in 3Q bolstering that. And then we waited to start up a number of wells until post turnaround in Eagle Ford. And so you're seeing some lumpiness in overall number of wells online there. On the Permian side, really good production there. We got 8% year-over-year for the third quarter. If you look at for the full year, the 6% and great wells in Delaware and Midland Basin. We had a number of 3-mile laterals in Midland Basin that has a very strong performance in 3Q. In 3Q itself, just to remember, there's probably a high number of wells online and that's going to create some lumpiness. And then if you look at kind of 4Q, it's going to be more ratable like 1% quarter-over-quarter, and then total year, it will be 5% overall growth for Lower 48. As Ryan mentioned, great quarter. Just shout out to the teams, we're running extremely well.

Our next question comes from Josh Silverstein with UBS.

You made some working interest acquisitions up in Alaska this quarter. Can you just talk about other opportunities like this that exist across your asset base? You've done it in Surmont and APLNG over the past few years. Just curious what else may be out there.

Yes, Josh, we did. Look, we watch all of this and I can have Kirk describe what happened in Alaska. You quite never know when these things are going to come about that we have ROFRs or right of first refusal across a lot of our assets. And you never know when decisions made by partners to make a change. And we take advantage of those when they make sense for the company. And Kirk can describe what happened up in Alaska with a bit more detail.

Josh, this is Kirk. Yes, certainly, many of you on the call might have seen that we released a statement directly out of our Alaska business that we did exercise our preemptive rights to acquire Chevron's non-operated interest in Kuparuk as well as Prudhoe for roughly $300 million. Chevron was preparing to sell to a private entity. And it's just as Ryan described, we have the right to take a look at proposed transactions of that nature and before they close and take the option of choosing to preempt. What's of interest to us on this one was the transaction price actually implied a PDP-only valuation. And so naturally, expects to seize on this opportunity. We saw this as a great way to increase our ownership across a set of assets that we know very well. We have a legacy position there in Alaska, and we know that the competitive cost of supply that exists for us on go-forward development plans. And so when you think about a PDP-only valuation or transaction price, couple that up with the fact that we have our known operated development plans around Nuna and Coyote in the Greater Kuparuk area specifically, you put all that together with the fact that Alaska has -- they've got high-margin volumes, nearly all oil and we fetch a premium to Brent up there. So you couple all that together with a low cost of supply development and that provides a pretty compelling return opportunity on that additional interest we picked up. So as Ryan said, we don't know when these are going to come at us. But boy, if they're compelling, we're going to capitalize on the opportunity.

We love ROFRs, Josh.

Our next question comes from Alastair Syme with Citi.

I wanted to return to the issue of Lower 48 volumes. I mean, you're clearly outpacing the rest of the industry this year. I just wonder if you think the slowdown in the rest of the industry is surprising. To what extent do you think that takeaway issues are perhaps holding back growth in the rest of the industry? Or is it just a natural maturity? Interested in your perspective.

Yes. I think, Alastair, operating in this stable environment where you can get into this efficient frontier with your kind of that relationship between rig count and frac spreads, we're there and the scale and the scope of what we're doing allows us to get there. I think other operators with less inventory or less quality inventory or, frankly, less balance sheet strength have to do these ramp-up, ramp down kind of things and we're kind of seeing that a little bit. I think as we go into the fourth quarter, we noticed it in our OBO or operated by others piece of it, and we see it kind of playing out across the industry a little bit, which allows us to maybe differentiate ourselves a little bit. I don't know, Nick, if you have anything more to add to that.

Yes, nothing further to add. I mean, we've got a fairly large non-operated portfolio within Lower 48. We look at a lot of balance. And as Ryan mentioned, when you kind of look at what's coming in the door for fourth quarter, they're slowing down. We typically have seen that in years past kind of more seasonality as folks drop rig and frac activity and then ramp back up in Q1 of the next year. So very similar drop of activity.

Our next question comes from Kalei Akamine with Bank of America.

This one is a little bit nuanced. Kind of thinking about APLNG, some vendors have the upstream piece declining from 2030. I suppose that means that you guys should be thinking about backfill today. So can you discuss the outlook for that asset? Any backfill plans, please?

Yes, you bet. This is Kirk. First, I'll just start by acknowledging the performance this year coming out of the JV. Production, operations and certainly, distributions have been quite strong. The upstream production is supplying our LNG facility, both in long-term contracts, spot and especially we're a large supplier of the domestic markets there. The decline is largely as per most of the gold bed methane gas fields that are out there. And so you can expect similar performance from us from the upstream operator and certainly from the JV in whole. And I'd come back to the fact that 70% of our APLNG production is sold under two long-term contracts, and those extend through the mid-2030s. And the supply forecast, the production expectations that we have coming out of that onstream or that onshore gas field gives us a lot of confidence that we're going to be able to meet those contracts through mid-2030s. And naturally, you start to begin some to, as you see some decline, a bit kind of late 2030s, 2040s. And so naturally, the JV is focused on opportunities for continued backfill of that facility. And so that's within the purview the scope of the JV. They'll be thinking about future opportunities. And we're happy to be a part of that, just given the fact that we understand LNG is going to play a really important role for the energy pathway demand looking into the future, and it's certainly a growing opportunity for us inside our strategy.

Our next question comes from Charles Meade with Johnson Rice.

I appreciate you guys running deep into the Q&A queue here. I want to pick up -- you guys made some comments about the Eagle Ford turnaround, but I wonder if you could talk more broadly about the big turnaround quarter you guys had, maybe starting with the one up in Surmont. And if you could add any color on whether better-than-expected results are one of the drivers with your strong 4Q guide?

Charles, this is Kirk. Yes, certainly, as mentioned in our release and by Bill this morning and our opening comments here, we did, in fact, have a once-in-every five year full facility turnaround there in the third quarter. And that really -- that went really quite well. During these large turnarounds, naturally, you expect us to perform the required both internal and regulatory-driven compliance activities around testing safety systems. But we also tend to open up both tanks and vessels, go into those, open them up, clean them out, and spec them and that went really quite well. In fact, we were able to transition a number of those tanks to being able to work on those during operations going forward. So really positive outcomes on that turnaround up there in Canada. And now being on the other side of that turnaround, having it behind us, we are seeing full run rates now of Pad 267, and that just continues to come in really very strong. In fact, the ramp-up coming out of the turnaround was very strong, came on line a bit faster than we originally predicted, and so of course, always pleased to see that. And as you've heard from me before, we do, in fact, intend to begin adding new pads even after Pad 267. That was the first pad to resume after the first two commissioning sequences of Surmont. And so now that we've restarted those, sustaining those development pad manufacturing program, you can expect we'll add a new pad about every 12 to 18 months. I mean, that's a pretty fair average assumption going forward over the next 5 to 10 years. This next pad is 104, 104 West A as we refer to it. It's smaller than 267 and we plan to start drilling here next year on that pad, and we're expecting first oil in 2026. So certainly, as we continue to progress the SEO on future pads, I'll keep you all abreast into that.

Our next question comes from Paul Cheng with Scotiabank.

Maybe this is for Ryan or Nick. You are already close to about 800,000 barrel per day in Permian. You have a lot of assets. But from the best capital allocation or an efficient use of capital, what kind of petrol rate we should assume for Permian in your operation? And when do you think you may be able to achieve it? And also along the line, if you can give us a little bit of the maybe insight how's the supply -- when the supply cost look like for 2025 versus 2024?

Yes, Paul, this is Nick. On the plateau question, maybe just take the whole group back to just the inventory that we have in the Permian. As you know, we're top tier in inventory. If you take a look at what we currently are drilling at rig activity levels, we've got two decades, two decades of inventory in the Permian. So we can grow at modestly as we talked about at AIM kind of that 4% to 5% for the 10 years. We don't plateau until into the second decade, so a significant amount of opportunities there, and then we'll bring in the Marathon assets as well. That very competitive cost of supply, when you -- if I'm just looking at the Permian, the cost supply that we've been drilling in 2024 with really good results, as you can see in the 3Q, very similar in 2025 as well, very robust, very durable out there.

Yes, on the supplier, the -- what we're seeing, kind of mixed results sort of in the supply chain and the categories of spend that you're talking about. We see some -- a bit of drop-off in rigs. We see some efficiency and maybe drop-off in pressure pumping, sand. We see some increases largely maybe on the OpEx side, chemicals, fuel, labor. So it's kind of a mixed bag. We haven't sort of -- we're in the process right now, Paul, of putting all that together to try to come up with an inflation/deflation estimate as we go into 2025. But it feels somewhat similar year to 2024. But we're in the middle of doing all that front-end work right now. I don't know if you have any more to add to that, Nick.

Yes. I think, Paul, obviously, we continue to see deflation capture through 2024 across all major spend categories. Tubulars as it was the largest as we've seen that, up to a 30% reduction. We can see proppant going down, pressure pumping going down. And rig rates, even this quarter, we're seeing some modest deflation capture on rig rates as well as pumping services going in there. I think that's going to level out to some degree in 2025. Just depends on kind of overall supply/demand of those services as we look forward based on what commodity prices are going to be out there.

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

I appreciate all the details on the Lower 48 production growth. It's certainly differentiating. My question is on oil mix. Company oil mix fell a little bit quarter-over-quarter. Should we assume that was mainly driven by Surmont downtime? And what are your expectations for that oil mix in 4Q and going forward into next year?

Well, yes, this is Nick. I'll talk a little bit about oil mix for Lower 48 and if there's any comments on the Alaska International, I'll turn it over to Kirk. Yes, our oil mix has really been tracking around 52% to 53% for a number of quarters if you've been tracking that. And third quarter is very consistent with the previous quarters. And so oil volumes grew around about 5% year-over-year. And as a reminder for the group, that really depends just due to the vast and deep and durable portfolio that we have in Lower 48. It depends on where we're drilling and bringing those new wells on related to oil mix. As you look forward into the few years, it's going to be, again, pretty consistent, 52%, 53% overall. We're very satisfied with how things are tracking. And as a reminder, too, for Lower 48 this year, we grew at 5% year-over-year. Andy O'Brien: I'd just add, I think you sort of answered the question for us. And there was nothing particularly unusual in the oil mix this quarter. We just had the large turnaround activity in an asset that's 100% oil.

Our next question comes from Phillips Johnston with Capital One Securities.

Just wanted to follow-up an earlier question about the Alaska transactions. Just wondering, how much production is associated with those deals? And I also wanted to confirm just that the impact isn't included in your fourth quarter production guidance.

Yes, this is Kirk. In fact, we expect it to be, on the margin, several thousand barrels a day associated with those transactions. And it's a good ask, certainly left that off, which is we're currently expecting those transactions to close in fourth quarter, albeit we haven't formally factored that into our guidance. So expect us to update that as we think about next year.

Our next question comes from Leo Mariani with ROTH.

Just a couple of questions here just around the guidance here. So wanted to get a sense if you guys could quantify what you're expecting in the fourth quarter in terms of production turnarounds as well as CapEx and as well as OpEx here. Andy O'Brien: This is Andy. So in terms of turnarounds, it's -- fourth quarter is a very small turnaround quarter for us. It's about 5,000 barrels a day, predominantly in Norway. I think we've given guidance for OpEx, sort of OpEx guidance is unchanged for the year. I think 1 thing I would add to that is that we did say on the last call that the third quarter would be the high quarter due to the heavy turnaround schedule, and that's exactly how things played out. It's also worth mentioning that we have -- we've beaten production this quarter by 27,000 barrels a day and upped the annual production by 10,000 barrels a day. And importantly, we have not increased the operating cost guidance as a result of that production increase. So we feel really good there. And then the same thing with the CapEx for the fourth quarter. That's playing out really exactly as we said on the last call. Most of what we suggested on the call has come to fruition, and we were kind of three things. We've covered most of these already, but we mentioned the Lower 48 non-operated activity typically tails off in the fourth quarter. That's exactly what we're seeing. We mentioned that out there the LNG, the CapEx there would go down as we go into -- more the project financing. That's exactly what we're seeing. And then as we talked about, we've seen some deflation in the Lower 48. So that all factors into sort of the lower CapEx number in the fourth quarter. So I think that covers the production OpEx and CapEx and turnaround. So I think I got all the drivers there for you.

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