Welcome to the Third Quarter 2024 ConocoPhillips Earnings Conference 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 Phil Gresh, Vice President, Investor Relations.

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 off the call with some opening remarks after which the team will be available for your questions. Along with today’s release, we published 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 a 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 to shareholders this year. We have officially incorporated our Variable Return of Capital (VROC) into 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 has now fully mapped out how we plan to achieve the initial guidance of at least $500 million in synergies, primarily from overhead and operating cost reduction categories that we have previously discussed. 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 forma CapEx of less than $13 billion. So, to wrap up, we're pleased with our operational execution and 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 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 due to turnarounds during the quarter, including approximately 55,000 barrels for Surmont's once every five-year turnaround. The Lower 48 achieved record production of 1,147,000 barrels of oil equivalent per day, which represents 6% underlying growth year-over-year. 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 cash flow from operations 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 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 to the operator to start the Q&A.

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? How long does it take to be realized?

Neil, this is Andy. I can take that question. To unpack it and maybe go back to what we said on the second quarter call, we stood up a team that’s been working on the bottoms-up integration and synergy capture detail. Now that team has already fully mapped out how we're going to achieve the $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, and we've identified non-labor duplication and process efficiencies to optimize costs. Additionally, during the acquisition announcement call, I mentioned there would 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. 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 activity compared to standalone companies; simply put, we need fewer rigs and frack crews to achieve the same outcome. When you combine all of that with the original announced synergies of $500 million, we now have clear line of sight to doubling that to $1 billion. In terms of the timing of those synergies, you can effectively think of the CapEx happening immediately when we get into 2025 in the reduction in the capital budget. As I said earlier, the OpEx and G&A will 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 gotten a complete look under the hood. So, I guess I am expecting that we'll have additional OpEx opportunities, we'll have additional capital opportunities, and additional commercial opportunities as we dive in post-close and look a little 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.

Doug, Andy here. Maybe I'll take you back to what we said back in our AIM presentation and build from there. In AIM, we said the long-term average free cash flow breakeven, excluding the dividends, is within the mid-30s. 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, bringing it down to the low 30s. Of course, you need to add the dividend on top of that, which is about $10. 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%. Very importantly, that's how we can continue our commitment to the S&P 500 top quartile growth. So, hopefully that unpacks the strength that we have there.

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

Our next question comes from Stephen Richardson.

As Ryan said, we're saying our expectation is less than $13 billion in 2025. To put that in context, this compares to $13.5 billion for the combined ConocoPhillips and Marathon guidance for 2024. The primary driver of that reduction is really what I just covered in the Marathon synergies across the Lower 48. It's also important to say that without the lower CapEx number, 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 Alaska North Slope.

Our next question comes from Devin McDermott.

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. Commodity prices have been very volatile since then, but you're also messaging a more capital-efficient program and better synergies. I was wondering if you can 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, there are a lot of moving pieces, as you might imagine. I'll start the answer by reflecting a little bit about how we've done in 2024. I think it informs how we think about this and how we might approach 2025. It's a bit early to give an indication of what 2025 is because of the moving parts that Steve just addressed. We have backwardation in the oil curve, Contango in the gas curve, and a lot of volatility happening in the commodity price. As we go through the course of the year and into next year, we'll all be assessing what our cash flow from operations looks like. Looking at our past history, we have provided about 45% of our cash flow back to the shareholder in the form of distributions through both the dividend channel and share buybacks. So we'll plan to continue offering our shareholders a compelling value proposition for the company. If you look at our early projections for 2024, we were thinking about an $80 kind of price deck; it has been softer than that. We've stuck to our $9 billion distribution target. We've paid off some debt, and we have a strong balance sheet with cash. We are equipped to handle the current market volatility. So those are the components we will factor into our 2025 outlook. We have a wealth of levers and ways to think about the business. The operations are running effectively under Kirk's leadership and the Lower 48 under Nick's leadership. This has resulted in additional production and efficiency that we are driving through the system. We'll combine all those factors to come up with a distribution target for next year post the Marathon close. Shareholders should expect a significant portion of our cash flow returning to them, likely exceeding our floor of 30%. It’ll probably be something 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 can you provide some insights into the Marathon properties, considering their activity trends?

Yes, I can let Andy jump in, Arun, but that was one of the surprises we saw when we got into the data room. It's really one of the attractive features of the Marathon properties—some really good low-cost supply resources that compete well in our portfolio. With the scale we have as a company and combining with Marathon, we plan to run these assets differently. Our Lower 48 team is eager to take on these assets because we will have an execution plan that doesn't involve ramping up early in the year and backing off later. With the scale we bring to the combination, we can run at a consistent pace, which is much more effective than the ramping approach that others may have to use. I'll let Nick provide more details on the competitiveness within the portfolio.

Yes, Arun, building on what Ryan just mentioned, we've looked at running level-loaded and steady state since mid-2022. Clearly, we've demonstrated that with that approach, we've improved operating efficiencies on the drilling side and the fracking side. As Ryan mentioned, we're going to apply that same methodology on the Marathon acreage. We're excited to bring that in. Traditionally, they have heavily favored the front end of the year, ramping up with fracking and drilling activity before tapering off later in the year. We are going to run at a steady state level. This year, we've presented that proof point by delivering over 10% more activity than we did in 2023. That translates to more feet per day, meaning more wells. The production performance for the Lower 48 is clearly reflected in our output numbers. The Marathon assets are cost-competitive across all basins. We have 2,000 wells there, mostly concentrated in Eagle Ford, which we know well and are eager to capture. Overall, we will rationalize rig and frac activity, as Andy mentioned, looking at the optimal operating level to find the most economical production growth.

Our next question comes from Lloyd Byrne with Jefferies.

Can you just comment on the differentials that you're seeing in gas, maybe Waha, and what you expect from Matterhorn? Any additional regas progress or targets you have going forward internationally?

Yes, I'll address that. As you noted, Henry Hub prices improved in Q3; however, Lower 48 gas realizations remained depressed due to the Permian pipeline constraints. Our Lower 48 gas realization as a percentage of Henry Hub dropped from 17% in Q2 to 8% in Q3, primarily driven by the Permian Waha pricing, which dropped to a negative $0.25 per MMBtu. We have noticed some improvement in October with the Matterhorn ramp-up, although that has been somewhat offset by some pipeline maintenance in the Permian. It's challenging to forecast the fourth quarter, but the forward curve suggests we should see some improvement. Concerning your question about Matterhorn, we expect Matterhorn to have a capacity of about 2 Bcf a day in November, increasing to 2.5 Bcf later in 2025 with compression. Regarding LNG, we've executed three agreements during Q3 to support an expected increase in gas to Europe from LNG, totaling about 1.8 MTPA of our capacity. This will allow us to allocate volumes more efficiently to multiple markets in Europe.

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 about the sale of non-core Permian assets, so I'm wondering about that. More broadly, as you optimize the portfolio today, what areas do you think could provide more value for others than they currently do internally?

As you know, we've been actively high-grading our portfolio over the years. The Marathon transaction offers us a chance to continue that process. We announced a target of around $2 billion from non-core asset dispositions over the next several years, and we are confident in achieving that. While we won’t comment on specifics due to commercial sensitivity, we are actively working on multiple disposition candidates at this stage.

Our next question comes from Bob Brackett with Bernstein.

We've been hearing a lot of questions regarding a possible wave of global LNG hitting the shores in '25, '26, or '27. It’s easy to project LNG projects on paper, but harder to bring them online. Any insights on whether we should expect a surge of liquefaction capacity?

Yes, Bob, you're right. The spreadsheet does assume a lot of final investment decisions, and it's quite tough to finalize those in this space. If there's a little supply overhang coming later in the decade, we might see some projects shift timelines. Some that are currently under construction are also running into delays. The marketplace will remain volatile. However, we anticipate some increase in supply later this decade. We're making investments now for the next 20, 30, to 40 years, and we're bullish on LNG demand growth beyond that. This strategy is about gaining access to premium gas markets. There are times when the market will be oversupplied, just as there will be periods of undersupply where prices spike. We expect those fluctuations to continue as they have historically.

Our next question comes from Ryan Todd with Piper Sandler.

Can you talk about the supply-demand balance for crude oil over the next couple of years? How much does this impact your activity levels and willingness to grow production going forward?

Yes, as we do every year, we'll conduct a bottoms-up evaluation of supply and demand. Looking into 2024, we initially expected 1.2 to 1.3 million barrels a day in demand growth; however, it seems it will fall closer to around 1 million barrels a day due to a slowdown in China and other regions. There is still spare capacity within OPEC+. We remain constructive about the market moving forward, expecting to maintain prices above equilibrium mid-cycle levels. We’ll make assessments using our cash flow projections to inform our capital program decisions to ensure we return shareholder value and support investment in long-term growth where needed.

Our next question comes from Roger Read with Wells Fargo.

I wanted to follow up on the pre-productive capital and inquire about Willow. You mentioned spending goes up in '25. Given the limited working season, what milestones should guide us this drilling season and the winter of '25, '26?

Roger, this is Kirk. Certainly, we would describe our third quarter progress as being on trend with prior quarters. Our project team continued to make strong progress through Q3 across all fronts: engineering, procurement, and fabrication. As I noted last call, we transitioned earlier from fabricating the operations center to fabricating the process modules, allowing us to sealift those modules into Alaska, not just on time but a little early, which went well. Most importantly, the team is currently preparing for the 2025 winter construction season, which is larger than last winter. In 2025, we will resume critical activities such as gravel placement for roads and pads, pipeline installations, and the placement of camps at Willow. Additionally, with the operations center modules now on the North Slope, once we have the ice roads constructed, we will transport them into the rural development area. The teams are diligently refining logistics for the next year, knowing we will have a larger construction season. It's premature to guide on capital for Willow, but we will be ready to share more once we can provide guidance for the total company.

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

This question is for Bill. Last quarter, you guided us to a working capital draw in Q3, but we saw a significant tailwind. Can you give us insights into this and what you project for Q4, including potential outflows related to Marathon like severance and other costs?

Yes, you're right. Last quarter, I mentioned we expected about $0.5 billion working capital headwind during the quarter. However, we had two key items: the IRS provided a deferral opportunity that allowed us to defer tax payments into 2025, and we also saw normal movements in accounts receivable and accounts payable with falling prices. This explains the reversal in our working capital expectations. Looking towards Q4, forecasting is challenging due to the pending Marathon acquisition and associated NOLs and other tax attributes that we will provide an update on after closing.

Our next question comes from Neal Dingmann with Truist.

I'm curious about your strong Q3 '24 well performance, particularly in the Lower 48. Ryan, could you point to a specific area or key operational driver for this upside?

Yes, I can let Nick chime in. It's just good performance across the whole Lower 48; our teams are running effectively. Nick can provide some detail.

Yes, Neal, you're right that we had a very strong quarter. Numerous attributes contributed to Q3. We had strong base production come in from Q2, and we continued to focus on operating efficiencies and troubleshooting. We've seen more feet per day and more stages per day. In Q3, the Delaware Basin achieved its best-ever feet per day for the entire quarter. This success comes from using technology to monitor wells and optimize our plans across all rigs. We also experienced two production records in our assets—both in the Permian and Eagle Ford. On the Eagle Ford, we had a successful large turnaround that was completed ahead of schedule and below budget with less downtime. For the Permian, we had 8% year-over-year growth in the third quarter. As Ryan mentioned, it was a great quarter, and kudos to the teams for their excellent performance.

Our next question comes from Josh Silverstein with UBS.

You made some working interest acquisitions in Alaska this quarter. Can you discuss other opportunities like this across your asset base?

Yes, Josh, we did. We monitor these opportunities and I can have Kirk describe what happened in Alaska. We never know when opportunities arise that we have the right of first refusal to consider. Our recent acquisition is an example of that. Kirk, can you share more detail?

Josh, yes, we announced that we exercised our preemptive rights to acquire Chevron's non-operated interest in Kuparuk and Prudhoe for roughly $300 million. Chevron was preparing to sell to a private entity. We leveraged our rights to preempt the transaction. The transaction price implied a PDP-only valuation. We saw this as a compelling opportunity to increase our ownership in assets that we know very well. Alaska offers high-margin volumes, with nearly all oil fetching premium prices. This acquisition aligns with our interests in Alaska and positions us for future development plans.

We value opportunities like our right of first refusals, Josh.

Our next question comes from Alastair Syme with Citi.

I wanted to revisit the volume performance in the Lower 48. You're distinctly outpacing the rest of the industry; do you find the industry slowdown surprising? To what extent do you think takeaway issues are holding back other companies' growth?

Yes, Alastair, operating in this stable environment allows us to reach an efficient relationship between rig count and frac spreads. Other operators with less quality inventory or balance sheet strength may face challenges that require them to adjust operational levels. In the fourth quarter, we noticed similar trends with our operated by others piece, and we anticipate some slowdowns across the industry, correlating with historical seasonal patterns.

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

This is a nuanced question about APLNG; some vendors expect the upstream piece to decline from 2030. Are you considering backfill opportunities today? Can you discuss that asset’s outlook?

Certainly, Kalei. First, let me note that the APLNG venture has performed quite well this year, with strong production and distributions. The upstream production supports our LNG facility and domestic markets. The decline is typical for most coal seam gas fields. However, 70% of our APLNG production is sold under long-term contracts extending through the mid-2030s. We are confident in our ability to fulfill those contracts. As we approach 2030 and face some declines, the JV is focused on continued backfill opportunities, recognizing LNG’s growing role in meeting energy demand.

Our next question comes from Charles Meade with Johnson Rice.

Could you elaborate on the large turnaround quarter you experienced, starting with the one at Surmont? Were better-than-expected results a driver of your strong Q4 guidance?

Charles, certainly. As noted in our release and by Bill this morning, we completed a once-in-every-five-year full facility turnaround at Surmont in Q3. It went remarkably well. During large turnarounds, we conduct internal and regulatory compliance tasks, but we also open, clean, and prepare tanks and vessels. We were able to transition a number of those tanks for future operational use effectively. With the turnaround successfully behind us, we see full run rates continuing from Pad 267. This success came on faster than we predicted. Now that it’s behind us, expect new pads to be added after Pad 267. The next pad is 104 West A, and we anticipate starting drilling next year with first oil expected in 2026. We will keep you updated on progress.

Our next question comes from Paul Cheng with Scotiabank.

Regarding the Permian, you are nearing about 800,000 barrels per day in production with various assets. For efficient capital allocation, what kind of plateau rate should we assume for the Permian operations, and when do you estimate you can achieve it?

Paul, this is Nick. Regarding plateau production in the Permian, we have tremendous inventory. We have about two decades of inventory, allowing for growth. We might average 4% to 5% growth for the next decade. We anticipate plateauing in the second decade, indicating significant remaining opportunities. For 2025, if we look strictly at the Permian's supply costs, we're seeing very robust and durable performance.

We're experiencing mixed results within the supply chain. There has been a decline in rigs and improvements in pressure pumping, sand, and chemicals, but we are facing some increases in overall OpEx, which includes chemicals, fuel, and labor costs. Hence, we are working on determining our inflation and deflation estimates as we head into 2025. It looks similar to 2024. We will solidify all estimates as we finalize our evaluations.

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

I appreciate the details on Lower 48 production growth; it's quite impressive. My question is regarding oil mix. The company’s oil mix fell slightly quarter-over-quarter; was this mainly due to Surmont downtime? What are your expectations for the oil mix in Q4 and into next year?

Yes, our oil mix has been stable at around 52% to 53% for several quarters. The third quarter was consistent with that. We saw about a 5% year-over-year growth in oil volumes. The oil mix mainly depends on our drilling activities. We expect this mix to remain consistent over the next few years. Overall, we achieved 5% growth year-over-year in the Lower 48.

You largely answered the question: there was nothing unusual regarding oil mix this quarter. The significant turnaround in an asset that is 100% oil influenced that.

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

I wanted to follow up on earlier comments about the Alaska transactions. How much production is associated with those deals? Is this impact included in your Q4 production guidance?

Expect production from those transactions to be several thousand barrels a day. We did not incorporate this into our Q4 guidance but will provide an update on that as we plan for next year.

Our next question comes from Leo Mariani with ROTH.

Could you quantify the fourth quarter expectations in terms of production turnarounds, CapEx, and OpEx?

In terms of turnarounds, Q4 is a small turnaround quarter for us, about 5,000 barrels a day mainly in Norway. Our OpEx guidance is unchanged, and I mentioned previously that Q3 would be the high quarter due to heavy turnaround activity; this was accurate. We beat production this quarter by 27,000 barrels a day and raised the annual production guidance by 10,000 barrels a day without increasing operating cost guidance. For Q4, the CapEx is performing exactly as we previously stated: the Lower 48 non-operated activity typically slows in Q4, and we have projected a decrease in LNG CapEx as project financing progresses. The deflation scenario in Lower 48 also factors into a more favorable CapEx number for Q4.

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.