Phil Gresh:

Thank you Liz, and welcome everyone to our second 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 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 a 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 measure can be found in today’s release and on our website. Third, before we move to Q&A, we will take one question per caller. With that, I will turn the call over to Ryan.

William Bullock:

Well, thanks, Ryan. In the second quarter, we generated $1.98 per share in adjusted earnings. We produced 1,945,000 barrels of oil equivalent per day, representing 4% underlying growth year-over-year and this includes the impact of 18,000 barrels per day of turnarounds. Lower 48 production averaged 1,105,000 barrels of oil equivalent per day, with 748,000 in the Permian, 238,000 in the Eagle Ford and 105,000 in the Bakken. Alaska International production averaged 839,000 barrels of oil equivalent per day, also representing roughly 4% underlying growth year-over-year, excluding the Surmont acquisition effects. Now this highlights the benefits of our diversified global portfolio. Moving to cash flows. Second quarter CFO was $5.1 billion, which included over $300 million of APLNG distributions. Working capital was $100 million headwind, which was lower than our guidance of $600 million as the expected timing of some of our tax payments shifted into the third quarter. Capital expenditures were just under $3 billion. We returned $1.9 billion to shareholders in the quarter, including $1 billion in buybacks and $900 million in ordinary dividends and VROC payments, and we ended the quarter with cash and short-term investments of $6.3 billion and $1 billion in longer-term liquid investments. Now turning to guidance. For the third quarter, we expect production to be in a range of 1.87 million to 1.91 million barrels of oil equivalent per day. This is inclusive of the 90,000 barrels per day of turnaround impacts that we discussed last quarter. The primary driver of that is our once every 5-year turnaround at Surmont, which will impact production by about 50,000 barrels per day during the quarter. For the full year, we have raised the midpoint of our production outlook, reflecting strong second quarter results. Our new range is 1.93 million to 1.94 million barrels of oil equivalent per day, which implies roughly 3% underlying growth year-over-year. Our full year turnaround forecast continues to be about 30,000 barrels per day. On income statement guidance items, we have lowered our DD&A guidance to a range of $9.3 billion to $9.4 billion and we have lowered our annual after-tax adjusted corporate segment net loss to a range of $800 million to $900 million. These decreases were partially offset by higher forecasted adjusted operating costs which we now anticipate to be in a range of $9.2 billion to $9.3 billion, primarily due to increased transportation and processing costs and inflationary pressures in the Lower 48. For CapEx, we expect to spend approximately $11.5 billion. Now this reflects strong progress on our Willow scope for the year as well as some additional capital allocated to Lower 48 partner operate activity that has highly competitive returns. On cash flow, we are increasing full year guidance for APLNG distributions by $100 million to $1.4 billion, and we expect $400 million of these distributions in the third quarter. Additionally, we’re going to have a $100 million pension contribution in the third quarter. Finally, regarding working capital. We anticipate a $500 million outflow based on the tax payment shift I mentioned from the second quarter to the third quarter. 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 we’re progressing towards closing the Marathon transaction. That concludes our prepared remarks. I’ll now turn it back over to the operator to start the Q&A.

Neil Mehta:

Good morning, Ryan and team. Thank you for taking the time. My question is just around everything buyback. So if you could just talk about share repurchase strategy and remind us, between now and August 29, you’re probably going to be out of the market. But your commitment to come back in the back half of the year and get to that over $9 billion -- at or above the $9 billion capital return number. So your perspective on taking advantage just on the volatility and as you plan for the back half as it relates to share repurchases.

Ryan Lance:

And Neil, I would add that, look, the share price has been frustrating to watch through the first half of the year, and we get it, we’ve been out of the market due to the Marathon transaction. I would just remind everybody that the shareholders come first in our value proposition, and that’s been consistent since we reset in 2016. We retired over 400 million of our shares over that period of time. And the average price per share that we purchased is somewhere in the $70 per share price. So it’s been -- the program has been managed really well. If you look at cumulatively, our return of capital over that period of time from 2017 through what we expect to do at the end of this year, that’s nearly $57 billion of capital has gone back to our shareholder over that period of time, representing about 45% of our market cap today. So with the -- and why we’re excited about the Marathon transaction is there’s just going to be -- we’re going to be bigger, but we’re going to be better and we’re going to have more free cash flow, and we’re going to have more funds to distribute back to our shareholders and we’ll retire the shares, as I said in my opening comments, 2 years to 3 years just based on our plans as we see it today. So this is an important question. It probably got some undercurrent around the share price performance, which we’re not pleased with as well, but we’re determined to be back in the market as soon as we can. And then buy back the shares to get our return of capital target for 2024.

Doug Leggate:

Sorry, I was trying to turn off the mute button. How’s everybody doing? Ryan, it was good seeing you a couple of weeks ago. Thanks for taking my questions. So I got done out of a question last time. So I’m going to stick to one, but I want to make one comment very quickly, and that is that market recognition of value, Ryan, flows through the dividends for companies of your size. So I commend you on your decision on the dividend decision. And I think you only have to look at CNQ to see what I’m talking about. So congratulations on making that decision. My question, however, is on the deal you announced while I was out. And more importantly, the tax benefits, but I don’t think we’re really fleshed out on the Q&A. Marathon has a lot of legacy NOLs. And what I’m trying to understand is how you use that and whether or not that was incorporated into your risk, view [ph] of synergies? And if not, what that could look like ultimately in terms of value?

Andrew O’Brien:

And Doug, this is Andy. And as Bill mentioned, we didn’t include the NOLs as part of our synergies. But in terms of the synergy, things are progressing really well there, too. We remain very confident of achieving that $500 million synergy run rate within a year of closing, and we see upside to that number. So our activities are now progressing well. As we mentioned previously, we expect this to be a pretty seamless integration. We stood up our integration teams. They’re focused on reviewing the organizational structures and systems so that we can be ready to close as soon as we get to go. So there are some obvious G&A synergies, primarily focused on the back-office support, the corporate function duplication as well as system integrations. The other synergies that we’re looking at are on the operating cost side of things, so there’s clear adjacency of the operating areas, which is going to lead to efficiencies such as improved productive time of our field staff. We’re also going to be able to rationalize the field office. And on the capital side, we’ve been really digging in here, too. We’ve worked the cost-saving opportunities from several angles here. And a couple of examples would be our ability to run the consistent program of scale is going to drive savings. As we look deeper, we see opportunities to bring the use of our super zippers and reroute frac operations to the Mountain Eagle’s position. So on the synergy side of things, we’re progressing really well. We’re going to be ready to go day one as soon as the transaction closes.

Operator:

Our next question comes from the line of Scott Hanold with RBC Capital Markets. Your line is now open.

Andrew O’Brien:

Hey Scott, this is Andy. I can take that one. As you mentioned, we have made further progress on marketing our LNG. We did secure a 0.75 MTPA of regas capacity at the Zeebrugge terminal in Belgium. And then we also entered into a long-term sales contract with an Asian buyer for approximately 0.5 MTPA. So these recent placements take our total now from the 4.5 we previously communicated to 6 MTPA. As a reminder, two of that is in support of the SPAs we have with Qatar. For competitive reasons, we don’t talk too much about in advance where we’re developing offtake sources or regas capacity. But as you can see from this quarter, we’re making really good progress on both fronts. And as we previously communicated, over the long-term, 10 to 15 MTPA would be a good range of capacity for us. At that size, we can achieve the full benefits of scale really across our organization. So I think we’re very happy with the progress we’ve made this quarter and I think everything is on track for what we’re trying to achieve here.

Betty Jiang:

Good morning. Thank you for taking my question. So I want to add about the upward movement in CapEx to the upper end of the guidance range, which was specifically attributed to Willow and then the non-operator activity, can you give us an update on how Willow is tracking versus your plan? And is that responsible for most of the increase in the budget?

Kirk Johnson:

Betty, this is Kirk. And I can give a little bit more color here on Willow specifically. Certainly, as Andy spoke to, our strong execution and the accomplishments that we’ve realized here in the first part of this year, just continues to give us a strong view of what Willow capital will be here in 2024. And that’s why we’re moving into this $1.5 billion to $1.7 billion range. Again, it is just a function of really strong execution across our workflows, and that is, of course, factored into our total company guidance. On any large projects such as Willow, achieving our scope and our milestones across the full suite of workflows from engineering through fabrication and construction all the way through supply chain in these first few years, especially having just taken FID here late last year. It’s just critical. And this sets the foundation for our success going forward as a project. Certainly, as you heard from me last quarter, our winter construction season here in 2024 wrapped up, and we were able to achieve all the critical scope that we had planned here despite some pretty challenging weather that caused some early delays, but ultimately, we were able to get all of that critical scope completed. On fabrication, the largest of our operation center modules, we completed ahead of schedule those modules shipped and they’ve now actually arrived in Alaska, and we have plans to take offload from bars to shore here this month in August. Engineering is also on track. And when we couple up the fact that we’re just doing really well on engineering as well as ramping up these operations center modules a bit early. It’s allowed us and our contractors to roll directly from fab to the ops center modules into the central processing facility modules. And we’re able to do that actually a couple of months better than planned, which just puts us in a strong position as this -- as we set this foundation for the large project. In fact, we cut steel here just last month in July. So I’ll wrap it up by, again, just reinforcing this first year post FID is important. And it’s also important in procurement. All of our major facility contracts have been landed in equipment orders. And in fact, we’re now at a place where we can say 80% of our total facility spend is wrapped up within contracts, and we continue to make progress on that here as we move into the second half of the year. So again, across all the workflows, just hitting these milestones early is really important and it gives us a lot of confidence to reinforce our prior guide on total project capital, and we’re still on track for a 2029 first oil [ph].

Operator:

Our next question comes from the line of Steve Richardson with Evercore ISI. Your line is now open.

William Bullock:

Maybe I’ll just start that, and Nick can talk to the details of Lower 48. So in terms of inflation and deflation, as we previously communicated, we’re seeing a bit of a bifurcation this year with Lower 48 seeing deflation, while ANI is experiencing some inflation. Now I’d say right at the margin, we’re seeing slightly more deflation than we expected in the Lower 48, while ANI is slightly higher than expected, but that’s right at the margin. Overall, our full year expectation is still in the low single-digit annual average deflation company-wide as we previously guided. I’ll let Nick provide a bit more color on the Lower 48. But industry-wide, what we’re seeing, we’ve seen a 20% drop in rig and frac activity over the last 12 months, driven by efficiency gains and activity reductions. And those efficiency improvements are still resulting in higher production, specifically to the Lower 48, where we are seeing high single to low double-digit deflation in some of our key spend categories.

Operator:

Our next question comes from the line of John Royall with JPMorgan. Your line is now open.

Andrew O’Brien:

Yes. Sure. I can take that one. And I think that -- the short answer is, yes, it is pretty steady when you adjust the turnarounds. We’re expecting organic production to grow 2% to 4% in 2024, and that should be pretty consistent across the Lower 48 and Alaska and International. And as Bill said in his prepared remarks, organic production was up roughly 4% year-over-year in the second quarter, which is towards the top end of our guidance, again, with a balance across Lower 48 and ANI. Now if you look at our production profile this year and I think is what you’re alluding to, is that if you exclude the turnarounds, we’re basically growing at 1% each quarter, it’s pretty straightforward. The profile is being masked a bit in the third quarter as that’s one of our heaviest turnaround quarters in some time with the 90,000 barrels a day of turnaround impact that Bill mentioned in the prepared remarks. Maybe just to give a little bit more color on that. That 90,000 barrels is split 50 in Canada, 20 in the Lower 48, 6 in Alaska, 5 in Norway and then 4 in Malaysia and Qatar. And in the Lower 48 specifically, now our second quarter actually outperformed our expectations, and we are expecting production to be fairly flat in the third quarter, and that’s due to the turnaround I just mentioned at the 20,000 barrels a day that we have at Eagle Ford. Then we’ll be up in the fourth quarter versus the third quarter. So bottom line, we’re tracking right in line with our guidance, just the quarter-to-quarter is somewhat masked a bit with the turnaround activity that you’re seeing.

Roger Read:

Yes, thanks, good morning. Maybe come back on the guidance side on the OpEx front. Obviously, you’re talking about cost going up a little bit. You’ve talked about some of the things on the CapEx side. I didn’t know if those were tied together like higher activity, higher costs. What part of this is kind of internal versus external? And broadly speaking, what are the inflationary pressures?

Operator:

Our next question comes from the line of Ryan Todd with Piper Sandler. Your line is now open.

Andrew O’Brien:

Yes, I can take that one, too, in terms of what we’re seeing. In terms of the offtake side of things, maybe I’ll comment from the offtake and the marketing. In terms of the offtake side of it, we’re happy with our position, and we continue to look for further opportunities at competitive pricing and the high likelihood of FID. The LNG pools is causing some questions from potential buyers on the timing of things. But again, against this backdrop, we’ve been able to sign two deals this quarter. And I think that clearly highlights the benefits of our permitted project. And in terms of the marketing of the LNG, we remain happy with the demand we continue to see, both in Europe and Asia for new LNG. And we’re continuing to work opportunities across the globe. And there’ll be more to come on that as we address them. We don’t talk too much about them in advance. But I’d say, big picture, we remain constructive on LNG and the role it’s going to play. And we’re quite pleased with the progress that we’re making to grow our position out in the 10 to 15 MTPA that we’ve previously communicated.

Neal Dingmann:

Hi, good morning. Thanks for the time. My question is on the Permian gas takeaway and maybe Lower 48 realization expectations. I’m just wondering, you all suggest you expect the Permian gas prices to remain depressed, and they can tell the -- more third-party pipeline capacity is added. And my question is, are you all thinking the pressure could be for several years ahead? And would you all consider curtailing anything until gas rebound? I know you have mostly oil. So just enough if there was anything to potentially curtail.

Operator:

Our next question comes from the line of Leo Mariani with ROTH. Your line is now open.

Nicholas Olds:

Yes, Leo, I’ll start here. So on Eagle Ford, you’re right, we’re really encouraged with the production. We hit 238,000 barrels equivalent per day versus 197,000 from Q1. And take the group back, we had that frac gap that we had in the second half of 2023, and then we reinstated that frac crew. And so you’re really seeing the benefit in Q2 as we work through that inventory. So really encouraged with the wells that we placed online end of Q1 and in Q2. So we’ve seen a strong bump in the production area. Wells are performing very strong throughout. Now as Andy mentioned, on the turnarounds, we’re currently going through, as we speak, large turnaround in Eagle Ford, that’s going as planned, as expected. So we’ll be slightly down on that. That’s 20,000 barrels per day impact equivalent per day for Q3 and you’ll expect to have Q4 back up and running. So really strong performance on Eagle Ford overall.

Operator:

Our next question comes from the line of Kalei Akamine with Bank of America. Your line is now open.

Andrew O’Brien:

Hi, Kalei, I can take this. Andy here. Maybe I’ll start with the demand side of that and then we can talk about sort of how we might respond to that. So I think you set up the narrative pretty well there in terms of sort of -- we are expecting to see tailwinds in sort of demand for gas on the LNG side, of the data center side and transportation needs. So just the under construction LNG plants, we’re going to add 10 to 15 Bcf a day over the next several years. That’s alongside the broader electrification trends. There has been a lot of forecasts. I think we’ve all seen them on AI-driven power demand, and they’re all constructive for natural gas demand. But I do want to point out, it’s important, so there are lots of different factors at play here such as a pace of those data center build-outs, constraints on the power expansion, the expected improvement in efficiency. So we’re still carefully working through that piece of the equation in terms of just seeing how material it’s going to be over time. But absolutely, we do see it driving demand. Then sort of going to the second half of the question, sort of what does that mean for us? So in terms of our portfolio, we have a lot of gas opportunities in our portfolio that we’re not currently developing today, a lot of dry gas opportunities. Now also, we have a lot of associated gas in unconventionals and we could choose to basically target gassier parts of the unconventionals. But for us, the bottom line is, it’s got to compete on a cost of supply basis where we are today to make the cut for our annual capital program. And the really nice thing about these gas opportunities is if the demand is there and the support is there, we can pivot very quickly to the gas in our portfolio if it makes sense, and it’s competing on a cost of supply basis.

Bob Brackett:

Good morning. And I’ll return to Willow project. It’s perhaps $7 billion of CapEx. It’s the biggest project, I think, on the North Slope in the last 20 years. And so I’ll ask some questions that are a little nitpicky to get comfort around the doability of the project. And I guess, on the facility side of spend, you mentioned the arrival of the operations center. The other pieces of the facility, I guess, are the drill pads and then the central processing facility, what’s the design philosophy around those? And how do you get comfort that you’re in strong control of those?

Ryan Lance:

And Bob, I’d add a couple of other things just from my long-term experience on the North Slope. This is, I don’t know, 25th or more drill site that we’ve built on the North Slope. They’re all truck and lateral designs. They’re the same design that we’ve done on drill sites for the last 10 or 15 years. So we know how to do that. We’ve done a lot of them and this isn’t any incremental scope. And then on the, central facilities to your question, we’ve done both. We’ve stick built facilities on the North Slope during our winter construction season, and we’ve built them off-site and sealifted them up. And the important part for Willow is the size of the opportunity there for us and the size and scope of the facilities lend themselves to offsite fabrication, and I think the team did a great job hitting the window pretty well on the Gulf Coast when there was ramping down of activity, we could slot our project in pretty quickly get the good productivity. And then as we’ve already demonstrated our ability to sealift the facilities up to the North Slope, it’s gotten really well with the first set of facilities showing up. So that’s an important distinction because a lot of stick built on the North Slope, but the size of Willow, to us, demonstrated the need to go off-site and build it on the Gulf Coast, get -- take advantage of better productivity and year-round building and then ship to the North Slope. So that should give you some comfort. We know what we’re doing. We’ve done this before. And these are just repeats of stuff we’ve done in the past.

Kevin MacCurdy:

Hi, good morning. To build on the earlier question about CapEx, your first half CapEx was in line, but now you’re pointing to that kind of the high end of the range for the year. We would assume that the Willow spend is more geared towards fourth quarter. But when do you see -- or when do you expect to see the higher activity in CapEx from the partner-operated activity, and how material is the production impact for non-activity?

Operator:

Our next question comes from the line of Paul Cheng with Scotiabank. Your line is now open.

Ryan Lance:

Go ahead, Andy.

Operator:

Our next question comes from the line of Josh Silverstein with UBS. Your line is now open.

Andrew O’Brien:

Yes. It’s Andy, I can take that one. On Port Arthur, specifically, as you mentioned, that is our Phase 1 is a fully permitted project. We started construction of the [indiscernible] construction there with the contractor. And at this stage, I just say things are on track. Really not much else to say in terms of the construction of the project at this point, it’s on track and going as planned. And then I think your second question was really on NPL. This one -- this impacted projects in U.S. and Mexico, these are impacted by the pause. And that is impacting the FID there. But I’d probably point you to go and -- so those questions are probably better answered by NPL in terms of sort of the pace of the project and where they’re at. We see, like you see sort of critical milestones being progressed. But they face the same regulatory hurdles that the rest of the industry does. You mentioned, you’re correct that we have we’ve agreed to take 2.2 MTPA of offtake in NPL. So we’re clearly watching the progress there, too, but that one is contingent on the LNG pause.

Ryan Lance:

Thanks, Phil, and thank you to everyone for joining our first quarter 2024 earnings conference call. It was another solid quarter of focused execution across the portfolio on our strategic plan. Starting with our international projects. We continue to ramp up production at Surmont Pad 267 in Canada, Bohai Bay 4B in China and 3 subsea tiebacks in Norway. And we expect to start up the fourth subsea tieback in Norway in the next month. In Canada at Montney, production reached a new record level following the start-up of the second central processing facility, leading to over 20% growth versus the fourth quarter.

Operator:

[Operator Instructions] Our first question comes from the line of Devin McDermott from Morgan Stanley.

Kirk Johnson:

Devin, this is Kirk. Yes. So we had a really strong start to project execution here on Willow this year. We were actively closing out here this week actually, our first major winter construction season on the North Slope where we were able to successfully mobilize over 1,200 workers and were able to successfully build out 7 miles of gravel road, 30 miles of gravel pads, 30 acres of gravel pads for future facilities. And we've successfully constructed all of the pipelines that we planned for this winter season. Certainly, in addition, module fabrication has continued to progress really well here this winter and this spring. And we're expecting to be ready to transport the first of those modules to the North Slope here on schedule here midyear, which is the Willow operations center.

Neil Mehta:

I wanted to spend some time talking about return of capital, and it is notable in the release you talked about at least $9 billion. So just your framework for thinking about what the right level of return of capital, it is early in the year. Oil prices have been volatile, gas prices have been weak, but certainly, you have a terrific balance sheet and have the capacity to raise that number. So I'd love your perspective on that.

Francis Lloyd Byrne:

Ryan, can you just comment strategically on the Permian gas and just kind of how you see that playing out? You guys have been really proactive in integrating some of that gas and looking forward, but any target levels you have? And maybe just how you're thinking about some of those differentials.

William Bullock:

Yes, sure. Lloyd, so as we talked about in the past, we have -- we shipped to multiple markets. We've got transport capacity to the Gulf. We've got transport capacity on West Coast. We're very supportive of offtake capacity from the Permian Basin. In fact, we do have some firm capacity on the upcoming Matterhorn pipeline, but a sizable portion of our volume also is exposed to prices and in-basin pricing. We don't disclose what percentage moves to each location for commercial reasons. But a really good way to think about the company's realizations is as a percentage of capture of first of month Henry Hub pricing that's what we show.

Scott Hanold:

I'd like to take a look at the Lower 48 activity. Obviously, 1Q is down a little bit just because of the weather, but can you give us some color on how you see that progressing through the year? Should we see a nice bounce back in 2Q and then that steady kind of slow single-digit kind of rise through the course of the rest of this year?

Operator:

Our next question comes from the line of Betty Jiang with Barclays.

Nicholas Olds:

Yes. Well, good. Let's start on some of the longer laterals. I talked a little about previously on the operating efficiency on the frac spreads and drilling. Again, our teams are very focused on long lateral development as we go forward. As a reminder for the group on the phone, if you look at our Permian inventory, 80% of the laterals are 1.5 miles or greater, and we got 60% 2 miles or greater. If you look specifically at 2024, again, 80% of the wells or 1.5 miles or greater and about 20% are 3-mile laterals. And we've got -- as I mentioned before, we got some of those longer laterals coming online in the second half of this year.

Operator:

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

Ryan Lance:

Yes. Thanks, Roger. I'll take a shot and maybe let Andy chime in a little bit as well. But as I said earlier, I think we certainly step back to a few years ago and wanted to continue to grow our LNG exposure in that position. We know the markets. We have our own technology. We know the business quite well, and we do have a strategic intent to continue to try to grow that. And it's really participating in all facets of it, the production side here in North America, in Qatar, in Australia, being in the liquefaction side here in North America and elsewhere being -- having ships and being in the regas potential as well.

Andrew O'Brien:

Yes. Thanks, Ryan, and thanks, Roger, for the question. I think this is a bit of our business that I don't think is completely understood. So it might be helpful if I just put sort of some of the details around it. As Ryan said, if you go back all the way to 2022, we increased our ownership on the resource side with taking more equity in APLNG. And then we've also participated in the 2 Qatari expansion projects.

Operator:

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

Ryan Lance:

Yes. Thanks, Nitin. I say, first, now on the Citgo, we're watching that process. Look, we're a creditor in that process. So we own quite a bit of money by the Venezuelans. So we're watching that process pretty closely. Look, I'm not trying -- we're not trying to become an integrated refining or major with -- refining in our portfolio. This is the way to protect what's the company and the credit that we have against the Venezuelan government. So we're watching that and following that process pretty closely, but that's to get the money that they owe us for the judgments that we have against the Venezuelan government for the expropriation of our assets. Look, we're obviously optimizing the portfolio. I think in the last call, Andy mentioned the acquisition of some APLNG interest a couple of years ago.

Operator:

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

Ryan Lance:

Yes. Thanks, Paul. Look, I think AI is going to be -- is going to revolutionize a lot of things in our industry, other industries around the world as well. I think Nick in his response to a previous question, talked about some of the things we're doing on the digital space with the date, the automation and some of what we're trying to improve our company, improve our operating efficiency. I can't comment on what somebody else said on their conference call. I think it's going to have an impact on the business, I think it goes to things like learning curve and its pace.

Ryan Todd:

Maybe just to follow up on some of your LNG conversations from earlier, you clearly talked about there's still work ongoing on the commercial and marketing side and building out some of those kind of things. Is there still appetite to add on the supply side, Qatar announced another LNG expansion in North Field West. Is that the type of thing you'd be interested in more of that in the portfolio or more supply-side LNG within the portfolio? And then are you seeing signs, we've seen -- or some compliance for others about signs of cost inflation on global LNG projects. What are you seeing as you look at the development of your LNG liquefaction trends across the portfolio right now in terms of cost inflation?

Operator:

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

William Bullock:

Yes, Neal, this is Bill. As we talked about, we have offtake capacity both to West Coast and the Gulf Coast, and we're interested in additional takeaway capacity on Matterhorn, like I talked about, so we are constantly looking for ways of optimizing that portfolio. Our commercial organization is in the market daily. We're doing orders of magnitude on that production. So we really have a good sense of where volumes are moving and what rates are going. And so I think that the improvement on margins. And as you're looking at that, that's really going to come down to getting additional takeaway capacity coming out of Permian. And as we've gone into the second quarter, we've had some maintenance going on there with El Paso and a couple of other pipelines and a couple of outages that's putting pressure on Waha pricing. I think everybody has been seeing that. That will likely clear through the system here as we go through this quarter.

Operator:

Our next question comes from Bob Brackett with Bernstein.

Kirk Johnson:

Bob, this is Kirk. Yes, first, I'll probably just start out by saying our operational performance that this past year has been really strong, and that's important having come through the acquisition of our -- of the remaining 50% interest in that asset. And of course, we brought on that new pad. Certainly, as you've heard from us before, first in on 267 and started earlier this year. And then we achieved first oil in December. And we've been seeing a really steady, strong ramp on Pad 267, having started that in December here through first quarter. Production for first quarter is up 3 MBOE, and we really have just seen 267 start to grow, and we expect that to continue to offset decline, especially when we normalize that for the third quarter turnaround that we have coming up.

Operator:

Our next question comes from the line of Alastair Syme with Citi.

Ryan Lance:

Yes. Yes, also, we're not making any capital allocation decisions. It's all driven by the liquid side of the business. I think, as Bill articulated, we need more takeaway capacity out of the Permian to get the Waha prices back up and we're advantaged a bit because we have El Paso volumes that we can take to the West Coast. They've been in a bit of a turnaround as well and some maintenance activities going on that pipeline. So there's a dynamic happening in the basin that is impacting Waha prices.

Operator:

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

Andrew O'Brien:

This is Andy. Yes, I can take that question. It's a pretty simple answer. As you said, we came in at $2.9 billion for the quarter, which was slightly less than our guidance. That slight underspend was a result of some Willow capital shifting from the first quarter into April. So if you exclude in that timing, our capital spend came in accordance with our expectations. Now as you look ahead to the second quarter, capital is expected to be slightly higher than the first quarter driven by PA LNG and the Willow timing. And then as you look forward to the second half of the year, capital is expected to be lower than in the second half than the first half, primarily due to the $400 million of Port Arthur LNG equity capital spend that rolls off as we go into project financing.

Leo Mariani:

I was hoping you could speak a little bit more to the expected trajectory of your Eagle Ford volumes. I know you had kind of the frac holiday a bit, which kind of impacted volumes in the last couple of quarters. I know they've been kind of trickling down here. I guess is that over? Do you have more of a normal activity cadence? And should we start seeing growth in those volumes as we roll into the second quarter and the second half of the year?

Operator:

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.

Phil Gresh:

Thank you, Liz. And welcome everyone to our fourth quarter 2023 earnings conference call. On the call today are several members of the ConocoPhillips leadership team, including Ryan Lance, Chairman and CEO; Tim Leach, Advisor 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. Ryan 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 publish supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. Second, during this call, we will make four 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 third, when we move to Q&A, after the prepared remarks, we’ll be taking one question per caller. With that, I will turn it over to Ryan.

Bill Bullock:

Thanks, Ryan. In the fourth quarter, we generated $2.40 per share in adjusted earnings. We produced 1,902,000 barrels of oil equivalent per day, representing 4% underlying growth year-over-year. This was consistent with our full year 2023 underlying growth rate of 4% also. Fourth quarter Lower 48 production averaged 1,086,000 barrels of oil equivalent per day, which represented 9% underlying growth year-over-year. We produced 750,000 from the Permian, 211,000 from Eagle Ford and 110,000 from the Bakken. Full year 2023 underlying growth for the Lower 48 was roughly 8%. Moving to cash flows, fourth quarter CFO was $5.5 billion and this included APLNG distributions of $281 million. Fourth quarter capital expenditures were $2.9 billion, which included $573 million for longer cycle projects. Full year capital expenditures were $11.2 billion, which included $2 billion for longer cycle projects. Now regarding returns of capital, we delivered $11 billion to shareholders in 2023. For the fourth quarter, we returned $2.5 billion. This was via $1.1 billion in share buybacks and $1.4 billion in ordinary dividends and VROC payments. We ended the year with cash and short-term investments of $6.9 billion, as well as $1 billion in long-term investments. In the guidance [ph], we forecast 2024 production to be in a range of 1.91 million barrels of oil equivalent per day to 1.95 million barrels of oil equivalent per day. This translates to 2% to 4% underlying growth pro forma for acquisitions and dispositions. We expect this growth to be well balanced between both Lower 48 and International. Our full year forecast includes turnaround impacts of 25,000 barrels per day to 30,000 barrels per day, which is about 10,000 barrels per day higher than in 2023. Now turnarounds are expected to be concentrated in the third quarter, when Surmont completes a one-month turnaround and that turnaround occurs once every five years. For the first quarter, production guidance is in a range of 1.88 million barrels of oil equivalent per day to 1.92 million barrels of oil equivalent per day, a roughly 1% to 3% underlying growth. While the first quarter will have minimal turnarounds, similar to the fourth quarter, it does include a 20,000 barrel per day headwind from January weather impacts. For APLNG, we expect distributions of $400 million in the first quarter and $1.3 billion for the full year. Now shifting to cost guidance, we see full year adjusted operating costs in a range of $8.9 billion to $9.1 billion, representing essentially flat unit costs on a year-over-year basis. Full year cash expiration expenses are expected to be $300 million to $400 million, and DD&A expenses are expected to be in a range of $9.4 billion to $9.6 billion. Full year adjusted corporate segment net loss guidance is $1 billion to $1.1 billion. And for taxes, we expect our effective corporate tax rate to be in the 36% to 37% range of strip prices, and that’s excluding any one-time items and that’s with an effective cash tax rate in the 33% to 34% range. For capital spending, our full year guidance range is between $11 billion to $11.5 billion, which includes $200 million to $300 million of capitalized interest. Now on slide eight of the presentation, we provided bridge from 2023 to 2024 with some of the key year-over-year variables, most of which we’ve discussed on prior earnings calls. These include our expectation of $200 million to $300 million in deflation benefits, primarily in the Lower 48; $200 million to $300 million of lower spending in Norway following the startup of our four subsea tieback projects; and $500 million to $600 million in lower LNG spending, mostly at Port Arthur. These decreases are offset by a $900 million to $1 billion increase at Willow, and $100 million to $200 million increase in Canada to account for the acquisition of the remaining 50% of Surmont and the addition of a second rig in the Montney. For Willow, we expect spending to be more heavily weighted to the first quarter and this is consistent with the normal timing of winter construction season. And for Port Arthur, we expect that our $400 million of equity contributions in 2024 will also be weighted towards the first half of the year. Now as a result, first quarter CapEx could be a bit above $3 billion. So to wrap up, we ended the year with another solid operational quarter. We continue to deliver on our strategic initiatives across our deep, durable and diverse portfolio, and we remain highly competitive on our shareholder distributions. Now that concludes our prepared remarks. I’ll turn it back over to the Operator to start the Q&A.

Neil Mehta:

Thank you. Thank you, and good morning, team. Ryan, I want to ask you about the Lower 48. Last year, you correctly predicted that many of us who thought production was going to be up 400,000 barrels a day to 500,000 barrels a day, were wrong and the number ended up being closer to your number of 800,000 barrels a day to 900,000 barrels a day. So as you think about exit -- to exit this year, how are you thinking about U.S. oil production and tie that into your own Lower 48 development plans. How are you thinking about prosecuting that acreage over the course of the year?

Neil Mehta:

Thanks, Ryan.

Doug Leggate:

Thank you. Good morning, everyone. I guess, your…

Doug Leggate:

Thanks, Ryan. Ryan or Bill, I’m not sure who wants to take this one. So we’re always interested to know how you see your portfolio breakeven evolving as it relates to not so much current capital, but sustaining capital. And what we’re really trying to get to is that dividend breakeven, that post-dividend breakeven level. If I may, maybe as a Part B to that, I’m curious whether cash in the balance sheet benefits or is a priority currently as it relates to how you think about cash returns in that dividend context, given that you’re entering a period of elevated spending here for a couple of years.

Dominic Macklon:

Yeah. Good morning, Doug. So maybe starting with our free cash flow breakeven, I take you back to our analyst meeting last April for our 10-year plan. And at mid-cycle prices, we highlighted our free cash flow breakeven averages about $35 WTI. That is higher through the first half of the plan, as you mentioned, as we have the sort of pre-productive capital in the first half of the plan and then lower during the second half of that 10-year plan as those projects increasingly come on stream. So that’s our free cash flow breakeven. And for our dividend, you would add an additional sort of $8 to $9 on that right now.

Bill Bullock:

Yeah. Sure. We’re really happy with where we’re at on the balance sheet right now, Doug. So, we exit the year with $6.9 billion of cash and $1 billion worth of long-term investments, like, I mentioned. Our net debt-to-CFO ratio is in a really good spot. We’re at 0.5 turns and that’s post-Surmont. So we’re quite happy where the balance sheet is at right now. And having a strong balance sheet is a strategic asset for the company. We continue to view it as such and that’s fundamentally one of the reasons why we feel really good about $9 billion of distributions this year.

Ryan Lance:

Yeah. In light of arguably a softer commodity price relative to where we started in 2023.

Roger Read:

Yeah. Thank you. Good morning. I guess I’d like to…

Roger Read:

… maybe get your thoughts, Ryan, on -- yeah, good morning -- on the M&A side. Obviously, you did the Surmont thing last year. There’s still transactions going on and just how you think about your cost of supply approach to anything on the acquisition front that’s out there, be it Lower 48 or elsewhere?

Roger Read:

Thank you.

Nitin Kumar:

Good morning, guys, and thanks for taking my question. Ryan or Bill, I don’t know who wants to take this one, but you reduced the cash return target from $11 billion to $9 billion. Last year, it was very evenly distributed between your dividends, both the fixed and the variable, and the buyback. How should we think about the mix across those three channels in 2024?

Nitin Kumar:

Great. Thanks for the color.

Lloyd Byrne:

Good afternoon, everyone, and thanks for all the detail so far. Ryan, I was hoping just to get your thoughts on the administration’s LNG pause and then in particular Conoco’s positioning and maybe whether it has any impact on your plans or your capital going forward?

Bill Bullock:

Yeah. Sure, Ryan. We’re really pleased that Port Arthur Phase 1. It’s fully permitted. It’s got not only its free trade agreement permit, but its non-free trade agreement permit. It’s got environmental permits in place. So we’re quite pleased to be investing in Port Arthur Phase 1. We think that actually what you’re seeing right now makes that more valuable. So it’s a good fit in our portfolio. We’re continuing to look at developing a diversified portfolio of offtake. We remain interested in a number of LNG opportunities, because we think the market’s going to be strong for decades to come. We’re focusing on low cost supply, low greenhouse gas intensity resources that meet that transition pathway. And you saw us last year announce 2.2 million tons from NPL at Saguaro, and in the fourth quarter, we signed 0.2 million tons off of Sempra’s ECA project on the west coast of Mexico for five years. So we’re continuing to look for opportunities that really fit that framework. But regarding your question on permitting right now, Port Arthur’s in a great spot.

Bill Bullock:

It’s not impacting us right now.

Operator:

Thank you. Our next question will come from the line of John Royall with JPMorgan.

Andy O'Brien:

Hey, John. This is Andy. I can take that question. So, yes, it’s pretty nice to also be at a point now where we can start talking about the project and not just give you a legal update. But we will, given your question, I’ll start with a bit of a legal update, because as you mentioned, we had a fair bit of positive activity in the fourth quarter on that front. So just to sort of summarize where we are right now is that, we’re very pleased that both the Alaska District Court and the 9th Circuit allowed construction work to proceed on the North Slope. And then separately, the Alaska District Court upheld the legality of the ROD issued by the BLM. So as you mentioned, this is currently being appealed to the 9th Circuit. But as we said before, we believe the BLM and the cooperating agencies conducted a really thorough process that satisfied all the legal requirements for them to grant their approvals. So these positive rulings gave us the certainty to make the FID decision. Now then, in terms of the second part of your question on execution itself, since taking the FID, we’re really pleased with how quickly we’ve ramped up the activity. We’re now into our second winter construction season on the North Slope. And we’re mobilizing 1,200 workers right now who are going to be building gravel roads, gravel paths for the facilities and beginning laying pipelines. We’re also making some pretty significant progress with our modular facility fabrications. So we do expect 2024 capital to be in the upper end of the previously communicated annual ranges of $1 billion per year to $1.5 billion per year. But our estimate for the capital to first production remains unchanged at $7 billion to $7.5 billion. Now just to give you a bit more color in terms of the progress, we’re now at a point where we have three quarters of the project scope under firm contract and expect to have 90% of that under contract by the end of 2024. And of those contracts that we’ve issued so far, 70% are either lump sum or unit rate contracts and then these kind of contracts, we’ve agreed a price now, so we have limited exposure to future inflation. So it’s still very early, but with all major projects, it’s really important we get off to a fast start. And we’re really pleased that’s exactly what we’re doing with Willow. So just to wrap it up, it’s great to see at this point now our team’s in full execution mode, focused on actually building Willow.

Operator:

Thank you. Our next question will come from the line of Neal Dingmann with Truist Securities. Your line is now open.

Dominic Macklon:

Yeah. Neal, it’s Dominic here. I think, I mean, first of all, I think, it’s probably three questions there, actually. I’ll take the activity one. We were holding our Lower 48 activity flat this year versus last year. We like that, we’re still seeing some modest growth there and we get -- we’re really focused on efficiency there. And so, if we did get more efficient and we felt there was some capital headroom there, I think, I suspect that we would pretty much hold things flat, because we’re just so focused on efficiency. We don’t want to swing our programs around. In terms of the total growth rate, remember, growth is an outcome of our plan. We’re not chasing growth. It’s really an outcome of a return that’s focused on returns. And so, we’re pretty happy with that sort of modest level growth. It’s pretty consistent with what we said at AIM. In terms of the overall profile, just to give you a bit of color on that, I mean, Bill mentioned a lot of this in his prepared remarks. But we do expect sort of underlying production in the range of 2% to 4% growth this year versus last year. And the good thing about it is that we’re seeing growth this year, not just coming from the Lower 48, but also from across our International portfolio. So it’s nice to see the diversity of that portfolio coming through. And then, of course, on top of that organic growth, we have the additional Surmont 50% interest on top of that. In terms of the shape for the year, fairly rateable year-over-year growth by quarter, except for Q1, we have the weather impacts. Bill mentioned that, about 20,000 barrels a day of weather we’ll see in Q1, and then in Q3, we have our turnaround impacts. So we have about 25,000 barrels a day to 30,000 barrels a day of turnaround impacts this year. Most of that will be in the third quarter and that includes a sort of month-long turnaround we have at Surmont, which occurs every five years. So -- but anyway, we’re all very pleased with just where the growth is coming from. We’re pleased with the level of growth and I think we’re pretty committed to keep the program steady, stable and focus on efficiency.

Neal Dingmann:

It’s great to hear that, guys. It makes much more sense. Thank you so much.

Josh Silverstein:

Thanks, everybody. So I just wanted to touch on the Montney. This is one of the key growth areas that you had highlighted back in April last year. You mentioned the processing facilities started up in the back half of the year as well. I know it’s 60% liquids, but how has the lower natural gas price environment changed the way you’re thinking about development there? And along those same lines, I know there’s only a small uptick in Canadian spend for the year. I figured that might be related to Surmont more than this. So any help there would be great? Thanks.

Josh Silverstein:

Thanks, guys.

Bob Brackett:

Yeah. Good morning. I was looking at the triple-digit organic reserve replacement ratio and wondering some of the moving parts and kind of curious what impact did the sanctioning of Willow play on that?

Bob Brackett:

Yeah. Very clear. Thanks.

Sam Margolin:

Hi. Thanks for taking the question and thanks for all the detail today. Maybe a follow up on Lower 48 capital. There’s some deflation that you’ve called out. It seems like most of it right now is driven by consumables and commodities. But, Ryan, you mentioned activity levels overall have cooled significantly over the course of the second half of 2023. And so I was wondering, if you -- where you think we are in maybe the lifecycle of this Lower 48 deflationary trend and maybe if that presents some opportunities to term out capacity and add even more visibility to the spending plan, because as you mentioned, you’re not really going to move activity around in different scenarios? Thank you.

Nick Olds:

Yeah. Sam, like Ryan was mentioning, again, you look at our activity level, it’s flat to 2023, so stable rigs, stable frac crews and the teams are really just focusing on driving operating efficiency, capital efficiency. And then capturing that deflation, as you mentioned, as we showed in the prepared slides there that we posted and it’s going to range across a number of spend categories. So we’ve got OCTG, we’ve got some propent, as well as rig horsepower. We’ll look at all of the contracts across our vendors and see if we want to turn them up. Typically, we’re looking at well-to-well, pad-to-pad as far as rigs, little longer term contracts on our frac spreads, especially the e-fracs. But the key thing for us is really just focusing on operating efficiency and capital efficiency with the level loaded steady-state program that we have in 2024.

Operator:

Thank you. Our next question will come from the line of Ryan Todd with Piper Sandler. Your line is now open.

Ryan Lance:

Yeah. Ryan, just talk first on Eagle Ford.

Ryan Lance:

When you look at Q3 to Q4, we had that 9% production drop. That met our type curve expectations. There’s no productivity issues or operational concerns there. It was a conscious decision. As we looked at the second half of 2023 and as we’ve talked about the completion efficiencies are actually outpacing our drilling efficiency. So it’s a good problem to have. So we’ve worked down through kind of our working level of ducks and decided on the second half of 2023 to take what I call an operational frack gap. So we built some ducks in that period of time and then reinstated late 2023 the frack group. So it’s really intentional, really good performance from the Eagle Ford going forward. Bakken, very similar. We’ve hit some production records. You think about a legacy asset like the Bakken, we were hitting 110,000 barrels equivalent per day. We’ve got a long level of inventory. We’ll have a steady program up there as well.

Operator:

Thank you. Our next question will come from the line of Alastair Syme with Citi. Your line is now open.

Ryan Lance:

Yeah. I’ll first talk about just the overall efficiency assumptions that we have and what we’re seeing out in the field. To remind you on both D and C, we continue to see step changes in both the drilling side, as well as the completion side. Probably differential on the completion efficiencies, as I just mentioned, related to Eagle Ford. And we’re leveraging all of the different kind of suite of opportunities to improve those frac efficiencies and drilling efficiency. I’ll just mention a few. And the key thing here is that we’re continuing to see improvement kind of quarter-to-quarter, year-to-year. And that manifests itself into essentially a 10% to 15% improvement in our pumping hours per day, year-to-year. A couple items that we have out there, we continue to deploy simul frac across the Board, but also super zipper down in Eagle Ford. We’ve had really good success of this particular application or we can hook up, for example, on a four-well pad, we’ll hook up all of the wells and if we have any operational downtime, we can quickly move from well-to-well and have high pumping hours, and therefore, more stages per day. So that’s been really successful. On the -- we also remote frac. I’ve mentioned that before. We’ve seen good success in that where we don’t have to mow and de-mow the frac spread so we can move on to Pad 2, Pad 3 without de-mowing it. And then, finally, I’ll just pivot to the drilling side. We’ve deployed that real-time drilling intelligence group out in the Permian. We’ve got the entire rig fleet that we’re monitoring 24x7 where we can optimize the plan, we can troubleshoot, and we can steer the wells and we’re seeing really promising results, 10% improvement in rate of penetration there. So combined through all of that, we are seeing improvement in those efficiencies. And again, 10% to 15% improvement in pump hours per day, as I mentioned on the collision side.

Paul Cheng:

Thank you. Good morning, guys.

Paul Cheng:

I think this maybe is for Phil or maybe it’s for Ryan. Ryan, you have said that the industry will need more consolidation and you have proven in the past that you are not shy in doing your share. For the right deal, when you’re looking at your balance sheet today, how much are you willing to put on the debt or how much are you willing to stretch your balance sheet from that standpoint if it is the right deal? Is there a number or a ratio or anything that you can share so that at least we get some better understanding? And from a balance sheet standpoint, the $9 billion of the distribution for this year, is there a fixed amount or that it will fluctuate based on the commodity prices, either better or worse, than your current assumption? Thank you.

Paul Cheng:

Ryan, you said maximum debt you’re willing to add based on a single transaction?

Paul Cheng:

Okay. Thank you.

Leo Mariani:

Hi, guys. You talked about having some pretty decent International growth this year, well above the Lower 48, which is obviously a nice contributor as well. It sounded like some of that’s coming from the Montney in Canada. Can you maybe just detail some of the other International growth that you’re seeing? I imagine there could be some chunkier projects that might be coming online during the year. Is there any call around that would be helpful?

Leo Mariani:

Thank you.

Philip Gresh:

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.

William Bullock:

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 organic 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.

Neil Mehta:

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?

Ryan Lance:

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.

John Royall:

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.

Operator:

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

Dominic Macklon:

Yes, it's Dominic. Stephen. What we'd say is very consistent with the AIM framework we laid out on CapEx. Just to recap the moving parts. We've got several moving pieces. We got -- assuming Willow is sanctioned, which we expect spending on that project will be higher. And then, of course, you have the incremental $100 million or so for the other 50% of the term of the Surmont that we're adding. And those increases will be mostly offset by, we're going to see lower spending on our LNG projects and roll off of the project capital at Norway. So but I think the key message there is really very much in line with the framework we laid out at AIM. Of course, you do have the addition of Surmont to extra 50% there.

Doug Leggate:

Although Phil has gone to the dark side with the one question...

Doug Leggate:

If I may, I'd like to make one comment and ask one question. My one comment is your stock's up almost 5% this morning. I think acknowledging your dividend move -- ordinary dividend move is gaining recognition in the market. And congratulations on taking that step. We'd like to see more of it. Okay. With that, my question is simply this. One of my peers asked a question earlier about performance in the Permian. I thought I'd like to ask it a little differently, one of your very large peers had some nonoperated portfolio problems in the quarter. You guys have got a large part of your production that comes from nonoperated production. Is there any discernible difference between your operated performance and your nonoperated performance that's driven this reliable production growth year-over-year.

Nicholas Olds:

Yes, Doug, good question. I mean, I think you're looking at the Q2 to Q3 performance this year, we were up 2%, so sequential growth. And as Bill mentioned in his prepared remarks, we're seeing 7% year-over-year. Obviously, that has a combination of our operated and nonoperated portfolio. Both are performing well. Specifically, Doug, in Q2 to Q3, a large component of that increase was our operated Permian program, as well as OBO. So we're seeing increases in the operated by others, and a little bit of Bakken as well. I mean we -- these operated by other assets are very competitive. We look at every ballot. We benchmark each one, and it performs well within our cost supply framework. As a reminder, if you look at Permian in general, about 30% of our production is coming from operated by other, within the Permian. And if I take you back a little bit in time to the Analyst Investor Day, when you think about the split between the 2 basins, we've got 2/3 of our inventories in the Delaware, 1/3 in the Midland Basin to generate the full Lower 48 of 5%. But bottom line, Doug, is that they're both competing well. We will review every ballot to make sure we're investing the right capital and drive that capital efficiency.

Francis Byrne:

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.

William Bullock:

Yes. I'm happy to put a bit more color on that. So we're very focused on developing market. And as we've talked about, we want to do this in a stair-step fashion with how we originate supply. You've seen us announce Port Arthur LNG and LNG. We're making really strong progress at 2.8 million tonnes per annum of regas capacity at German LNG, 2 of that is dedicated to supporting our LNG out of Qatar that leaves 0.8 at Germany. We just added 1.5 million tonnes of regas capacity at Gate. So that's 2.3, that's roughly half of Port Arthur. And I think importantly, we're continuing to see a lot of interest and strong demand for LNG. As we've talked, we're looking to develop a diversified portfolio that's both sales into Europe and also sales into Asia, perhaps some FOB sales at the facility and having a mix of variety of term links in that. And so I'm just -- I'm really pleased with the progress we're making within 6 months of kind of FID on Port Arthur, we've got roughly half of it placed. And I think the way to think about that, just going back to the vignette, I showed at AIM is, you look at the capacity that we have into Germany and the TTF, the way to think about that as you're modeling returns as you start with the Henry Hub price, you add liquefaction tools shipping and regas, you compare that to what you think European gas price will be. That's going to give you your base CFO for volumes into Europe before adding any diversion optionality on to that. You can do a similar type analysis going to Asia. So yes, we share your view here that these are very interesting additions to our portfolio, and we're really pleased with the progress we're making.

Devin McDermott:

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.

Operator:

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

Ryan Lance:

Yes. I'll let Nick respond to that specifically. And I guess I'd make this one broad comment is, I think as we talk about this topic, I think in the companies and a lot of people are guilty of this inflation a bit, between recovery and recovery rate or recovery factor. So I think you have to be really careful when we talk about this, in light of these unconventionals, we're doing everything we can to improve the recovery that we get from the wells, the acreage, the blocks, the layers that we have within our portfolio. And -- but be careful not to conflate that to recovery factor or a recovery rate. And I can have Nick speak a bit more specifically about the things we're doing to make sure we get maximum recovery out of our assets.

Operator:

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

Andrew O’Brien:

Roger, this is Andy. So yes, let me take that one. I'll start with the legal and then we'll give you a bit of an update on where we are with the project. So on the legal side, I talked about this on previous calls, there are lawsuits challenging the federal government's approval of the project. As I mentioned on the last call, we expect to see a ruling on this in November. The preliminary rulings in April were favorable and then the upcoming ruling will address the full scope of the legal challenge. Again, I'm repeating myself a little here, but as I said on the last call, we're very happy with how the BLM and competing agencies conducted the process, and satisfied all the requirements to grant their approval. So we're confident, and we're looking forward to those court rulings in November as we get ready for the 24 season. And then I think the other part of the legal question you were alluding to is the, separately, in September, the Department of Interior proposed additional regulations for the management and protection of the NPRA. And we don't expect these draft rules to impact Willow or prevent our exploration program. It doesn't have any impact on the 10-year plan we've previously laid out at AIM. But that said, we are concerned if the rules are adopted as currently drafted, they could impact future developments beyond Willow, in the National Petroleum Reserve Alaska. So the way to be providing feedback to the Department of Interior to try and make the proposed rules more consistent with the existing statute. And again, I'll just finish the legal bit with -- as a reminder, the statute recognizes the primary purpose of the NPRA is to increase domestic oil supply. So that's kind of where we are on the legal side. And then just very quickly where we are in terms of the project. Taking a step back here, as I described back at our investor update, Willow, is the kind of project that's right in our wheelhouse. We've got no first-of-the-kind type risk here. It's 3 drill sites to 1 new processing facility. And our track record and our [indiscernible] of excellence in delivering on schedule and on budget. But specifically to where we are right now, work is progressing well, and our 2023 capital is fully factored into the total company guidance we gave today. We started the first phase of module fabrication on the Gulf Coast. And then on the North Slope, we've successfully opened the gravel mine, and we're preparing for the 24th construction season. We've already got over half of the project scope under firm contract. And these contracts include clauses if we don't FID the project that we can exit. Now all the contracts we've issued today, 75% from a lump sum or unit rate for these type of contracts, we have a greater price and now have limited exposure to future inflation. So as we continue the contract negotiations, our estimate of capital to first production remains unchanged at $7 billion to $7.5 billion that we previously provided. So I think that probably gives you a good update on where we are on the legal and on the project side of things.

Ryan Todd:

Maybe one for you, Ryan, you've been on you've been busy on the portfolio over the last few years across a wide range of regions and types of assets across the portfolio. As you -- and some of that is obviously opportunistic just when the timing of things like Surmont and APLNG came up. But if you take a step back now and look, is there still more to do on the portfolio, in terms of portfolio management? Are there increased high-grading opportunities on the divestiture side that we should expect, as you continue to develop things, or any places that you would like to change or increase your exposure, maybe as you look going forward down the line in terms of long-term competitiveness.

Operator:

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

Ryan Lance:

Yes, we sure can, Paul.

Ryan Lance:

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 3 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.

Operator:

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

Ryan Lance:

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 pay off 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 up cycle to the price commodity price, we might look at adding more cash to the balance sheet as well. So I think all 3 of those are in play as we think about, what we do over the course of each quarter as we go into next year.

Sam Margolin:

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.

Operator:

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

Ryan Lance:

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 compete 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, 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.

Scott Hanold:

I was just kind of curious, does consolidation that creates larger peers in the Permian impact the competitiveness of comps development and positioning. Specifically, if you look at services and midstream capacity, as you kind of move forward on your -- kind of 7% growth CAGR over the next decade plus?

Operator:

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

Ryan Lance:

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.

Leo Mariani:

I wondered if you could just comment on what you're seeing in terms of -- kind of Lower 48 service cost trends. I think there was a lot of expectations a handful of months ago that costs may be falling, but now kind of commodities that have kind of recovered. Maybe just give us kind of your perspective of what you're seeing there on leading edge costs.

Operator:

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.

Philip Gresh:

Thank you, Liz, and welcome to everyone to our second 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, Planning and Development. Ryan and Bill will kick off the call 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 be making 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. So with that, I will turn the call over to Ryan.

William Bullock:

Thanks, Ryan. Diving into second quarter performance, we generated $1.84 per share in adjusted earnings. We recognize that this result was below consensus, which we primarily attribute to transitory price capture headwinds in Lower 48 natural gas and Alaska crude. Now based on strip pricing for the second half, we expect price capture to normalize and be consistent with our previous full year guidance of $22 billion in CFO at $80 WTI and our published full year sensitivities. Moving to production. We set another record in the second quarter, producing 1,805,000 barrels of oil equivalent per day, representing 6% underlying year-over-year growth with solid execution across the entire portfolio. Planned turnarounds were successfully completed in Norway and Qatar. And Lower 48 production was also a record, averaging 1,063,000 barrels of oil equivalent per day, including 709,000 from the Permian, 235,000 from the Eagle Ford and 104,000 from the Bakken. Lower 48 underlying production grew 8% year-on-year, with new wells online and strong well performance relative to our expectations across our asset base. Moving to cash flows. Second quarter CFO was $4.7 billion at an average WTI price of $74 per barrel. This includes APLNG distributions of $405 million. And in the second quarter, we also received $200 million in proceeds, primarily related to a prior year disposition. Second quarter capital expenditures were $2.9 billion, which included $624 million for long-cycle projects. Now through the first half, we have now funded $700 million for Port Arthur LNG of the planned $1.1 billion for the year, which we expect to lead to a step down in overall capital in the second half. We also expect to see a step down in Lower 48 capital in the second half of the year. And as a result, we have narrowed our full year capital guidance range to $10.8 billion to $11.2 billion, with no change to the midpoint. Regarding returns of capital, we returned $2.7 billion to shareholders in the second quarter. This was via $1.3 billion in share buybacks and $1.4 billion in ordinary dividends and VROC payments. And we announced a fourth quarter VROC of $0.60 per share, which has us on track to deliver our $11 billion target for total return of capital in 2023. Turning to guidance. We forecast third quarter production to be in the range of $1.78 billion to 1.82 million barrels of oil equivalent per day, which includes 20,000 barrels a day of planned seasonal turnaround, primarily in Alaska and Europe. We have also increased the midpoint of our full year production guidance. Our new full year range is 1.8 million to 1.1 million barrels of oil equivalent per day up 15,000 barrels per day from the prior midpoint of $1.78 billion to $1.8 million previously. For APLNG, we expect distributions of $400 million in the third quarter and $1.9 billion for the full year. Consistent with our higher production guidance for the year, we have raised our full year adjusted operating cost and our DD&A guidance by $100 million each to $8.3 billion and $8.2 billion, respectively. We have also lowered our corporate cost guidance by $100 million to $800 million due to higher interest income. And finally, as a reminder, all guidance excludes any impact from announced but not closed acquisitions such as Surmont and APLNG. So to wrap up, we had another solid operational quarter. We're confident in our outlook, leading to our increase in full year production guidance. We continue to progress our strategic initiatives across the portfolio, and we expect to return $11 billion to shareholders this year. Now that concludes our prepared remarks. I'll turn it back over to the operator to start the Q&A.

Neil Mehta:

Want to build on Slide 7 here on price realizations. As you mentioned, a little weaker in Lower 48 gas and Alaska. You had mentioned some of the stuff is transitory, and it's moving in your direction in Q3. Can you provide a little more color there?

Neil Mehta:

Really appreciate that. The follow-up is a small bump here in production guide. It's been 2 quarters in a row where Lower 48 crude oil has come in strong above 560,000 barrels. So just curious on the driver of the bump was it in the Lower 48? Or is it throughout the portfolio and just your thoughts on production momentum over the course of the year?

Nicholas Olds:

Yes. Thanks, Dominic. Yes. So there are probably 2 main reasons for that driver for the top end of the range on Lower 48. First, we had modest accelerations of activity kind of late Q1 and 2Q, therefore, accelerating some wells online and then strong well performance. Now the accelerations that I mentioned was resulting of improved drilling and completion efficiency. So as I mentioned at the Analyst and Investor Meeting, we continue to realize improved efficiencies in 2023, therefore, accelerating some of the wells. So that's point #1. And then if you look at the overall strong well performance, we're seeing that across the board. So we're either at 2022 performance or exceeding our type curves in certain areas as well. So that's, as Dominic mentioned, very encouraging I will point out a couple of points on the drilling and completion efficiency that's making a large difference. We continue to realize efficiency improvements, for example, in our Permian real-time Drilling Intelligence Group, where, Neil, we have 24/7 real-time monitoring where we can optimize the rig program, we can troubleshoot across the entire Permian rig fleet and then share best practices across the rigs as well. That's resulting in 10% improvement in ROP. And then we continue to high-grade rigs across the Lower 48 to drive and improve operational efficiency. And then on the fracking side, simul frac, remote frac, and we're testing out some new technology down in the Eagle Ford continue to drive efficiency. So very encouraging.

Stephen Richardson:

I was wondering if you could talk a little bit about the Mexico-Pacific offtake agreement. Conceivably, you have a lot of -- looking at these types of deals. So why was this the right project for you? And also, what do you see the path to sort of FID and timing there? I would love to hear a little bit more about that and how it fits in the broader strategy.

William Bullock:

Yes, sure. So as we talked at AIM, we're really focused on building up both our market and our originating highly competitive supply on a pretty stair-step basis. And we're making excellent progress on both those fronts, Steve. So as Ryan mentioned, we've secured million tons of regas in Germany. That supports our 2 million-ton offtake from our LNG SPAs with Qatar. That leaves 0.8 for our commercial LNG business. And putting that in perspective, that's 16% of Port Arthur LNG right there. And we are continuing to make excellent progress advancing offtake into Europe, and we've been progressing discussions with several Asian buyers. Really happy and pleased with how we're moving forward with developing market. And against that backdrop, we are pretty thrilled to be adding 2.2 million tons of offtake on the West Coast of Mexico. That's obviously pending successful FID by Mexico Pacific. But you'll recall, at AIM, we mentioned that we're really interested in adding West Coast LNG into our portfolio. This particular facility adds diversity to our offtake options. It avoids the Panama Canal. It's supportive of volumes into Asia. And from a supply perspective, it really does complement our offtake from Port Arthur very nicely. It creates some excellent optimization opportunities. You probably noticed it's got strong backing from very credible counterparties in addition to ConocoPhillips, and it supports a dedicated pipeline from the Permian. So that's always appreciated. It provides further takeaway optionality from the basin, which I think is helpful for Waha pricing. And it also is using ConocoPhilips' optimized cascade technology. So there's quite a few reasons why we like having capacity at Saguaro. Now note that it is an offtake agreement. There is not an equity component to this one. It is simply offtake. And I think the most important point that Ryan has already mentioned is we can -- to see really strong demand for LNG, and so this fits quite nicely as we're kind of laddering our build-out of market and supply.

William Bullock:

Yes, I'm happy to. So let me just start with some overall context to how we're thinking about our cash balances and the acquisition of additional 50% interest. We ended the second quarter with a little over $7 billion of cash and short-term investments. And as we talked at AIM, that really provides strategic flexibility. It supports our investments in these mid- and longer-cycle projects in our shareholder distribution commitments. And when we look forward at the current strip, we expect that our organic sources and uses for the remainder of the year are going to be pretty balanced, Steve, and that our ending cash absent Surmont would be flattish with what we're seeing right now. Now as Ryan mentioned, Surmont is a long-life asset. It's got a really great resource base, and it's one of these ideal assets to think about funding with debt because of its long-dated cash flows. You can match your assets and your liabilities pretty well with something like this. So for the Surmont to transaction specifically, and it's a bit tactical, but it's likely that we will use debt for a majority of the funding for Surmont. And then I'll just wrap up by pointing out, Ryan said in his remarks that the pricing that we're seeing right now. We see strong incremental CFO from that 50% increase in working interest Surmont. That's starting to approach $1 billion of incremental CFO next year at $80. So we're quite happy with the Surmont acquisition and quite comfortable with our funding plans.

Doug Leggate:

Dom, I wonder if this is probably for you. I want to follow up on the question about well performance productivity, the terrific product production performance, the raise that you've introduced today. But I want to ask it a slightly different way. Your partner in the Permian -- specific to the Permian, I should say, has been talking about, I don't want to call it some magic formula or sauce or whatever, but the well productivity is off the charts, and you obviously are a big beneficiary of that. I'm wondering if you can comment as to whether there's any osmosis towards Conoco's operated production. And if you could maybe contrast and compare any differences you see between your 60% ownership position in the JV and your legacy position in the operated area around the Conoco assets?

Doug Leggate:

Basically, yes. Exactly right.

Doug Leggate:

Maybe do you say there's a notable difference between the productivity and the JV and your legacy assets or no?

Doug Leggate:

Great. Ryan, my follow-up is probably for you. you're adding $1 billion of cash flow from Surmont. Fantastic deal for you guys. Again, congratulations on that. You've evolved the LNG portfolio even since the Analyst Day. But yet, we still have 1 of the lowest ordinary dividend yields in the sector that you can clearly cover at very, very low oil prices. So I'm just wondering if I could ask you again to share your thoughts on whether some of that increase in free cash power of the portfolio translates to a more ratable or a higher ordinary dividend, which, frankly, we think you get better recognition for.

Operator:

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

Dominic Macklon:

Thanks, Sam. It's Dominic here. So it is a bit early for us to be talking about 24%, but there hasn't really been any change since -- to the long-term framework we've had and what we talked about at AIM back in April. We showed there an expected capital range depending on how oil prices and inflation was trending. Given that WTI is back to around $80 and the forward curve is about there as we have been anticipating, frankly, we'd expect to be at the higher end of that range that we talked about back in April. So a similar capital level for next year to this year. I think one other dimension I'll talk about is how much growth in the Lower 48, what amount of growth do we need as a company do we want. Well, that's always an outcome of a plan. We're always focused on returns, of course, returns on and of capital. But one of the things we're looking at next year is do we keep Lower 48 relatively flat, it's performing very well this year, or do we add a little bit of activity. That's one of the things we're thinking about. In terms of the longer cycle capital, yes, LNG spend is -- will be rolling off from this year over the next few years just as Willow picks up. We expect our longer-cycle capital to average around $2 billion, pretty flat for the next few years here. So that would probably give you the pointers in terms of the general direction for next year. It's like I said, it's pretty early, but that gives you a good sense of where our heads are at on that. So...

Dominic Macklon:

Yes. I mean we don't really relate those investments specifically and directly, but it's obviously all helpful in terms of demand for North American gas. So that's in our minds, certainly as we think about the overall value equation of LNG in North America.

Devin McDermott:

So I wanted to build on what Sam was asking about, some of the comments you made just on inflation or deflation trends. You had some benchmarks baked into the multiyear guidance at the investor meeting earlier this year. We've seen some signs of deflation in U.S. shale and some still rising costs in other pockets internationally. On a net basis across your portfolio, I was wondering if you could talk a little bit about the trends you're seeing here in the back half of '23 and then how that plays into the 2024 outlook to the extent you can comment.

Devin McDermott:

Great. And then I wanted to separately come back to the LNG strategy. One of the other opportunities that you had talked about at the investor meeting was brownfield expansion at Port Arthur. And we've seen with some other U.S. Gulf Coast projects, very compelling economics on the additional trains that can get added. Can you just talk a little bit about how you're thinking about the commercialization process there and Conoco's appetite for taking further offtake of further expansion at that facility?

Operator:

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

Ryan Lance:

Yes, we can.

William Bullock:

Yes, this is Bill. This is really just a pretax income mix story. Our estimated annualized effective tax rate has moved down to 35% for the year. That compares to the last time I provided guidance to you all of mid- to upper 30s when we talk to sometime last year on our effective tax rates. And this reflects a shift in the mix of our forecast annual pretax income from some higher tax jurisdictions to lower tax jurisdictions. It's really largely driven by Norway, given the reduction that we've seen recently in EU gas prices relative to last year. So obviously, these tax rate changes. They create some quarterly noise as they flow through as a noncash catch-up adjustment when they happen, and so that's why you see our second quarter tax rate was 33.6% versus first quarter of 36%. And that puts our year-to-date right at this 35% level, matching our current expectation of full year. Now that noncash adjustment, that's going to flow through the corporate and other segment. You can see that on our supplementary disclosures. You can see it's a $20 million positive swing quarter-on-quarter in that corporate segment. Now -- so that's pretty straightforward. It's really just a mix story. Now when you think about deferred tax, the positive tailwind that you saw on the cash flow statements quarter-on-quarter was a bit lower. That was because of the income statement adjustment I just talked about. But the bottom line is for the second half of the year, 35% annualized effective tax rate is a reasonable run rate for book tax at our current commodity prices. And the deferred tax tailwind of about $200 million for the second quarter, that's also a good run rate for the remainder of the year. Now obviously, that can move around a lot if there's some discrete items that come up. And as you know, they often do, but it's a pretty good run rate at this point in time.

Nicholas Olds:

Yes, John, this is Nick. Yes. You look at our operational performance from the rigs and frac crew that we have in Bakken, it's is just performing extremely strong. Like other assets in the portfolio, you're going to see a little bit of lumpiness from quarter-to-quarter. And you can think of Bakken at plateau. So 100,000 barrels a day for several years is a good number. I would refer you to the AIM presentation, where we talked about Eagle Ford and Bakken essentially sustaining production for $330,000 through the decade. That will give you a good long-term view. We like the asset. It's competitive, low cost of supply, and we continue to find opportunities and looking to increase the overall inventory in that asset.

Roger Read:

It broke off, but I'll assume I'm the only Roger on the call. Anyway, I just wanted to come back around -- you've had some opportunities here on the investment in the acquisition front with Surmont and the deal here in Mexico. So I was just sort of curious, as you look at, let's call it, the M&A opportunity versus the organic opportunity, what how are you comparing those 2? How are the opportunities looking on those? Thinking returns, right, where to put your incremental dollar.

Roger Read:

Absolutely. And then just as a follow-up question on the agreement to go the LNG route on the West Coast of Mexico. What is the situation with takeaway capacity to get there, presumably from the Permian? Just what pipelines might need to be constructed in order to make this project or bring it to fruition?

Operator:

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

William Bullock:

Yes. That's a really interesting question. So as we've laid out, we think about this as building up in kind of a latter fashion. You have to have the market placement with the LNG offtake that you secure. We feel very comfortable with where we're at in that progress even just since AIM in April. So that's why you're seeing us being pretty confident with our West Coast volumes here. But you should expect that to kind of develop as a ladder. So you don't get out ahead of your skis. We do see pretty strong demand on that. But I think we're getting pretty close to critical mass here over time. So I think we're pretty comfortable with where we're at right now. We continue to look for capacity on the West Coast, but a lot of those things are more longer dated out in time right now.

Andrew O’Brien:

This is Andy. So I'll ask on the legal front, as you recall, we had the 2 lawsuits that were challenging the federal government's approval for the project. So probably the main update since we last spoke is we're pleased that a schedule has been agreed now, and we expect to see a ruling on that in November. As we previously communicated that given the prior rulings on this, the scope of what's being challenged is narrow. And we believe that the BOM, the cooperating agencies have conducted a third process and satisfied all the legal requirements. So we're kind of very much now looking forward for the court ruling in November as we start to plan for our 2024 winter season.

Francis Byrne:

I just have a couple of quick questions on long cycle -- you talked about long cycle development and then deflation comments and whether -- maybe you could take that to Willow. The FID that would seem like peak inflation and then some important costs have come down. So wondering whether you have a cost update there. Or I guess where do you expect costs to come down? And I understand it's a 6-year project. But...

Francis Byrne:

Okay. Great. And then let me just go back to Surmont. I know you answered a few questions on it. But it kind of fell into a lapse and whether the exercise of the rofer changes any strategic capital decisions elsewhere in the portfolio. It feels like it gives you a lot of flexibility going forward, but I was just wondering if the change is the timing on any other project. I'm thinking Montney or anything like that.

Operator:

Our next question comes from the line of Alastair Syme with Citi.

William Bullock:

If you look...

William Bullock:

Yes, sure. So if you look at the projects, we picked up. So in Qatar, those are really nice projects that we've pursued for a long period of time. Those compete very well on our cost of supply. We're quite happy with those. Port Arthur, we've talked about it pretty extensively. We've talked about how Port Arthur on an integrated basis that we'd expect low to mid-teens returns overall but with really steady cash flow and low-risk returns on that equity component. And then Saguaro is not an equity investment.

William Bullock:

Yes, sure. So that comes down to what your cost to supply into your portfolio. We think that Saguaro is quite competitive because it's on the West Coast, particularly when you compare that to Gulf Coast LNG because you're on the other side of the Panama Canal. And so it's a quite competitive supply location for deliveries, particularly into Asia and fits very nice in terms of if you think of an acquisition cost for LNG. It's very competitive.

Alastair Syme:

Okay. And my follow-up, probably to Dominic, I think you hinted at a question on 2024 CapEx that you're sort of evaluating Lower 48 activity levels. And I was just sort of wondering what is sitting behind that. Is it something about tanking of the deflation you're seeing? Or is it related to what you're seeing on well productivity?

Operator:

This question comes from the line of Josh Silverstein with UBS.

William Bullock:

Yes. I think the key difference is a timing issue right now, the Mexico Pacific is available right now. It's getting ready to take FID. It's in a good location with a very competitive tariff. And as we're marketing today, that would be accretive and in the money based on the tariff rates that we're looking at. So we do have options for ECA, Energias Costa Azul, on the West Coast through our interest in Port Arthur Phase 1. But that's more longer dated. That project is not yet ready to consider taking FID, and there's a bit of time to go on it. It's a timing issue when they start up, or we think it's an option for West Coast.

William Bullock:

Yes. So certainly, as we put the portfolio together, we're looking at a diversified portfolio of offtake. We are actively developing pro-acement into Europe. We're developing long-term deliberate opportunities into Asia, and we're considering some sales FOB at the facilities that are in the money right now. We also are thinking about these in a time horizon basis with a mix of shorter- and longer-term dates as a portfolio. And we'll be using our commercial organization to optimize across that value chain. So yes, we are looking at actively building out both European and Asian market and doing that through a variety of formats and time horizons.

Phil Gresh:

Thank you, Michelle, and welcome to everyone to our first quarter 2023 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; Dominic Macklon, Executive Vice President of Strategy, Sustainability and Technology; Nick Olds, Executive President of Lower 48; Andy O'Brien, Senior Vice President of Global Operations; and Tim Leach, advisor to the CEO. Ryan and Bill will kick off the call 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 be making 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. Finally, 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. With that, I will turn the call over to Ryan.

William Bullock :

Well, thanks, Ryan. In the first quarter of 2023, we generated $2.38 per share in adjusted earnings. First quarter production was a record for the company at 1,792,000 barrels of oil equivalent per day, driven by solid execution across the entire portfolio. The Eagle Ford stabilized our expansion and QatarGas 3 planned turnarounds were both successfully completed. And Lower 48 production was also a record, averaging 1,036,000 barrels of oil equivalent a day, including 694,000 from the Permian; 227,000 from the Eagle Ford; 98,000 from the Bakken. And Lower 48's underlying production grew 8% year-on-year with new wells online and strong well performance relative to our expectations across our asset base. Now moving to cash flows. First quarter CFO was $5.7 billion, excluding working capital at an average WTI price of $76 per barrel. This included APLNG distributions of $764 million. Now first quarter capital expenditures were $2.9 billion, including $400 million for Port Arthur Phase 1 and $100 million in Lower 48 acquisitions. Regarding Port Arthur, as you will recall from our fourth quarter call, we said we plan to spend about $1.1 billion in 2023. So first quarter spending was very front-end loaded relative to the full year. In the first quarter, we also received $200 million in disposition proceeds. And regarding capital allocation, we returned $3.2 billion back to shareholders. And this was via $1.7 billion in share buybacks and $1.5 billion in ordinary dividends and VROC payments. Turning to guidance. We forecast second quarter production to be in a range of 1.77 million to 1.81 million barrels of oil equivalent per day. This includes 10,000 to 15,000 of planned seasonal turnarounds. We have also increased the midpoint of our full year production guidance by 10,000 barrels a day. Our new range is 1.78 million to 1.8 million barrels of oil equivalent, up from 1.7 million to 1.8 million previously. For APLNG, we expect distributions of 350 million to 400 million in the second quarter. And for the full year, we expect APLNG distributions of 1.8 billion. All other guided items remain unchanged. So to wrap up, we had a strong first quarter. We remain confident in our outlook, leading to our increase in full year production guidance. And we expect to return $11 billion to our shareholders this year. And we're well positioned to deliver on our commitments throughout this year. So that concludes our prepared remarks. And now I'll turn the call back over to Phil.

Operator:

[Operator Instructions]. The first question comes from Stephen Richardson with Evercore.

Ryan Lance :

Yes. Thanks, Stephen. I think let me just start by recognizing the volatility that's currently in the market. But even with that, as we look at the first quarter average, prices were in the mid-70s WTI, quarter-to-date in the second quarter in the high 70s. So that's close enough to our planning framework that we set out early in the year that close enough to 80 and delivering the $22 billion in cash for the year. So we're not going to overreact to kind of what we're seeing in the volatility right now. So we're on track, and hopefully, you see that with the VROC that we set for the third quarter, on track to deliver the $11 billion distributions that we set out at the beginning of the year. We're comfortable with that. We have the balance sheet to support it if prices turn out a little bit lower as well. So it would take a structural change, and we certainly don't view this volatility we're seeing right now as a structural change in the marketplace. In terms of the mix and the balance, we said we'd do about 50% shares. We leaned in a little bit in the first quarter on the shares. But through the year, we expect to be about 50-50 between our VROC and the shares to deliver the $11 billion of returns back to the shareholder. Hopefully, you see that with the third quarter setting of the VROC at $0.60 a share. That should give you for comfort that we're on to deliver that.

Neil Mehta :

Yes. Thank you so much and congrats on a really good Lower 48 quarter in particular. Ryan, I think you sort of cut -- headed this question off, but I'd love you to comment to the extent you can on Surmont, recognizing it's an active situation. And as you think about that asset, first of all, it seems from the Analyst Day that it is a core position for you guys. And just any thoughts on whether it makes sense to be a bigger part of the portfolio to the extent you can comment at all?

Andy O’Brien :

Good morning, Neil. Yes, as we said in the Analyst Meeting, we do like Surmont as the nice sort of long life, low capital intensity asset for us. As we covered in the Analyst Meeting, that low capital intensity is an important part of our portfolio. And just to sort of reiterate that, sort of the maintenance capital on Surmont -- I'm referring now to our 50% share of Surmont, has been in the $20 million to $30 million a year range for the last four, five years. And you'll recall, I mentioned that we're drilling our first new pad since 2016. Now that pad, for example, will be in the $40 million to $50 million. So it's a very low capital intensity asset for us with that sort of basically flat production profile. And as you know, sort of -- pretty much all of our other driver information we disclose in terms of our production data, our bitumen realizations, our operating costs, that's all out there. So you can form your own view on the asset, but it's an asset that is a core asset in our portfolio. I'll probably just stop there.

Roger Read :

I guess I'd like to follow up on Port Arthur LNG. Obviously, the Phase 1 was covered. There's always a possibility of greater expansion in LNG. Just what would be the things we would watch coming up in terms of the second phase?

Operator:

The next question comes from Doug Leggate with Bank of America.

Ryan Lance :

Well, as we said, Kalei, that we're currently reviewing the proposal that we got and the terms and the conditions. So it's a bit early to comment on tax pools.

Sam Margolin :

The capital efficiency looks like it's going in the right direction with the production guidance and the capital plan in line. At the Analyst Day, you made some comments where you thought it was at least possible that you could start to see inflation ease if not reverse. And the question is just as you think about this production results, is that an outcome of maybe an opportunity to press activity a little bit as costs are easing? Or is this -- is it more of a well results-driven outcome?

Nicholas Olds :

All right. Thanks, Dom. Yes, Sam, just to take you back to the analyst call when we talked about drilling and completions efficiency. If you recall, we had from 2019 to 2022, we had a 50% improvement in drilling, 60% improvement in completion at stages per day. We continue to see that in Q1, very promising results, and that's the use of technology like simul-frac, e-frac. We're testing out some remote frac as well where we keep a frac spread on pad 1 and then we frac pad 2, pad 3, pad 4. So very promising results there. as well on the drilling front, we continue to use data analytics and rig automation, but all that's coming together, so really promising. That did lead to some accelerated places on production of wells in Q1 driving some of the over-performance.

John Royall :

So my question is just on Willow. Are there any updates there to how the lawsuits are progressing? And are you any closer to a resolution there and getting to FID then when we last saw you a few weeks ago with the [AIM]?

Operator:

The next question comes from Ryan Todd with Piper Sandler.

Ryan Lance :

No. Thanks, Ryan. In terms of how we're running the company day to day and the allocation of capital that we put in each year, it really doesn't -- we're only investing in things that have a cost of supply less than $40 WTI in the portfolio. So what a mid-cycle price change, our Chief Economist Office, our commercial team, we go through a process every year where we take a current view of the macro and have a long-range view of what we think is happening. And as we've gone through a lot of turmoil in the business, the Russian invasion of Ukraine, just the lack of investment going into the business these days. we stepped back and did our own bottoms up, which we do every year, but important this year, we did our own bottoms-up work to try to understand where we think the mid-cycle price is moving to and was is to staying at kind of that $50 level. Our assessment of the price required to generate that incremental barrel to meet that incremental demand, our assessment put it at around $60 today. And so that -- so the implications of that are really just how much cash flow we think we're going to be generating as we interrogate the portfolio, as we invest in the growth and development of the company, and we put capital into the company the way it manifests itself is just how much floor we can deliver at that kind of mid-cycle price, which is obviously a little bit more than what we would deliver at the lower price. So it goes to sort of how we think about cash in the balance sheet, how we think about the debt that we're carrying, how we think about distributions and how much capacity there is to distribute a bunch of our cash, which our commitment is about 30%. And when we get above mid-cycle price in our case like we are today, obviously, we're generating a lot more cash, and we're returning a lot more cash to the shareholder, now something in excess of 50% today. But that's driven by the reinvestment rate that we have in the company our commitment to only invest in the lowest cost supply things we have in the portfolio.

Devin McDermott :

So I wanted to go back to the Lower 48. It was helpful detail before on some of the efficiencies that you're seeing there. I think one of the other drivers of the strength in production that you called out in the prepared remarks was well performance beating your expectations. Can you talk a little bit more explicitly about what you're seeing there and if there's any development changes that you've made driving that uplift?

Operator:

The next question comes from Josh Silverstein with UBS.

William Bullock :

Yes. So I think we laid this out pretty well at our analyst meeting. So for Port Arthur, we've got options on both equity and offtake for future phases. Those can be executed either for equity, offtake or both as they present themselves through time. We also have some options on the West Coast of Mexico at Energy Costa Azul on Phase 2. And so those are long-dated options that we continue to look at. I talked a bit about Phase 2 earlier in the call. And so there need to be some pretty unique opportunities on that as we think about that right now. Now as we think about future phases we have structured our investment in Phase 1, such that we benefit from the economies of scale for future phases on our Phase 1 investment. So future phases actually benefit Phase 1.

Paul Cheng :

Maybe this is for, Nick. Nick in the Investors Day, I thought luckily you were talking about 2023, the shale oil production of around 1 million barrels per day. And in the first quarter, you're already there. Does that means that for the rest of the year that the Lower 48 shale oil and Montney together will be pretty stretched? Or that, that number is somewhat conservative now?

Operator:

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

Ryan Lance :

Yes, Scott, yes, we're right in the middle of all those conversations, as you might imagine, including the most recent conversations around the Citgo refining assets. We're in the queue. We're in the -- right in the middle of anything that would happen there. We have -- as a reminder, an ICC judgment of $2 billion. We've collected about $700 million on that judgment to date. So we have an outstanding -- what they owe us on that particular judgment. We're in an appeal process with ICSID which is the other tribunal, and that's an $8 billion potential award coming. Now there's some overlap between the two, so you can't necessarily add the two together. But I guess the point is there was a lot of money. And we're hard at trying to get some resolution of that. And the recent news out of the judge and the U.S. government around Citgo is certainly helpful in that regard. It looks like despite the sanctions that are on the Venezuelans and on U.S. companies for doing work in Venezuela, there's a little bit of -- some light developing at the end of that tunnel, and we're right in the middle of it all.

Alastair Syme :

In your remarks, beginning on the Lower 48, you mentioned about infrastructure build. And I was really just interested to try and understand across the Lower 48, but I guess, especially in the Permian, what's the sort of ratio of capital that's going into infrastructure versus drilling? I guess, it changes over the life of the assets. So I'm just kind of intrigued what's the point of asset like are we in terms of that ratio?

Nicholas Olds :

Yes, Alastair, it's very limited as far as on the infrastructure spend, most of your expenditures is on drilling and completions in the Permian as an example.

Raphael DuBois :

I just have one question about the working capital deterioration in 1Q. I was wondering if you could tell us how much of it is due to some Norwegian cash tax catch-up? And what is it to expect for the rest of the year?

Operator:

The next question comes from Neal Dingmann with Truist Securities.

Ryan Lance :

Yes. Well, I think, Neal, you have to kind of go back to how we set the VROC in the first quarter. That was actually set in the third quarter of last year in a $100 price environment. So we probably had a ratable -- a little bit higher distribution in the quarter and then it gets more ratable as we go through second, third and fourth quarter as we deliver the $11 billion that we've targeted for this year. And that's evidenced by how we set the VROC for the third quarter at $0.60 a share.

Leo Mariani :

Obviously, strong results out of COP today, you enumerated a couple of reasons. The first quarter production beat. It sounds like some wells came on early, and well results continue to be very strong. But just wanted to dive in a little bit on the maintenance side. I know you guys kind of talked about 35,000 BOE per day of maintenance in the quarter that actually come to fruition. Maybe that number was a bit different. And then can you talk about maintenance rest of the year, you had 10,000 to 15,000 expected in 2Q, but any expectations for 3Q or 4Q?

Phil Gresh:

Thank you, everyone, for being here today. We appreciate it.

Phil Gresh:

Yes. Thank you, operator and welcome to everyone joining us for our fourth quarter 2022 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; 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; and Tim Leach, advisor to the CEO. Ryan and Bill will kick off the call 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 presentation which you can find on our Investor Relations website. Second, during this call, we will be making 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. Finally, to make – 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. With that, I will turn the call over to Ryan.

Bill Bullock:

Thanks, Ryan. Starting with fourth quarter results, we generated $2.71 in adjusted earnings per share. Fourth quarter production was 1,758,000 barrels of oil equivalent per day, which included a 27,000 barrel a day negative impact from weather in the Lower 48. Lower 48 production averaged 997,000, including 671,000 from the Permian, 214,000 from the Eagle Ford, and 96,000 from the Bakken. Moving to cash flow. Fourth quarter CFO was $6.5 billion, excluding working capital at an average WTI price of $83 per barrel. APLNG distributions were $639 million and fourth quarter capital expenditures were $2.5 billion, including $2.1 billion of base capital and $300 million for acquisitions and North Field East payments. On capital allocation, we returned $5.1 billion to shareholders through ordinary dividends, VROC payments and share buybacks, while also reducing gross debt by $400 million. Full year CFO was $28.5 billion, excluding working capital at an average WTI price of $94 per barrel in 2022. Full year APLNG distributions were $2.2 billion and full year total CapEx was $10.2 billion with base CapEx achieving our guidance of $8.1 billion and $2.1 billion of acquisitions in North Field East payments. Full year return of capital was $15 billion, while $3.4 billion went to debt reduction with cash and short-term investments ending the year at $9.5 billion. Turning to 2023 guidance, we forecast full year production will be in a range of 1.76 million to 1.8 million barrels of oil equivalent per day, which represents 1% to 4% of organic growth. Our first quarter production guidance range is 1.72 million to 1.76 million, which includes $35,000 of planned maintenance, primarily in Qatar and the Lower 48. Our full year planned maintenance is expected to be similar to 2022. On capital spending, we expect a range of $10.7 billion to $11.3 billion, which I will discuss in more detail in a moment. We expect operating costs of $8.2 billion, DD&A of $8.1 billion, and corporate segment net loss of $900 million. For 2023 cash flow, we forecast $22 billion in CFO at $80 barrel WTI, $85 Brent and $325 Henry Hub at current strip prices for regional differentials. Included in our cash flow forecast is $1.9 billion in APLNG distributions with $600 million expected in the first quarter. Now regarding CapEx, we provide a waterfall in our prepared materials bridging 2022 actual spending to 2023 guidance. Starting with base capital spending, we forecast an increase from $8.1 billion in 2022 to a range of $9.1 billion to $9.3 billion in 2023. The remaining $1.6 billion to $2.0 billion is allocated to longer term projects. Of this amount, $1.5 billion to $1.6 billion is for LNG projects, which includes Port Arthur, North Field East and North Field South. For Port Arthur specifically, after factoring in expected project financing, we forecast that ConocoPhillips net investment will be just under $2 billion over the 5-year investment period. However, more than half of this capital investment will be in 2023. For Willow, we are guiding to $100 million to $400 million of incremental spending with the higher end of this range, assuming that the project is sanctioned this year. In summary, we are happy with our strong 2022 results, which would not be possible without the hard work and dedication of our talented workforce. And we are well positioned to balance investing in our deep and diversified portfolio this year while also continuing to return capital to our shareholders. That concludes our prepared remarks. I will now turn the call back over to Phil.

Operator:

Thank you. [Operator Instructions] Our first question will come from Neil Mehta with Goldman Sachs. Your line is now open.

Andy O’Brien:

Hey, Neil, this is Andy. Yes, there has been a lot of moving parts on Willow since the last earnings call. So let me just step through where we are in the overall approval process and then I can clear where we are with CapEx and scope. So with the approval process, I think most people saw that the final supplemental environmental impact statement was released by the Biden administration earlier this week. Now that should be published in the federal register in the next day or so and then that starts the required 30-day clock before the ROD can be issued. Now given the Biden administration’s commitment to the Alaska congressional delegation, we then expect to receive that ROD in the first week of March. Once the ROD has been issued, our focus for 2023 will be to immediately initiate gravel road construction, ramp up fabrication and supply chain activities. Now we are going to need to take a look at the ROD in some detail, but assuming it’s consistent with the BLM’s 3-pad preferred alternative and there are no new unworkable restrictions added, we would then proceed to final investment decision. So switching to CapEx, 2023 is very dependent on the ROD timing. And as Bill mentioned, we have given a range. So with the ROD timing, any resolutions of outstanding issues, what we are guiding is about $100 million to $400 million of incremental spend in 2023. In terms of the total project costs, we have recently gone out to market to update our cost estimates and we have seen some inflationary pressures. We have also refined the scope, including an update to accommodate the BLM’s 3-pad preferred alternative. So we are in the process of finalizing our cost estimates, but we would anticipate the AFE to first production to be in the $7 billion to $7.5 billion range. Of the increase versus the update we provided in 2021, it’s been about 50-50 between inflation and scope refinement. So hope that gives you a pretty good update on where we are with Willow. And then at our April Investor Day, we will be happy go into some more details.

Andy O’Brien:

That’s correct. That’s an apples.

Ryan Lance:

No, we are not trying to message that. What I remind people is the 30% commitment that we have is through the cycle commitment. We have also signaled to – or we have also told to shareholders that when prices are above our mid-cycle price, you should expect higher distributions for the company and that’s consistent with what we have done over the last number of years. So as we look today, where the strip is trading, where the regional differentials are at, we have kind of picked $11 billion at an $80 price deck. So that’s how we are going into the year. It represents about 50% of our cash flow. But again, that $80 is well above our mid-cycle price in our commitments tied to – through the cycle kind of mid-cycle price call. And it just represents that we are constructive with the environment that we see today and we expect the prices to be above our mid-cycle price call, which should inform that the distributions would be above that 30% as well.

Phil Gresh:

Great. Thanks, Neil. Next question?

Doug Leggate:

Well, thank you. Good morning, everyone. Happy New Year guys. So Bill, I think I didn’t actually get to write down the numbers quickly enough. Could you just go through again the expected cadence of the three LNG projects? Full disclosure, I think we had expected a slower pace on Sempra or in Port Arthur, I guess. So can you just walk us through what you – how you expect that cadence to look please? That would be really helpful. And I’ve got a follow-up, please.

Doug Leggate:

That’s really helpful, Bill. And you’re exactly right. We were not expecting half. But of course, that means that the other half is probably more ratable, I’m guessing, over time, but that’s really helpful. My follow-up is a favorite topic of me, Bill. I hate to get in the weeds here, but again, another sizable deferred tax credit this quarter, although it does kind of look a little bit more like your – almost like you’re moving to a new normal based on your U.S. spending, thinking IDCs and things of that nature. Can you move just – am I thinking about that right? Should we be expecting a ratable deferred tax credit going forward in your cash flow? And I’ll leave it there. Thank you.

Doug Leggate:

Really helpful. Thank you. Thanks.

Operator:

Our next question comes from Steve Richardson with Evercore. Your line is now open.

Ryan Lance:

Yes. Thanks, Steve. Let me make a couple of comments, and then I’ll turn it over to Nick for maybe a couple of his thoughts in a bit more detail. We’re not worried about our long-term development plans in the Lower 48. We see durability to our plans. And I know there is been a bit of noise about productivity and length and durability. And we’ve been there for a long time. We know what we’re doing after the acquisitions that we made over the last 1.5 years. And I don’t have any concerns about the durability to length, the efficiency of our program. And maybe I’ll let Nick provide a few more detail and color on that comment.

Steve Richardson:

That’s great. Thanks. I really appreciate it. I mean if I could – just one quick follow-up, Nick. Could you just address the 25,000 acres of swaps and coring up that you mentioned this morning, I would, I mean one of the questions, I guess, is...

Steve Richardson:

Sorry, I must be the phone line. The question is on the – you have the 25,000 acres on the core up. And I’m just wondering if you could address, Nick, how much more to go is there on that side? And where are you just looking at the checkerboard of the map down there?

Steve Richardson:

Thanks so much.

Operator:

Our next question comes from John Royall with JPMorgan. Your line is open.

Ryan Lance:

Yes, John, thanks. So we – I think we will show how we’re pretty excited about where the company has gone. We’ve got a better plan. It’s the strategic and the financial plan of the company are got better duration, better depth, and we will show that to you what it means for the company for decades to come. I mean – so we’re pretty excited about where it’s at. We will do a deeper dive into where we’re at in the Lower 48, our global portfolio as well as the LNG business that we’ve been developing here over the last 1.5 years. So look forward to sharing kind of our excitement around our plans, where it’s headed and just the quality of what we’re doing both strategically and financially.

Dominic Macklon:

Hey, John, it’s Dominic here. So yes, I think as Bill remarked, we do have above normal seasonal maintenance in the first quarter. That’s at Qatar Train 6 and 7, but also Eagle Ford Sugarloaf of our stabilizer facility down there. We’ve actually been preparing that for a bit of expansion. So that explains the Q1 sort of rate. But thereafter, our expectation is that each quarter will be around 2% to 3% year-on-year growth. So that’s really our base case.

Phil Gresh:

Michelle, next question.

Jeanine Wai:

Hi, good morning. Good afternoon, everyone. Thanks for taking our questions.

Jeanine Wai:

Good morning, Ryan. Our first one, maybe following up on Neil’s question on the cash return for the year, we realize that it’s still early in the year, but you’ve already declared the ROC for the first part of the year. How are you ultimately thinking about the split of the $11 billion of total cash return between cash and buyback, and is the buyback more of a function of your mid-cycle price assumptions?

Jeanine Wai:

Okay. Very helpful. Thank you. I’ll pencil that in – our second question, sticking with ‘23, but moving to CapEx here. We noticed that there is about $500 million to $600 million of incremental inflation included in the budget versus 2022 and there is some noise with the categorization of the Port Arthur spend. But it looks like Lower 48 will comprise about 60% of total CapEx for ‘23. And so our question is, how much of that $500 million to $600 million of incremental inflation is in the Permian and Lower 48 versus maybe other parts of your portfolio? And what’s your estimate on how inflation ended up by region in ‘22 and maybe any assumptions that you have in your budget for ‘23 inflation? Thank you.

Jeanine Wai:

Great. Thank you.

Operator:

Our next question comes from Ryan Todd with Piper Sandler.

Nick Olds:

Yes, Ryan, this is Nick. Yes, let me talk – walk you through that. So as you mentioned, we’ve assumed a level-loaded steady-state program for 2023 based on that second half of 2022 for rigs and frac crews. The focus for this year will really be around improving capital and operating efficiency. Now we do expect some modest growth in partner activity as the year progresses. And then we have some larger operated pads that will come online in kind of 2Q, 3Q. So our Lower 48 plan will deliver production in that mid-single digits, with the majority of that growth weighted to the Permian. Now with respect to the profile shape, it will be kind of mid to back-end weighted in 2023. And as we talked about, Dominic mentioned this, we do have that Eagle Ford Sugarloaf stabilizer maintenance that’s going on. And actually, I’m pleased to mention that the turnaround that Dominic referred to is 5 days, and we completed that successfully in January. Now we will have a little bit of brownfield modifications on that stabilizer through mid-February as well. And then I’ll mention two kind of month-to-month, we will have wells, a little bit of lumpiness. But in the back end, we will be weighted in 2023 for a production profile.

Bill Bullock:

Yes, sure. This is Bill. So I’ll just start with – we’ve got a really strong understanding and presence in the LNG market have had for several years. We’re regularly selling spot volumes into Asia of our APLNG venture. And we do think that Europe is going to be a long-term market for U.S. Gulf Coast and you will have seen where we recently secured regas capacity in Germany, which we’re really happy about and excited about. And so we’re looking at the best options in terms of long-term placements, but these are 20-year projects off the Gulf Coast. And so we think that the long-term strength of international pricing relative to U.S. gas is going to be pretty interesting. And that driver and that strength in LNG, we think, it’s going to be driven by its role in energy transition and reducing carbon emissions. So as you see us build out our LNG portfolio over the next few years, we may take some longer-term contract decisions in there. But right now, we’re not really disclosing where we’re at for competitive reasons in terms of how we’re developing that market.

Phil Gresh:

Thanks Ryan. Michelle, next question.

Devin McDermott:

Hey. Good morning. Thanks for taking my questions. So, I wanted to first follow-up on some of the CapEx questions. Earlier, you laid out the $1.6 billion to $2 billion of spending this year on major projects, and you talked with some good detail about Port Arthur. It’s not necessarily ratable across the projects. But when you put it all together, I was wondering if you could talk about how you see the magnitude of major projects been evolving or changing over the next few years. Outside of Port Arthur were some of the key moving pieces that we should be thinking about across the projects that could move that number higher or lower?

Devin McDermott:

Got it. Makes sense. Just a quick follow-up on NFE and NFS, are those fairly ratable over the next few years? Any additional color on those projects specifically?

Devin McDermott:

Okay. Thank you.

Operator:

Our next question comes from Paul Cheng with Scotia General. Your line is now open.

Nick Olds:

Alright. Yes. This is Nick there. I will just kind of walk you back through kind of the inventory related to our longer laterals as we have done the core up. Again, over 60% is greater than 2-mile laterals, and that does include the 3-miles as well. So, that’s a significant part of our inventory in the Permian Basin. We have actually, this last year, in 2022, brought on, I think more than 30 wells that are in the 3-mile category and are seeing very encouraging results. So, we will continue to execute those as we are going forward. As we continue to core up and do swaps, that will give us more inventory as well for that longer lateral execution. Again, you will see probably cost of supply of about 30% to 40% reduction as we drill those longer laterals.

Dominic Macklon:

Yes. Paul, I don’t have that in front of me at this point in time, but let’s wait until AM and I will give you a further update on that overall 3-mile categorization.

Dominic Macklon:

Okay. On your second part of that first question related to plateau. Again, we will update the group on overall Permian plateau, Eagle Ford and Bakken at the April 12th Investor Day. Obviously, there is a number of factors that go into that. The macro, maintaining execution efficiency, continuing to capture the learning curve and capital efficiency, right now, with our middle – mid-single digit growth, we feel that’s right in line with what we have communicated earlier. And then your second question was related to weather. Glad you brought that one up. Again, Bill, you had mentioned 27,000 barrels a day for fourth quarter 2022. Just a quick breakdown on that. That’s 13,000 barrels for Permian, 10,000 barrels for Bakken and then last 4,000 barrels in Eagle Ford. I think you asked kind of maybe quarter-to-quarter, Q3 to Q4, you are right, it was flat. We are at 96,000 barrels equivalent per day. And Paul, the main driver for that is we had some really strong operated wells that carried into Q4. And then on the operated by others, we had some larger pad projects come online in Q4 that offset that weather.

Operator:

Our next question comes from Bob Brackett with Bernstein. Your line is now open.

Dominic Macklon:

Hey Bob, it’s Dominic here. Yes. So, let me talk a bit about that. I mean we are obviously very pleased with our organic reserve replacement ratio this year, 177%. The real drivers for that, I mean obviously, the LNG, we did have some bookings there from NFE as we commenced payments on NFE. We also saw some bookings to make LNG performance and for some project advancements in Norway. So, our international portfolio is contributing. But the main area this year was actually in the Lower 48 development program. And that’s particularly in the Permian and that included an increase to our PUD bookings by extending the approved era we established by reliable technology, which is an SEC term. So, it’s consistent with SEC requirements. And so basically, we have a very extensive geoscience and reservoir engineering data set across the Permian now that allows us to support that. So – and you will be aware, Bob, just the rigor and the process and the controls governing the reserves booking process. So, this further demonstrates the depth and quality of our Lower 48 inventory. So, that’s really the story this year. Going forward, we will continue to see bookings in the Lower 48. We will see bookings in Alaska, obviously with pending FIDs. And then we will continue to see some LNG bookings as well, particularly on the resource projects as we call them, NFE and NFS. You are absolutely right what you are saying about Port Arthur. But – so, I think you will see a mix going forward, right, as it stands now, our Lower 48 represents about 46% of our reserves and the remainder across the international. So, yes, we have simply appreciating the performance of our sort of diversified portfolio around our reserves booking. So, thanks for the question.

Ryan Lance:

We are pretty pleased where the portfolio is at. I mean Dominic did a good job of kind of going across the globe. I think we spent a lot of time over the last 5 years really coring up the portfolio, really focused on getting it as low cost of supply as we can, getting the margins as expanded as we can leading to kind of the returns and the productivity that we are seeing today. So, we are just hyper-focused on making sure the efficiencies are there and the returns are there. And pretty happy with where we stand today. And then as you rightly note, Bob, we are leaning in a bit on some of these mid and longer-cycle projects because we are just very constructive. The world is going to need this all. It’s going to need low greenhouse gas and emissions intensity oil, it’s going to need low-cost supply oil. That’s what we are all about. That’s what we are doing in our portfolio. And most recently, leaning in on the LNG side because we think the world is going to need this gas as part of the transition that we are going through.

Phil Gresh:

Thanks Bob. Next question.

Neal Dingmann:

Good morning. Thanks for the time. My question is around just production and maybe around the Permian. I am just trying to get a sense of, you have got I think the 1% to 4% type overall growth. So, I am just trying to get a sense of expectations for the Permian, if you would back out obviously, what’s going on up in Alaska. Have you all clarified or kind of said what the expectation is at. And it sounds like – second part of that, it sounds like it’s going to be pretty that growth you expect in the Permian, I assume that would be pretty linear for the entire year, if you could comment on those two things.

Neal Dingmann:

That’s very clear. And then just one last one. You all are obviously in a fantastic position financially. You have done some really positive M&A deals in the past. I think actually in the last couple of years among the best that I have seen out there. My question that comes in, I mean how do you view the landscape today? I mean obviously, prices are up, maybe commodity prices are up, so maybe expectations are higher, but just wondering overall, how do you view the M&A landscape?

Neal Dingmann:

That’s very clear. Thank you all.

Operator:

Our next question comes from Paul Sankey with Sankey Research. Your line is now open.

Ryan Lance:

Yes. Thanks Paul. No, I think we are – our view pretty constructive over the next number of years and through the decade. So, the time you want to do some of these big projects sort of front end of the cycle, we probably are a bit unique given our global diversified portfolio. We have opportunities in Alaska and Norway, in the Far East – in the Middle East. So, we look at those, make sure they fit our framework around cost of supply and what we want to go invest in. And as we look forward, we believe now is the time to be doing these projects, which is why you see us leaning in on the LNG side. We are constructive on the gas and why we are moving forward with our little project up in Alaska. And I will make a site com [ph], this is what the administration has asked us for U.S. production, this low GHG emission production. This is exactly what the administration has asked us to do as an industry, and that’s what we are trying to do as a company. Now, looking forward, I think we will talk at AM about where we think mid-cycle price is and frankly, we think it’s probably come up from where we have been over the last 5 years, 6 years. We will show that to you at AM. And then finally, to your last question, yes, we have set a cash return target at $80 WTI, $85 Brent. And I think it’s 3.25 Henry Hub. Those are the assumptions we made that underpin the $11 billion. The price would have to go down considerably. I mean you said into the 60s, full year average, I think before we would talk about changing that. And we are prepared to use our cash on the balance sheet to fund these projects. That’s why we have that cash. That’s why we have that financial strength in that resilience. So, we are happy to use the cash if we need to. So, I think it’s resilient across a broad range of prices in terms of what we have established as our distribution target for the year.

Ryan Lance:

Yes. It will be some of the lowest GHG emission production in the world, less than 10 kilograms per barrel. So, it’s going to be something that we believe is what the world needs right now as we go through this energy transition. We need more oil and gas. We need more base load to supply the world reliable and affordable energy. And coming to the United States and North America broadly, in general, is the right thing to be doing right now. And it comes from companies like ours that have over 40-year experience on the North Slope. We know how to do this. We know how to do it responsibly and all the stakeholders support it, including the native community on the North Slope, the congressional delegation, the union labor leaders who need this opportunity for employment in Alaska. So, there is full alignment behind what we are trying to go do there. It’s just the politics in D.C.

Phil Gresh:

Thanks Paul. Michelle, I think we have time for one more question.

Bill Janela:

Hey. Good morning. Thank you. I wanted to ask on the pace of CapEx as you move through this year. I am wondering with all of the major project components that there are some quarters that might be chunkier than others, or if there are any other timing or seasonal factors to consider? So, any guidance you can give there in terms of how to think about the progression of quarterly spending for some of those bigger ticket items as well as the base business would be very helpful. Thanks.

Bill Janela:

Thank you.

Operator:

Thank you. Ladies and gentlemen, this concludes today’s conference. Thank you for participating. You may now disconnect.

Philip Gresh:

Yes. Thank you, Richard, and welcome to everyone joining us for our third quarter 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; Dominic Macklon, Executive Vice President of Strategy, Sustainability and Technology; Nick Olds, Executive Vice President of Global Operations; Jack Harper, Executive Vice President of Lower 48; and Tim Leach, adviser to the CEO. Ryan and Bill will kick off the call with opening remarks, after which the team will be available for your questions. Just a few quick reminders. First, along with today's release, we published supplemental financial materials and a presentation which you can find on our Investor Relations website. Second, during this call, we will be making 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. Finally, 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. With that, I will turn the call over to Ryan.

William Bullock:

Well, thanks, Ryan. From a financial standpoint, we had a solid third quarter. We generated $3.60 per share in adjusted earnings. Production was over 1,750,000 barrels of oil equivalent per day, which included our previously guided approximately 15,000 barrels of oil equivalent per day impact from scheduled turnarounds as well as some impacts from the temporary force majeure in Lithia in July. For the fourth quarter, we do not expect any material turnaround impacts. Lower 48 production averaged a record 1,013,000 barrels of oil equivalent per day, including 668,000 from the Permian, 224,000 from the Eagle Ford and 96,000 from the Bakken. Cash provided from operating activities was $8.7 billion. Now this included a $15 billion benefit from working capital, primarily related to the timing of Norway tax payments and lower receivables. Excluding working capital, cash from operations was $7.2 billion. APLNG distributions were $257 million in the quarter, and we expect fourth quarter distributions to be about $600 million. On capital, we invested $2.5 billion back into the business in the third quarter, including around $300 million for acquisitions. This resulted in free cash flow of $4.7 billion, which more than covered the $4.3 billion we returned to shareholders in the quarter. Factoring in $400 million of disposition proceeds, ending cash and short-term investments were $10.7 billion at September 30, up from $8.5 billion at June 30. Turning to guidance, we still expect full year production of 1.74 million barrels of oil equivalent per day, with a fourth quarter guidance range of 1.74 million to 1.8 million barrels of oil equivalent per day. On costs, we've increased full year adjusted operating cost guidance to $7.7 billion from $7.5 billion, and this is driven by inflationary impacts. We have also increased full year organic CapEx to $8.1 billion from $7.8 billion, also driven by inflationary impacts and partner-operated working interests. Partially offsetting these increases, we have reduced full year DD&A guidance from $7.6 billion to $7.5 billion. In terms of 2023 guidance, we anticipate providing full details with our fourth quarter earnings call in early February. We will also be hosting an Analyst and Investor Meeting next spring at the New York Stock Exchange, so please stay tuned for more details. And with that, I'll turn the call back to Ryan.

Jack Harper:

Thanks, Ryan. As Ryan mentioned, I will be leaving ConocoPhillips due to a family medical situation. It has truly been a privilege to work for both Concho and ConocoPhillips over the past 16.5 years. When Concho agreed to the merger with ConocoPhillips, we did so because we believe that the transaction would create a uniquely strong and differentiated company, and I cannot feel better about how this has played out. This may be one of the most dynamic times that we've ever seen in the industry. And my competitive side certainly makes me wish that I could stay on board for what is ahead. However, I'm confident that we have set up the team for success with our organizational structure and planned transition over the next few months. With that, let me turn the call back over to Ryan.

Philip Gresh:

Great. Thanks, Ryan. [Operator Instructions]. And with that, Richard, we'll turn it back to you.

Neil Mehta:

Ryan, I want to kick off with you on the LNG strategy. And we've seen a lot of interesting individual announcements. But maybe you could pull it all together and talk about how you see these coming together for how Conoco thinks about LNG as part of its portfolio. And as it relates to that, maybe you could talk about risk around long-term LNG as we have a lot of new supply coming in from Qatar in the U.S. by the middle of the decade. And do you worry about spending on these projects into what could be a sloppier market towards the end of the decade?

Neil Mehta:

Yes. That's really clear, Ryan. And the follow-up is just on capital spending for 2023, recognizing we're going to get more thoughts, it sounds like here in February on it. But if we took the $8.1 billion as the starting point, what are some of the moving pieces as you go into '23 that we can bridge off of?

Operator:

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

Ryan Lance:

Yes, Stephen, I think if we have the macro environment today that's similar to next year that's similar to the average over the course of 2022, I think you should expect a similar level of distributions. And I think we signaled that a little bit with setting the first quarter VROC at $0.70 a share. At this , we look at the macro and it's going to be similar next year, you ought to expect a similar level of distributions, which is in excess of our 30% commitment. But we're going to watch the macro because we think it's going to be incredibly volatile. But we think we've just got the right value proposition in combination of VROC-based dividend and how we're thinking about buying our shares back, that it's well set up for the kind of volatility we may see. But that would be sort of my comment as you think about going into 2023, it's a function of the macro, which is reasonably strong right now.

Jack Harper:

Yes. Thanks, Stephen. This is Jack. Yes, the production is back half loaded, like we've been talking about. I hope you saw that in the quarter with the progression. We've also seen our OBO plans, our partners targeting increasingly longer laterals than we first anticipated, which, of course, yields a lower cost of supply and more economic return. In the Lower 48, we do expect to see continued growth, as Ryan mentioned, in the fourth quarter and in the Permian should modestly exceed that kind of low single digits that we expect out of the Lower 48. In terms of well productivity and our plans are progressing as we have planned. We monitor this very closely internally and with our peers externally and really like where we stack up.

Doug Leggate:

Jack, I wish you well and hope our paths cross again at some point. Good luck. I've got 2 quick questions, if I may. Bill, I wonder if I could deal first with the deferred tax in the quarter. I think we've heard you talk in the past about when you would hit full cash tax in the Lower 48. Has that been delayed somehow? Or maybe you could just walk through what happened in the quarter. It's quite a big deferred tax number, which we're happy to see obviously, but any updated guidance would be appreciated.

Doug Leggate:

I understand the point about mix and that's actually really helpful. I guess my follow-up, my question is on the Permian takeaway. We're obviously seeing a lot of volatility around Waha, but you guys have obviously had a lot of changes in your portfolio. Could you just give a quick refresh as to what your takeaway looks like? I guess, the differential widened a little bit this quarter in your realization. So just trying to get a handle on that, and I'll leave it there.

Operator:

Our next question comes from Jeanine Wai from Barclays.

Nicholas Olds:

Yes. Jeanine, this is Nick. Definitely, I'll go through that. Maybe as a reminder, I'll just walk back in time a little bit here. There was a key milestone that was accomplished in early July, and that was that draft SEIS. The comment period has been completed as well. And as I mentioned in the 2Q call, the draft SEIS put forward a new 3-pad alternative, reducing the footprint in that Lake special area. And that is supported by ConocoPhillips. Now that addresses and is responsive to the Alaska District Court findings. Now with respect to schedule, we're still targeting the final SEIS in a supportive record of decision by the BLM end of this year. Jeanine, as I mentioned previously, we would only take FID following a final SEIS and support a record decision by the BLM and we are targeting FID early next year. Now pending that successful record of decision, we expect to have 2023 capital spend for this upcoming winter season, and that's mainly focused on civil construction, so that'd be opening up mine site and laying some gravel roads. Now again, we won't take FID or make significant investments until we have a clear path to development. We also continue to do detailed engineering and update our final cost estimates. I know that you referenced that. We recently went to market to update our project costs and have seen some inflationary pressures as expected. We're seeing that globally as well as some of the impacts related to the updated scope due to the BLM's Alternative E in their draft SEIS. But I want to leave you with this. Despite all the cost pressures, the project remains very competitive in our cost supply framework. And finally, we'll provide more details on Willow at the market update that Bill referenced for next year.

William Bullock:

Yes. Sure, Jeanine. This is Bill. So first, based on our forward prices, we'd expect to end the year with roughly $10 billion of cash, also the same -- roughly the same amount that you noted for the end of third quarter. And that's, I'd note, is predicated on us achieving our $15 billion of distribution to shareholders this year. Now the framework of how we think about allocation and cash balance really hasn't changed. It's continuing to be guided by our priorities of having a competitive shareholder distribution, strong balance sheet strength and efficient organic and inorganic capital allocations. And the framework that we've laid out of intending to carry $1 billion for operating cash, $3 billion of reserve cash and anything above that as strategic cash continues to be the way that we think about that. So when you think about strategic cash, we think about that for the opportunity to capture value-enhancing opportunities like you saw us do with the Shell Permian acquisition is to fund our program [indiscernible] cycles and to fund mid- and long-cycle projects. So the basic way that we think about our cash balances is unchanged.

Scott Hanold:

I was wondering if we could go back to shareholder returns and just give us a sense of how you think about the mix of the shareholder returns. I mean, obviously, there's some companies that are highly formulaic with it. But as you look into sending that VROC for the first quarter, like what goes into play when you think of like what level you want that set at?

Scott Hanold:

That's great color. I appreciate that. And actually, before I get to my second question, I should have started out with this. But Jack, all the best to you and your family. I mean, we've worked together over the past decade-plus so it was a pleasure to work with you all these years and good luck. But my follow-up question then is looking at the opportunities that you all have in Norway, you look like you're progressing on Tommeliten and Eldfisk. Now can you give us a sense, is that more just a process of just maintaining production out there? Or is there an opportunity really to grow that and really part of sort of this global gas opportunity? Because I do believe it's a little bit more gassy in a lot of these new developments.

Operator:

Our next question comes from John Royall from JPMorgan.

Dominic Macklon:

Yes. John, it's Dominic here. Just in this, the split of capital in terms of the increase of $300 million, $200 million is really related to inflation, and then about $100 million related to a change in working interest we're seeing in our OBO well mix. And I think probably we're seeing some of our partners may be doing a little bit of capital management and shifting their own working interest down, and that's causing us to go up with it. But they're still good wells. In fact, I'll maybe just ask Jack to comment a little bit on what we're seeing in our OBO program there.

John Royall:

That's helpful. And then maybe just switching over to LNG. Just a little bit of color will be helpful on the Western Mexico opportunity with Sempra and how that could take shape and how we should think about potential timing there if you're getting involved relative to the 1Q target that I think Sempra has put out there for the Port Arthur FID.

Operator:

Our next question on line comes from Ryan Todd from Piper Sandler.

Jack Harper:

Yes, Ryan, we're very happy with our execution out there and feel that it's prudent right now to keep a steady amount of activity going into next year. And I would say our internal plans this year and going into next are very consistent with our long-term outlook on production out of the Permian and the Lower 48.

Ryan Lance:

Yes, Ryan, I think we'll get a chance to talk more about that in our analyst meeting that we have that we talked about early in the spring of next year. But yes, basically, it's a longer-term view, given the dynamics that are going on in the market today. We've had a certain mid-cycle price that we've talked about over the last 4 to 5 or 6 years. And I think it is reflective that we think that mid-cycle prices moved up a bit. And so as a result, we can afford more base dividend and reflective of the raise that we announced here in the fourth quarter.

Paul Cheng:

Two questions, please. The first one, maybe go back into the split between dividend and buyback. In the third quarter, your split is about 65% in buyback, 35% in dividend. If we're looking into the future, is that a reasonable proxy that how should we look at it or that we can't really with [indiscernible] and saying that, okay, that's maybe what you guys are going to do. So that's the first question. Second question is on the Qatar LNG that -- congratulations, you get into the North Field South. Is there any capital number that you can share? I think, in the North Field extension, your share of the commitment is about and given that it's the same volume, say, here. So should we assume it's similar? And also whether that the terms between the North Field South and North Field expansion are basically the same, is there anything that maybe you can share? And also that when that spending on North Field South will kick in because that, I don't think will come on stream until 2028?

Nicholas Olds:

Yes. Just to add, Paul, just on -- as we talked about in the Q2 call, remember North Field expansion, that total nets $900 million for us. We will have catch-up payments. And so once the condition precedents are set, we'll reverse energy for COP share and those NFE project costs. That could happen early next year or even late this year, again, $900 million net total for the project. Startup again for NFE is 2026 and then NFS will probably follow a year later.

Raphael DuBois:

Seen from this side of the pond, it looks like there is a bit of a trade-off between the industry increasing production of phase, windfall tax and/or extra tax on distribution. Can you maybe explain what projects you call sanctioned if you were better incentivized to increase production? Are there any resources that you could monetize faster if you received some sort of guarantee from the U.S. government in terms of permitting, as you mentioned in your remarks, or in terms of tax stability? That would be my initial question.

Raphael DuBois:

Great. My second question is Total Energy has recently announced that they will spin off their [indiscernible] in Surmont and [indiscernible]. And I was wondering if you could tell us what it might change for the way Surmont is run and whether it's something you could also consider to lower your GHG emissions intensity.

Ryan Lance:

I would say, Raphaël, it does nothing for global emissions what Total is trying to do.

Jeoffrey Lambujon:

My first 1 is just on portfolio management on the acquisition strategy. I know you've talked about bolt-ons as more of the focus, and we're obviously seeing that quarter-to-quarter. But wanted to get any updated views you might have on the environment as you see it for larger deals, particularly for upstream assets in the Permian. I don't know that the cost of supply framework continues to be kind of the focal point in assessing those in terms of what opportunities would need to hurdle. But anything you'd say just around what you see today and where results in your appetite might be, particularly in the Permian would be great, just given the position you've assembled there over the years.

Jack Harper:

Sure. Thanks, Ryan. Yes, we're always opportunistically looking to add to our core areas. And as we've talked about in previous calls, we find the highest value right now in swaps and trades. The team has completed about 20 of these and that approaches 30,000 acres or so in that allows for longer lateral development and lower cost of supply development. So in addition to those 20-ish deals, we have about that many or more in the pipeline.

Dominic Macklon:

Jeff, it's Dominic. Yes. So the -- we've sold -- well, since we closed the and then the Shell transactions, we obviously wanted to do a little bit of portfolio cleanup. So we've sold $2.4 billion, as you said, of assets, and that's inclusive of the $0.3 billion this quarter. And we're pretty pleased about that because they represent really the priority assets we have for sale, typically very mature low-margin or high-cost supplies. So that's assets like Indonesia, the high H2S Builder Madden, some legacy assets in the Central Basin platform and so on. So we've been pleased with that. We've monetized those in a strong market. Going forward, I would say we're really just back into normal sort of high-grade opportunity as usual. We're not focused on any target at this point. We're happy with where we are. We'll always look for opportunities. But -- so we're pretty happy that we've basically completed the main cleanup that we wanted to do after those 2 big transactions.

Neal Dingmann:

And again, Jack, prayers with you and your family. Hope all goes well. Ryan, my first question, maybe I guess, I would call it for the top du jour on shareholder return on capital allocation. Specifically, any change to how you all are thinking about the shareholder returns versus -- or specifically the buybacks versus just particular to maybe accelerate your growth opportunities? I say that, obviously, given the stocks hit an all-time high and knowing just the incredible high well opportunities, high well return opportunities you all have.

Neal Dingmann:

Great to hear. And then my second question, probably for Jack, on the Permian and specifically the former Shell assets now purchased, I guess, it was about a year ago. I'm just curious to now when you look at those well returns that you've been seeing there, how those are stacking up versus those initial expectations maybe a year or more ago and how you guys are -- if you all are utilized, I think there was about, what is it, 600 or more miles of pipe there. I was wondering if that's being fully utilized.

Philip Gresh:

Operator, I think we have time for 1 more question.

Leo Mariani:

Wanted to quickly follow up around some of your prepared comments. You certainly discussed the LNG deals that you've entered into. And you kind of alluded to the fact that there's some nice benefit with your kind of U.S. production base, I guess, particularly for the Port Arthur project. Just as you're thinking about that, I mean, do you think there's obviously an ability to kind of hold some of those volumes into that in the next couple of years? And would you anticipate maybe trying to kind of increase some of your gas production as you look out into the middle of this decade to kind of take advantage of that as feedstock?

Leo Mariani:

Okay, that makes sense. And I guess, you also talked in your prepared comments about having to kind of start some of this medium-term major project capital in 2023 that we should kind of layer on top of this kind of second half '22 annualized spend, if you will. Is it possible to offer any order of magnitude on this? In this major project spend, are we talking kind of in the hundreds of millions or potentially could this be north of $1 billion?

Operator:

As we have no further questions, I will now turn it over to Phil for closing comments.

Operator:

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

Mark Keener:

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

Bill Bullock:

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

Neil Mehta:

And Mark, you will be definitely missed, and congratulations to Phil, who, if you're listening on the line, looking forward to working with you in the new capacity. The first question is for you, Ryan. Big announcement in terms of incremental return of capital. And the questions we got from investors this morning, given there's a variable element to it, is should we think of this as being oil price dependent in any way? Or should we view this as a financial commitment from Conoco that no matter -- assuming reasonable market volatility, that's a number you can count on.

Neil Mehta:

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

Operator:

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

Ryan Lance:

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

Ryan Lance:

Yes, NEPA needs reform, Stephen. It can take 10 years or more cycle time. And it's not just our industry, it's all industries, even the guys that I talked to that are wind developers and solar farm developers complain to the same thing. It takes a long time, the coordination through all the various government agencies that have responsibility within the NEPA for process and it just takes a lot of time. So having some better coordination, giving some deadlines to response times, giving good public comment review periods, but don't let them extend and definitely like this administration tends to do a little bit and past administrations have tended to do for that matter. So you have a NEPA process is in desperate need of reform to try to make it run smoother, quicker, and have coordinating groups shepherd this through the various agencies that have some responsibility through the course of the process. And I understand they're looking at that, maybe it's a companion bill to the Schumer-Manchin bill. So it gives us a little bit of question as to whether or not it will get done, but it is in desperate need of some NEPA reform. Now Willow specifically, we've been in this process a long time, so we're in the final throes of that. We've got the supplemental EIS statement through the Department of Interior, it's out in the public comment today. Again, we'd like to -- the public has had plenty of time to comment on this project. I think we know where everybody stands. So it's time to make a decision to move forward. And we look forward to that record of decision coming here later this year so we can get moving forward on the project. We think we've satisfied all the concerns that the federal judge has had, and we're ready to move forward.

Jeanine Wai:

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

Jeanine Wai:

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

Bill Bullock:

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

Ryan Lance:

Yes. So Jeanine, that's incremental. If it did -- if a catch-up payment that did occur this year, that would be incremental to the $7.8 billion that we guided to.

Roger Read:

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

Bill Bullock:

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

Roger Read:

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

Operator:

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

Bill Bullock:

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

Bill Bullock:

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

Dominic Macklon:

Yes. Thanks, Doug. It's Dominic here. Yes, there are some moving parts, and we'll be refreshing that as we pull our plans together. We're just going through our annual planning cycle right now. I mean, I think looking at this year, our actual breakeven this year is still calculating out around $30 a barrel capital breakeven. So sustaining capital around $6 billion. Now there's obviously some inflation pressure on that. But the way we think about sustaining capital is you're probably going to be focused on that in a lower macro world, if you like, and inflation not quite so high. So we still think that structurally, this year, we're in about -- sustaining capital would be about $6 billion. Clearly, that, with some long-cycle projects coming, longer cycle, low cost of supply projects coming, that will add to that for a temporary period, and we'll provide more information on that I expect by the end of the year.

John Royall:

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

John Royall:

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

Operator:

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

Ryan Lance:

Yes, Paul. We're in the market quite a bit. I think a lot of our focus right now in the Lower 48, and Jack can comment on as well as doing a lot of the core up. We noted that in some of our slides. So it's -- we've been a lot of focus right now on swapping and trading acreage with the large transaction that we did earlier this year to try to corp the acreage so we can make sure we're not drilling 1 mile, but we're drilling the -- we have the opportunity to drill the two and the three-mile laterals. We've seen a lot of the -- we looked at the bolt-on that you described. In the Bakken here more recently, we call all of the Eagle Ford. I guess, the bar is still pretty high in our company, and we're pretty -- we rigidly follow our $40 and $50 cost of supply cutoffs. So all in, any acquisition comes in have to have a lower than $50 and the future exploitation of the asset has to have something that's lower than $40 to compete in our portfolio. So the margin is pretty high. We watch all of them, and we're doing a few of them, but more of them are around the swaps in the Permian. I don't know, Jack, you might -- if you have anything to add there at all.

Ryan Lance:

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

Bob Brackett:

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

Operator:

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

Ryan Lance:

Well, Neal, we look at all the different ways of thinking about shareholder value. And I think it starts to your point earlier that we have a commitment to return at least 30% of the cash from operations. Not free cash flow, cash from operations back to the shareholder. If you look at our track record, it's been well over 40% as the commodity prices strengthened and the quality of the investment program and what we're doing continue to lower cost of supply has been sort of an active mantra inside the company. So I'd say what we're trying to do is reduce our capital intensity. We're trying to manage the capital as low as we can for the scope that we'd like to commit. So we go into our planning cycle thinking what is our view of the macro and that sets an amount. We can afford the capital we can invest, having taken 30% of our cash right off the top. We think that's a better value proposition to the shareholders rather than just focusing on either growth or return to capital. So it is a combination of the two. We want to grow and develop the company over the long haul. We want to make sure that the shareholders are getting an adequate part of that cash back right off the top. So we have to live with the capital or the cash that's left over. And then in the course of that, we recognize that the value of the balance sheet, which is like another asset, a huge asset inside the company, and we want to make sure that the balance sheet is as strong as it possible, which means we'll carry some cash and we'll carry some cash on the balance sheet because of the volatility we see in the commodity markets, the scope that we want to execute to grow and develop the company and we're not shooting -- we don't have a growth target in mind. It's an output from our plans to make sure that we're maximizing our returns on and of capital. So we'll adjust our plans to make sure that we're hitting those two really key components, returns on and of capital. And then out of that comes a production number and a sequencing of the projects to allow the further growth in the development of the company over the long haul.

Jack Harper:

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

Leo Mariani:

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

Leo Mariani:

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