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

Thank you, Liz, and welcome 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.

Thank you, Phil, and thank you to everyone joining our second quarter 2023 earnings conference call. It was certainly another busy quarter for ConocoPhillips. In April, we hosted our Analyst and Investor Meeting in New York City where we laid out our 10-year strategic and financial plan, and we committed to you that we would keep working to make the plan even better, and we've done that again this quarter. We executed an agreement to purchase the remaining 50% of Surmont, which we expect to close in the fourth quarter. Surmont is a long life, low decline and low capital intensity assets that we know very well. In the current $80 per barrel WTI price environment, we expect incremental free cash flow from the additional 50% interest to approach $1 billion in 2024. We expect first production in early 2024 from Pad 267, our first new path since 2016, and we see debottlenecking potential at the facility to further improve our cash flows. We also continue to progress our global LNG strategy. In the quarter, we finalized the acquisition of our interest in the Qatar North field South joint venture. And in North America, we executed agreements for 2.2 million tonnes per annum of offtake at the Saguaro LNG project on the West Coast of Mexico. And in Germany, we can confirm we have secured a total of 2.8 million tonnes per annum of regasification capacity at German LNG. And while it's only been a few months since FID at Port Arthur, we are further progressing our offtake placement opportunities in both Europe and Asia. Now shifting to the quarter. While commodity prices were volatile, ConocoPhillips continued to deliver strong underlying performance. Once again, we had record global and Lower 48 production and we raised our full year production guidance for the second straight quarter. This was achieved through continued capital efficiency improvements as the midpoint of our full year capital guidance remains unchanged. We continue to deliver on our returns-focused value proposition. We have distributed $5.8 billion through dividends and buybacks year-to-date, putting us well on track to achieve our planned $11 billion return of capital for 2023. And we did this while funding the shorter and longer-term organic growth opportunities that we see across the entire portfolio. So in conclusion, our deep and our durable and diversified asset base continues to get better and better. And we are well positioned to generate competitive returns and cash flow for decades to come. Now let me turn the call over to Bill to cover our second quarter performance in more detail.

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.

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

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?

Yes, absolutely, Neil. So obviously, second quarter was a bit challenging on our capture rates. And as you noted, it's particularly Lower 48 gas and Alaska crude. And I'll give you some details on each, but the punchline here is that we're already seeing Lower 48 gas differentials and elastic crude pricing returning to more normal levels in the third quarter. And as I mentioned, based on strip and differentials for the rest of the year, we remain comfortable with our framework reference of $22 billion in CFO at $80 WTI and $3 Henry Hub that we provided at the beginning of the year, along with our published full year price sensitivities. But let me start with Lower 48 gas. Our slides show that our second quarter capture rate was 68% of Henry Hub. That's down from 85% in the first quarter, which compares to our expectation of roughly 80% capture for the full year that we laid out a couple of quarters ago. And as you probably recall, I said that we expected Lower 48 capture to be volatile quarter-to-quarter this year, and we are certainly seeing that. Now the 68% rate in the second quarter was mostly driven by what we're seeing in still wide Permian differentials relative to Henry Hub for the first half of the year as well as the absence of some strength in SoCal and Bakken that we saw in the first quarter, which really explains the quarter-to-quarter change. Now looking at third quarter, Permian differentials have narrowed back to more normal ranges. That's with some pipeline takeaway improvements and additional debottleling ahead, and SoCal's looking a bit better as well. But Clearly, the story here is Permian disk. That's what matters the most. Now on Alaska crude, this one's a bit more unique to ConocoPhillips. Capture rates slipped to 97% in the second quarter from 101% in the first quarter, and that's largely timing related. With some of our second quarter cargoes, they were priced when A&S was trading at a discount to Brent. But as you can see on the screen right now, A&S is back to premium to Brent more towards historic levels. So I'd say when we look at this and pull it out all together, we remain encouraged by our recent capture rates, and we're confident in our full year estimates and activities, and we're pretty constructive on the second half of the year, Neil.

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?

Yes. Thanks, Neil. It's Dominic here. Yes. We're pretty pleased with production performance. I think it's really across the board. We're seeing everything perform well. But certainly, it is a Lower 48 that is standing out a little bit more, and even -- and Nick will talk to that in a minute. So you're right, yes, that's the second quarter that we've increased in a row. Our production guidance were up 25,000 BOEs equivalent since the beginning of the year, and what's interesting about 80% of that increase is actually oil. And so our full year underlying growth is expected to be 3% to 4% this year, and that would be 7% to 8% in the Lower 48. Now there is a lot of focus on product mix right now in the sector. So let me just say that we expect our product mix to be consistent over the year also. So those growth numbers really work on both the BOE and the ball of oil basis. And we can get some noise on mix from quarter-to-quarter in the Lower 48, depending which particular pads are brought online across our basins, but that will average out over the year to a consistent product mix. So for example, if you look at our second half 2022 compared to first half of this year, we've had very consistent product mix in Lower 48, around 54% oil. So yes, we're pleased with the production progress. Like I said, really the Permian and the low 48 is driving that. So Nick, do you want to talk a little bit about that?

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.

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

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.

Well, maybe, Steve, I'll take some of the broader strategy and then turn specifically over to Bill for the Saguaro project itself. But as we try to lay out a game kind of looking at a high level, we think from a energy transition perspective and just confidence in what we're really good at on the LNG side, we wanted to expand that piece of our business. So we set out a couple of years ago to go do that. I think it's consistent with the Qatari volumes. Of course, getting Port Arthur to FID and then and now the Saguaro opportunity, specifically on the West Coast. But it's all in service to trying to build up more -- a bigger LNG business inside the company and taking opportunities as they become available, both on the equity side at Port Arthur but, more importantly, on the offtake side in trying to service some of the growing demand that we see coming out of Europe and Asia. I can have Bill -- Bill can talk more specifically about the Saguaro project.

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.

That's great color, Bill, and Ryan. Bill, I was wondering if I could just follow up quickly on Surmont. It's been a little while since you exercised, but wondering if you could give us your latest thoughts on funding of that transaction and how you're thinking about it.

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.

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

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?

Yes, Doug, this is Nick. I'll take a stab. I think you're looking at the non-operated versus operated split. Is that where you're going with?

Basically, yes. Exactly right.

Yes, yes, yes. So if you just take a look at that second quarter top end of the range performance from Lower 48, as I mentioned, we had strong performance both on accelerating the wells, but also strong well performance. That's roughly split between operated and non-operated. And obviously, when you look out in the Delaware, OXY has a large component, but we have a number of other JV partners that are contributing to that as well, but OXY has a big component.

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

We constantly, Doug, look at all benchmarking. So we receive the ballots from our non-operated positions. We evaluate that to meet our cost framework. I'd say in general, we're fairly aligned. There's always a little bit of difference in spacing and stacking and completion design, but we're roughly in line. And obviously, the positions that we have in the operated position is really in the core, less than 12 billion barrels of resource, less than 40, averaging 32. We got great legacy positions out in the Delaware.

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.

Thanks, Doug. You've been a consistent messenger on this particular point. I give you credit for your tenacity, that's for sure. Look, yes, we recognize that we're acquiring some assets to get significant free cash flow potential at $60 to $80 even at our mid-cycle price. I guess the thing I'd say, first and foremost, Doug, is you shouldn't question ConocoPhillips' commitment to giving a significant amount of our cash flow back to our shareholders. So the last 6, 7 years, we've averaged 45% this year, depending on your outlook for prices. We're probably closer to 50%. So first and foremost, we're going to be competitive on giving a significant amount of our cash back to shareholders. And again, that's CFO, not free cash flow. Now to your point, even at a constant price, we're going to be generating more free cash flow as we come out of the APLNG and Surmont activity. Our framework really hasn't changed. Look, what I want -- what we want on the base dividend is something that is that we said we see a lot of value being able to grow that at a top quartile rate over time, over the long term, and we intend to go do that. We set our framework around a mid-cycle price, and you may differ or argue with our mid-cycle price, but we try to set a framework around a mid-cycle price. We want to buy some of our shares back through the cycles so we don't get caught pro-cyclically. And then we introduced that third tier VROC to address when prices are well above mid-cycle, and you'd argue $80 as well up in mid-cycle. So I think our cash yield is competitive. I think your point is we may get more credit if we put a lot more into the base dividend. We just think that growing the base dividend in a top-tier amount annually gives us a lot of credit as well and doesn't obviously raise the fixed cost to the company. But the improvements are we can afford a bit more, but we're focused on sort of the framework that we outlined and watching pretty volatile commodity prices. So I'd just remind people, just a month ago, WTI was back in the 60s. So we're trying to set a framework that we know works through the mid-cycle, and we set a framework that rewards the shareholders and recognizes the torque that the company has to the upside when prices are much higher. We like the 3-tiered framework. We'll look at it again. As we finish this year and go into 2024 we'll look at where our shares are trading, we'll look at where the commodity prices are at, and we'll try to set the channels appropriately. But you can count on us delivering a significant amount of our cash flow back to our shareholders as we've done over the last 6, 7 years.

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

Apologies if this is a little early, but I want to ask about 2024 capital if I can and maybe focus on Willow. There should be a natural tailwind in capital because the step-up in Willow is less than the Port Arthur payment. But I just wanted to see if there's anything we should know about project life cycle at Willow that creates a different shape of spend over the development for '24.

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...

Understood. And this is a follow-up on your point on Lower 48 and particularly sort of the phasing of your development because now with Mexico Pacific, and Port Arthur, you've got quite a bit of evacuation from North America for gas. It integrates with your marketing team and through the supply agreement, which you talked about the AIM. And I wonder if -- thinking about those projects and their impact on maybe even NPV of your -- of some of your Permian positions with respect to realizations is a factor or if these are evaluated for you totally separately.

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.

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

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.

Yes. Thanks, Devin. Dominic again here. So obviously, something we're watching incredibly closely with everybody else in the industry. I think we are seeing some areas of deflation in the Lower 48 going in the second half. I would say, however, we still expect our overall company capital inflation to average out in the mid-single digits this year versus last year on an annual basis. But just to talk a little bit about what we're seeing. I mean, certainly, I think as we've said before, tubulars, we've seen some significant price relief on any oil price-related commodities, fuel and chemicals and things. We've seen some material reductions in sand and proppant. Rig rates have softened a bit, and that's obviously driven by the gas basin. So you're starting to see some high-performance rigs come in and compete with the oilier basins. So that is -- we are seeing some day rates come down there. And I would say I think we are beginning to see some examples of frac spread rates coming down in some basins. So that's all looking positive. Activity internationally and offshore is picking up. It's probably as high as it's been for many years. So we are seeing some pressure on labor rates there. So we're watching that. But overall, certainly seeing some deflation going into the second half, and that's a big part of the reason we see a lower capital run rate for the second half for the first half. That's an important part of it. And that's all reflected in our annual capital guidance that we have narrowed to $10.8 billion to $11.2 billion, $11 billion still on midpoint. So -- but certainly, we're seeing turning the corner here with inflation and moving into deflation again.

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?

Yes, this is Bill. We talked about this a bit at AIM. So as we think about Port Arthur LNG, we're pretty happy with the level of equity that we have right now in the project. When we took equity, that has some pretty unique reasons for taking it for the options that we secured there. And so as we look forward, it would have to make -- there have to be some pretty unique reasons why we take additional equity. Now as we have mentioned that our agreements are structured for future phases, continue to benefit our investment in the first phase, and so we're pretty positive on that. As you know, we've got some predefined options on that. We're certainly evaluating options. But I think that you should kind of have in your mind that we're not expecting to spend additional capital there at this point in time.

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

Can you hear me?

Yes, we can.

Okay. Sorry. It looks like the tax rate on your corporate segment earnings took a big step up in 2Q. So I was just hoping you could speak to the tax rate on corporate. And then I think it impacted just the overall blended rate stepped down a bit in 2Q. So just maybe a little bit of color on that as well would be helpful and just what we should expect moving forward with the tax rate.

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.

Great. That's really helpful. And then my next question is on Bakken production. You were up well over 100 kbd in 2Q. What was the driver of the strength there? And should we be thinking about Bakken as plateauing somewhere above that kind of mid- to high 90s that we used to think about? Or is there any stickiness to the strength in 2Q?

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.

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

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.

Yes. Right now, I think we're pretty focused on the organic side, Roger, but just because of the resource base right now and the stuff that we're executing has got pretty compelling opportunity for the company to focus most of our capital and our allocation towards our organic side of the business. But it's performing as well as it is. We're delivering the efficiencies that Nick talked about in the Lower 48 and what Andy is delivering around the rest of the world. that just looks to be compelling opportunities for the company. But with that said, you kind of -- you hang around the hoop, and you catch these rebounds a little bit because -- we never know when our partners in some of these assets make different strategic decisions, which is clearly what our partner at APLNG has done or is doing and what's clearly what our partner at Surmont is done and is doing. So we know these assets really well, and we've tried to -- we're consistent in the framework around cost of supply that we described to you a number of years ago of how we kind of match up inorganic opportunities with organic opportunities. And that's why we want to have the financial strength that we do with cash on the balance sheet and the ability to fund these projects when they come available. You just never know when your partner makes the kind of decisions that they have made. And we want -- when we know the assets well and we can get it for a deal that's very competitive, as you talked about, vis-a-vis Surmont and APLNG, for that matter, we're going to be all over those when those opportunities present themselves. We never quite know when they do. But -- so we're mostly focused on the organic side of the portfolio, but we want to have the firepower and be there. And we watch everything. We pay attention to everything that's going on in the market. We know what we like, and we know what we can afford to pay more importantly. And when we can bring those 2 together, we want to be able to execute those when those opportunities present themselves. And that -- and it was really opportunistic with both APLNG and Surmont. We had partners that made strategic decisions to go in a different direction, and that was to our advantage. So we want to take advantage of that.

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?

Yes, Roger, this is Bill. So 2 points. First up, the 2.2 million tons from Saguaro, that is an offtake agreement. It's not an equity investment. So I just think it's important to make sure that that's clear. And then for the specific question about the pipeline, I'd really direct you to the operator of Mexico Pacific for a detailed answer, but they've had several press releases out, including one in July that announced a 20-year agreement with CFE. That's the Federal Electric Commission in Mexico to supply Mexico Pacific with natural gas delivered from the Permian Basin via CFE's pipelines in Mexico. And so that's the best source of information for you on that. And of course, that takeaway from the Permian is helpful for Waha differentials and pricing overall.

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

Sorry, I cut out there for a second. I missed it. Maybe one follow-up question on the Saguaro LNG offtake, at least a broader question on offtake agreements. Is there -- you've got that offtake agreement now. You've got the 5 million tons from Port Arthur. Is there -- when you look at your interest in offtake agreements in LNG. Is there a relative size in terms of how much feels appropriate in the portfolio relative to equity gas production either on a global basis or in the U.S. relative to kind of U.S. gas versus offtake agreements? How are you thinking about -- partially which -- should we expect to see you look at additional offtake agreements? Or do you feel like you've got a pretty good balance at this point in the portfolio?

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.

Great. And then maybe -- and I apologize, I'm not sure if you said something on this here. I missed the first minute of the prepared comments. But any comments on what -- like the latest update on Alaska, particularly regarding outstanding legal or permitting issues that would dictate timing there at Willow? 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.

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

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... Andrew O’Brien: Lloyd, it's Andy again. So when it was a longer-term project, it is a little hard to comment on sort of deflation and inflation through 2029. But I guess it is important to frame it. Willow is not a turnkey contract. And as we are entering into individual contracts, those contracts do have terms linked to agreed indices. That can move up and down with inflation. So probably just a couple of other things I'd mention is that we haven't seen the same kind of inflation in Alaska, as we've seen in the Lower 48 over the last couple of years. So as we said in AIM, I think in terms of the capital range, that still holds. We expect the capital range to be in the $7 billion to $7.5 billion. That really hasn't changed from the CapEx to first production. And it's also worth emphasizing, like all of our projects, Willow has got some inflation factor into those estimates. So we understand the project really well. This kind of activity is sort of -- a lot of this is sort of typical activity we do in Alaska. And we haven't seen the same kind of inflation that we have, having the lower 48. So I think the $7 billion to $7.5 billion that we provided at AIM is still a good estimate of what our thinking is in terms of the CapEx to first production.

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. Andrew O’Brien: As you said, Surmont, one of the things that we really like about Surmont, it's a low capital intensity asset. So it really doesn't change that much in terms of allocating capital to other projects. It's just providing us a lot more cash flow. So I think the plan we outlined at AIM, it doesn't really change how we consider the other projects, and we have the benefit of another long cycle asset with low capital intensity.

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

I wonder -- sorry, back on LNG again. I just wonder if you could talk about the 3 opportunities you've taken on over the last 12, 18 months about how they compare on a cost of supply basis once you put together costs in fiscal, how it all comes together.

If you look...

Go ahead, Bill.

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.

Although there's still an inherent cost of supply associated with it in terms of how you're thinking about the market position?

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.

And I would add, Alastair, for the -- yes, we look at the liquefaction fee and our reason for choosing Port Arthur and obviously, NPL is what we believe is a very, very competitive liquefaction fee and avoiding some of the costs through the Panama Canal, then places it at a premium to Asian buyers.

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?

Yes, Alastair. I mean it's really looking at the performance of Lower 48 this year, I mean, it's doing very well. We've got a very efficient machine running as we think about returns, we think about the growth that we are likely to see from the Lower 48 even at relatively flat levels. We will see growth, we anticipate even at maintaining flat activity levels. So we're just looking overall and saying -- looking at the macro and so on and just saying how much growth do we think is appropriate. So that's just something that we're considering. We haven't made any decisions on that yet. But yes, it's just a case of fine-tuning that as we think about 2024. So...

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

So in Mexico as well, you guys have the option and offtake in, I think, potential equity agreement at Costa Azul as well. What are the key differences between the 2 projects and why the first one with Mexico Pacific versus the cost do project?

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.

Got it. And then as you guys are putting together your portfolio, are you trying to optimize the exposure you have to both the Atlantic and Pacific basins? And maybe discuss some of like the key differences you see or risks you see between both sides.

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.

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