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

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.

Thanks, Phil, and thank you to everyone for joining our first quarter 2023 earnings conference call. Since we just hosted our Analyst Day and Investor Meeting in New York a few weeks ago, we are going to keep our prepared remarks fairly brief today. ConocoPhillips delivered a strong first quarter result, setting a new production record for the company as well as in the Lower 48. Underlying production growth was 4% year-on-year, including 8% year-on-year growth in the Lower 48. We are confident in our outlook for the rest of the year, and we are increasing the midpoint of our full year production guidance. We're keeping our full year capital and operating guidance unchanged. Shifting to returns on announced capital, we continue to demonstrate our returns-focused value proposition in the first quarter. Our return on capital employed once again exceeded our goal of being top quartile in the S&P 500. And as we highlighted at the recent Analyst and Investor Meeting, we remain confident in our ability to achieve this objective in a mid-cycle price environment over the course of our 10-year plan. On return of capital, we are on track to deliver on our planned $11 billion for 2023, which represents greater than 50% of our projected CFO and is highly competitive with peers. And we are able to achieve all of this while investing in our attractive mid- and long-term opportunities. Our first quarter was also quite busy from a strategic perspective. At Port Arthur LNG, we acquired a 30% equity interest in the joint venture upon final investment decision on Phase 1. At Willow, we are pleased to receive a positive record of decision and began road construction. And at APLNG, we announced plans to become upstream operator following the closing of EIG's transaction with Origin and to purchase up to an additional 2.49% in the project. We also accelerated our 2030 greenhouse gas emissions intensity reduction target to 50% to 60% versus a 2016 baseline as we further advance our net zero operational emissions ambition. I know everyone has the question on Surmont, so let me address that right now. We acknowledge that we received our right of first refusal notice, and we're certainly reviewing it carefully. Now in conclusion, as we shared at our Analyst and Investor Meeting last month, our deep, durable and diversified asset base is well positioned to generate solid returns in cash flow for decades to come. And as I said then, we challenge any other E&P company to show you a plan with this kind of duration. Now let me turn the call over to Bill to cover our first quarter performance in more detail.

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.

Great. Thanks, Bill. So before we move to Q&A, just a quick reminder here that we are sticking to one question per caller this quarter, since we just hosted the Analyst Day a few weeks ago, and it’s obviously quite a busy earnings day for everybody. So with that, Michelle, let's move to the Q&A.

The first question comes from Stephen Richardson with Evercore.

Ryan, could you discuss the return of capital? Clearly, it's exceeding 50% of cash flow from operations and is positioning well against the $11 billion target. Given the current environment, which is quite volatile, how do you view the balance between the VROC buyback and maintaining general flexibility considering the fluctuations in the commodity market from a shareholder perspective?

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.

The next question comes from Neil Mehta with Goldman Sachs.

Thank you very much, and congratulations on a strong quarter in the Lower 48, especially. Ryan, you've somewhat addressed this already, but I would appreciate your comments on Surmont, understanding that it is an evolving situation. Considering that asset, it appears to be a key part of your strategy based on the Analyst Day. Could you share any insights on whether it would be beneficial to increase its role in the portfolio?

Yes, Neil, thanks. No, I can let Andy maybe make a few comments about the assets, which would be kind of reiterating what we said at the Analyst Meeting. But yes, we're in receipt of the notice on the transaction between Total and Suncor. We have a right on the Surmont asset, which we know really well because we own 50% and operate it. So we're in the process of taking a pretty serious look at that. I can maybe have Andy reiterate some of our thoughts about the asset that we described in the Analyst Meeting.

Good morning, Neil. As we mentioned in the Analyst Meeting, we view Surmont as a long-term, low capital intensity asset. This low capital intensity is a key component of our portfolio. To emphasize, the maintenance capital for our 50% share of Surmont has been around $20 million to $30 million per year over the past four or five years. We are currently drilling our first new pad since 2016, which will cost in the $40 million to $50 million range. This reinforces that Surmont is a very low capital intensity asset with a relatively stable production profile. We also disclose all relevant information regarding our production data, bitumen realizations, and operating costs, allowing you to form your own view of the asset. It remains a core asset in our portfolio. I'll stop there.

The next question comes from Roger Read with Wells Fargo.

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?

Yes. Sure, Roger. This is Bill. As we talked about at the Analyst Investor Meeting, we're currently really satisfied with 30% for Phase 1 and our 5 million ton equity offtake, and we're prioritizing market development over any additional offtake in equity right now. We really think we've got sufficient capital allocation to Port Arthur, and we're looking for ways to optimize our current investment. So our plate's pretty full, and we don't see the need to allocate significant additional capital in the near term. And so there need to be some pretty unique reasons to make it attractive.

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

This is actually Kalei on for Doug. My question is a follow-up on Surmont. So our understanding is that Suncor could receive certain tax benefits as part of their deal. And I'm wondering if those tax benefits would be available to you if you exercise your right of first refusal. And I'm asking the question because I think yours would look more like an asset deal, while theirs is more of a corporate deal.

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.

The next question comes from Sam Margolin with Wolfe Research.

The capital efficiency appears to be trending positively with production guidance and the capital plan aligned. At the Analyst Day, you mentioned that there might be a chance for inflation to ease or even reverse. Considering the production results, do you see this as an opportunity to increase activity due to decreasing costs, or is it primarily influenced by well results?

It's Dominic here. Just to talk to inflation a little bit first. I think overall, our capital inflation for the company, we still expect to be in the mid-single digits year-over-year. So we certainly see that all leveling off. As you mentioned before, we've probably seen deflationary trends in steel tubulars, oil price-related commodities such as fuel and chemicals; beyond that on the rig and other services. They've certainly leveled off. We may be trending towards some reductions. We have seen rig counts peak and begin to decline. That's led by the gas basins. So our teams are very focused on costs, and they're working with our many service providers on that, but we still expect around the mid-single digits at this stage on inflation. Having said that, we certainly see capital efficiency coming through. I think that's really on an execution front. So we've had a strong start, particularly in the Lower 48. Our full year production guidance, as we've said, is up at the midpoint. We do expect low to mid-single digits growth for the year, and that's pretty consistent with the long-term 4% to 5% CAGR we presented at our Investor Meeting. We're holding our capital range the same with $11 billion at the midpoint. So we're definitely seeing some execution efficiency. We're pleased about that. Nick, you may want to talk a little bit more about the Lower 48 on that.

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.

The next question comes from John Royall with JPMorgan.

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?

Hi, John, this is Andy. Yes, there's really not too much new to comment on over the last few weeks. So the only incremental news we've had has all been positive. The 9th Circle Court of Appeals denied motions attempting to stop our construction work. So we've been progressing with the winter season, and we've had gravel extraction and road construction underway. It's pretty much going as we expected it would in the last two or three weeks. Not much more to add than we talked about at the Analyst and Investor Day.

The next question comes from Ryan Todd with Piper Sandler.

Ryan, following up on the Analyst Day, what impact does your increased view of the mid-cycle oil price from 50% to 60% have on your business considerations? You remain focused on low-cost assets that are well below this price. Does your perspective on oil prices being structurally higher over time affect how you manage the business long-term, including your balance sheet and capital allocation?

No. Thanks, Ryan. Regarding the day-to-day operations and capital allocation, we are only investing in projects with a supply cost under $40 WTI. Each year, our Chief Economist Office and commercial team assess the macroeconomic situation and provide a long-term outlook. Given the recent upheaval in the industry, such as the Russian invasion of Ukraine and declining investments, we conducted our own detailed analysis, which is crucial this year. We sought to determine where we believe the mid-cycle price is heading and found it likely to remain around the $50 mark. Our analysis suggests that to produce additional barrels for increased demand, the necessary price is approximately $60 today. The implications of this are tied to our anticipated cash flow and how we evaluate our portfolio, alongside our investments for growth and development. This affects the amount of cash we can allocate at the mid-cycle price, which is higher than what we would offer at lower prices. It influences our approach to cash on the balance sheet, our debt management, and distribution capacity, which we aim to maintain at about 30%. When prices exceed the mid-cycle benchmark, as they do now, we're generating significantly more cash and returning over 50% to shareholders, driven by our reinvestment strategy focused on low-cost supply assets.

The next question comes from Devin McDermott with Morgan Stanley.

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?

Yes. Devin, this is Nick. You're right. Strong well performance was definitely a contributing factor for Q1. If I take you back to the Q4 call, I had mentioned that our well performance was meeting or exceeding-type curve expectations, and we continue to see that trend in Q1. So that's very encouraging. No overall development changes. We're just seeing very promising results across all assets. It is just not the Permian as well. And as I mentioned earlier, the completion and drilling efficiency has allowed us to accelerate some wells earlier into Q1, and so we're seeing that production come into play. And then on the Eagle Ford stabilization plant that we've updated, the team just did a remarkable job in sheltering the amount of downtime in Q1. So we had less downtime. But overall, a very strong quarter.

The next question comes from Josh Silverstein with UBS.

Just some questions around potential LNG opportunities in the future. You mentioned at the Analyst Day that you have options around Port Arthur Phase 2, 3 and 4 and even at Costa Azul as well. Can you just give us some more details around the options? Does it need to be at the 30% like you did in Phase 1 of Port Arthur? Or could it be 10% or some other agreement there? Could it be before or after FID as well? And then just along the same lines. Because there will already be some infrastructure in the ground for Phase 1, will the capital outlay for Phase 2 or 3 be less because of that?

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.

The next question comes from Paul Cheng with Scotiabank.

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 mean 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?

Yes, Paul, this is Nick. You're right. I mean, we had a very strong performance in Q1, as we just described. As you look at the future quarters of this year, we've got some larger pad projects, longer horizontal wells. And kind of put that in context, we've got 80% of our 2023 Permian wells are 2 miles or greater as we've got a fairly large portion that are of the 3 miles. But you're going to see kind of small variations. But overall, that's going to be relatively flat. But I'll leave you with this Paul, our plan will deliver at least mid-single digits for Lower 48.

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

I just wonder if you could provide some updated commentary if you have any on Venezuela. About a month ago, there was some talks about kind of easing oil sanctions there. And you all have a potential big asset or at least valued that at one point in time, were looking to extract. Is there any update on that? Or is there any kind of color you can talk about like the progress and remind us of the value there?

Yes, we're currently engaged in discussions, including recent talks regarding the Citgo refining assets. We are actively involved in every development concerning that situation. As a reminder, we have a $2 billion ICC judgment, of which we've collected approximately $700 million so far. Thus, we still have a balance owed on that judgment. Additionally, we are in the appeal process with ICSID, which could potentially result in an $8 billion award. There is some overlap between these two amounts, so they can't be simply added together. The key point is that there is significant financial potential involved, and we are working diligently towards a resolution. Recent updates from the judge and the U.S. government regarding Citgo have been encouraging. Despite existing sanctions against the Venezuelans and U.S. companies involved in Venezuela, it seems there may be some progress, and we are right in the midst of these developments.

The next question comes from Alastair Syme with Citi.

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?

Yes. I'm not sure the exact ratio. Maybe Nick might have some numbers, but I think most of what we're doing is large pad development with not single well facilities, but central facilities supporting those large pads. I don't know what the split between drilling and infrastructure spend is. I can let Nick have a comment, but I don't think it's much different than what we've been doing for the past few years.

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.

The next question comes from Raphael DuBois with Societe Generale.

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?

Certainly. Happy to discuss working capital. In Q1, the working capital usage was approximately $100 million, as indicated in our supplementary documents available on our website. For Q2, we anticipate this to exceed $1 billion, primarily due to tax payments in Norway, which is standard for operators in that region. We accrued these taxes in 2022, and they are due in the second quarter of 2023. Looking ahead, assuming there are no significant fluctuations in foreign exchange rates for the rest of the year, we do not expect any significant changes in working capital for Q3 or Q4. I hope this provides clarity for the full-year outlook.

The next question comes from Neal Dingmann with Truist Securities.

My question is on shareholder return plan specifically. What do you all view sort of in broad terms as an optimal quarterly payout given, I guess, now how even more volatile the commodity market continues to be and looking at your most recent, I guess, the payout was a bit over 100%?

Yes, I think it's important to revisit how we established the VROC in the first quarter. It was set during a $100 price period in the third quarter of last year. We likely had a slightly higher distribution in the quarter, which will become more consistent as we progress through the second, third, and fourth quarters while working towards the $11 billion target for this year. This is reflected in the VROC we set for the third quarter at $0.60 per share.

Our last question comes from Leo Mariani with ROTH MKM.

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?

Yes. Thanks. It's Dominic here. So you're right. We did anticipate about 35,000 barrels a day of turnaround and maintenance impact in the first quarter. That actually came in at 25,000, so 10,000 lower. That was partly because of the efficiency that Nick talked about at the Lower 48. The Eagle Ford Sugarloaf stabilized expansion went really well, and the team did a great job sheltering some of that. Then there was a little bit of timing there around Qatar turnarounds as well. So we had 25,000 barrels a day impact in the first quarter. We still expect a full year average impact from our turnarounds of about 15,000 barrels a day equivalent. Bill said, second quarter, I think, as he mentioned, we expect to be 10,000 to 15,000. And there will also be some standard sort of seasonal downtime in the second and third quarter we typically see in Norway and Alaska and APLNG. But all of that's reflected in our new guidance, 1.78 million to 1.8 million barrels a day for the full year.

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

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