Conoco Phillips (COP) — Q2 2023 Earnings Call Transcript

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; 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 asset 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, 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 cash flow from operations (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 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 depreciation, depletion and amortization (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. 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.

I 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, the 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 debottlenecking 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 guidance. 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?

Thanks, Neil. It's Dominic here. We're really pleased with our production performance across the board, but the Lower 48 is particularly noteworthy. This marks the second consecutive quarter of growth, with our production guidance increased by 25,000 BOEs equivalent since the start of the year, primarily driven by an 80% increase in oil. We expect our full-year underlying growth to be between 3% to 4%, and for the Lower 48, it should be around 7% to 8%. There's a lot of attention on product mix in the sector, and we anticipate our mix will remain steady throughout the year. The growth figures apply to both BOE and oil calculations. While there may be fluctuations in the Lower 48 from quarter to quarter due to different pads coming online, this should balance out over the year to maintain a consistent product mix. For instance, comparing the second half of 2022 to the first half of this year, our product mix in the Lower 48 has been consistently around 54% oil. We're satisfied with the production progress, with the Permian and the Lower 48 being the key contributors. Nick, would you like to elaborate on 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 a result 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.

Could you discuss the Mexico-Pacific offtake agreement? It seems like you have a lot of interest in these types of deals. What made this particular project the right choice for you? Additionally, what is your perspective on the timeline and steps towards final investment decision? I'd appreciate more details on how this fits into your overall strategy.

I will address some of the broader strategic elements and then hand it over to Bill to discuss the Saguaro project specifically. As we formulate our high-level plan, we believe it’s vital to enhance our LNG business, given our strengths in energy transition. Several years ago, we embarked on this initiative, which aligns with the volumes we see in Qatar. Securing FID for Port Arthur and the opportunity presented by Saguaro on the West Coast are all part of our efforts to expand our LNG operations. We aim to capitalize on opportunities in equity at Port Arthur and, importantly, respond to the increasing demand from Europe and Asia. Now, Bill will provide more details about the Saguaro project.

Yes, we are focused on building our market and establishing a highly competitive supply in a gradual manner. We are making significant progress on both fronts. We have secured 2 million tons of regas in Germany, which aligns with our 2 million-ton offtake from our LNG agreements with Qatar. This leaves us with 0.8 million tons for our commercial LNG business, representing 16% of Port Arthur LNG. We are also advancing our offtake into Europe and discussing opportunities with several Asian buyers. We are pleased with our progress in developing the market. Additionally, we are excited about adding 2.2 million tons of offtake on the West Coast of Mexico, contingent on a successful Final Investment Decision by Mexico Pacific. This facility enhances our offtake options, avoids the Panama Canal, and supports volumes into Asia. It complements our offtake from Port Arthur and offers optimization opportunities. This project has strong backing, including support from ConocoPhillips, and features a dedicated pipeline from the Permian, which enhances takeaway options for Waha pricing. It also utilizes ConocoPhillips' optimized cascade technology. Therefore, we see many advantages in securing capacity at Saguaro. It’s important to note that this is an offtake agreement without any equity component. We are seeing robust demand for LNG, making this a fitting addition as we continue to build our 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 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.

Dom, I have a follow-up regarding well performance productivity and the impressive production results you've announced today. Specifically, your partner in the Permian has mentioned that the well productivity is exceptional, and you are clearly benefiting from that. Can you comment on whether there has been any transfer of knowledge or practices to Conoco's operated production? Additionally, could you compare the differences you observe between your 60% ownership in the joint venture and your legacy position in the operated areas 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 in 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.

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. 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.

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.

Sorry, I missed part of that. I have a follow-up question regarding the Saguaro LNG offtake and, more generally, offtake agreements. Now that you have the offtake agreement in place, with 5 million tons secured from Port Arthur, how do you assess your interest in LNG offtake agreements? Is there a certain amount that you consider appropriate for your portfolio in relation to equity gas production, both globally and in the U.S., particularly when comparing U.S. gas to offtake agreements? Should we anticipate that you'll pursue additional offtake agreements, or do you believe your portfolio is balanced at this time?

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. I apologize, but I'm not sure if you mentioned this earlier since I missed the first minute of the prepared comments. Could you provide an update on Alaska, particularly any outstanding legal or permitting issues that might affect the timing at Willow?

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 thorough 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.

I have a couple of quick questions about the long cycle. You mentioned long cycle development and inflation changes, and I was wondering if you could provide an update on Willow. It seems like we reached a peak in inflation, and some key costs have decreased. Do you have a cost update for that? Where do you expect costs to decline? I know it's a 6-year project, but...

Lloyd, it's Andy again. When discussing a longer-term project, it can be challenging to comment on deflation and inflation through 2029. However, it’s important to clarify that Willow is not a turnkey contract. As we engage in individual contracts, those agreements are connected to specific indices that can fluctuate with inflation. Additionally, I’d like to note that we haven’t experienced the same rate of inflation in Alaska as we have in the Lower 48 over the past couple of years. As we mentioned at AIM, we still expect the capital range to remain between $7 billion to $7.5 billion, which hasn’t changed from the CapEx to first production. It's also important to highlight that, like all our projects, Willow includes an inflation factor in those estimates. We have a solid understanding of the project, and much of this work aligns with the typical activities we undertake in Alaska. Therefore, I believe the $7 billion to $7.5 billion estimate we provided at AIM is still a sound estimate regarding 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 right of first refusal 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.

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.

I would like to return to the topic of LNG. Could you discuss the three opportunities you've pursued over the past 12 to 18 months and how they compare in terms of supply costs once you factor in all expenses related to fiscal considerations?

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.

I would add that we look at the liquefaction fee and our reason for choosing Port Arthur is that we believe it offers a very competitive liquefaction fee. Additionally, avoiding some of the costs associated with the Panama Canal gives it a premium position for 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. The performance of Lower 48 this year is very strong. We have an efficient operation, and despite the levels being relatively flat, we expect to see growth in returns and activity from the Lower 48. We are assessing the overall situation and determining what level of growth we believe is reasonable. This is something we're considering, but no decisions have been made yet. It’s just a matter of refining our outlook as we approach 2024.

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 Costa Azul 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 placement 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 markets and doing that through a variety of formats and time horizons.