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Good day, and welcome to the Cheniere Energy Third Quarter 2023 Earnings Call and Webcast. Today's conference is being recorded. At this time, I'd like to turn the conference over to Randy Bhatia. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to Cheniere's Third Quarter 2023 Earnings Conference Call. The slide presentation and access to the webcast for today's call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere's President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer;

Thank you, Randy, and good morning, everyone. Thanks for joining us today as we review our third quarter results and improved full year 2023 outlook. Before we get started, I would like to acknowledge the tragedies of war taking place around the world. Our thoughts and prayers are with those whose lives have been and continue to be impacted by these devastating and heartbreaking events. These events are contributing to disruptions, risk, uncertainty and volatility in the energy markets around the world. International gas supply sources and the critical infrastructure, enabling cross-border trade have become focal points with risk to this supply and its access increasingly reflected in price and volatility across international gas benchmarks in recent weeks. As the operator of the second largest LNG platform in the world, stable and reliable operations at our facilities have arguably never been more critical than it is today. As you all know, ensuring stable and reliable operations at our facilities with safety as a foundation has been my central focus since becoming CEO in 2016. When I joined Cheniere just begun LNG operations, producing its first LNG cargo that February. Today, we produce about two cargoes every single day. And during the third quarter, we produced our 3,000th cargo of LNG becoming the fastest LNG producer in history to achieve that milestone. I'm extremely proud of the work we do at Cheniere as a result of that work are providing tangible benefits in the lives of millions of people around the world. Our customers can take comfort knowing that my focus and the focus of my approximately 1,600 Cheniere colleagues remains on maintaining best-in-class operations to help ensure energy security for our 30-plus customers throughout five continents. Turn now to Slide 5, where I'll review key operational and financial highlights from the third quarter 2023, as well as cover another long-term SBA we announced this morning. We achieved successes across the Cheniere platform during the third quarter, generating consolidated adjusted EBITDA of approximately $1.7 billion, distributable cash flow of approximately $1.2 billion and net income of approximately $1.7 billion. We exported a total of 152 cargoes, an increase relative to the second quarter as we had lower maintenance in the third quarter. As I just mentioned, we also produced our 3,000th cargo during the quarter and maintained our perfect track record of foundation customer cargo deliveries. These operational milestones are a tremendous source of pride for Cheniere and serve to further distance our reputation from the competition. Looking ahead to the balance of 2023, our forecast has improved slightly. And while we aren't raising our full year guidance to date, we are currently tracking to the high end of the $8.3 billion to $8.8 billion of consolidated adjusted EBITDA and $5.8 billion to $6.3 billion of DCF ranges. The improvement to our outlook is mainly driven by portfolio optimization activities the timing of some expenses to a lesser extent, from higher marketing margins than previously forecasted.

Thanks, Jack, and good morning, everyone. While the LNG market kicked off the third quarter with prices reflecting the relatively subdued demand of the shoulder season, unprecedented early winter gas procurement in Europe, coupled with threats of potential supply disruptions globally, resulted in increased volatility and higher pricing throughout August and September. Prices remain elevated relative to pre '21 as the market is still precariously balanced, sensitive to any sign of disruption given the lack of spare supply capacity in the system, which is expected to continue for the next few years. The proposed strikes at the Australian LNG export facilities, representing approximately 10% of the global LNG market, garnering significant coverage during the quarter as the market tried to gauge the scale and length of any potential disruption to global flows. Fortunately, these risks were largely inverted and LNG exports continued to flow through the end of the quarter. Nevertheless, even the threat of disruption led to significant volatility in LNG prices, which was further exacerbated by the about 48% decline in Norwegian piped gas to Europe in September following extensive maintenance at the brownfield and the [indiscernible] gas processing plant. As a result, despite elevated storage inventories throughout the region, volatility persisted as TTF spot price has experienced some fairly significant swings throughout the quarter. The maintenance in Norway supported prices from early June, with July settling at $11.30 in MMBtu, while August settled over 25% lower at $830 an M, as Norwegian volumes returned only to rebound in September, which settled at $11.5 amid concerns around the Australian strikes as well as additional unplanned Norwegian maintenance. Still TTF prices remained at pre-Russian-Ukraine war levels during the quarter and continued to edge higher with futures settling October above $12 an M. Meanwhile, JKM prices largely tracked TTF throughout the third quarter, ultimately settling September slightly below TTF at $11.20. However, more recently, JKM futures settled October higher at $13.30 due to the uncertainty around the potential industrial action in Australia as well as increased demand from China and India. Prices have since climbed further as indications of winter demand started to emerge towards the end of the quarter with JKM November trading around $14 to $15 an M. This is in stark contrast to Henry Hub prices, which averaged $2.55 an M during the quarter as inventories held above the 5-year average. These price levels continue to support the attractiveness of U.S. LNG globally. Unfortunately, threats of further disruptions in global gas markets remain ongoing, exposing key risks to an increasingly susceptible market that already lost 12 Bs a day of Russian last year. Furthermore, the recent lease at the Baltic Connector add to market apprehension highlighting the critical need for the development of sufficient capacity globally in order to meet elastic demand and ensure the security of supply globally for the long term. Let's address the regional dynamics on the next page. During the third quarter and for the first time in 2 years, Europe's LNG imports were lower year-over-year. Imports were near 7% or 1.8 million tons lower in the third quarter due largely to the same fundamental reasons we discussed previously, including high storage levels, reduced gas use across sectors due to price elasticity as well as conservation efforts, plus increased renewables generation. EU gas storage levels continue to grow nearing full as of early October, while lower economic activity put downward pressure on both industrial demand and electricity generation. Demand for gas fired power dropped by nearly 20% in Europe's key markets amid renewable power generation, which was 12% higher year-on-year. As a result, the reduced gas storage fill requirements coupled with the lower gas demand year-on-year, more than compensated for the further reduction in Russian pipe supply and the extended maintenance in Norway, allowing Asia to reenter the market and pull some additional LNG cargoes from the Atlantic Basin, as shown in the upper middle and right charts. However, the cross base on price spreads throughout the quarter were not wide enough to drive meaningful volume away from Europe towards Asia. Total LNG imports in Asia grew over 4% or 2.7 million tons year-on-year in the third quarter, driven by a rebound in imports to China and India as prices softened and high summer temperatures boosted spot purchases. However, lower imports across the JKT market largely offset the significant gains seen in China and other emerging Asian markets, as shown in the lower left chart. In fact, imports into the key growth markets of China and India were 21% and 27% higher in Q3, respectively. In China, gas demand picked up during the quarter, primarily due to the year-on-year recovery in gas-fired power generation, following a drought that reduced hydro generation. Despite the higher demand, gas demand recovery in the industrial sector remains subdued, with consumption still below 2021 levels. Long-term fundamentals remain bullish for the Chinese market due to favorable policy targets and a massive gas infrastructure build-out as we described in previous calls. This year alone, China has added 9 million tons of regas capacity across three new terminals, bringing the total to 110 MTPA with another 95 MTPA under construction. Similarly, the country continues to expand its gas-fired power generation fleet with 46 gigawatts currently under construction on top of the existing 121 gigawatts. In India, it prolonged the heat wave and below average rainfall during the annual monsoon season increased the region's call in LNG. India reported 6 million tons in the third quarter. 1.3 million tons higher year-on-year as spot LNG prices moderated, incentivizing downstream gas use in the fertilizer and power sectors. Gas-fired generation was up 48% year-on-year in July and August, leading domestic players to issue tenders for cargoes to feed power demand. Furthermore, the new 6.5 MTPA Dhamra LNG terminal, the first in India East Coast ramped up to import 10 cargoes since starting commercial operations in May, ending to total imports in the quarter. The terminal which raised the country's regas capacity to 44 MTPA should enhance gas availability in Northeastern India, as connections to the grid improved, making gas more accessible to city gas distributors as well as refineries and fertilizer facilities. India's regas capacity is expected to reach 63 million tons, and that, along with the additional 11,000 kilometers of pipelines under development could make the country a top 3 LNG importer before 2040. In contrast, JKT imports dropped 11% or 3.7 million tons during the quarter, following previous declines and offsetting much of the gains in Asia. Year-to-date, JKT imports are 7.5 million tons lower versus last year, due largely to increased nuclear availability in Japan and Korea. Structural factor we have discussed previously. Japan's nuclear availability reached its highest level since the Fukushima disaster, and we expect this to present headwinds for gas power generation and LNG demand growth going forward. Accordingly, Japan's long-term gas demand is expected to decline gradually through 2040. Let's now elaborate on our updated expectations for long-term supply and demand on the next slide. As noted previously, the energy trilemma, especially with the market's heightened focus on long-term energy security has led to significant long-term LNG contracting in the past 18 or so months. These contracts signal the need for further investment in liquefaction capacity and serve to underpin some of the recent project FIDs. As a result, we now see a significant amount of new capacity currently under construction. While this is expected to help reverse the systemic market tightening that has resulted from the curtailment of Russian volumes over the last 2 years, we believe that further LNG supply is needed to fully meet demand in 2028 and beyond which we expect to be fulfilled with some of the proposed pre-FID export projects, of course, including our own expansion plans at Sabine Pass and Corpus Christi. The concentration of FID is taking place this year next along with the start of delayed projects in East and West Africa, should help make LNG more accessible to price-sensitive markets while also making the industry more resilient in the fact base of supply disruptions or major geopolitical upsets, such as those threatening the market balances today. And just as liquefaction development has been active this year, the same is true for the regas side of the business. Market players continue to develop import capacity across Europe and Asia which in total is expected to increase by 50% by 2030. We continue to forecast healthy demand for LNG over the coming decades with Europe sustaining its growth through the midterm and Asia driving future growth over the long term. As we've discussed before, we expect South and Southeast Asia as well as China to drive future demand growth as LNG plays a critical role in the economic prosperity, energy availability and decarbonization efforts in these regions. Overall, we estimate that by 2040, more than 130 MTPA of additional supplies needed beyond what is under construction today, which is due in part to the decline in production from legacy projects where feedstock availability and upstream developments appear limited going forward. For all these reasons, we believe overall market conditions remain constructive for Gulf Coast LNG and at Cheniere, we remain resolute in building on the commercial successes of recent years to support our capacity growth. In 2023 alone, we have signed almost 6 million tonnes per annum with customers across Europe and Asia including today's announcement of our second 20-year SBA with Foran. This contract could very well extend into the second half of this century. Further evidencing our customers and the market's conviction in the long-term role of natural gas in the global energy mix and the need for further development of LNG capacity globally. With that, I'll turn the call over to

Thanks, Anatol, and good morning, everyone. I'm pleased to be here today to review our third quarter 2023 results and key financial accomplishments, which are the result of our team's commitment to operational excellence and financial discipline, the long-term outlook as we continue to deliver upon our stated objectives of supplying the world with much needed LNG, while creating long-term value for our stakeholders. Turn to Slide 12. For the third quarter, we generated net income of approximately $1.7 billion, consolidated adjusted EBITDA of approximately $1.7 billion and distributable cash flow of approximately $1.2 billion. Our third quarter results continue to reflect a higher proportion of our LNG being sold under long-term contracts with less volumes being sold into short-term markets as well as the further moderation of international gas prices relative to last year. Once again, these impacts were partially offset by certain portfolio optimization activities, upstream and downstream of our facilities. During the third quarter, we recognized an income 555 TBtu of physical LNG, including 545 TBtu from our projects and 10 TBtu sourced from third parties. Approximately 89% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements with initial terms greater than 10 years. As a reminder, our reported net income is impacted by the unrealized noncash derivative impacts to our revenue and cost of sales line items, which are primarily related to the mismatch of accounting methodology for the purchase of natural gas and the corresponding sale of LNG under our long-term IPM agreements. The decline in international gas price curves quarter-over-quarter led to a lower mark-to-market valuation of the future liabilities associated with these agreements, increasing our net income. With today's results, we have earned cumulative net income of approximately $12.4 billion for the trailing 12 months and have now reported positive net income on a quarterly and cumulative trailing 4-quarter basis, four quarters in a row. Throughout the quarter, we continued to deploy capital pursuant to our comprehensive capital allocation plan, our 2020 vision. Increasing shareholder returns, strengthening our balance sheet and investing in accretive growth. During the quarter, we repaid $50 million of long-term indebtedness redeeming a portion of the senior secured notes due in 2024 at SPL. As a reminder, in July, we used the proceeds from our inaugural investment-grade offering at CQP to refinance and redeem $1.4 billion of the SPL 2024 notes. We plan to address the remaining balance of the SPL 2024 notes with cash on hand in 4Q and into the first half of next year, after which point, we will have addressed all maturities in the complex through early 2025 with currently no refinancing needs across our complex until then. Since rolling out our revised capital allocation plan last year, we have received 14 distinct rating upgrades throughout our structure. A result of our operational track record and capital allocation plans to opportunistically delever and efficiently refinance in the short amount of time, which has not only strengthened our balance sheet for through-cycle resilience but has also positioned Cheniere for our next phase of growth. Most recently, S&P upgraded CCH to BBB in mid-October. And in August, Moody's upgraded CEI to Baa3 and CCH to Baa2, while Fitch upgraded SBL to BBB+. With the Moody's upgrade, our parent entity is now investment grade across all three agencies. A major milestone for Cheniere considering where it started financially on this LNG export journey over a decade ago. As we've previously discussed, now that we have achieved investment-grade ratings across our corporate structure we are targeting a 1:1 ratio of deleveraging and share buybacks on an aggregate basis through 2026. During the third quarter, we repurchased approximately 2.2 million shares of common stock for approximately $357 million, which reinforces our intent for the catch-up of buybacks compared to the amount of capital deployed towards deleveraging going forward. We expect to continue to work towards achieving that 1:1 ratio over the next year as we continue to initially target buying back approximately 10% of our market cap over time. We expect to deploy the remaining just under $2.5 billion of the repurchase authorization ahead of the 3-year plan, but recognize there may be variability quarter-to-quarter as we aim to be opportunistic and are subject to the parameters of our 10b5-1 program. For the third quarter, we followed through earlier this week by announcing an increase of our quarterly dividend by 10% to $0.435 per common share or $1.74 annualized, which is consistent with our 2020 plan of growing our dividend by approximately 10% annually into the mid-2020s through the construction of Stage 3. We intend to steadily increase our payout ratio over time while maintaining financial flexibility with a balanced capital allocation plan and the ability to fund brownfield growth with internally generated cash flow. And for the final pillar of our comprehensive capital allocation plan, disciplined growth. We funded approximately $312 million of CapEx at our Stage 3 project during the quarter, with cash on hand. We still have over $3 billion available on our CCH term loan that we plan to utilize beginning in the second half of 2024 as the project progresses and the total capital spent to date continues to grow. By primarily funding the 50% equity component of the project ahead of the drawing down on the construction loan, we have saved considerably on interest expense while retaining all of our liquidity flexibility for the coming years to complete funding of the full project by 2026. Turning now to Slide 13, where I'll provide additional detail around 2023 guidance and our open capacity for 2024. Today, we are reconfirming our full year 2023 guidance ranges of $83 billion to $8 billion in consolidated adjusted EBITDA and $5.8 billion to $6.3 billion in distributable cash flow. But as Jack noted, we are tracking to the high end of those ranges. The improved outlook is driven by portfolio optimization activities, primarily in gas procurement and vessel subchartering and, to a lesser extent, the timing of some expenses moving to 2024 and higher marketing margins on the minimal and the open capacity for CMI, we still had available to sales since the last call. With respect to our EBITDA sensitivity for the remainder of the year, we now have an immaterial amount of unsold LNG remaining. So we're confident in our ability to deliver financial results at the high end of the ranges. As always, our results could be impacted by the timing of certain cargoes around year-end as well as incremental margin from further optimization, upstream and downstream of our facilities. Our distributable cash flow for 2023 could also be affected by any changes in the tax code under the IRA. However, the guidance provided today is based on the current IRA tax law guidance. in which we would not qualify for the minimum corporate tax of 15% this year. However, as noted previously, both of these dynamics would mainly affect timing and not materially impact our cumulative cash flow generation through the mid-2020s as we think about our overall capital allocation plan and our 2020 vision goals. Looking ahead to next year, 2024 will be our most contracted year-to-date as all of the contracts underpinning the initial nine train platform will have commenced as well as some bridging volumes for contracts tied to our growth. Additionally, our team continues to put away the few remaining uncontracted volumes, leaving us with approximately 50 TBtu unsold for the full year as of today's call or about 2% of our 2024 production capacity. The open volume is based upon a production forecast of approximately 45 million tons, which is similar to our production this year and takes into account planned maintenance activities for the year. With such minimal open exposure to the market, 2024 is expected to look to most like a 9 train run rate year as any we will have. with results that should largely reflect the economics of a long-term fixed fee, take-or-pay style cash flow business model. With that said, currently forecast that a $1 change in market margin would impact EBITDA by approximately $50 million for the full year, with market margins currently elevated through the next year compared to our run rate CMI assumption of $2.25 per MMBtu. We should be able to still beat the midpoint of our 9 train run rate of $5.5 billion of EBITDA and before any further volatility in commodity prices. 2024 results are expected to come down from this year as our open capacity narrows until Stage 3 starts ramping up our operational capacity again in 2025. Thanks to our cash flow visibility, 2024 was always assumed to be a heavily contracted year and consistently baked into our financial plans, including in our 2020 vision to generate over $20 billion of available cash through 2026 provided back in September 2022. As Jack noted, given the progress made by the Bechtel and Cheniere teams on Stage 3, we remain optimistic and hope to be in commissioning with first LNG from Train 1 by the end of next year, which would provide additional LNG supply to the delicately balanced market Anatol discussed earlier and increased our operational LNG capacity again in 2025. However, as a reminder, commissioning volumes would not impact our revenues or EBITDA for the year and instead show up in our financials as a reduction in our capital costs. With the meaningful progress achieved to date, we expect to invest between $1.5 billion to $2 billion of CapEx towards Stage 3 in 2024, consistent with this year as we still expect to fund another approximately $0.5 billion of equity into the project this quarter. While the last few years have proven Cheniere's ability to respond to market signals and optimize throughout our business, our conviction in our highly contracted business model rooted in longer duration fixed fee cash flows from creditworthy counterparties has only been reinforced as we look forward to internally funding further growth as well as even more meaningful shareholder returns that can be relied on over time. These dependable cash flows form the foundation of the $40 billion natural gas infrastructure platform we have developed over the last decade plus. We remain focused on maintaining reliable and safe operations to ensure we can continue delivering affordable LNG as well as meaningful long-term value to our stakeholders around the world for decades to come. That concludes our prepared remarks. Thank you for your time and your interest in Cheniere. Operator, we are ready to open the line to questions.

[Operator Instructions]. We'll take our first question from Michael Blum with Wells Fargo.

Thanks. First question, I just wanted to make sure I understood. This quarter, you had a pretty big variance in volume at Sabine and at the CTP level. Just wanted to confirm that, that was really just a maintenance taking the facility offline? Or is there anything else to flag over there?

This is

Okay. Got it. That makes sense. And then on the Sabine Pass expansion, obviously, BioMath roughly, I don't know, 30% contracted on the total size of the project, but you're almost that contracted on the first train. So my question is, would you consider going ahead with FID on just one train of the capacity? Are you going to wait until you get some percentage of the total project before you FID the entire project.

No, I think -- Michael, this is Jack. And you're right, it would be old to FID in whatever fashion that made the most financial sense. And if it makes sense to build it in phases, do Train 7 first and then train 8 later, we're going to do it that way. So we're currently working through Bechtel not only on a fixed price for the entire project, but also on implementation and execution. And -- so that's the way we think about it also. But we're going to continue to do it the way we've done it in the past, which is we're going to commercialize the project. We're going to get a fixed price and we're going to work with Bechtel to make sure that there that were locked in with price schedule and budget.

We'll go next to Ben Nolan with Stifle.

I'll put both of my questions into one, if I could. Your -- effectively, with the new contracts, including the two that are here, you're assuming, I suppose, a certain level of economics and cost inflation. And I know,

This is

That makes sense. And just maybe as a follow-up. In your conversations as far with Bechtel the expansions, are you starting to see some stability with respect to price any sort of early indications as to whether or not things are leveling off a bit?

Yes. This is Jack, Ben. And we are -- and I'm glad to say that some of the steel prices in cement and rebar and everything else, structural still have come back down off their highs. So I think it's all moving in the right direction. And I feel really good about the timing of the project, and we have time to wait to see how this all works out before we lock in.

Moving next to Jeremy Tonet with JPMorgan.

Question maybe somewhat more operational or construction development in nature here. But just Curious, if we look back, I guess, in the history of LNG development, both domestically and internationally, there's been just a long list of projects that have been delayed and not come out on time yet Cheniere is not just hitting the time lines of bringing them forward early. Just wondering specifically, if you could help us understand how Cheniere is able to bring these facilities online earlier than expected? And I guess, is there room for more?

Yes. So Jeremy, I mean, that's where our relationship with Bechtel has really paid off. And when we talk about the One Team approach between Cheniere and Bechtel really mean it. we do everything together. We walk the site together. We try to execute on different construction plans to see which one will work better for us, be more efficient, more effective. It really is a win-win between the two companies. And I can't say enough about how appreciative I am of Bechtel for working so collaboratively with us over these -- at least for me, close to the last 8 years. So it's no more or less than that.

Got it. That's helpful. And then maybe just kind of pivoting towards capital allocation a little bit here.

Hey Jeremy, I was expecting that question from you. But basically, yes, we have over $3 billion of cash sitting at CEI specifically. And you should assume over time as we fund Corpus and there's still about $1.2 billion of equity funding to go on stage 3, and obviously, pick up on the buyback, that will trend to $1 billion in a run rate phase once we get really through Stage 3. And in terms of the buyback, you just look at the last 2 quarters and you're starting to see that the buyback deployment is higher than the debt pay down. Just in Q3, it was $300 million higher, 7x as much. And at this point, buybacks for the year are about to eclipse the amount of debt pay down we did mainly earlier this year to get to IG and for everyone to just be tracking the buyback, it will be lumpy, volatile quarter-to-quarter as we try to be opportunistic. But what you can track it to is basically, we have already deployed over $3.5 billion to debt pay down in the updated capital allocation plan and just over $1.5 billion of buybacks so far in the same plan. So there's basically a $2 billion plus catch-up trade that needs to occur really through 2024. So you can imagine we're pretty focused at CEI on funding the Corpus Stage 3 growth as it accelerates and to catch up on the buybacks with that, yes, at least $2 billion to go in the next year or so. In the meantime, we'll focus on Sabine growth, getting ready with all this commercialization that we've done by likely ramping down the variable DPU next year to start being in a position to fund that project once we can FID that in the next few years. And in terms of the Stage 3 expansion upon that for Train 8 and 9 we might fund that debt. There's going to be plenty of equity up there as well with the $20-plus billion of available cash through $26 million.

Got it. Very helpful. That makes sense. And also looking forward to Corpus coming online early some extra marketing margins there, helping out even more. So thank you for all the color, and we'll be talking later to see you at the conference.

We'll go next to John Mackay with Goldman Sachs.

Thank you for the time. why don't we pick up on the CQP variable distribution comments there, I figured that would be a fourth quarter call conversation, but thanks for kind of flagging that. Would just be curious on kind of where you think that needs to go at the CQP level? And then kind of more broadly, where do you want to see the kind of CQP-specific balance sheet go to, to be able to fund the SBL expansion if that moves forward?

Sure. So we'll provide guidance for EBITDA and DCF for CEI on the Q4 call in February, and we'll provide guidance on the DPU for CQP at the same time as we work that through with our partners in Brookfield, Blackstone and the Board there. But basically, CEI is going to be focused on the growth and focused on the catch-up on the buyback in the billions. CQP is going to be focused on a robust distribution and really trending their debt-to-EBITDA metrics closer and closer to 4x or under. Basically, CEI is a consolidated entity and why it's investment grade is because we're already under 4x on a run rate basis with lower margins than today. CQP slightly above. So how we think about it is, basically, if we can retain some of that cash flow over the next couple of years, get the metrics down a bit lower, we're going to give ourselves a lot of flexibility financially to really re-up the leverage when we FID the Sabine expansion, keep at the very least, but probably more than the base distribution going and yes, keep the ratings and everything intact while growing that DPU over time to something closer to over $5. So yes, we're still pretty comprehensive across the board in terms of debt paydown, buybacks and growth. it's just going to be mixed between LNG and CQP.

Right. I appreciate that. Maybe just picking up on one thing we haven't talked about I guess, more recently, just the CCUS potential for some of the expansions. Would just be curious to hear how much you're getting asked by your customer base to kind of include that? I know you've been able to sign a couple of different types of customers without necessarily moving forward on that. But would be curious kind of where broader sentiment sits there.

Yes. Thanks, John. I'll talk about the CCUS capabilities or what we've been doing at Sabine and Corpus. We've spent an enormous amount of time on engineering looking at ways to capture whatever carbon or greenhouse gases we can. We think the IRA bill going from $50 to $85 was a step in the right direction and we continue to look for opportunities to make our operations cleaner and more sustainable, which is a real focal point of myself and the team, and our customers, as you know, quite a few of them are from Western Europe and they're asking us as many questions as you are, and I'll turn it over to Anatol.

Yes. Thanks, Jack. Thanks for the question, John. The customers that engage with us on this front, and obviously, it's a growing percentage. Jack mentioned some of the key European partners that are probably more advanced stages of developing these strategies is it a comprehensive approach, and we partner with them across a number of dimensions. Nothing is prescriptive, but one of the reasons we have these engagements and have the opportunity to proceed is because of all of the things that we are doing to improve our life cycle emissions profile. CCS is part of it as well as all of our programs with producers pipeline shipping companies that measure and ultimately report our emissions. We have the only program to date that issues cargo emissions with every cargo that we've had in place for a little over a year. All those are critical components to these engagements now that it is so prescriptive as to say we will work on X and we will deliver why.

And if you haven't already seen it, it's posted on our website, our CR report went live about 2 months ago.

We'll go next to Jean Sadsbury with Bernstein.

There's been some news articles recently highlighting that the Biden administration is moving extremely slowly on approving non-FTA LNG export permits. Could this become a gating issue for CC 8 and 9 FID? And is there any flexibility that you might have in your portfolio to FID, CC 8 and 9, even if you're waiting for that permit.

I don't think it's going to be a gating issue at all. We're already commercialized the repeat customers 8, 9 are backed by Chevron, Equinor, and Petro China. Yes. So I feel pretty good about where 8, 9 are. I'm also very optimistic. I mean, Chairman, Willie Phillips at FERC, he's been moving things along. I mean he's been acting in a bipartisan manner. We've seen good signs coming out of there recently. I'm hopeful that energy security now is on top of everybody's mind and our allies need more, not less from the U.S.

And I'll just add, basically, we need to get going on construction of Train 8 and 9 at Corpus in 2026 as the first 7 trains complete. And our goal is definitely well ahead of that to get going. In the meantime, with the cash that we have, the flexibility we have in our revolvers and term loans long lead items opportunistically. We'll lock that in, in the coming year or so when possible. So yes, we don't see issues there. We have quite a bit of buffer just with trains 1 through 7 coming online in '25 and '26.

Okay. Great. That's helpful. Sounds like the news reports are a little overstated. And then as a follow-up, my understanding is that most are all of the recent contracts that you signed that are linked to the Sabine Pass expansion can be kept even if you delay the expansion. Which would give you the option to be close to 100% contracted on your volumes exiting Pass expansion. Am I thinking about this correctly as sort of the base case for Cheniere here if you can't ultimately get to the numbers that you want for the Sabine Pass expansion ?

I guess we'll tag team this to some extent. But yes, you're absolutely right in the sense the contracts that we enter into give us tremendous flexibility on where they ultimately wind up and what projects they ultimately support. Now of course, for, we're very proud of the fact that unlike most projects to date, it does not have bridging volumes. It is linked initially to Sabine Train 8, our first contract that supports Train 8. But ultimately, we have full flexibility on where that contract ends up. So you're absolutely right in your assumption of kind of an extreme case that can be the decision to keep the contract if we so choose and not proceed for example.

Yes, that's right. So basically, depending on the timing, yes, we might have to bridge some of these contracts with existing capacity, and we'll have that with our 55-plus million tons when Stage 3 comes online. And in these other scenarios that you just can't see when you're seeing out on the curve, still $5, $6 margins in a few years. Yes, we could be 100% contracted in a downside scenario. But that's not the plan. We're moving forward with the development of both of the sites. And we're going to try to stick to that 90%, give or take, contracted level.

We'll go next to Keith Stanley with Wolfe Research.

On the 2024 volume, so I realize it's only 50 TBtu unsold and you're closer to the run rate EBITDA. Is there any way to think about or quantify if any material amount of next year's production was sold as bridging volumes for Stage 3 or shorter-term contracts that are more linked to what forward curves were at the time or should we think of it as 98% of productions effectively sold at long-term SPA type prices?

I'd say almost, some of the numbers I'd give you is basically this year, we had over 40 million tons of long-term contracts. Next year, once we have full year of some of the contracts that started this year, some step-ups and even the start of a contract with PETRONAS will be over 43 million tons of long-term contracting. I will say with 50 TBtu open, the team has always been proactive. And they've already sold a few cargoes for next year in the -- on a short-term basis, but just a few, but in that $9 to $10 range that you can see on the curve today. So there's a little already embedded in there. And yes, we'll see where we are in February. We'll probably sold a bit more, but this is really our operational coverage to really fulfilling our obligations on 43-plus million tons of long-term contracts.

That's helpful. Second one, just clarifications on Stage 3 with it running ahead of plan. So can you remind us commissioning cargoes are treated as a reduction in the capital cost, but if you get the substantial completion early, those excess volumes should drive higher EBITDA in 2025 and '26? And then relatedly, if we think about a 7 train project, should we expect if the first train comes on 3 to 6 months early, is that pretty even then for the rest of the trains as you see it coming on 3 to 6 months early? Or is it lumpy?

Basically, yes. We'll give you updates as we keep on progressing on each. We have goals for each of the trains. First and foremost is getting Train 1 up and running. And hopefully, the rest are relatively cookie cutter to there, but it will take through '26 really to complete the state, the 7 trains and get them to substantial completion. And you're right, if we get into commissioning, you won't see like you won't see EBITDA in 2024 related to Stage 3. But at the rate we're going, next November's call for production in '25 and open capacity will be a lot more interesting than today.

We'll go next to Craig Shere with TE Brothers.

So what -- how does it look in terms of further potentially upsizing legacy train capacity beyond 5 MTPA and could any concerted effort in that regard work concurrently with your efforts to contract out in FID, your SPL Stage 5 expansion?

Yes. So Craig, this is Jack. So the team is constantly looking at our debottlenecking and maintenance optimization program. So I have a lot of respected faith for this operating group and their ability to continue to surprise us. So it's my expectation that we will get technically get above 5 MTPA per train. But it may take some additional work before we get there. As far as how it connects to the SPL expansion, as

And Craig, just for some numbers that we've talked about before is basically with Stage 3, we'll be a little over 55 million tons. And then with Train data, those are 3 million -- that's 3 million tons, but we'd hope just by adding those trains and some debottlenecking from Stage 3 and even maybe some from Train 1, 2, 3 there, we're going to get to 6 months. And then as we think about some of the efforts that we're doing and the development at Sabine, we're thinking of things like oil reliquefaction of the gas. So that could add incremental capacity as well. So we're pretty focused on the debottlenecking today. We're still at 5 million tons per train and we'll update you when we make more progress there.

And the second question, more for Anatol. Beforehand agreement seems comparatively more vanilla than your prior SPL Stage 5 offtake agreements or related agreements. Would you say that the market is starting to -- with higher interest rates, would worry about cost of capital and execution and large infrastructure projects the progress you've already made on scale Stage 5, your obvious historic execution and worries about peers are starting to make market off-takers look at saving expansion with greater value even without all the bells and whistles of DES or early cargoes and things like that.

Yes, Craig, I will not take offense to your comments on behalf of the origination team. But as we've said in the past, we do expect, as we move forward, that the contractual support will largely rhyme with what we've done in the past. It will be a mix of the complexity in these transactions is, as you guys know, Stage 5 and specially Train 8 is quite far out. So there's nothing that is as valuable in the market today as prompt volumes. You can see that obviously in the curve. And when we're talking about a contract that will start in most likely early next decade and continue for 20 years, there's complexity in that, right? So that is the -- that is the key issue there. But you're absolutely right on the second leg of your complement. As Jack said, 3,000-plus cargoes perfect delivery track record at a time when other facilities in the U.S. globally -- globally, the utilization rate for liquefaction is in the mid-80s. And of course, we don't even count the Libya and the Yemen's in those numbers, right? So our track record and the team's performance is a standout relative to our peers globally, and that is being reflected in our commercial engagements.

We'll go next to Brian Reynolds with UBS.

I'll keep it to one question on that will be our

Sure. So basically, I mean, you can even look at like other revenue where the subchartering revenue comes in. And that goes all over the place quarter-to-quarter, just depending on the dynamics of how much length we have in our shipping portfolio to even sublease out. So these types of things they wouldn't be in our run rate numbers whatsoever. They're not even usually in our guidance until it's locked in because we just can't rely on it. It's another reason why we wait for guidance in February because there is a good amount of variability for in-transit between '23 and '24. Those are the types of things we don't want to count on with the guidance and somehow miss for just a timing reason. So that's why we'll come out with guidance in '24. And you could assume when we give you guidance, maybe on the high end, we're taking advantage of some of the optimization, not just in subchartering out our length on the shipping side and using third-party volumes to deliver some of our DES deals. But upstream of the sites as well. We've been really successful this year, taking advantage of basis differentials in lifting margin and yes, enhancing that lifting margin that we've made at both facilities. So not baked into run rate guidance, and we'll see where we are in February, but usually a tailwind to our guidance quarter-to-quarter.

Great. Makes sense. I'll leave it there. Thanks for the reminder on the CapEx to EBITDA swap for commissioning cargoes. Enjoy the rest of your morning.

At this time, there are no further questions. I will now turn the call back to management for additional or closing remarks.

I just want to thank everybody for their continued support of Cheniere and we'll talk soon.