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; Zach Davis, Executive Vice President and CFO; and other members of the Cheniere senior management team. Before we begin, I would like to remind all listeners that our remarks, including answers to your questions, may contain forward-looking statements, and actual results could differ materially from what is described in these statements. Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix of the slide presentation. As part of our discussion of Cheniere's results, today's call may also include selected financial information and results for Cheniere Energy Partners LP, or CQP. We do not intend to cover CQP's results separately from those of Cheniere Energy, Inc. The call agenda is shown on Slide 3. Jack will begin with operating and financial highlights. Anatol will then provide an update on the LNG market, and Zach will review our financial results and 2023 guidance. After prepared remarks, we will open the call for Q&A. I'll now turn the call over to Jack Fusco, Cheniere's President and CEO.

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 they are 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, we had just begun LNG operations, producing our 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, 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. Turning 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 Sales and Purchase Agreement 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 distributable cash flow ranges. The improvement to our outlook is mainly driven by portfolio optimization activities, the timing of some expenses, and to a lesser extent, from higher marketing margins than previously forecasted. Zach will provide more color on the guidance, but we have excellent visibility into the balance for the year and are confident in our ability to finish the year at the high end of the ranges. On the commercial front, Anatol and his team continue to build momentum for the SPL expansion project as we signed a long-term contract with BASF in August. Early volumes under the offtake agreement will begin in 2026, ramping to the full 0.8 million tons with the commercial start of the first train 7 of the SPL expansion project, and extending until 2043. This contract illustrates the rapid evolution of LNG into Europe, as it's a long-term contract executed directly with an industrial consumer in Germany, which only a year ago didn't have a single LNG import terminal. I'm also pleased to share that this morning, we announced our second 20-year agreement with Foran, building upon the Sales and Purchase Agreement we executed with them in late 2021, that commenced earlier this year. Of the almost 6 million tons of long-term offtake executed year-to-date, over 75% of that annual total is contracted with repeat customers who clearly value their long-term partnership with Cheniere. This contract is for approximately 0.9 million tons, extending until 2050 and notably marks the first Sales and Purchase Agreement tied to the second train of the SPL expansion, Train 8, as commercialization on the first train has effectively been completed. We are extremely excited about the market's response to the SPL expansion project and demand for additional capacity from Cheniere. Since announcing the project in February, we have signed nearly 6 million tons per annum of long-term contracts in support of the project and our best-in-class long-term contracted portfolio, all with investment-grade counterparties. I'm confident we have more to do this year. As always, we remain laser-focused on developing that project to meet or exceed our disciplined capital investment parameters to deliver the world-class contracted infrastructure returns that our shareholders are accustomed to. While on the topic of return, Zach and his team continued to progress on our comprehensive 2020 vision capital allocation plan. During the third quarter, we paid down another $50 million of long-term debt. We bought back approximately 2.2 million shares for $357 million, and we increased our quarterly dividend by 10% to $0.435 for the third quarter. On Stage 3, we continue to equity fund that project, investing over $300 million during the quarter, with a total of more than $2.5 billion invested to date. Speaking of Stage 3, now turning to Slide 6, I'm pleased to provide an update on the accelerated progress we are seeing. Since activities on the project moved more heavily into the construction phase a few quarters ago, we've indicated that certain of these construction activities were taking place ahead of plan as we are now over 44% complete overall across engineering, procurement, and construction. While we remain in single digits in terms of percentage completion of construction for the overall project, it's becoming increasingly clear that the project is tracking a month ahead of the guaranteed schedule. I'm optimistic we will be commissioning Train 1 with first LNG production by the end of 2024 and forecast all 7 trains to achieve substantial completion by the end of 2026. We are extremely excited about the progress being made on State Street. We look forward to maintaining our accelerating progress in order to deliver LNG to the market well ahead of schedule, increasing our operating capacity again starting in 2025. On the earnings call in August, I mentioned Stage 3 was beginning to take shape, as the first structural steel was erected in our Train 1 coal boxes that arrived on site. One can certainly appreciate the progress that's been made since then from the photos on this slide. All Train 1 coal boxes have been set in place, structural steel installation is advancing, and piping and electrical installation has commenced. With the excellent progress made to date, headcount of over 1,500 personnel on site each day, and the One Team culture firmly established between Cheniere and Bechtel, I'm confident in the team's ability to maintain focus and continue on the accelerated schedule to deliver Corpus Christi Stage 3 safely and ahead of schedule. With that, I'll hand it over to Anatol to discuss the LNG market. Thank you again for your continued support of Cheniere.

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-2021 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, garnered 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 approximately 48% decline in Norwegian piped gas to Europe in September following extensive maintenance at the brownfield and the gas processing plant. As a result, despite elevated storage inventories throughout the region, volatility persisted as the 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 per MMBtu, while August settled over 25% lower at $8.30 per MMBtu, as Norwegian volumes returned, only to rebound in September, which settled at $11.50 amidst 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 in October above $12 per MMBtu. Meanwhile, JKM prices largely tracked TTF throughout the third quarter, ultimately settling in September slightly below TTF at $11.20. However, more recently, JKM futures settled in 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 per MMBtu. This is in stark contrast to Henry Hub prices, which averaged $2.55 per MMBtu 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 Bcf per day of Russian supply last year. Furthermore, the recent leak at the Baltic Connector adds 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 long-term. Let's address the regional dynamics on the next page. During the third quarter and for the first time in two 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 renewable 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 re-enter the market and pull some additional LNG cargoes from the Atlantic Basin. However, the cost base on price spreads throughout the quarter was 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. 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-over-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. 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, a prolonged heat wave and below-average rainfall during the annual monsoon season increased the region's demand for 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 meet power demand. Furthermore, the new 6.5 MTPA Dhamra LNG terminal, the first on India's East Coast, ramped up to import 10 cargoes since starting commercial operations in May, adding 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 by 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, largely due to increased nuclear availability in Japan and Korea. Structural factors we have discussed previously show 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 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 two 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, including our own expansion plans at Sabine Pass and Corpus Christi. The concentration of FIDs taking place this year, alongside 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 face 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 will be 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 Sales and Purchase Agreement 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 Zach to review our financial results and guidance.

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, and 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. Turning 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 fewer 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 both upstream and downstream of our facilities. During the third quarter, we recognized an income of 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 Sales and Purchase Agreements or Index Price Market agreements with initial terms greater than 10 years. As a reminder, our reported net income is impacted by the unrealized non-cash 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 Index Price Market 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 four-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 Q4 and into the first half of next year, after which we will have addressed all maturities in the complex through early 2025, with currently no refinancing needs 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 deleverage and efficiently refinance, which has not only strengthened our balance sheet but has also positioned Cheniere for our next phase of growth. Most recently, S&P upgraded CCH to BBB in mid-October. 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 catching up on buybacks compared to the amount of capital deployed towards deleveraging going forward. We expect to continue achieving that 1:1 ratio over the next year as we 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 three-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 in 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. 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 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 $8.3 billion to $8.8 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 sub-chartering, and, to a lesser extent, the timing of some expenses moving to 2024 and higher marketing margins on the minimal open capacity 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 most like a nine-train run rate year as 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, we 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 next year compared to our run rate CMI assumption of $2.25 per MMBtu. We should still be able to beat the midpoint of our nine-train run rate of $5.5 billion of EBITDA 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 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 the 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 increase 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.

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 maintenance taking the facility offline? Or is there anything else to flag over there?

This is Zach, and I'd say there's not much to flag there. Basically, the major maintenance on Trains 1 and 2 at Sabine was in June. And with that, the ramp-up then began. It takes time to eventually deliver those volumes. So it reduced the amount of interest going into Q3. And then on top of that, it was a really warm summer. So with the ambient temperatures, we had a little less volume than you'd have with a bit cooler. So regular core was still on track with our forecast.

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? Or 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. You're right, it would be ideal to make the final investment decision in whatever way is most financially beneficial. If it makes sense to construct it in phases, starting with Train 7 and then moving on to Train 8 later, we will proceed that way. We are currently collaborating with Bechtel not only on a fixed price for the whole project but also on its implementation and execution. That's how we approach it. However, we will continue with our established method, which is to commercialize the project, secure a fixed price, and work with Bechtel to ensure we are aligned on price, schedule, and budget.

I have two questions to combine. With the new contracts, including the two we have, you are likely accounting for a certain level of economics and cost inflation. Zach, you've mentioned that you will avoid non-economic decisions, but inflation keeps rising. My question is regarding the arrangements that involve bridging volumes. How does the mechanism operate if inflation increases and you are already committed and selling on volumes? How do you adjust if costs end up being higher than expected?

This is Zach. So I'd basically say anything that's firm, we're assuming is going to be part of the operations of the 9 trains plus Stage 3. So the economics work, we're making the margins that we want to make. And we're being covered for inflation in that, let's say, 15% to 20-plus percent range to the fixed fee over time, which is really attractive in covering what we variance over the last few years. In terms of the rest, those are speed to the FIDs of those projects. We're just going to be disciplined. You've seen that in every FID that we've done. If we can target that around a 7x CapEx to EBITDA, get to 10% unlevered returns, and always hold it up to beating the returns just embedded in buying back more of the stock without the growth, we're going to do that. With inflation and cost of capital going up, that should be embedded in the stock price to an extent. So we'll keep ourselves honest and make sure it's clearly accretive to Cheniere.

That makes sense. And just maybe as a follow-up. In your conversations thus far with Bechtel on 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. I'm glad to report that some of the steel prices for cement, rebar, and structural steel have decreased from their previous highs. I believe this is a positive trend. I'm optimistic about the project timeline, and we have the flexibility to wait and see how things develop before making any commitments.

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 timelines 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, our partnership with Bechtel has really proven to be beneficial. When we refer to the One Team approach between Cheniere and Bechtel, we truly mean it. We collaborate closely, inspecting sites together and testing various construction plans to identify the most efficient and effective strategies. This partnership is mutually beneficial for both companies. I am extremely grateful to Bechtel for their collaborative efforts with us over the past nearly eight years. That's essentially the crux of it.

Got it. That's helpful. And then maybe just kind of pivoting towards capital allocation a little bit here. Zach, if I could. Just wondering current thoughts here, I guess, on the pace of buybacks as you see it as it relates to debt paydown and also financing the Corpus expansion, latest thoughts on how you see that all balancing. It looks like on the balance sheet, there is a mountain of cash that's pretty high. So just wondering what your current thoughts are?

Hey Jeremy, I was expecting that question from you. But basically, yes, we have over $3 billion of cash sitting at CEI specifically. 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 the buyback, that will trend to $1 billion in a run rate phase once we get really through Stage 3. In terms of the buyback, you just look at the last two quarters and you're starting to see that the buyback deployment is higher than the debt paydown. Just in Q3, it was $300 million higher, 7x as much. At this point, buybacks for the year are about to eclipse the amount of debt paydown we did mainly earlier this year to get to investment-grade status. Everyone just be tracking the buyback. It will be lumpy and volatile quarter-to-quarter as we try to be opportunistic. But you can track it to the fact that we've already deployed over $3.5 billion to debt paydown 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. 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. There's going to be plenty of equity up there as well with the $20-plus billion of available cash through 2026.

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 SPL expansion if that moves forward?

Sure. 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, 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 is 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 keep the ratings and everything intact while growing that DPU over time to something closer to over $5.

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. 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, obviously, it's a growing percentage. Jack mentioned some of the key European partners that are probably more advanced stages of developing these strategies as 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. Carbon Capture and Storage 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.

And if you haven't already seen it, it's posted on our website. Our CR report went live about two 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 PetroChina. Yes, so I feel pretty good about where 8, 9 are. I'm also very optimistic. I mean, Chairman Willie Phillips at FERC has been moving things along. He has 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.

I'll just add, basically, we need to get going on the construction of Train 8 and 9 at Corpus in 2026 as the first 7 trains complete. Our goal is definitely to get going well ahead of that. In the meantime, with the cash that we have, the flexibility we have in our revolvers and term loans for 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, if not 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 the 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 that the contracts 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. 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.

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 production is 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 a 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 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. Yes, we'll see where we are in February. We'll probably sell a bit more, but this is really our operational coverage to 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 that 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 seven-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. Hopefully, the rest are relatively cookie cutter from there, but it will take through '26 really to complete the state, the seven trains, and get them to substantial completion. And you're right, if we get into commissioning, 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.

What does it look like in terms of potentially increasing legacy train capacity beyond 5 MTPA? Can any focused efforts in that area coincide with your plans to contract for the final investment decision on your SPL Stage 5 expansion?

Yes. So Craig, this is Jack. The team is constantly looking at our debottlenecking and maintenance optimization program. So I have a lot of respected faith in this operating group and their ability to continue to surprise us. So it's my expectation that we will 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 Zach said, our focus is to get that commercialized to get those costs under control and locked in, and meet our financial objectives and build those trains. While we have a lot of optionality and flexibility, we are 100% focused on construction.

And the second question is more for Anatol. The previous agreement seems to be more straightforward compared to your earlier SPL Stage 5 offtake agreements or similar contracts. Would you say that the market is starting to be concerned about the cost of capital and execution for large infrastructure projects, especially with higher interest rates? The progress you've already made on scaling Stage 5, along with your proven track record and concerns about competitors, seems to be leading market off-takers to consider expansion more valuable, even without the additional features of DES or early cargoes.

I appreciate your comments regarding the origination team. As we've mentioned before, we anticipate that the contractual support moving forward will be similar to what we've experienced in the past. There is a degree of complexity in these transactions, particularly with Stage 5 and Train 8 being quite far in the future. Currently, prompt volumes hold significant value in the market, as reflected in the curve. When discussing a contract likely starting in the early part of the next decade and extending for 20 years, it's clear there are complexities involved. You are correct about our performance, as demonstrated by Jack highlighting our record of over 3,000 successful cargo deliveries during a time when the global utilization rate for liquefaction sits in the mid-80s. Our track record and team performance are noticeably superior compared to our global peers, which is evident in our commercial dealings.

I'll keep it to one question on that will be our Zach, thanks for the clarification on the follow-up on the nine-train run rate guidance and the commentary there. But Cheniere has made a lot of money on optimization on the portfolio, whether it's gas sourcing, regas or shipping. So just kind of curious if you can just update us if this is included in kind of the nine-train run rate guidance? And is there a way to kind of capitalize this number going forward, just given that it seems pretty ratable over the last 24 months? Or should we think about more cargoes going to Asia over the long term, maybe biting into some of that optimization?

Sure. So basically, I mean, you can even look at like other revenue where the sub-chartering revenue comes in. 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. 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 good 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. That’s why we'll come out with guidance in '24. 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 sub-chartering 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 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.

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.

This does conclude today's conference. We thank you for your participation.