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Good day, and welcome to the Second Quarter 2025 Cheniere Energy Earnings Call and Webcast. Today's conference is being recorded. At this time, I'd like to turn the conference over to Randy Bhatia, Vice President of Investor Relations. Please go ahead.

Thank you, operator and good morning, everyone. Welcome to Cheniere's Second Quarter 2025 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; and

Thank you, Randy. Good morning, everyone. Thanks for joining us today as we review our results from the second quarter of 2025. Our momentum from the first quarter propelled us forward in the second quarter, which was highlighted by our formal FID on Corpus Christi Midscale Trains 8 & 9 project and our upwardly revised run rate production and financial forecast. Our proven growth strategy is built upon leveraging our significant brownfield platform to deliver highly visible, financially accretive growth projects. And Corpus Christi Midscale Trains 8 & 9 is further execution of that strategy. In addition, our tireless debottlenecking efforts are bearing real fruit as we were able to increase the run rate production capacity of our existing large-scale trains to 5.0 million to 5.2 million tonnes per annum each, economically adding about 1 million tonnes per annum of production on a run rate basis. Our intent is to execute our growth strategy with a phased approach. First, on the regulatory front, we will seek to permit the maximum site capabilities for both Sabine Pass and Corpus Christi. These additional development projects represent an opportunity to further leverage our brownfield platform to over 100 million tonnes per annum. Second, we will execute our strategy in a financially disciplined way, and we currently have line of sight to grow our operating platform by approximately 25% to a total of 75 million tonnes by the early 2030s, and retain optionality for even more brownfield growth beyond this. We are focused on capturing the moment and delivering accretive growth into the next decade. Please turn to Slide 5, where I'll highlight our key results and accomplishments for the second quarter of 2025. In the second quarter, we generated consolidated adjusted EBITDA of approximately $1.4 billion, distributable cash flow of approximately $920 million and net income of approximately $1.6 billion. Today, we are tightening our full year 2025 guidance range to $6.6 billion to $7 billion in consolidated adjusted EBITDA, and raising our guidance range to $4.4 billion to $4.8 billion in distributable cash flow. Given the financial visibility our highly contracted platform provides, we are tracking well to deliver financial results within these upwardly revised ranges. During the second quarter, we successfully completed our large-scale maintenance turnaround on Trains 3 and 4 at Sabine Pass safely and on budget, extending Sabine Pass' record of consecutive man hours worked without a lost time incident to over 13.5 million hours. This was not only the largest turnaround we've ever completed, but also one of the largest turnarounds ever executed in the LNG industry. And I'm exceptionally proud of our team for once again demonstrating Cheniere's safety-first culture and our execution and operations capabilities. To provide some context, the complex turnaround saw Trains 3 and 4 down for a little over 3 weeks. And during that time, over 1,650 contractors were on site, helping complete over 2,550 work orders and over 17,000 tasks, including the repair and replacement of nearly 1,000 valves and the testing of over 3,500 flanges. Mother Nature further contributed to the challenge with some unfavorable weather during that span, but the team once again delivered. In addition to the large maintenance event at Sabine Pass, we also optimized some planned maintenance at Corpus Christi, accelerating and executing a maintenance turnaround in the second quarter that was previously planned for the third quarter. This work was built into our full year forecast, but did further amplify the seasonality of the second quarter by adding to the impact from maintenance activities in terms of both lost production and O&M expense. On the commercial front, I hope you saw this morning, we announced a new 1 million tonne per annum SPA with JERA, one of the largest buyers of LNG in the world, and the first long-term contract we have signed with a Japanese counterparty. We've enjoyed a long and successful commercial relationship with JERA on shorter-term business, and we are excited to expand that relationship with this long-term SPA that extends through 2050. This agreement, along with the Canadian Natural IPM deal signed in second quarter, help provide further certainty on our ability to meet our recently increased run rate growth and financial forecast and support future growth. During the quarter, we continue to execute on our comprehensive capital allocation plan and provided an update in late June in conjunction with the FID of Midscale Trains 8 & 9, where we now forecast to generate over $25 billion of available cash through 2030 to reach over $25 per share in run rate DCF. During the second quarter, we deployed another approximately $1.3 billion towards our capital allocation priorities. We funded nearly $900 million in growth CapEx, mainly on Stage 3 and Midscale 8 & 9, paid our quarterly dividend and repurchased approximately 1.4 million shares for over $300 million.

Thanks, Jack, and good morning, everyone. Please turn to Slide 8. Throughout the second quarter, the LNG market continued to navigate global uncertainty and persistent volatility driven by various trade policy issues, rhetoric and geopolitical tensions. Conflicts in the Middle East contributed to gas prices rising in Europe and Asia near the end of the quarter, renewing concerns around infrastructure damage, flow disruptions and security of supply. While these initial concerns have fortunately proved overstated with prices quickly moderating, these events and the subsequent market reaction serve as a reminder of the delicately balanced LNG market today as well as the critical role of destination flexible LNG in addressing regional shortages and maintaining global energy balances. During the quarter, these conditions continue to support elevated prices with JKM and TTF each strengthening relative to last year as a result of tighter supply conditions in Europe, lower storage levels and extended periods of low renewable output, all amidst the backdrop of increased geopolitical tension, putting LNG flows at risk for disruption. Monthly price settlements during the second quarter averaged $12.53 an MM for JKM and $11.70 for TTF, 31% and 22% higher year-on-year, respectively. However, prices during the second quarter moderated from the first, reflecting not only seasonal changes marking the start of the shoulder season, of course, but also increased confidence in near-term LNG supply growth. For the first half of 2025, global LNG imports reached record levels despite the aforementioned market uncertainty. And looking ahead, we anticipate the forecast increase in global LNG demand to be efficiently met by growth in global liquefaction capacity with about 88 million tonnes of liquefaction capacity projected to come online in 2025 and '26. North American LNG exports, in particular, continue to ramp up as our Stage 3 project comes online alongside other LNG projects in Canada and along the Gulf Coast. In addition to helping meet growing global gas demand, we expect this new liquefaction capacity will support improved availability and affordability of gas supply globally, while helping to alleviate the impact of reductions in Russian gas flows to Europe and gradually moderating the current multiyear cycle of tight balances. We expect a significant portion of these near-term increases in global liquefaction capacity to come from the U.S., which highlights the importance of U.S. LNG and maintaining global gas balances and its role in mitigating the impact of legacy resource depletion and project development delays elsewhere. Let's turn to the next page to address regional dynamics in more detail. Europe's LNG requirements in the first half of '25 significantly outpaced 2024 levels amid colder weather, the cessation of Russian pipeline gas flows via Ukraine, and lower renewables output in the first quarter, driving injection demand in the second quarter. Europe's total LNG imports in the first half of 2025 increased 25% year- on-year or 13.2 million tonnes as availability of supply, especially from the U.S., coupled with the lack of competition for cargoes from Asia helped gas prices moderate towards the end of the quarter despite heightened risk of supply disruptions. This increase in European imports year-on-year was driven by the continent's need to replenish storage levels, coupled with an increase in gas-fired power generation demand. In contrast to near record high European underground storage levels reached in the second quarter of 2024, European inventories dropped to comparatively low levels in the second quarter of this year. While the inventory level has improved recently, thanks to the steady stream of U.S. LNG imports, it remains at a 20 Bcm or 700 Bcf deficit compared to last year. To put that deficit into context, it's equivalent to approximately 200 LNG cargoes. We believe Europe's call on LNG and specifically on U.S. cargoes will remain high, especially if the EU's recent legislative proposal to ban gas imports from Russia by as early as 2026 is passed. By contrast, Asian LNG imports declined 7% or 9.5 million tonnes year-on-year in the first half. Almost all of this decline came from China, where total gas demand remained flat year-on-year for the first 5 months of 2025, while domestic production and pipeline imports increased broadly in line with last year's growth. This softened LNG demand during the period was driven by a combination of macroeconomic headwinds, warmer weather, robust growth in renewable power generation, all amid relatively high gas and spot LNG prices with the elevated spot pricing incentivizing the diversion of destination flexible LNG cargoes to higher-value markets, such as those in Europe. Much akin to 2022, we're witnessing the impact of China utilizing flexibility in its supply portfolio as a significant balancing force in the global LNG market. As China represents about 1/4 or more of Asia's total LNG imports, we continue to monitor how these trends develop throughout the balance of the year. Meanwhile, LNG imports into the JKT region increased by approximately 2% as Korea and Taiwan supported demand. LNG imports in Taiwan increased by 15% in the second quarter as the country decommissioned its last nuclear reactor in May and continues to steadily phase out coal-fired power generation, driving further demand for LNG. LNG imports into South and Southeast Asia declined by 5.4% year-on-year in the first half of 2025, driven in large part by elevated pricing combined with relatively moderate early summer weather in contrast to '24 when severe and protracted heat waves across the region drove a surge in imports. Despite the seasonal variability, South and Southeast Asia remain a key LNG market, roughly equivalent to China in terms of LNG market size and remains a key pillar of future LNG demand growth in Asia. We expect the recent softness in Asian LNG demand to prove transitory and moderate as key fundamental demand drivers improve and additional liquefaction capacity comes online, which will aid in rebalancing the global gas market and support a more stable and affordable pricing environment over the long term. Looking ahead, we continue to expect Asia to underpin long-term LNG market growth, which we will discuss further on the next slide. Let's move to the next slide. The long-term outlook for LNG demand across Asia remains robust. Asia continues to be the growth engine for all energy sources as the region is expected to account for over 60% of primary energy demand growth globally through 2050 according to the IEA. In fact, Asia is expected to represent nearly 90% of worldwide growth in LNG demand through 2040 as its primary energy needs expand to meet fast-growing economies, rapid urbanization, declining domestic gas production and increased power demand. These expectations are clearly shared by key gas market participants in the region as they demonstrate increased commitments to long-term gas use through further investment in new natural gas infrastructure, including additional LNG import capacity as well as new multi-decade LNG supply contracts. The region continues to invest in regas capacity with about 280 million tonnes per annum of regas capacity proposed or currently under construction across Asia. This is on top of approximately 115 million tonnes per annum of regasification capacity that has entered service since the end of 2020. This increased investment in LNG import infrastructure not only signals expectations of further gas demand growth ahead, but also underscores the criticality of diversification, flexibility and security of supply for the growing economies in the region. Similarly, LNG contracting activity among Asian counterparties has ramped up significantly in recent years, averaging over 28 million tonnes of long-term LNG contracts executed per annum from '21 through 2025, more than double the annual average from 2016 through 2020. Within this surge of contracting activity, long-term contracts with U.S. projects represent approximately 1/4 of these contracted Asian volumes from '21 through '25, 5x that of the trailing 5 years, reflecting the growing importance of U.S. LNG in meeting rising global gas demand. As Jack already highlighted, we announced our first long-term contract with a Japanese counterparty earlier this morning. We look forward to building upon our long-time successful commercial relationship with JERA, one of the largest end-use buyers of LNG globally, further supporting its energy portfolio needs with our destination flexible, reliable LNG supply for decades to come. This new SPA marks our 10th contract signed with an Asian counterparty since 2021 as Cheniere represents over 9 million tonnes of the aggregate long-term contracted volumes signed with Asian counterparties from 2021 through 2025. While there is no doubt that the projected growth in LNG demand over the next several decades will be largely driven by growth in the Asia region, we continue to prioritize diversity within our long-term commercial portfolio, having signed agreements across a variety of counterparty and contract types from various geographic regions, which underscores the value of both our tailored solutions, which help companies and countries around the world meet their long-term energy needs as well as the resiliency of our long-term contracted book. 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 second quarter 2025 results and key financial accomplishments and to discuss our increased and tightened financial guidance ranges for 2025. Turning to Slide 12. For the second quarter 2025, we generated net income of approximately $1.6 billion, consolidated adjusted EBITDA of approximately $1.4 billion and distributable cash flow of approximately $920 million. Compared to the second quarter of 2024, our 2025 results reflect higher total margins as a result of the higher gas prices and optimization downstream of our facilities with third-party cargoes that freed up incremental SPL and CCL sourced cargoes for CMI to sell in the spot market opportunistically. This increase was partially offset by higher operating expenses due to a full quarter of operations of Stage 3 Train 1 and ADCC, the planned major maintenance turnaround at Sabine Pass and the accelerated maintenance at Corpus Christi previously forecast for 3Q. The successful planned maintenance activities across both of our sites during the second quarter resulted in a combined impact to LNG production, which was in line with our forecast, along with the expectation of lower seasonal production in the warmer months of Q2 and Q3, making Q2 what we expect to be our lowest production quarter of 2025. We have generated approximately $3.3 billion of consolidated adjusted EBITDA and approximately $2.2 billion of distributable cash flow in the first half of 2025, supporting our confidence in our updated forecast for the remainder of the year, which I'll address further on the next slide. During the second quarter, we recognized in income 558 TBtu of physical LNG, which included 550 TBtu from our projects and 8 TBtu sourced from third parties, respectively. The 550 TBtu exported from our projects was about 10% lower compared to the first quarter and in line with 2Q 2024, owing to the seasonal impact we see on production and of course, the impact from planned maintenance activities in 2Q. Approximately 95% of our LNG volumes recognized were sold in relation to term SPA or IPM agreements. Our strong financial results year-to-date enabled our team to deploy another approximately $1.3 billion towards shareholder returns, balance sheet management and disciplined accretive growth during the second quarter. We have now deployed over $16 billion of our initial target of $20 billion through 2026. As we continue to reduce our share count and enhance our capital returns, while retaining the financial strength and flexibility to self- fund accretive growth across our platform as demonstrated by how we have equity funded Stage 3 to date and took FID on Midscale 8 & 9 without needing to raise any additional financings. This accelerated progress on our capital allocation plan prompted us to update our long-term company forecast, increasing and extending our capital allocation targets. In June, in combination with the positive FID of the Midscale Trains 8 & 9 project, we announced that we expect to deploy over $25 billion of available cash towards the key pillars of our capital allocation framework through 2030. During this enhanced plan, we now expect to reach over $25 per share of run rate distributable cash flow by the early 2030s with room for upside from further capital allocation. The successful debottlenecking of an additional 1 million tonnes of liquefaction capacity from our original 9 Trains, along with our improved outlook for long-term LNG margins enabled us to upwardly revise our run rate guidance ranges as well. With the FID of Midscale 8 & 9 and Debottlenecking, we now expect to achieve run rate consolidated adjusted EBITDA of $7.3 billion to $8 billion at CMI margins of only $2.50 to $3, despite projected margins well above that range throughout the curve in the coming years. During the second quarter, we repurchased approximately 1.4 million shares for approximately $306 million. As you can see in our 10-Q today, we were highly opportunistic in April around so-called Liberation Day as we repurchased over $200 million in the month despite the stock recovering quickly. With now less than 220 million shares outstanding as of last week, we are making meaningful and value-accretive progress towards our initial target of 200 million shares outstanding. With the FID of Midscale 8 & 9 as well as our increased run rate forecast now included in the framework that governs our repurchases, you can see from the share count on the 10-Q cover that the plan has been relatively active, opportunistically buying approximately $400 million in shares since the start of July amidst some of the recent volatility. This leaves less than $3 billion remaining on our current buyback authorization through 2027 and already over $1 billion deployed in buybacks in the first 7 months of the year. For the second quarter, we declared a dividend of $0.50 per common share. And as part of our June update, we announced plans to increase our third quarter dividend by over 10% to $2.22 per common share annualized. With this planned increase, we will have grown our quarterly dividend by approximately 68% since initiation in the third quarter of 2021. Looking ahead, we remain committed to our guidance of growing our dividend by approximately 10% annually through the end of this decade, targeting a payout ratio of approximately 20% over time, enabling the financial flexibility essential to our comprehensive and balanced long-term capital allocation plan and our disciplined approach to self-funded and accretive growth. In July, we repaid $1 billion of senior secured notes due 2026 at SPL with the net proceeds from the issuance of $1 billion of unsecured notes due 2035 at CQP. Along with cash on hand, extending our maturity profile while further desecuring and desubordinating our balance sheet. Concurrent with that issuance, S&P upgraded CQP's unsecured rating to BBB, reflecting our significant progress on that desubordination. We expect to repay the remaining $500 million of principal on the 2026 notes with cash on hand over the next year, reducing our interest expense, strengthening our investment-grade ratings while continuing to prepare the CQP complex for financing the SPL Expansion Project. Last week, we also refinanced CEI's $1.25 billion revolver, securing liquidity for the next 5 years into 2030. This facility with improved terms is reflective of the long-term support we enjoy from our bank group and our proactive approach to liquidity in conjunction with the over $3 billion still available under the Corpus Christi term loan for Stage 3 and now accessible for Midscale Trains 8 & 9 as well. During the second quarter, we funded approximately $400 million of CapEx on Stage 3, bringing total spend on the project to approximately $5.2 billion unlevered. We also deployed approximately $400 million in the second quarter towards the Midscale Trains 8 & 9 project and Debottlenecking. We continue to deploy tens of millions of dollars of development capital to progress the SPL Expansion and CCL Stage 4 projects. With approximately $2 billion in consolidated cash and ample undrawn revolver and term loan liquidity throughout the Cheniere complex, we are well positioned to fund our growth objectives while retaining great financial flexibility for all of the pillars of our balanced capital allocation program. Turn now to Slide 13, where I will discuss our updated 2025 guidance and outlook for the remainder of the year. Today, we are tightening our full year 2025 EBITDA guidance range from $6.5 billion to $7 billion to $6.6 billion to $7 billion, and raising and tightening our DCF guidance from $4.1 billion to $4.6 billion to $4.4 billion to $4.8 billion. We are reconfirming our guidance range of $3.25 to $3.35 per common unit of distributions from CQP. The $50 million increase to the midpoint of our EBITDA guidance range is largely attributable to further derisking of our production forecast for the year, following the successful completion of our planned maintenance program, further forward selling of our limited remaining open capacity and the completion of Train 2 at Stage 3. Our production forecast of 47 million to 48 million tonnes of LNG in 2025 is unchanged and continues to reflect our existing 9 Trains platform plus our outlook for production from the first three trains at Stage 3 this year. Given the successful start-up of Trains 1 and 2 at Stage 3 and that the CMI team has sold another approximately 1 million tonnes of open volumes for the year since May, we are left with less than 25 TBtu remaining unsold for the balance of 2025. Given this exposure, we forecast that a $1 change in market margin would impact EBITDA by less than $25 million for the full year. Now that 2025 spot capacity has mostly been sold, the team is starting to opportunistically lock in some of our open capacity for 2026. We plan to provide an update on our 2026 production profile and spot capacity on our next call, consistent with our cadence previously and with a better understanding of Stage 3's progress going into 2026. The incremental $200 million increase to the midpoint of our DCF guidance compared to EBITDA largely reflects an improved outlook of our cash tax burden this year under the new tax law passed last month, particularly as it relates to bonus depreciation for this year changing from 60% to 100%, which we expect to benefit the first three midscale trains this year. and is expected to result in nominal cash taxes for 2025. Longer term, we forecast benefits to our cash flows through 2040 due to changes related to both bonus depreciation as well as the foreign export deduction. Today, we have further updated our run rate DCF guidance by $100 million to $200 million to reflect the revised tax rules as we currently estimate an improvement to our effective tax rate on pretax distributable cash flow under the new law from the 15% to 20% range to the 10% to 15% range upon reaching run rate through the 2030s with further near-term benefits from 100% bonus depreciation expected to bring down our effective tax rate for the rest of this decade to under 10% on average as Stage 3 and Midscale 8 & 9 come online. As always, our full year results could be impacted by the timing of certain cargoes around year-end, as well as the timing of incremental trains on Stage 3 reaching substantial completion. While we have tightened the guidance ranges today, this variability and uncertainty necessitates maintaining a range of $400 million for EBITDA and DCF. With the substantial completion of Trains 1 and 2 achieved and the progress Jack highlighted earlier on Trains 3 and 4, we are confident we can achieve our goal of completing the first three trains at Stage 3 this year and deliver financial results within the upwardly revised ranges. Beyond the next few years, our line of sight to growing our platform to approximately 75 million tonnes by early in the next decade and $9 billion of run rate EBITDA with potential for up to 100 million tonnes longer term, only reinforces our conviction in Cheniere's role as not only a leader in the growing global LNG market, but also as a premier contracted infrastructure platform with decades of cash flow visibility and a risk-adjusted return profile that is second to none in this industry. As we embark on this next chapter of growth, we remain committed to creating sustainable long-term value for our stakeholders, while safely operating our platform in order to supply our global customer base with our secure, reliable and flexible LNG 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 for questions.

[Operator Instructions] We'll go first to Spiro Dounis with Citi.

First question, just want to maybe start with commercializing new SPAs from here, and it's a two-part question. So one, seeing a lot of trade deals working out now and LNG seems to be at the center of some of these. And so I'm curious, do you see the pace of SPAs accelerating from here on that backdrop? And then two, there also seems to be a view that SPA liquefaction fees will need to come down to be competitive. I don't believe you're doing that just based on prior comments. And so I'm curious, what is it about the market structure in place now that allows you and a lot of your peers to sign SPAs at what seems to be very different price points?

Spiro, thanks. This is Jack. I'll start, and then I'll turn it over to Anatol. So first off, yes, it makes a huge difference when you go from a pause to where you have an administration that is very, very supportive of LNG in regards to customer conversations. So as you all know, we're the single largest LNG supplier to Europe. We're working very closely with both sides of the pond to make sure that they have certainty of supply from the U.S. And it is nice to have an administration that actually appreciates that we help with trade, we help with energy security, we also help with the energy transition. So we're very, very grateful to have those tailwinds behind us in our conversations with customers. And then I'll see if Anatol has anything to add.

Yes. Thanks, Spiro. Thanks, Jack. We have a decade track record now of performance, and that's not lost on the industry. As we've mentioned in previous discussions and calls, the 20-year [ CET-ed ] FOB product is now roughly 15 years old. It's very competitive. The U.S., as you know, is well underway to have 250 million tonnes of exports, and we just don't compete in that market. We work with long-term partners that value our performance. As Jack mentioned, the government here, EU, many Asian countries really value and appreciate the reliability and the consistent product that we have supplied. And that's really what differentiates us, and we engage with counterparties that value that, and deliver the economics that makes all of these pieces fit together and deliver the superior risk- adjusted returns that

Great. That's helpful color. Second question, just moving to optimization.

Spiro, it's

We'll take our next question from Jeremy Tonet with JPMorgan.

Just wanted to follow up on commercial discussions. Thank you for the color this morning. The EU agreed to energy purchases as part of the tariff negotiations there. I was just wondering how this impacts your conversations, cost or demand at this point. And any interactions this dynamic might have with APAC customer conversations?

Jeremy, in regards to the EU, as you know, we've provided over 2/3 of all of our volumes since 2022 are going to the EU. And we're very close with governments and regulators there on helping them with their needs for whatever duration that they feel is appropriate. Anatol, do you want to?

Yes. Thanks, Jeremy. Kind of following up on the Spiro dynamic. All of this creates an environment where our product with large is appreciated and desired. But in all of these arrangements, whether it's our transaction with JERA, that backdrop helps. JERA's backdrop also includes METI's revised energy plan that shows a growth in electricity demand as opposed to decline. Same dynamics playing out in Europe, and the EU is very quick to point out that while, yes, this agreement has been reached, it is up to the commercial counterparties to come up with the products that will fill those buckets. So as Jack said, we've got a great track record. Our product has been keeping the lights on certainly since the Ukraine war broke out in early '22. And of course, that's not lost on anybody. But ultimately, it is the commercial agreement that is key to us, and that commercial agreement needs to meet our very strict parameters. So all of it is a good backdrop and a very healthy environment and a tailwind to those commercial terms.

And I would say, Jeremy, I'll just parrot what Anatol said previously is that our reliability has been second to none. We haven't missed a foundation customer cargo. And that we're over 4,200 tankers into this journey, and it's being recognized worldwide. We deal with over 45 different countries and regions of the world today. So I think that size and scale is unmatched and appreciated. And I think that's why we're able to negotiate some more favorable transactions.

Got it. And then looking at future growth in general, both at Sabine and Corpus, you've talked a bit about that here. You already have a number of contracts in place and kind of in excess of current capacity. And so a lot of progress there. Just wondering what we should be looking for, for milestones to further commercialize towards reaching FID at this point. How should we be thinking about that?

I mean, first off, we filed with FERC and the federal government for an accelerated permitting process. So when you talk about milestones, seeing how that progresses, I think, will be very, very important. We're working through value engineering as we speak. And then we'll continue to look for ways to commercialize and meet all of our financial objectives.

So Jeremy, it's really all about permitting. As you could see, we FID 8 & 9 and then prefiled the next month for Stage 4. And I believe just in the last day or so, we were accepted into prefiling for Stage 4. So that's progressing well. And we should have more updates, especially going into next year as we have a little bit more clarity on how the FERC process is going and to be in a position to FID something, let's say, late '26 or early '27 at Sabine first, most likely and then Corpus. As you can tell from our filings, we're permitting a lot. We're permitting basically 20 or so million tonnes at each site. You add that all up, we get to over 100 million tonnes, but you're not going to hear from this company that that's the ultimate goal. The ultimate goal is to find these projects that we can meet all of the investment parameters and be truly accretive at the same standard we held every other project to, at the same standard that makes it demonstrably accretive to just buying back the stock and when you all own more of Sabine and Corpus through less shares at LNG. With that said, we see a path to do a phased approach at both where we basically FID initially one train. Those one trains will be as brownfield as they get probably globally. At Sabine, though we are permitting things like an interstate pipeline into Texas, there's a path to do one train there without the interstate pipeline, without a tank or a berth and put it right next to the first six trains. And basically bid out for Stage 4 and the first train at Corpus. Though we're permitting another berth, tank and pipeline, there's likely one train there that could be done without that extra equipment to make it as brownfield as it gets. Commercially, what Anatol and the team are doing, we're already basically covered for at least one train with how many contracts that we have in place. So there will be incremental deals to be done. It's nice to see the CNRL deal done in Q2 and the recent deal with JERA. They align very well with the run rate guidance that we updated to in June with CMI ranges of $2.50 to $3. And from there, the last thing I'd like to say is, as you think about the CapEx outlay that goes into all of this, just to get to 75 million tonnes, basically increase the platform by like over 25%. We have less than $2 billion to go at Stage 3. We have less than $3 billion to go on Midscale 8 & 9 and then Debottlenecking. If you think about the first train at both Sabine and Corpus, that's like 11 million, 12 million tonnes. Let's just say for round numbers, it's around $10 billion. So all in, it's less than $15 billion through 2030 or so, which is over the next 6 years, $2.5 billion a year, and we fund things 50-50. We're not even talking about 1/3 of our run rate distributable cash flow. This shows you the flexibility, the ability to have like meaningful capital allocation, especially on shareholder returns and potentially do more if it aligns with the standards that we hold ourselves to.

[Operator Instructions] We'll go next to Theresa Chen with Barclays.

On the topic of growth, beyond the first phases of Corpus Christi Stage 4 and SPL Stage 5 that brings capacity to 75 mtpa. Can you walk us through the path to get to that next leg, the 100 mtpa? When we think about key inflection points for that long-term growth in addition to permitting, is it primarily a matter of upstream infrastructure bottlenecks to solve in commercialization? How should we view this? And over what time frame could that likely take place?

It's just the standard, the Cheniere standard. What we see today and with the guidance that we gave you in June, we see a path with the deals that we're signing in our, let's say, $2.50 to $3 range, that we can still hit those 6 to 7x CapEx to EBITDA levels for those first trains. As you start adding incremental equipment or incremental pipelines and interstate pipelines for that matter, we're not here today to tell you that we're absolutely 100% FID-ing those projects in the near term. We'll see where SPA levels get to, and we'll see where costs shake out with Bechtel over time. And those two things together ideally will align one day to help us march methodically up to 100 million tonnes. But that's not the game here. Like we're focused on the stock, not just trying to get to 100 million tonnes.

Got it. And I want to go back to Anatol's Slides 9 and 10 on the supply and demand outlook. As this wave of new LNG capacity enters the market over the next few years, increasing liquidity and supply, when would you expect to see more evidence of demand elasticity, consistent with the visible structural need for additional gas from developing countries? And what would you view as key signals to observe in the market on that front?

Yes. Thanks, Theresa. Well, you'll see it kind of on a quarterly basis as all of this infrastructure, which in many cases, is pre- investment for these various business models plays out. We'll see it a little bit before you as tender activity and diversion start to take place, but that's a little harder to observe outside of the day-to-day industry. But you're seeing not only, again, this investment in infrastructure, but also the contractual commitments. And yes, while the contractual commitments are for flexible supply, there is a tremendous amount of, again, infrastructure being developed. The advantage for us and our industry, we were a little over 400 million tonnes last year. As we've discussed, we're about 3% of primary energy. So it does not take a lot of the 150 gigawatts of Chinese gas power generation running at slightly better utilization to absorb tens and tens of millions of tons of additional LNG. So a lot of price elastic markets, and you'll see that play out. We think that now in the kind of very low double digits, high single-digit markets like India will become much more active, but you'll see more and more of that again, unrestricted by infrastructure, which was a constraint in the second LNG supply cycle of 5, 6 years ago.

We'll go next to Burke Sansiviero with Wolfe Research.

Just one for me today. What level of capital costs do you foresee expansions at Sabine and Corpus for the next round of growth? 8 & 9 and the Debottlenecking looks closer to $600 a tonne. One of your peers cited all-in costs closer to $1,100 per tonne. And

Little too soon to say, especially on an earnings call, where we think it will work out by the time we FID a project in late '26 or early '27. What I focus on clearly the most is that 6 to 7x CapEx to EBITDA, working with the E&C team as well as our commercial team to align that to get to the right place. But as you can imagine, like laws of gravity, laws of brownfield growth, when you're only building a train and the rest of the infrastructure and pipeline connectivity and tanks and berths is all set up, it's going to be the cheapest. So we feel confident that it will be closer to the numbers that we're able to achieve so far than to some of those other numbers out there.

We'll take our next question from John Mackay with Goldman Sachs.

I wanted to go to the cash tax savings,

Sure. So there's quite a few moving parts here. But like just for this year alone, as you can see, we raised the midpoint of EBITDA guidance by $50 million, and that's really just following through with what was expected this year. We raised DCF guidance by $250 million. The incremental $200 million is solely related to taxes. Originally, the plan was that these trains would come online this year and receive 60% bonus depreciation, dropping down to 40% bonus depreciation next year. Going forward, including this year, it's 100% bonus. That benefit alone allowed us to reduce taxes this year by $200 million. It will also help reduce taxes next year as the rest of Stage 3 comes online. Mind you with 100% bonus, we won't have much depreciation in 2027. However, based on the 8 & 9 at least guaranteed completion dates that are in 2028, we'll get a big benefit from that as well. So with the 100% bonus, we're talking about comfortably under 10% tax rate on average between 2025 to 2030. Going forward, inclusive of, say, the bonus depreciation benefits, the foreign export deduction that we have by producing a product in America and exporting it to the rest of the world also is quite beneficial. And you can see in at least the run rate guidance that we gave in the back of this earnings presentation, it went up by $100 million to $200 million versus even what we showed everybody in June. So up $1 per share or so. So that clearly is also quite beneficial, that we're able to take advantage of just being an export product. In terms of where the cash would go, more cash on the balance sheet is basically more cash to execute on capital allocation, more wind in our sales to load up the buyback quarter after quarter, keep on funding these projects with a little less leverage to have the balance sheet as strong as possible, et cetera.

That's helpful. I appreciate that. And then just second one for me. You talked about being comfortable with kind of where SPA prices are for the first big trains on each side, but talked about them effectively needing to move higher to maybe to get to that 100 million tonnes eventually. I guess I'd be curious to hear your view on kind of what pushes those SPA prices higher from here? Is it just demand growth? Is it cost overruns at other facilities? What's kind of the moving pieces of that, that we could watch from our side?

Yes. Thanks, John. This is Anatol. We have gone through a number of cycles in SPA pricing just in this last post-Ukraine war build. The ebbs and flows are hard to predict. But as you said, as projects that are, let's say, very aggressive in trying to get to the finish line and that finish line may be determined by validity of the EPC contract or something similar, if that doesn't work out from the start of '22, there's order of magnitude, 50 million tonnes of binding agreements that have yet to reach FID, right? So as those dynamics play out, as the EPC market continues to firm potentially, as the 250 million tonnes of exports are executed one way or another, and you see projects not move forward beyond that, I think you can see another period of firming. And as

We'll take our next question from Alexander Bidwell with Weber Research and Advisory.

Can you talk through some of the OpEx differences between midscale, larger-scale stick built and modular facilities? With some of the newer public comps, we've seen a particularly wide spread when it comes to operating costs with Cheniere sitting on the lower end. We're just trying to get a sense of where the natural differences would be in terms of OpEx and maintenance and how technology and site layout come into play.

I can't speak for the other projects here. But what I can say, it doesn't hurt being a 45 million tonne program going to 55.5 million going to 60-plus million tonnes and the scale that we get from that and the fact that, especially on the first nine trains, they're all the same. What I can get to is we even have nuances quarter-to-quarter. As you can see, this is our lowest LNG producing quarter that we'll have all year because of the major maintenance. But because of the major maintenance, it's also going to be the highest O&M quarter that we have all year. So I think there's more that you'll have to see on an annual basis to appreciate some of these differences. But who knows? We'd like to say that we're exclusively focused on Sabine and Corpus with our 1,700 people, and that's all we do. So maybe that's why our costs are pretty good.

And Alexander, we spent an awful lot of time benchmarking our operations against other worldwide LNG producers. I haven't actually looked at the data from the different technologies, but because we've only had the midscale technology now for a few months, but you bring up a valid question on how they all compare. So more to come. Let us have a little more time, but I can assure you that we are totally focused on being best-in-class in the ConocoPhillips optimized platform.

And then I'd just say, like when we talk about CapEx to EBITDA for these projects, it's everything, contingency, it's the development capital that we put in ahead of the project FID, et cetera. We also show up each and every quarter with that lifting margin as well, which probably varies quite a bit project to project as we're most likely the most interconnected of all the projects in North America.

All right. And if I could just squeeze one more in. We noticed you switched back to the ConocoPhillips technology for some of these future expansions. Can you give a little bit of insight into what drove that decision?

Yes. I think -- this is Jack. So when we switched to midscale, for us, we thought at the time, and now this is way back 2018 -- '17, we thought the market was going to be smaller and shorter term, and it would take longer to commercialize a large train. It didn't work out that way, as you know. And there's just a lot more economies of scale, right? We've learned that in power generation in spades, which is why facilities got bigger, not smaller. And we're learning it here with LNG facilities that it's overall cheaper to build and operate larger trains than it is the smaller facilities. And that's why we pivoted back to trains that we know very, very well.

We'll take our last question from Robert Mosca with Mizuho Securities.

So could you or have you delineated the EPC cost for Trains 8 & 9 on a stand-alone basis? I guess how much of that $2.9 billion is specifically related to Trains 8 & 9?

The vast majority of it is well over $2 billion, but it comes down to what it takes for us to continue to hold to the standard of the 6 to 7x CapEx to EBITDA with a lump sum turnkey contract, get to 10-plus unlevered contracted returns, et cetera. And in a competitive environment and with a lot of folks building projects, it took some of this debottlenecking, which actually needed hundreds of millions of dollars of equipment to unlock those types of returns that are basically second to none around the world. So I'd say 8 & 9 is still a vast majority of it. But for the first time, there was real equipment in the hundreds of millions of dollar range that we're invested in that's incorporated into the construction plan to get the most out of not just 8 & 9, but Trains 1 through 7 of Stage 3.

Got it. That's helpful. And am I interpreting it correctly that OBBB isn't in your DCF outlook provided in June?

It wasn't. And if you look in the appendix, we give you the run rate guidance, and it's up another $100 million to $200 million. Basically, what that shows with now having less than 220 million shares outstanding, at the midpoint, we're already at $20 per share of DCF. So that's why it's moved on to $25 per share as we continue to develop the platform.

Got it. So it seems like that $15 billion excess cash target might even screen conservative when you take into account the remaining FID CapEx, tax savings, Phase 1 expansions, assuming 50% leverage. So how do you think about deploying that excess cash if you come in materially above that $15 billion bogey? And I understand you just issued this 1.5 months ago, but I wanted to get your thoughts there.

Well, I'd say that even in June, we said it was over $15 billion. So we're pretty confident there's a lot of money here to deploy across the platform and into capital allocation. And it goes back to what I said to even get to 75 million tonnes, we're not even talking about using for equity funding 1/3 of our distributable cash flow per year. So what you can see from us is we're growing the dividend by over 10% in the next quarter. We're going to have to, at some point, ask the Board for a reauthorization to upsize the buyback program in the next year or 2 as we continue and it will be even quicker if we go at the pace we just did in July and just more of the same. Ideally, there will be bigger projects that's being Corpus to take care of. But if they're not demonstrably accretive, you're going to see a lot more buybacks, a growing dividend and a pretty pristine balance sheet ready to go for eventually more growth.

That will conclude our question-and-answer session. At this time, I'd like to turn the call back over to our speakers for any additional or closing remarks.

I just want to thank all of you for your continued support of Cheniere. Be safe.