Cheniere Energy, Inc. (LNG) Q2 2026 Earnings Call Transcript

Good day, and welcome to the Second Quarter 2026 Cheniere Energy Earnings Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Randy Bhatia. Please go ahead, sir.

Thanks, Operator. Good morning, everyone, and welcome to Cheniere's Second Quarter 2026 Earnings Conference Call. The slide presentation and access to the webcast for today's call are available at cheniere.com. 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, a reconciliation of non-GAAP measures to the most comparable GAAP measure can be found in the presentation appendix. The call agenda is shown on Slide 3. After prepared remarks from Jack, Anatol and Zach, we will open the call for Q&A. I'll now turn the call over to Jack Fusco, Cheniere's Chairman, President and CEO.

Thank you, Randy. Good morning, everyone. Thanks for joining us today as we review our results from the second quarter of 2026 and our further improved outlook for the full year. The LNG market in the second quarter continued to be defined by elevated volatility driven by the war in Iran and the resulting significant constraint on global LNG supply with the effective closure of the Strait of Hormuz. This market disruption is significant, not just for LNG, but for many other commodities and products that benefit the world, which transit the Strait en route to their respective end markets. We are hopeful for a timely and peaceful resolution and continue to pray for the safety of those in harm's way. Without a doubt, this supply disruption has brought to sharp focus the necessity of energy security and diversity of supply amongst LNG buyers. While in the immediate term, buyers have been active in sourcing replacement LNG volumes, procuring alternative fuel sources and implementing demand-side management initiatives, long-term security of supply and building a durable, reliable portfolio have been reinforced as a critical strategic priority, and our reputation as a customer-focused, safe and reliable operator only further distinguish us from competitors. On my recent trips to Washington, I've met with Energy Secretary Wright, National Energy Dominance Council Chair Burgum, and FERC Chairman Swett, among others. Our dialogue with Washington is extremely constructive, which is especially important amidst this volatile commodity market backdrop. We appreciate this administration's broad support for the U.S. LNG industry and its growth. Our regulators and policymakers seek and value input from industry leaders like Cheniere, and they are focused on supporting energy infrastructure projects like ours with a robust yet transparent regulatory and oversight regime so that the U.S. can continue to meaningfully contribute to the energy security priorities of customers and countries around the world. I encourage you all to read the recently published LNG impact study led by Dan Yergin at S&P Global, which highlights the vast benefits and advantages of U.S. LNG, both at home and for our allies abroad. To think that the first LNG cargo from the Lower 48 was exported just 10 years ago from our Sabine Pass facility, and now U.S. LNG is on track to be the second highest value export product from our country and a $1 trillion contribution to our economy is an incredible story, and we at Cheniere are proud to be at the forefront of this industry. Please turn to Slide 5, where I'll highlight our key results and accomplishments for the second quarter of 2026, and introduce our second upwardly revised guidance ranges for the full year. I'm pleased to report that our excellent performance in the first quarter across all facets of our business continued through the second quarter. We generated consolidated adjusted EBITDA of approximately $1.8 billion, distributable cash flow of approximately $1.2 billion and net income of over $3 billion. On the production side, we produced and exported 184 cargoes or 672 TBtu, a 20% increase over the same period last year. Our production and operations continue to outperform our forecast in the second quarter, thanks to the completion and accelerated start-up of additional trains at Stage 3 and enhanced operational reliability during the quarter. Today, we are further increasing our full year 2026 financial guidance to $7.9 billion to $8.4 billion of consolidated adjusted EBITDA and $5.3 billion to $5.8 billion of DCF. This is the second quarter in a row we are upwardly revising guidance. And this quarter, the new low end of the guidance is above the previous high end for both EBITDA and DCF. The primary drivers of the increase are further improvement in our production forecast of approximately 0.5 million tonnes at the midpoint, thanks to improved reliability, realized outperformance and acceleration of new Stage 3 trains, sustained higher marketing margins, both achieved and forecasted for the remainder of the year and contributions from the optimization activities achieved year-to-date, both upstream and downstream of our facilities. Zach will cover guidance in more detail in a few minutes. But we look forward to delivering financial results within these further upwardly revised ranges for the year. During the second quarter, we continued to execute on our comprehensive capital allocation plan. We were able to repurchase another approximately 2.2 million shares for $550 million, as sustained elevated volatility in our shares presented opportunities for our repurchase plan to be active over the quarter. We funded approximately $1.1 billion of growth CapEx with equity and debt and declared a dividend of $0.555. We continue to make excellent and safe progress on our growth and expansions during the second quarter. Our CCL Stage 3 project is now over 98% complete. Substantial completion of Train 6 was achieved in June and commissioning on Train 7 has commenced with first LNG expected imminently. We continue to expect Train 7 substantial completion in the coming months, well ahead of the guaranteed date in 2027, which will officially complete Corpus Christi Stage 3 and further reinforces Cheniere's execution track record for bringing LNG capacity online ahead of schedule and on budget. On our mid-scale Trains 8, 9 and debottlenecking project, we have now safely progressed over 48% complete and continue to track ahead of the schedule across critical work streams. Piling has recently been completed, underground piping and steel installation is progressing well and key materials and equipment packages, including the Train 8 cold box, are arriving at site on or ahead of schedule as we move further into the construction phase of execution. Turn now to Slide 6, where I'll provide some detail on our next growth project, Phase 1 of the Sabine Pass expansion project. During the second quarter, we took another critical step towards our final investment decision on this expansion when we signed a lump sum turnkey engineering procurement construction contract with Bechtel Energy. We look forward to continuing our multi-decade relationship with Bechtel as we execute this project. Bechtel has commenced early engineering and critical equipment procurement under a limited notice to proceed, further locking in the project's cost and derisking the timeline. The EPC contract with Bechtel is approximately $4.7 billion and its scope covers one large-scale train at Sabine Pass, Train 7, a boil-off gas reliquefaction unit and related infrastructure and tie-ins to the existing facility. Baker Hughes will once again supply the gas turbines and compressors. As we have described, Phase 1 is a very brownfield project, efficiently leveraging the site in-place infrastructure and equipment at Sabine Pass to significantly reduce cost and enhance returns. The project does not require support infrastructure, such as additional marine berths, LNG storage tanks or a significant investment in additional natural gas pipelines. Train 7 is a replica of the first 6 trains at Sabine Pass with a design capacity of approximately 5 million tonnes per annum. The contract also includes the addition of a boil-off gas or BOG reliquefaction unit to debottleneck the large trains and will add approximately 1 million tonnes per annum of capacity across Sabine Pass. In addition to the EPC contract with Bechtel as part of Phase 1, we also awarded Baker Hughes a multiyear services contract covering fleet-wide gas turbine upgrades across all of Sabine Pass in order to enhance power output and further increase LNG production across the facility. In total, Phase 1 is expected to add over 6 million tonnes per annum of production capacity to our platform or a total growth of approximately 10%. We've been working hard developing the SPL expansion project, and it's both exciting and rewarding to see the pieces come together. Our disciplined, highly contracted brownfield and returns-focused approach to project development pays off. With the regulatory approvals expected later this year and the financing process already underway, we now have excellent line of sight to an FID on a significant accretive brownfield growth project that meets or exceeds our capital investment parameters, enabling us to continue to deliver the through-cycle risk-adjusted returns our stakeholders have become accustomed to. With over 40 million tonnes per annum in the permitting process to potentially grow our platform to over 100 million tonnes per annum, we have an exceptional opportunity today to support not just tomorrow's global energy balances, but the long-term growth and prosperity of the economies around the world, including ours at home here in the U.S. I'm proud of the critical role we play in the global energy market, and I'm excited for our future as a leading global infrastructure platform. With that, I'll now hand it over to Anatol to discuss the LNG market. Thank you all again for your continued support of Cheniere.

Thanks, Jack, and good morning, everyone. Please turn to Slide 8. As Jack mentioned in his opening remarks, security of supply remains the defining theme for global gas and LNG markets throughout the second quarter. Although the ceasefire announced in mid-June raised cautious optimism that tensions would ease and LNG flows would gradually normalize, recent developments suggest the outlook for sustained de-escalation remains uncertain. Throughout much of the quarter, LNG exports through the Strait of Hormuz remained severely constrained. While the market has proven remarkably resilient, the disruption has reinforced just how dependent global gas and LNG markets remain on reliable sources of supply and how quickly geopolitical events can destabilize and tighten the market. Let me walk through what we've observed during the quarter. Tanker traffic through the Strait of Hormuz recovered only gradually following the mid-June ceasefire. Both crude and LNG tanker movements improved from their lows, but remained materially below pre-conflict levels throughout quarter end. Outbound crude tanker transits recovered to approximately 25% of their pre-conflict average, while LNG tanker transit recovery was under 10%. That divergence reflects the greater operational complexity of restarting LNG supply chains. Unlike crude exports, LNG production requires upstream gas supply, liquefaction facilities, marine logistics and vessel scheduling to all return to normal before exports can fully recover and long-distance cryogenic pipelines are simply not an option. As a result, LNG flows remained significantly more disrupted throughout the quarter. The reduction in Qatar and UAE exports represented approximately 18 million tonnes of lower LNG supply during the quarter. Growth in production elsewhere, including our own Stage 3, largely offset those losses, but overall global LNG exports still declined by approximately 3 million tonnes year-over-year, and this decline is expected to grow over the rest of the year if the conflict persists. The key point is that this was not simply a regional disruption. It represented one of the largest sudden disruptions to internationally traded gas supply in recent years. Additionally, as Asian prices moved to a premium over Europe, U.S. LNG flows shifted decisively east. U.S. exports to Asia reached a quarterly record of approximately 11 million tonnes, while deliveries to Europe declined materially from recent levels. Flexible destination contracts once again allowed Atlantic Basin supply to respond quickly to changing market signals. These developments were also reflected in global benchmark prices. As security of supply became the dominant market priority, both TTF and JKM moved sharply higher following the disruption. While prices moderated after the ceasefire announcement, recent developments have pushed both benchmarks back up to levels last seen in March. By contrast, Henry Hub has remained stable throughout the period. Domestic U.S. gas fundamentals have remained largely unchanged, highlighting that this is fundamentally an international security of supply event and is not constrained by U.S. natural gas. As shown in the lower right chart, that divergence also extends into the forward curve. TTF, JKM and Brent continue to carry a meaningful geopolitical premium relative to pre-conflict levels, while Henry Hub remains anchored by abundant North American gas supply. Regional demand also adjusted. China provided the greatest source of flexibility with imports declining by approximately 3 million tonnes year-over-year during the first half. Its diversified supply portfolio, including domestic production, pipeline imports and fuel switching capability allow China not only to reduce imports, but also to continue to redirect flexible cargoes into higher-value markets. Finally, as has been the case all year, Europe entered the summer with storage materially below last year and the 5-year average, ending the quarter with an approximately 11 bcm storage deficit versus last year, equivalent to roughly 100 cargoes of LNG. That deficit persisted despite record amounts of LNG imports. Much of the incremental LNG received during the first quarter was consumed during the winter rather than injected into storage, while weaker indigenous production and lower pipe imports further limited inventory rebuilding. Injections have also remained below last year's pace since the storage season began. Looking ahead, Europe is likely to begin the coming winter with less inventory than last year. The '25-'26 winter began with storage 82% full and ended this March at 28%, illustrating how quickly that buffer can be consumed. Even if Middle East LNG flows normalize soon, we currently expect Europe to struggle to reach the 80% storage target before the start of winter. Generally, negative seasonal price spreads have reduced the economic incentive to inject and any continued disruption through Hormuz would further reduce that starting position and leave the market more exposed to weather and competing Asian demand. Just as a rule of thumb, each additional month of constrained Hormuz LNG flows could reduce Europe's storage position by approximately 5 percentage points, carrying through from winter starts to winter exit, absent offset elsewhere. Weather remains equally important. In winter, a 1-degree Celsius warmer or colder than normal can move that balance by approximately 10 percentage points. Taken together, these developments highlight two important features of today's LNG market, which has proven considerably more resilient than many expected, but resilience should not be mistaken for surplus. Flexible portfolios, destination optionality and demand-side adjustments have allowed the market to absorb a meaningful supply shock. At the same time, higher prices, Europe's slower storage rebuild and continued geopolitical uncertainty all point to a market that remains precariously balanced. The next slide illustrates how regions drew on different sources of flexibility to build resilience and maintain security of supply through the disruption and what we see as the implications for the industry's longer-term outlook. The first chart highlights how global LNG consumption evolved across the major importing regions during the first half of the year. Despite the loss of Middle East supply, higher spot prices and increased volatility, LNG consumption remained at or near the top of the 5-year range across most major importing regions. Europe imported a record volume of LNG during the first half of the year as it competed to rebuild storage while replacing lost Middle East supply. While the JKT region and South Asia remained within their historical range, Southeast Asia reported its highest first half LNG imports of the past 5 years. The resilient demand across these regions despite the loss of approximately 18 million tonnes of Middle East LNG supply and materially higher spot prices demonstrates the importance of LNG to their energy systems and the limited short-term price sensitivity of many consuming markets. China was the notable exception. First half imports declined 10% to approximately 27 million tonnes, reflecting the broadest set of flexibility options of any major importer. Its diversified supply portfolio, including domestic production, pipeline imports, renewable generation, fuel switching capability and flexible LNG contracts allow China both to reduce imports and redirect cargoes into higher-value markets. As a result, the market largely absorbed the supply shock through Chinese flexibility rather than widespread demand destruction. The mechanisms differ by region. Europe responded through higher LNG imports, albeit slower storage injections, while North Asia relied primarily on fuel switching and storage withdrawals. And Southeast Asia balanced affordability through a combination of fuel switching, procurement timing and selective demand destruction. The middle chart illustrates that investment in new LNG supply continues against the backdrop of recent market volatility. Approximately 77 million tonnes of new LNG capacity reached FID in '25, followed by another 38 million tonnes so far this year. Despite tighter near-term market conditions, the industry continues to advance the next wave of liquefaction capacity needed to meet long-term demand growth. Finally, the chart on the right illustrates how the global supply landscape continues to evolve. Over the past decade, the United States has emerged as the world's largest source of incremental LNG supply. That leadership has been enabled by two structural advantages: an abundant low-cost natural gas resource base and consistent access to deep pools of capital capable of funding large-scale infrastructure. As a result, the global LNG market is becoming both larger and more diversified, with the United States expected to account for approximately 270 million tonnes of operational capacity by 2035, alongside substantial supply from Qatar, Australia and other producers. Importantly, that growth is being delivered through a variety of commercial models serving different customers and projects. Cheniere's strategy has remained consistent throughout that evolution. We continue to have unwavering conviction in our belief that a highly contracted, returns-focused business model provides the best foundation for long-term value creation. That approach has enabled us to build a recognized reputation for reliability, while remaining disciplined in our returns-focused approach to growth. In an increasingly fragmented global energy market, we believe that combination of reliability, commercial flexibility and disciplined execution remains a meaningful competitive advantage—an advantage that also accrues to our long-term customers as we approach cargo number 5,000 with an untarnished track record of cargo deliveries. Recent events have reinforced both the importance of LNG and the resilience of the global market. While geopolitical uncertainty has increased and market conditions remain tight, the industry's response has demonstrated the value of reliable and flexible supply, diversified portfolios and trusted long-term partnerships. Those characteristics have defined Cheniere's strategy from the outset and continue to position us well to support not only our existing long-term partners, but also capture additional long-term opportunities as the market evolves. 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 discuss our financial results and further improved outlook for the full year. Before I begin, I wanted to reinforce that this highly contracted investment-grade LNG infrastructure company has been built for much more than as a trading proxy for prompt LNG prices. While today's results and upwardly revised guidance highlights the financial upside that can present itself by bringing trains on early, debottlenecking and most importantly, operating reliably in the midst of a highly elevated and volatile LNG price environment, we don't see these financial results as one-off going forward once LNG prices stabilize. These forecasted results of $8-plus billion of EBITDA are levels we plan on achieving in run rate as we simply build out the Corpus mid-scale trains and FID SPL Train 7 by early 2027. And that's in an LNG market environment of not over $10 LNG margins, but at a fraction of that in our $2.50 to $3 margin range before any upside. This should highlight the financial resiliency of Cheniere's disciplined business model for the long term that will continue to set us apart as the premier U.S. LNG company or, for that matter, contracted infrastructure company in North America. Please turn to Slide 11. For the second quarter of 2026, we generated consolidated adjusted EBITDA of approximately $1.8 billion and distributable cash flow of approximately $1.2 billion. Compared to 2Q 2025, our second quarter 2026 results reflect higher volumes of LNG delivered due to increased production from new capacity online at Stage 3 and no major planned maintenance outages during the quarter. Our second quarter results were also supported by higher marketing margins achieved and optimization due to continued gas price volatility. During the quarter, we recognized in income 657 TBtu of LNG, which while up quarter-over-quarter due to the in-transit cargo timing dynamic impacting 1Q that we discussed on our last call, 2Q volumes recognized are also partially lower due to several cargoes rerouting from Europe to Asia intra-quarter, pushing delivery into 3Q. During the second quarter, we also generated net income of approximately $3.1 billion, up nearly $1.5 billion from 2Q 2025. The increase is driven primarily by the noncash derivative impact related to our long-term IPM agreements, which are designed to secure long-term natural gas supply to our facilities, while providing stable fixed fee economics for our project infrastructure, similar to the economics of our long-term SPAs. Historically, our net income has experienced significant variability related to these unrealized noncash derivative impacts due to the mismatch of accounting methodology for the purchase of natural gas and the corresponding sale of LNG related to our long-term IPM agreements. Near the end of the second quarter, we designated the normal purchases and normal sales accounting exception for approximately 75% of the volumes related to our IPM agreements after considerations of the evolving U.S. gas market transactions landscape. As a result of this designation, these agreements will no longer be marked to fair value each period, eliminating derivative accounting adjustments for these volumes in future quarters. We expect this election for the volumes that are delivered directly into our sites to result in reduced variability in our net income quarter-to-quarter going forward as there will be less sensitivity to commodity prices related to these designated agreements, which is more reflective of the stable long-term cash flow profile afforded by our highly contracted infrastructure platform. During the second quarter, we deployed almost $900 million of equity cash flow towards our comprehensive pillars of capital allocation, including accretive growth, shareholder returns in the form of buybacks and dividends and balance sheet management. For the first half of the year, our capital deployment of equity cash flow totaled approximately $2.1 billion. And of that, over $1.3 billion was returned to shareholders in the form of buybacks and dividends. For the second quarter, we declared a dividend of $0.555 per common share, bringing total dividend payout to common shareholders in the first half of the year to approximately $230 million, and we remain committed to growing our dividend by at least 10% annually through the end of this decade, with the expectation to seek Board approval for Q3 for our next increase as this recent declaration completes a full year's worth of dividends at this level. In the second quarter, we repurchased approximately 2.2 million shares for $550 million, bringing total buybacks in the first half of the year to approximately $1.1 billion for nearly 5 million shares. As a reminder, each quarter, we allocate capital to our share repurchase plan, which is then opportunistically deployed under our disciplined value-based framework as we work towards crossing over 200 million shares and then to our current target of 175 million shares outstanding later this decade. With the continued volatility in the shares this year, the plan is working as designed and remains an advantaged form of capital return for our shareholders, enabling them to own more of Sabine and Corpus and our run rate cash flows while preserving the financial flexibility essential to our growing infrastructure platform and long-term capital allocation plan. Moving to the balance sheet. In May, we issued $1 billion of 2036 notes and $750 million of 2056 notes at CQP, marking our second 30-year issuance and first ever at CQP, further extending our maturity stack into the second half of this century alongside a growing list of our long-term LNG contracts. The net proceeds were used to opportunistically redeem the $1.5 billion of senior secured notes due 2027 at SPL, further reducing the amount of secured debt on our balance sheet and to fund a portion of the LNTP on Phase 1 of the SPL expansion project. We also amended and restated our Cheniere and CCH credit facilities, extending maturities, improving pricing, enhancing flexibility and preserving $2.75 billion of credit capacity. Our tactical approach to liquidity and balance sheet management continues to afford us flexibility as we pursue further expansions of our existing brownfield platform while remaining opportunistic on our buyback program and preserving our investment-grade ratings across our corporate structure. During the quarter, we funded approximately $1.1 billion of growth capital across our business, as we progress construction of Stage 3 and mid-scale 8 and 9, development of the SPL and CCL expansion projects as well as Gregory Power Plant. Of the $1.1 billion of growth CapEx in the quarter, approximately $200 million was equity funded and approximately $900 million was efficiently debt funded via our delayed draw Corpus Christi term loan as well as a portion of the net proceeds from the CQP bonds issued during the quarter. As Jack noted, in conjunction with the signing of the lump sum turnkey EPC contract with Bechtel Energy for Phase 1 of the SPL expansion project, we issued Bechtel limited notice to proceed with early engineering and procurement, increasing our spend on that project during the quarter ahead of an expected formal FID early next year. Last week, we launched the process to raise a senior secured delayed draw term loan at SPL that, together with the proceeds from our recent CQP bond deals, will fund the 50% debt component for Phase 1, while we fund the other half of the total project cost with equity cash flow by continuing to flex the variable component of the CQP distribution. With the EPC contract signed, the project fully commercialized and the financing process underway, we have significant visibility into the economics of Phase 1 at SPL, and we are confident that this highly brownfield project represents one of the most competitive risk-adjusted return profiles in energy infrastructure today. Looking ahead, we remain well positioned to fund our disciplined growth objectives and comfortably within our cash flow forecast, while retaining our strong investment-grade credit metrics and our significant financial flexibility for shareholder returns through any commodity cycle. Turning now to Slide 12, where I will discuss our upwardly revised 2026 financial guidance and outlook for the year. Today, we are increasing the midpoint of our guidance ranges for full year 2026 consolidated adjusted EBITDA and distributable cash flow by $650 million and $550 million, respectively, bringing an expected consolidated adjusted EBITDA to $7.9 billion to $8.4 billion and distributable cash flow to $5.3 billion to $5.8 billion. We are maintaining our CQP distribution guidance for the year of $3.10 to $3.40 per common unit as we fund the LNTP for the SPL expansion. These increases are primarily driven by an upwardly revised 2026 production forecast from increased utilization and outperformance at both SPL and CCL, and the further accelerated ramp-up of our mid-scale trains as well as capturing higher margins on recent spot sales, along with the higher margin outlook for the remainder of the year. We are tightening our expected full year production range, increasing our forecast from 52 million to 54 million tonnes to 53 million to 54 million tonnes. Contributions from optimization activities, both upstream and downstream of our facilities locked in since our last call also supported our results. With enhanced visibility in our forecast and continued forward selling by our team during the quarter, we continue to forecast less than 1 million tonnes or 50 TBtu of unsold open volumes remaining in 2026. Therefore, we continue to forecast that a $1 change in market margins would impact EBITDA by less than $50 million for the full year. Despite having very little open exposure for the balance of the year, we are maintaining the $500 million guidance ranges as results could still be impacted by a number of factors, particularly given the sustained elevated pricing and volatility in LNG markets, the ramp-up and specific timing of substantial completion of Train 7 at Stage 3, the timing of certain cargoes around year-end, contributions from further optimization activities during the balance of the year, and the impact Henry Hub prices can have on lifting margin. As we progress through the year and further lock in some of these variables, we will look to tighten these ranges as we have done in years past. And on our next call for 3Q, we expect to provide our 2027 production forecast and expected open capacity for next year, our first full year with all of Stage 3 operational. Our strong results year-to-date support today's full year guidance raise, both of which are a testament to the competitive advantages afforded by our world-class infrastructure platform and business model that yields decades of cash flow visibility, thanks to our portfolio of long-term contracts with creditworthy counterparties, but also positions us to respond to market signals and capitalize on optimization opportunities throughout our business. We believe our stable long-duration cash flow profile paired with this upside potential presents through-cycle risk-adjusted value for our shareholders that is unmatched in the market today and is only further supported by our disciplined all-of-the-above capital allocation framework. As we embark on this next chapter of growth at both Sabine and Corpus, 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. Our first question will come from Theresa Chen with Barclays.

As we look ahead to winter, Anatol, your comments paint a stark picture. How do you see LNG demand and trade flows balancing between Asia and Europe, particularly given Europe's relatively low storage levels and inventory deficit? Do you expect increased competition for marginal LNG cargoes? And what implications could that have for global LNG pricing trade patterns? And against this backdrop, could you provide an update on commercial discussions with existing and prospective customers across both regions? How are conversations progressing around incremental LNG offtake? When might we see additional SPAs that could underpin further expansion phases at both Sabine Pass and Corpus Christi?

Theresa, thanks for the three questions in one. First, we honestly don't know. This is a very challenging environment. We're doing everything we can. You heard from the team about our operational excellence and how we're putting as much volume into the market as we can, with trains arriving early. We're supporting customers wherever and whenever possible. But as you point out, it's no secret: Europe is in a very challenging position. It was in the spring and that has only been accentuated by these delays and the continued disruptions. Today, we think it will be tough to get to 70%, much less 80% of inventory, and it will be a challenge, especially as Asia restocks, which has been one of the flexibility levers that has allowed the market to rebalance and China goes into winter. We will do everything we can to support our partners. All of this, even in the fog of war, is a great tailwind for us, as we commented in the prepared remarks: reliability, our ability to work with our partners, find solutions, and use the flexibility in our portfolio of the IPM agreements and the volumes that we have in that bucket that can go and solve short-term BTU shortage issues is all a tailwind. We're very comfortable—we are partially commercialized the Corpus expansion—and we're very comfortable that over the next 12 to 18 months, we will have the kind of mid-single-digit millions of tonnes that are aligned with our commercial objectives to commercially support Phase 1 at Corpus, now that Phase 1 at Sabine is commercialized.

Thank you for that comprehensive answer and bearing with me, Anatol. Just a quick follow-up as a result. Do you think we've reached the limits of China's LNG demand flexibility, particularly with respect to fuel switching? Or do you believe that their imports could decline further from current levels?

I think we're very close. The last few months, China has been at or above last year's levels in terms of imports. As we go into winter, Q2 is clearly a period where the world is much more flexible during the shoulder, and the system will be keenly aware of its inventory levels and will not allow itself, we think, to get into the position that Europe has found itself in. So short answer: yes, I think China is at or near its limit for solving this issue for the world.

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

Just wanted to follow up on some of the market dynamic questions there. I think Anatol, in the past, you might have said that there's a recency bias when it comes to contracting. With LNG prices being higher here, does that influence the tone of conversations as you look to sign up more SPAs?

Thanks, Jeremy. What influences it is much more the importance of reliability and partnership in this period. The headwind, as we've discussed over the last couple of years, is that in aggregate from the start of '25 through today, over 100 million tonnes have been FID-ed and a lot of that volume has not found its way to end users, which is not how we conduct business, but that is how the market is evolving. So you have those two competing forces. The race to the bottom of the standardized 20-year offtake agreement is not a market that we participate in. We participate in the premium market that values our reliability and what we've been able to do for our customers over the last decade plus.

Got it. That makes sense. And then just wanted to turn towards the operational outperformance. With the guidance moving up with improved reliability and being able to produce a bit more, can you speak to some of the drivers of that? Do you think effective capacity for these units is marginally higher than what you thought in the past?

Jeremy, I'm always amazed and pleased with my operating folks because they are finding ways to not only get more production immediately out of the trains, but also to optimize maintenance schedules. Their execution on turnarounds and our preventative maintenance program has been incredible. We feel really good that the work we've done on debottlenecking is paying off. For example, we added new fin fans developed together with Hudson; those fin fans for the same motor amperage provide over 40% more airflow, providing more cooling during this hot summertime. That's providing real benefits, especially at Sabine Pass, and that's what we're seeing. Knock on wood, some of the root cause problems we had last year around the first quarter, we've figured out and fixed, and those seem to be behind us. Everything that we've mentioned, we feel good is repeatable year-over-year.

I would just highlight, Jeremy, as well as we think about the numbers and how we started the year at 51 million to 53 million tonnes of production, and now we're at 53 million to 54 million tonnes, only one-third of that increase is the Stage 3 ramp-up and trains coming on early and getting to full run rate quicker than we originally anticipated. More than two-thirds is all this outperformance that Jack mentioned. It's the resiliency efforts and debottlenecking, but mainly resiliency efforts we've done at both sites that has decreased downtime, decreased defrost periods and decreased maintenance time for the year that we really had to bake in after the experiences we had in 2025. It's paid dividends this year, even adding 0.5 million tonnes added roughly $300 million to the guidance when margins are this high. We're optimistic this will pay dividends not just for this year but going forward on the reliability improvements.

Got it. And Jack, even post the LS sale, it will always be the Jack Fusco Energy Center to us.

Thank you, Jeremy. I was hoping they would change the name of that power plant before now.

We'll now take our next question from Spiro Dounis with Citi.

I want to go back and pick on some of the comments addressed already, starting with the Middle East conflict. It's been months now after that initial conflict began. Could you put a finer point on what's changed in commercial discussions pre- and post-conflict? It sounds like there's a hyperfocus on supply security here. Does that give you room on the margin or price side? And when the dust settles, how are you thinking about the timing for that to translate into longer-term SPAs? Would those contracts start to fill the hopper for trains beyond 75 Mtpa?

Thanks, Spiro. I'll start backwards. Going into the conflict, the world was very uncertain about the timing of a resolution and assumptions were fairly short-term. On the last call, we talked about our key partners in the theater that were affected by this finding solutions through the second quarter. We went through the second quarter with the market disrupted, even for the brief period that volumes were moving out of the market. We will probably exit the third quarter still in this fog of war and uncertainty about the disruption, even if volumes start picking up today. Counterparties have been dealing with this period and figuring out literally how to keep the lights on. We've been positively surprised by how certain markets have actually been more resilient in terms of LNG demand than we would have expected. Moving to the long-term issue, discussions have continued to be very robust. We're very comfortable where we are and the progress we will make in the coming quarters to continue to support Stage 4. We think those discussions are benefiting from how we have performed and the ability of companies to have that diversification and flexibility. In terms of quantity, the question is whether we can get more than single-digit millions of tonnes at our usual $2.50 to $3 range. The issue for now is the competitive landscape where we think on the order of magnitude, 100 million tonnes is trying to find a home. That's the tug of war. We're, at this point, very comfortable that we can get our premium with our key partners, both existing and new ones. Am I comfortable that 20 million tonnes can be done at that level today? I'm less comfortable with that over the 12- to 18-month period than I am with the mid-single digits.

Spiro, I wouldn't discount the fact that later this month we will have sent out our 5,000th cargo. We haven't missed a foundational customer cargo and that reliability, especially during all the volatility we've seen since February 2022 with the Ukraine conflict, has been worth a significant amount to our long-term customers. That reliability helps make Anatol's job a lot easier.

I think that counts for something. Second question, a quick one on nitrogen. It was a bit of an issue late last year. You've been working to address feed gas nitrogen content. Where are you on that process now? With more gas coming out of the Permian with new egress, do you feel prepared to deal with composition going forward?

With nitrogen, we have a couple of tools in our toolkit. One is process oriented: if we subcool the LNG, we can actually liquefy the nitrogen in the process and evacuate it that way. Another is the Gregory Power project where we'll send high-nitrogen gas to the power plant and have it burn and consume it. We've seen the nitrogen stabilize at about 1.5% from the Permian, which has been good, and we've blended it ourselves with some lower-nitrogen gas that we've procured directly from suppliers. We have a lot of different handles we've been using to manage nitrogen, and we have a few more up our sleeve that I won't divulge on this call.

We'll now take our next question from Keith Stanley with Wolfe Research.

You recently got FERC approval to raise the capacity of the mid-scale trains by about 5 MTPA. How are you thinking about the potential to raise those capacities and over what time frame could we think about this getting done?

We've been spending a lot of time since Train 1 figuring out ways to debottleneck the mid-scale trains. It's a mixed refrigerant process with many refrigerant components. Our process engineers have come a long way in figuring out how to effectively mix the refrigerant to get the maximum amount of cooling out of the trains. That's why you're seeing a big step-up in the production of the mid-scale trains. Process-wise, it would happen relatively soon. We have a program where we take it slowly and work with equipment suppliers to make sure we don't exceed any of their limits. I would expect over the next year or so that we should have worked through most of the mid-scale trains.

I'll add that when we FID-ed mid-scale 8 and 9, it included the debottlenecking project. We were going to get two trains out of this, but incrementally more volume out of all of Stage 3 and mid-scale 8 and 9. That's paying dividends and is why we need to tee ourselves up to produce at higher levels. This allows us to bring cost per tonne down on these FIDs and hold to the 7x CapEx to EBITDA at $2.50 to $3 margin levels. We're also planning further debottlenecking projects that could fold in with CCL expansion Phase 1 because delivering incremental volume benefits from being brownfield and having scale helps bring the cost per tonne down, especially in the current inflationary environment. This is all going in the right direction. More to come on that, and we'll see how much we can get out of the mid-scale trains and the large-scale trains as a whole.

Sorry, just to clarify: this is maybe partially incorporated in your run rate production forecast, but not fully. Is that fair?

Yes. If you start going up to the high end of these approvals, that's not baked in whatsoever.

Second question: the guidance uptick is very large at $650 million. Is there any way to think about how much of the upside is tied to higher margins in the back half of the year versus optimization? If a lot of it's optimization, can you give more color on the activities you executed on?

I'll break it out simply. By adding 0.5 million tonnes to the production forecast, which gets you to the new guidance range midpoint of 53.5 million tonnes from the previous midpoint of 53 million tonnes, and multiplying that by $10 to $13 margins, you're talking about roughly $300 million added to the guidance just from the production increase. Then, with less than 1 million tonnes or less than 50 TBtu open as of the last call, opportunistically putting that away helped. In addition, Henry Hub is up a bit since then year-to-date, which added about $200 million. Optimization contributed $100 million to $150 million in upside. So production drove the increase, and optimization and higher gas prices contributed. We're still down to less than 50 TBtu open. There is some exposure to the current market in the forecast, but we are locking in cargoes for this year and working to lock in cargoes for next year. Since the last call, we've added roughly 0.5 million tonnes for next year as margins have been elevated. With such elevated margins, we kept a $500 million range on guidance because there's still potential volatility in ramp timing, cargo timing and market margins.

We'll now take our next question from Jean Ann Salisbury with Bank of America.

I just wanted to make sure I understood Zach's comments about the mark-to-market accounting change for 75% of the IPM volumes. Can you confirm this new change has started with the 2Q net income number? And can you give a sense of how much that could tighten the quarterly net income range in a volatile year such as this year or 2022?

Yes. We made that designation in mid-June, and it is reflected in the Q2 results. With the volatility and spike in prices in Q1 and then moderating in Q2, a lot of that occurred by mid-June and that's why there was a large unrealized gain in net income for Q2. Going forward, this will mitigate things. The market has evolved—there are more long-term gas supply deals in North America that are not just priced off Henry Hub but off global indices. With the prevalence of those, it allowed us to make this exception. For deals delivered directly to our sites at Corpus and Sabine and that are not optimized but passed through into LNG and sold at a global price, that's about six of the eight deals we have—roughly 75%. We ran some numbers: since '21, across 22 quarters, we've had six negative net income quarters because of unrealized derivatives. That would have dropped to two if we could have made this designation earlier. So it definitely mitigates volatility in net income and is much more representative of who we are and the stable fixed fee cash flow that is the base of the business. Less mark-to-market accounting on our derivative and contracted positions going forward should be clear to investors.

We'll now take our last question from Olivia Halferty Foster with Goldman Sachs.

I wanted to ask about the maintenance outlook going forward, particularly given the strong volumes in the quarter. For this year, can you remind us the timing and scope of maintenance activities that were completed to address the feed gas composition quality variances we saw last year? Looking forward, how should we think about the timing for the next major maintenance turnarounds? Is there a possibility that there will be a major maintenance turnaround at Sabine or Corpus in 2027?

We went into the year and made it clear we weren't going to have the same type of major maintenance that we had in '25 at Sabine that took out two trains for over half a month. That alone would allow year-over-year Q2 to Q2 production to be up. We had various planned maintenance items scattered throughout the year to address resiliency efforts, feed gas variability and some additional unplanned downtime from 2025. Those efforts will be taken care of by the end of this month. We usually take care of those types of efforts in Q2 and Q3 besides regular planned maintenance, but nothing at the scale of the major maintenance turnarounds. That's almost behind us for this year and part of why we increased confidence in production guidance. Going forward, next year we'll give more insight on our 2027 production profile on the next call. With nine trains and eventually nine mid-scale trains all up and running, there will always be planned maintenance and almost always major maintenance. The trains are running well and we've been able to optimize major maintenances over time and spread them out further than originally budgeted, which is a tailwind going into '27 and beyond. Next year will be the first year with all of Stage 3 up and running, and we've given guidance that production will be kind of in the mid-50s with Stage 3 operational. Nothing is holding that back, and we'll provide more detail in November.

That concludes our question-and-answer session for today. I'd like to turn the conference back to our presenters for any additional or closing comments.

This is Jack. I just want to say thank you all for your support and for your attention to Cheniere.

That does conclude today's conference. We thank you all for your participation. You may now disconnect.