Cheniere Energy, Inc.LNGNYSE
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Operator: Good day, and welcome to the Cheniere Energy, Inc. Fourth Quarter and Full Year 2025 Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Randy Bhatia. Please go ahead.
Randy Bhatia: Thanks, Operator. Good morning, everyone, and welcome to Cheniere Energy, Inc.'s Fourth Quarter and Full Year 2025 Earnings Conference Call. The slide presentation and access to the webcast of 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, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP financial measure can be found in the appendix of the slide presentation. As part of our discussion of Cheniere Energy, Inc.'s results, today's call may also include selected financial information and results for Cheniere Energy Partners, L.P., or CQP. We do not intend to cover CQP's results separately from those of Cheniere Energy, Inc. The call agenda is shown on Slide 3. Jack A. Fusco, Cheniere Energy, Inc.'s President and CEO, will begin with operating and financial highlights as well as Cheniere Energy, Inc.'s growth outlook. Anatol Feygin, our Chief Commercial Officer, will then provide an update on the LNG market, and Zach Davis, our CFO, will review our financial results, 2026 guidance, and long-term capital allocation plan. After prepared remarks, we will open the call for Q&A. I will now turn the call over to Jack A. Fusco, President and CEO.
Jack A. Fusco: Thank you, Randy. Good morning, everyone. Thanks for joining us today as we review our results from the fourth quarter and the full year 2025 and we look forward to 2026. Before we dive into the results and outlook, I would like to take a moment to acknowledge a significant occasion that occurred here at Cheniere Energy, Inc. earlier this week. On Tuesday, we celebrated the tenth anniversary of our first export cargo, a milestone achievement that not only ushered in a new era of prosperity for Cheniere Energy, Inc., but for the U.S. and global energy markets as well. The significance of that first cargo cannot be overstated. In fact, earlier this week, I participated in the Transatlantic Gas Security Summit in Washington, D.C., with Energy Secretary Chris Wright, Secretary Doug Burgum, as well as leaders and ministers from over a dozen countries where the anniversary of our first cargo was commemorated. Getting to the point of that cargo being exported was a Herculean effort. Cheniere Energy, Inc. charted an unprecedented path in order to realize our vision. In doing so, we resolved a myriad of project development challenges, enabling the energy abundance and affordability we enjoy here in America to reach international markets, while rewriting the LNG rule book on long-term contracting by leveraging the vast natural gas resource and in-place energy infrastructure of the United States. Now, ten years and nearly 5,000 cargoes later, we have cemented our position as the industry's gold standard. We lead the U.S. LNG industry thanks first and foremost to the Cheniere Energy, Inc. workforce and their steadfast commitment to safety and excellence, which they demonstrate every single day. We also would not be here today without the unwavering support of our over three dozen long-term customers, construction partner Bechtel, our community partners, regulatory agencies, and financial stakeholders. Together, we have achieved something truly transformative in our first ten years, and we are just getting started. Please turn to Slide 5, where I will highlight our key results and accomplishments for the fourth quarter. We had an excellent fourth quarter operationally, and we generated consolidated adjusted EBITDA of approximately $2,000,000,000, bringing our total for the full year to $6,940,000,000 at the high end of our guidance range. We generated distributable cash flow of approximately $1,500,000,000 in the fourth quarter and approximately $5,300,000,000 for the full year, which is approximately $100,000,000 above the high end of our guidance range. Net income totaled approximately $2,300,000,000 in the fourth quarter. 2025 was a record year for LNG production, totaling 670 cargoes, or over 46,000,000 tons. During the fourth quarter, we exported 185 LNG cargoes from our facilities. This is an increase of 22 cargoes compared to the third quarter as not only did we benefit from additional volumes from Stage 3, production reliability, and the seasonal benefit in production, we also had improved and reduced unplanned maintenance compared to the third quarter as our efforts to mitigate some of the feed gas-related challenges we addressed on the last call delivered positive results across the quarter. Looking ahead to the remainder of 2026, we are on track to set another annual production record aided by the expected completion of the remaining three trains at Stage 3. I am pleased to introduce our 2026 financial guidance of $6,750,000,000 to $7,250,000,000 in consolidated adjusted EBITDA, $4,350,000,000 to $4,850,000,000 in distributable cash flow, and $3.10 to $3.40 in per unit distributions at CQP. These ranges reflect our forecast for higher production in 2026 offset by lower margins on spot cargoes than last year, as well as the start-up of a number of long-term contracts over the course of the year. We look forward to once again delivering financial results within our guidance ranges. The 2020 Vision capital allocation plan we revealed in 2022 has been completed, and in typical Cheniere Energy, Inc. fashion on capital deployment and share buyback, it was completed ahead of schedule. We have deployed over $20,000,000,000 across our capital allocation priorities and have achieved over $20 per share of run-rate DCF. In conjunction with our advanced progress, our Board of Directors has increased our share repurchase authorization to over $10,000,000,000 through 2030 after approving a $9,000,000,000 increase. And lastly, early this morning, we announced a new long-term SPA with CPC Corporation of Taiwan for up to 1,200,000 tons per annum on a delivered basis. It commences later this year and extends through 2050, and will bolster our contracted profile as we continue to grow our platform. This is our second long-term SPA with CPC following the approximately 25-year, 2,000,000-ton SPA we signed in 2018, which commenced in 2021. This SPA is a salient reminder that our product provides customers with long-term visibility through commodity cycles, certainty, and reliable supply in light of the recent volatility in the market, and contracting appetite is not dictated by the trajectory of margins in the front of the curve, but to support the lasting demand for our product for decades to come. I am very proud that CPC has become another repeat long-term customer of Cheniere Energy, Inc. It is clear evidence of how much the market values the reliability and customer focus that has come to define our first ten years of LNG export operations. Turn now to Slide 6, where I will provide an update on our major growth projects. Construction progress on Corpus Christi Stage 3 has advanced to approximately 95% complete, with the substantial completion of Trains 3 and 4 in the fourth quarter. Our forecast for the expected substantial completion of Trains 5, 6, and 7 to occur in spring, summer, and fall respectively is unchanged from our last call but moving in the right direction based on recent progress. I am pleased to announce that first LNG has been achieved at Train 5 this week, supporting that forecasted timeline. On CCL midscale Trains 8 and 9, groundwork and site prep continues, progressing extremely well, with work streams currently focused on concrete piling, piling work is already halfway complete, as well as further materials procurement and spool and steel fabrication. All the piles for Train 8 have been set. Substantial completion for these trains is forecast in 2028. As construction progresses, I am optimistic we have some advancement on that timeline. And nearby at our Gregory Power Plant, work on the planned expansion and interconnect is going well. We are set to optimize our power strategy with a ramp-up of Stage 3 and midscale 8 and 9. The SPL expansion project is our next major growth project, and we are making significant progress along multiple parallel paths advancing the first phase of this project towards FID as our visibility and confidence in this project continues to grow. We have secured significant commercial support for this brownfield capacity expansion, we continue to prepare the CQP complex for conservatively financing the project, and we are working diligently on project cost with Bechtel while advancing the project through the permitting process. We currently expect to be in a good position to receive our permits by the end of this year and make FID on the first phase in 2027. Back at Corpus Christi, our major CCL expansion is advancing well, with the critical path items and FID timeline of a brownfield Phase 1 approximately six months to a year behind the same at SPL. The full FERC application was submitted earlier this month. We have line of sight to accretively grow our LNG platform by approximately 50% from today, meeting the Cheniere Energy, Inc. standard while adhering to our disciplined capital investment parameters, including the Phase 1 expansions at Sabine Pass and Corpus Christi. We are full steam ahead on these development projects and have excellent line of sight to bring both of these projects to life and deliver market-leading contracted infrastructure returns to our stakeholders. With that, I will now hand the call over to Anatol to discuss the LNG market. Thank you again for your continued support of Cheniere Energy, Inc.
Anatol Feygin: Thanks, Jack, and good morning, everyone. Before I get into the LNG market update, first some comments about the SPA we announced this morning with our longtime customer CPC. It is not only a core long-term transaction in its own right, but also an all-but-perfect summation of our strategy and value proposition. Like most of the transactions we have executed in this cycle, it is with a repeat customer. Reliable LNG supply is absolutely critical to Taiwan’s rapidly growing economy, and we take pride that CPC put its trust in our ability to perform. It is approximately a 1,200,000-ton contract that is yet another transaction we have executed that extends beyond the middle of this century. We look forward to starting this incremental tranche later this year with our usual unwavering commitment to our multi-decade partner, CPC. It features a number of bespoke components, as buyers continue to value Cheniere Energy, Inc.’s customer-focused tailored solutions. All of the things that set us apart from the competition—safety, operational excellence, customer-first approach, and a stellar execution track record chief among them—have and will continue to contribute meaningfully to our commercial approach and ability to sign contracts like this one that support our disciplined growth plans. Together with constructive LNG market fundamentals supporting a clear need for more capacity, we will continue to leverage our advantages in the market to accretively commercialize our brownfield growth projects and target market-leading multi-decade returns to shareholders. Now please turn to Slide 8. As you can see from the chart on the left, 2025 was another year of generally elevated and volatile spot prices. A key driver supporting the overall elevated prices relative to historical norms was the strong pull on LNG cargoes from Europe as demand rose approximately 27% year over year in the fourth quarter and remained above the levels seen over the past four years. Trade disputes and geopolitical conflicts fueled uncertainty and sent prices soaring at various points throughout the year. Europe set a new annual record for LNG imports in 2025, reaching about 125,000,000 tons, aided by new LNG supply and the replenishment of underground storage inventories, which were approximately 20 BCM at a 14 BCM deficit today, about 25% behind last year, in fact, with a cold snap in January spiking prices once again. European storage levels are once again starting the year at five-year lows, or approximately 140 cargoes. Until additional volumes come to relieve the market, Europe will likely maintain its premium pricing to ensure readiness for next winter. Furthermore, a 17 BCM year-on-year reduction in pipeline from Norway, North Africa, and of course, Russia, were more than offset by LNG imports, as shown on the top middle chart. We expect these drivers will help keep LNG demand in Europe resilient, especially in light of the EU Parliament's vote to ban all residual Russian gas including Russian LNG by 2027. In contrast, Asian LNG imports in aggregate contracted slightly last year, likely as a consequence of the still-elevated levels of TTF spot prices in 2025 incentivizing greater deliveries into Europe. Asia's LNG consumption was down about 4% in 2025, lowered by 12,400,000 tons year on year to 270,000,000 tons but still comfortably within the five-year range for the region. A mix of factors were at play across Asia driving these import levels. Seasonal demand was impacted due to milder weather in the region, while China, the largest and most diverse LNG market in the world, continued to redirect cargoes to markets of higher margin, namely Europe, as it took advantage of its LNG delivery flexibility. While many of the major markets in Asia saw year-on-year declines, China's was the largest, as LNG imports declined 16% or 12,100,000 tons year on year due to muted industrial demand, macroeconomic challenges, and optimizing some of its LNG into higher value markets. Gas demand growth of about 3% in China in 2025 was below the 7% average in recent years. Additionally, higher piped gas flows from Russia, which were up 30.6% year on year, and increased domestic gas production, up 6.3% year on year, also contributed. With that said, as we watched LNG prices fall in November and December and into January, we saw a rapid increase in Chinese LNG imports and active restocking in South Korea, highlighting the at-the-ready price-sensitive depth of demand for LNG. Both of which were partially offset by lower gas burn in Japan. The year-on-year growth in the market area was supported across JKT. LNG imports were up 1.4% or 1,900,000 tons in 2025. We continue to expect robust growth in China's appetite for LNG to become the LNG industry's first market to meaningfully surpass 100,000,000 tons per annum in the medium to long term. In contrast, LNG imports to South and Southeast Asia decreased by 3.8 or 2,600,000 tons year on year. India’s imports were down 7% to 25 MTPA, while those in Pakistan were down 15% to 6.7 MTPA, in large part due to milder weather versus 2024 as well as these being price-sensitive markets. High spot prices, coupled with efforts to reduce gas sector circular debt in Pakistan, led to levy and tariff increases which curtailed LNG imports amid macroeconomic challenges following the devastating monsoon floods of last year. In summary, slightly lower LNG imports year on year across Asia are in large part due to sustained elevated price levels in 2025, but we are steadfast in our expectation that moderating pricing going forward will generate a market increase in gas and LNG consumption, as evidenced by the late-year surge in imports when prices moderated, as well as the continued strength in long-term contracting across the region as counterparties seek to secure and diversify their gas supply into the second half of this century. Additionally, given the record level of U.S. FIDs taken last year, we expect the price trajectory to continue to normalize as supply additions increase. We saw this starting to materialize at the end of 2025 when production from our Corpus Christi Stage 3 trains, among others, began to ramp up in scale and size. Let us turn to the next page to expand on this. We see fairly ratable supply growth over the next five years, which we expect to further moderate and stabilize the forward price outlook to bring the depth of LNG demand to the forefront. These projects are expected to enter service by the end of the decade. Commercial activity in 2025 enabled project sponsors to greenlight over 60,000,000 tons per annum of LNG capacity in the U.S. and about 10 MTPA in other regions, which, along with a few additional projects vying for FID this year, should support a steady stream of supply additions extending into the early 2030s, creating the next LNG supply wave. The escalation between feast and famine in relatively short cycles in the industry in recent decades has made it challenging for price-sensitive demand segments to grow and prosper. This has particularly been the case in the emerging markets of Asia, where there has been limited aggregate import growth since 2021 amid the current multiyear period of low supply growth and high spot prices. The region's price elasticity is clearly illustrated by the correlation between the spot price of LNG and the rate of growth in LNG consumption in the price-sensitive markets in Asia excluding JKT. During the five-year period to 2021, spot prices in nominal terms averaged approximately $7 per MMBtu, and Asia's price-sensitive markets grew imports by a compounded average rate of almost 20%. In contrast, the compound annual growth rate for these same markets dropped to just 1.7% in the period from 2021 to 2025 when JKM averaged $18 per MMBtu. We expect lower LNG spot prices with the coming growth in supply to stimulate demand in these markets over the coming years. While the scale of impact and specific growth drivers vary by market, the overall net growth in each of the Asian regions is expected to be above, and in most cases well above, the levels seen over the past four years. In summary, 2025 marked the end of a multiyear period of low supply growth. We see 2026 as the start of a multiyear LNG supply cycle, one that will improve availability and affordability of reliable supply and in turn stimulate price-sensitive Asian LNG demand that has historically driven this industry. With two long-term contracts signed with two of the largest Asian LNG buyers in the last six months, we continue to do our part to support the long-term energy priorities and long-term demand growth of the region with our flexible and reliable LNG supply. We believe that safely, reliably, and affordably supporting this growth will allow us to capture incremental long-term commitments to fully underwrite much of our growth up to 75,000,000 tons per annum. With over 95% of our capacity for the next ten years contracted, we are well positioned to further execute on our capital allocation strategy through the cycles. We have sufficient contracts in place today in support of our disciplined, accretive brownfield growth strategy. With that, I will turn the call over to Zach to review our financial results and guidance.
Zach Davis: Thanks, Anatol. Good morning, everyone. I am pleased to be here today to discuss our financial results and plans going forward. Turn to Slide 11. For the fourth quarter and full year 2025, consolidated adjusted EBITDA was approximately $2,000,000,000 and $6,900,000,000, and distributable cash flow was approximately $1,500,000,000 and $5,300,000,000 respectively. We generated net income of approximately $2,300,000,000. EBITDA came in at the high end of the guidance range, and DCF ended up above the high end of the range despite being close to fully sold out on our open capacity as of the last call. This outperformance can be attributed to further optimization locked in during the fourth quarter, higher lifting margin due to higher year-end Henry Hub pricing, and certain end-of-year cargoes being delivered in 2025 instead of early 2026. Compared to 2024, our 2025 results reflect higher total volumes of LNG produced across our platform, primarily as a result of the substantial completion of Trains 1 through 4 at CCL Stage 3, which resulted in almost doubling our spot capacity year over year from approximately 2 to approximately 4,000,000 tons that we were able to proactively lock in for 2025 at similar levels as the year prior, at over $8 per MMBtu margins on average. The year also benefited from higher Henry Hub pricing and more volume supporting lifting margin, and greater optimization activities upstream and downstream of the sites compared to 2024. These increases were partially offset by higher O&M costs primarily related to the substantial completion of the initial midscale trains at Stage 3 and the major maintenance turnaround at SPL during the year. While we have many significant achievements to highlight from 2025, I am particularly proud of the execution of our long-term capital allocation objectives and the early completion of our 2020 Vision capital allocation plan, ahead of schedule this quarter after a strong 2025. Last year, we deployed over $6,000,000,000 towards accretive growth, shareholder returns, and balance sheet management. We paid out approximately 60% of our distributable cash flow towards shareholder returns in the form of share repurchases and dividends. During the year, we repurchased over 12,100,000 shares for approximately $2,700,000,000, and the fourth quarter was the second consecutive quarter of over $1,000,000,000 in share buybacks. This brought our shares outstanding down to approximately 212,000,000 as of year-end. As of last week, we are down to approximately 210,000,000 shares outstanding, with less than $1,000,000,000 remaining on the $4,000,000,000 share repurchase authorization from 2024, once again highlighting the power of the plan to accelerate to be opportunistic and value-accretive during periods of share price dislocation, representing over $450,000,000 for common shareholders. We remain committed to growing our dividend by approximately 10% annually through the end of this decade, bringing total dividends declared for 2025 to $2.11, while maintaining the financial flexibility essential to our long-term capital allocation plan and our disciplined approach to accretive growth with an investment-grade balance sheet. In 2025, we repaid $652,000,000 of long-term indebtedness, fully retiring the SPL 2025 notes, partially redeeming the SPL 2026 notes, and amortizing a portion of the SPL 2037 notes. Earlier this month, we paid down the remaining $200,000,000 of SPL 2026 notes, leaving us with no debt maturities anywhere in the Cheniere Energy, Inc. complex until 2027. Our strategic management of our balance sheet earned us five distinct credit rating upgrades during the year, highlighting our trajectory to a mid- to high-BBB investment-grade corporate structure. In 2025, we equity-funded approximately $2,300,000,000 of CapEx across our business, including $1,200,000,000 on Stage 3 and deployed over $800,000,000 towards the midscale 8 and 9 debottlenecking project. During the year, we also began drawing on our CCL term loan during the fourth quarter with a $550,000,000 draw. In the context of almost $6,000,000,000 and over $1,000,000,000 funded to date for Stage 3 and midscale 8 and 9, respectively, this highlights part of how we have strengthened the balance sheet over time. In addition, we continue to deploy capital towards the SPL expansion as we progress development and permitting, and CCL expansion projects Jack highlighted, as well as on our Gregory Power Plant at Corpus to support incremental power needs over time as Stage 3 and Trains 8 and 9 are completed. We maintain substantial liquidity with approximately $1,600,000,000 in consolidated cash and billions of dollars of undrawn revolver and term loan capacity throughout the Cheniere Energy, Inc. complex. We are ideally positioned to fund our disciplined growth objectives while retaining significant financial flexibility fundamental to our capital allocation framework. Turn now to Slide 12, where I will discuss our 2026 financial guidance and outlook for the year. Today, we are introducing our full-year 2026 guidance ranges of $6,750,000,000 to $7,250,000,000 of consolidated adjusted EBITDA and $4,350,000,000 to $4,850,000,000 of distributable cash flow, and $3.10 to $3.40 per common unit of distributions from CQP. Compared to 2025 results, these ranges reflect additional production from a full year of operations of Trains 1 through 4 of Stage 3, the substantial completion of Trains 5 through 7 across this year, higher levels of contractedness as several new contracts will commence during the year, and lower margins on spot cargoes as prices have moderated. We also have a one-time benefit from the confirmation of the alternative fuel tax credit in the first quarter, contributing over $300,000,000 to EBITDA and DCF in our cost of sales. Our production forecast remains approximately 51,000,000 to 53,000,000 tons of LNG across our two sites this year, up approximately 5,000,000 tons year over year, inclusive of forecast Stage 3 volumes from Trains 5 to 7 and planned maintenance and resiliency efforts across both sites. With approximately 4,000,000 tons of incremental contractedness in 2026, or approximately 46 to 47,000,000 tons of long-term contracts, approximately 1,000,000 tons of commissioning/in-transit timing volumes, and over 4,000,000 tons of volumes forward sold by CMI to date, which is up from approximately 1,500,000 tons as of the last call. We now forecast less than 1,000,000 tons, or less than 50 TBtu, of unsold open capacity remaining in 2026, underscoring the cash flow visibility of the contracted platform. Despite having little open volumes exposed to the market, consistent with our prior practice of initial guidance, we are introducing these $500,000,000 guidance ranges as results could still be impacted by a number of factors, including variability in our production forecast, the ramp-up and specific timing of substantial completion of Trains 5 through 7 at Stage 3, contributions from optimization activities during the balance of the year, the timing of certain cargoes around year-end, and the impact that Henry Hub volatility can have on lifting margin. As we move through the year and the potential impact of these variables on our financial forecast reduces, we expect to tighten the guidance ranges. Also consistent with precedent, the year-over-year decline in the 2026 DCF guidance range is primarily due to the discrete tax benefit that we had in 2025. Our distribution per unit guidance at CQP for 2026 is wider than it had been last year, as the wider range provides the flexibility to potentially reinvest some of CQP's distributable cash flow towards limited notices to proceed for the 2027. Turn now to Slide 13. We are proud to announce the completion of our 2020 Vision capital allocation plan. We introduced the plan in 2022 with the goal of deploying over $20,000,000,000 of available cash across our capital allocation pillars of shareholder returns, accretive growth, and balance sheet management, to reach over $20 per share of run-rate DCF by 2026, and under that program, we have now surpassed those objectives almost a year ahead of schedule. Under the plan, we repaid approximately $5,500,000,000 of long-term indebtedness, which has led to 22 distinct credit rating upgrades, bringing our issuer rating at CEI from high yield when we started the plan to solidly investment grade today. We deployed approximately $6,500,000,000 towards equity funding our growth CapEx. While most of this spend was for Stage 3, the initial trains of which have come online ahead of schedule, we also funded CapEx related to the midscale Trains 8 and 9 project, as well as development and engineering related to the SPL and CCL expansion projects and CapEx related to our Gregory Power Plant adjacent to Corpus. Most significantly, we redeployed almost $9,000,000,000 towards shareholder returns in the form of share buybacks and dividends. Under the plan, we repurchased approximately 40,000,000 shares, or over 15% of our shares outstanding, for over $7,000,000,000. We also increased our quarterly dividend by approximately 68% since our inaugural dividend in 2021, representing approximately $1,500,000,000 of dividends declared under the plan. Given our accelerated progress under our $4,000,000,000 share repurchase authorization, with only $1,200,000,000 remaining as of year-end and aided by the fact that our LNG platform is over 95% contracted through 2030, our Board of Directors has approved an upsize of our share repurchase authorization to enable over $10,000,000,000 from 2026 through 2030. This $9,000,000,000 upsize to our authorization is a major extension of our comprehensive capital allocation strategy and a clear mark of confidence in our business model's contracted cash flow visibility and our capital investment discipline that has been developed to withstand the cyclicality of commodity markets. We now have the financial strength to not only opportunistically deploy approximately $10,000,000,000 into share repurchases over the next five years—approximately 20% of our market cap—but simultaneously grow our dividend by 10% per annum the rest of this decade and budget for FIDs at the Cheniere Energy, Inc. standard at both sites. The all-of-the-above capital allocation strategy for Cheniere Energy, Inc. remains firmly intact. These initial phases of the SPL and CCL expansion projects, developed to maximize brownfield economics, are expected to bring our total liquefaction capacity up to approximately 75,000,000 tons per year, with a risk-adjusted return profile unmatched in this industry and supported by decades of take-or-pay contracted cash flows from creditworthy counterparties. Accordingly, we are resetting our target run-rate DCF per share to reach approximately $30 by the end of this decade after the full deployment of the repurchase authorization, approximately 175,000,000 shares outstanding, and the completion of the first phases of our brownfield expansions at both Sabine Pass and Corpus Christi. Even before accounting for the growth, we are now in position to reach $25 of DCF per share by simply following through with our upsized share repurchase authorization. As we have done since our first export cargo ten years ago, we will continue to leverage our many advantages to create sustainable and growing long-term value for our shareholders while supplying our global customer base with our secure, reliable, and affordable LNG through cycles and for decades to come. That concludes our prepared remarks. Thank you for your time and your interest in Cheniere Energy, Inc. Operator, we are ready to open the line for questions.
Operator: Thank you. If you would like to ask a question, please press star 1. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Please limit yourself to one question and one follow-up question. Again, press star 1 to ask a question. The first question will come from Jeremy Bryan Tonet with JPMorgan.
Jeremy Bryan Tonet: Thanks for all the detail today in the slides. Anatol, I want to turn to Slide 9 and the big uptick you see in Asia there. Could you talk a bit more about how demand across Asia from 2026 through 2030 might be influencing the tone of commercial conversations as you look to lock in more supply agreements? And separately, we have seen some weather activity here locally and force majeure from some gas producers, predominantly in the Haynesville. Did that have any impact on Cheniere Energy, Inc.?
Anatol Feygin: Sure, Jeremy. Good morning, and thank you. Look, we have always been of the view that moderate prices are good for this industry. As we have said over the last few years, one of the things that we expect to change as this wave of supply moves through the market is that the world will recalibrate its outlook on 2040 and that 700,000,000-ton outlook. But even with the 700,000,000-ton outlook, we do expect—obviously—long-term contract economics have been much lower than spot prices over the last few years, and we think that continues to be appealing. Reliable, stable, very secure product is something that the world will need more of, and we think that our reliability and security of supply are very valuable. Even in the fourth quarter, the world signed over 17,000,000 tons of long-term contracts, primarily driven by Asia. So we are very, very constructive on what global LNG demand is going to look like over the coming decades, and we are proud to be part of that wave, and we will continue to find these core opportunities to work with customers that value our reliability and our security of supply.
Jack A. Fusco: Hi, Jeremy. It’s Jack. On the weather-related events, first and foremost, I was really pleased with the way our winter emergency preparedness at the facilities and operating teams were able to position ourselves and take care of the facilities to make sure that there was no harm to either our employees or to any of the equipment. They once again far exceeded storm firm. There was not anything material one way or the other. We saw price blowout and producers declaring force majeure; we were able to manage around that, operate in the system to help support some of the local areas, and it was a slight positive to optimization for the first month of the year.
Zach Davis: Yeah, that’s right, Jeremy. Overall optimization for the first month of the year is baked into the guidance we just gave you for this year, but only for January. And just to be clear on how we think about optimization and guidance, if it is not officially locked in, it is not in the guidance. So as things accrue into February and for the rest of the quarter, we will give a clearer update on the May call. We have a ways to go to catch up to the amount of optimization EBITDA that was generated in 2025 for 2026, and that is part of the upside to the current guidance that we just provided.
Operator: The next question will come from Spiro Michael Dounis with Citi.
Spiro Michael Dounis: Thanks, Operator. Good morning, team. First question just on commercial progress, a bit of a two-part question. As you noted, you have about 10,000,000 tons per annum signed up now to support the next set of growth projects. Does the next SPA that you sign from here start to underwrite the expansions beyond Phase 1 of Sabine and Corpus? And where would you say market LNG contracted margins are right now, especially in light of some competing projects being rationalized?
Anatol Feygin: Yes, thanks, Spiro. I would say at this point, the first train of our super brownfield expansions is spoken for, and we have some modest amount of work to do on the second one. Obviously it depends on the economics and on the volume of the SPAs, but I think some single-digit millions of tons still need to be contracted to get us into the right position for Train 2 of the expansions, namely the large-scale train of Corpus that we filed for. In terms of market margins, you are absolutely right—it is a very competitive market. We had over 60,000,000 tons of FIDs in the U.S. last year. A number of those tons are still not contracted, so that is a dynamic we see in the market as well as those few projects that are still trying to get to the finish line. But as you also know, we do our utmost not to compete in that commoditized market of the 20-year CP product, and everything that you will see from us going forward is a relatively bespoke product that receives the premium that we think we deserve for our reliability.
Jack A. Fusco: And, Spiro, this is Jack. In my conversations—and in my keynote address—having ten years of export capability here at Cheniere Energy, Inc., over 5,000 cargoes delivered, and never missing a foundation customer cargo means a lot to the JERAs and the CPCs and the POLINs—you can go on and on. Those building gas infrastructure now want to ensure that they get the LNG they need, and the deals that Anatol and the team have been able to execute reflect a premium customers are willing to pay to ensure that reliability.
Zach Davis: And the fact that we are well over 95% contracted now, not just through 2030 but 2035, is why we were able to make the announcements we did today. The cash flow visibility is basically unparalleled, solidifying the run-rate guidance—if not better—comfortably within our range. So we are in a good place right now. If someone does not have that in their model—let’s say, the first phase of Sabine—and increased shareholder returns, that $10,000,000,000 of buyback better be finished a lot sooner. Message received.
Spiro Michael Dounis: Alright, message received. Second question: Jack, you noted in your prepared remarks that you had already started to benefit on the nitrogen and inert gas side even in the fourth quarter. Last call you indicated a long-term plan to deal with excess nitrogen. Have you beaten that estimate? Would you say you have dealt with that issue, or is there still more to go?
Jack A. Fusco: There is still more to go. It is a combination of issues, Spiro. The nitrogen is just an inert gas—it takes up space, so we have to evacuate it. What caused us a hiccup in the third quarter was variability in feed gas with heavies—C12 to be exact. The process engineers and operating folks put their heads together with suppliers and some oil companies, and we figured out different operating modes that are starting to pay dividends. We have adjusted operating modes, and we have been able to buy and inject certain solvents as fast and as much as possible. Some of the capital that Zach referenced is for longer-term resiliency of our facilities to make sure the front end can handle variability in gas coming from anywhere.
Zach Davis: And I will credit the whole team that maybe we were at the lower end of production last year in our range, but still got to the high end of our financial guidance as we proactively sold open capacity. Stage 3 progressed really well and came online with four trains, and the optimization came through. This year, the production guidance that stayed intact since last call bakes in a healthy amount of planned maintenance for these resiliency efforts. If that does not take as long, we will update both production and financial guidance.
Operator: The next question will come from Theresa Chen with Barclays. Good morning.
Theresa Chen: Great to see the continued commercial success in your second DTC SPA. Maybe putting a finer point on the economics of the commercialization process at this point, can you provide any quantitative color on your outlook for the production fees based on your recent success and ongoing commercialization—what would you say is the range at this point? And more broadly, going back to Anatol's comments and the earlier question about elasticity, what evidence of demand elasticity have you seen already in your commercial discussions for long-term contracts, taking into account the significant incremental liquefaction capacity set to enter the market through the end of the decade and beyond?
Anatol Feygin: Yes, Theresa. As Zach and I have said for many quarters now, we are very comfortable with the $2.50 to $3.00 range, and we are really doing things above the midpoint of that range. But as we have said to you and others, I cannot tell you that if we needed to contract 20,000,000 tons of additional volumes to get to super brownfield economics and meet our investment parameters, we would be able to maintain that. So to your question and Spiro's, the “market economics” are not at that level; we would say they are below that level for U.S. product. It is our performance, reliability, and commercial engagement—our flawless performance and ability to continue to deliver day in and day out—that give us the ability to capture these premium contracts. On price elasticity, even in the rearview mirror, the LNG market has had periods where in the aggregate it has consumed about 600,000,000 tons. As you look at where price-elastic markets can land, the numbers are comfortably above what we have operating and under construction today. There is well over 1,200,000,000 tons of regas capacity, growing to 1,400 with what is under construction. Markets like Vietnam—obviously from a very small base—grew over 200%, and that market alone will likely be well north of 10,000,000 tons by early next decade. Asia should grow from the roughly 270,000,000-ton level, where it has been stuck due to high prices, to well over 400,000,000 tons as affordable supply—ratably affordable over years—stimulates investment. We remain sanguine, and as long as we keep contracting at those economics and underwriting disciplined expansion plans, we hope the market remains constructive and continues to grow. But we are quite immune from those dynamics given our contracted platform.
Theresa Chen: That is very helpful. Thank you. Switching gears, as gas-fired power demand reaches new highs across the U.S., partly driven by growing data center electricity needs, there are concerns that rising LNG exports could exacerbate domestic affordability pressures. What is your view on this? Do you see these dynamics affecting Cheniere Energy, Inc.'s ability to permit and/or commercialize incremental capacity? And how do domestic affordability issues reconcile with LNG's importance as a strategic trade and geopolitical lever for the U.S.?
Jack A. Fusco: I will start, then hand it to Anatol. Theresa, it takes us 18 months to two years to get a permit, our pipeline plans are filed with FERC and made public, and then it is another three to four years for construction. In all cases, we buy firm transportation—we have it to all five basins. We process 24/7 and provide stability in cash flow to producers and midstream companies that has never existed before in their lifetime, allowing them to grow significantly. When the first cargo left Sabine Pass in February 2016, U.S. gas production was around 67–68 Bcf/d. Today it is well over 110 Bcf/d, in part because they see the exports coming. Having been on the gas-to-power side most of my career, gas-to-power generally does not like buying firm transportation or paying forward for gas—they prefer interruptible supply at the cheapest price possible to price into real-time markets. That can help in the short term but is not helpful longer term for production growth. We are starting to see that whole paradigm on exports shift in Washington as we explain how the markets really work.
Anatol Feygin: Three quick points. One, we do not think we compete for molecules with those incremental demand centers. By definition, they will try to build in places with trapped resource and limited infrastructure to access markets, whereas we rely on points of liquidity—quasi-religion for us as we supply our customers. Two, even the EIA says 2026–2027 will not see the same level as 2024 for gas-for-power, so we think the market may be disappointed by the rate at which gas demand into power grows. Three, for our product and our customers, NYMEX is a pass-through, and we do not expect tremendous competition in the Southwest Louisiana pool that is NYMEX for those molecules. We are optimistic the domestic resource is there to meet all needs, and we are careful about how we approach expansions; our current infrastructure is more than sufficient to avail us of the molecules that we need.
Operator: We will go to Jean Ann Salisbury with Bank of America.
Jean Ann Salisbury: Hi. Good morning. In 2025, there was significant EPC CapEx escalation in LNG greenfield costs. Can you talk about the drivers of that and whether that has begun to moderate? And as a follow-up, is CapEx escalation impacting brownfield projects like yours as materially?
Jack A. Fusco: Jean Ann, as you know, we FID’d Trains 8 and 9 and did so within our financial parameters that Zach laid out. We do see some escalation and are working through it with Bechtel. We have managed it by issuing limited notices to proceed on longer lead-time items. At this point, lead times worry me more than inflation. We also optimized our plan to get economies of scale and reduce dollars per ton for both SPL and CCL expansions. We asked for identical repeat trains—another SPL 6 for SPL 7, and another CCL 3 for CCL 4—which should help on all fronts.
Zach Davis: And on the math, it is transparent—we file quarterly CapEx and PP&E. We basically have the lowest cost per ton, the best or highest SPAs, the lowest leverage, and the least amount of equity partners. We are well placed for the FIDs of Train 7 and Train 4. We are permitting more than that, but we see a path to hold to the standard by being as super brownfield as possible right now.
Jean Ann Salisbury: Very clear. Thank you.
Operator: Moving on to Michael Blum with Wells Fargo.
Michael Blum: Thanks. In terms of your December FERC filing to increase CCL Stage 3 and midscale 8 and 9 by 5,000,000 tons, can you talk about the timing to achieve that expansion, and how to think about the use case for that incremental capacity?
Zach Davis: Those filings reflect continued debottlenecking and engineering of the site that we plan to take advantage of over time. That increment is to accommodate peak production at certain times of the year at Corpus. It folds into the broader story that we will likely FID a train at each site plus debottlenecking projects—that is how we get to 75,000,000 tons. Ideally, a first phase of a Train 4 at Corpus plus other items will make the economics crystal clear as accretive and within our parameters.
Michael Blum: Got it. And on the new CPC contract you announced this morning, when do you expect it to kick in during 2026?
Anatol Feygin: It starts midyear. Some of how we structure transactions includes flexibility we can take advantage of as we debottleneck. That is why we are a little cagey with the 1,200,000 tons—this is the number for the vast majority of the term, but it includes some flexibility starting mid-2026.
Michael Blum: Understood. Thank you.
Operator: The next question comes from Jason Gabelman with TD Cowen.
Jason Gabelman: Hello. Thanks for taking my question. You mentioned the ramp-up in Corpus Stage 3 is going very well, and it seems like those trains could come online earlier than contemplated in your volume guidance. How do you think about the upside to that volume guidance? And as a follow-up, on additional expansions beyond the very brownfield trains at Sabine and Corpus: Anatol, you mentioned roughly 20,000,000 tons’ worth of SPA opportunities. Do those support the higher margin guidance embedded in your economics, and do they support higher-cost trains beyond the initial brownfield opportunities?
Zach Davis: Still early in the year, and note we did not update substantial completion dates of Trains 5 through 7 in guidance. We just achieved first LNG at Train 5 earlier this month. To put some math on it, if all three trains were a month early, at current margins, that is comfortably over $50,000,000 of incremental EBITDA over the year. We are already four-for-four, and it is looking like five-for-five of being early, but in February it is too soon to tell. We will update as trains come online through the year.
Anatol Feygin: Jason, to clarify, if we had to do 20, we would not be able—at current “market” levels—to maintain the $2.50 to $3.00 standard. Market economics today are below $2.50. Our performance, reliability, and commercial engagement allow us to capture premium contracts and maintain brownfield economics to meet our investment parameters. Beyond that, it is a step-function change in CapEx per ton that today’s market economics do not support for meeting our parameters.
Zach Davis: Jack’s whiteboard got us to 75,000,000 tons, and we will go from there.
Jason Gabelman: Got it. Thanks.
Operator: Our last question will come from John McKay with Goldman Sachs.
John McKay: Hey, thanks for the time. Back to the macros for you, Anatol. On Slide 9 you are showing strong growth for China through 2030. What price do you think underwrites that growth? And on coal-to-gas switching, what is your framework for magnitude?
Anatol Feygin: Our guess—subject to hedging—is delivered LNG in the $8 to $9 range against $60–$65 Brent. China is massively fragmented and distributed—dozens of companies, multiple business models and competing fuels. The market is approaching 300,000,000 tons of regas capacity, mostly coastal, and over 200 GW of installed gas-fired capacity. At the right price, it can consume substantial volumes. In 2025, for a host of reasons, it behaved as a quintessential invisible hand and redirected cargoes to where most profitable. At high single-digit delivered prices, we think China comes roaring back like 2018–2019.
John McKay: Super interesting. Last quick one for Zach, maybe Jack as well. Latest thoughts on the dividend—where that could grow over time, especially with the $30 per share framing—and how that plays relative to buybacks?
Zach Davis: We are following through on what we have said: committed to growing the dividend by about 10% a year through the decade. Over time, we will get to something over a 20% payout ratio—different than most in midstream. Our shareholder return policy is on average 60% of DCF, with roughly 50% of that 60% as buybacks. This flexibility lets us self-fund equity for Stage 3, Trains 8–9, and first phases at both projects, while being opportunistic on buybacks, as we were the last couple of quarters and earlier this year. We like this approach; the 10% compounding gets powerful later this decade.
John McKay: That is clear. Thank you. Appreciate the time.
Operator: And that does conclude the call.