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

Thanks, Operator. Good morning, everyone, and welcome to Cheniere’s fourth quarter and full year 2023 earnings conference call. The slide presentation and access to the webcast for today’s call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere’s President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; Zach Davis, Executive Vice President and CFO, and other members of Cheniere’s senior management. 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 two of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix to the slide presentation. As part of our discussion of Cheniere’s results, today’s call may also include selected financial information and results for Cheniere Energy Partners LP or CQP. We do not intend to cover CQP’s results separately from those of Cheniere Energy, Inc. The call agenda is shown on slide three. Jack will begin with operating and financial highlights, Anatol will then provide an update on the LNG market, and Zach will review our financial results and 2024 guidance. After prepared remarks, we will open the call for Q&A. I’ll now turn the call over to Jack Fusco, Cheniere’s President and CEO.

Thank you, Randy. Good morning, everyone. Thanks for joining us today as we review a successful 2023 and discuss our outlook for what is setting up to be a very busy and promising 2024. In 2023, we drove exceptional results across the key strategic priorities of the company and we did so while reinforcing our track record on safety, execution, and operational reliability. I’m extremely proud of my 1,600 Cheniere colleagues across operations, engineering, construction, origination, and others who continue to be driven by excellence and take pride in solidifying Cheniere as best in class across our platform. We made significant strides despite some persistent macro headwinds and increased uncertainty in 2023, largely driven by conflict, geopolitics, and the evolving regulatory landscape, particularly right here in America. I’ll touch on the latter in a moment, but the macro backdrop for LNG today provides a blunt yet clear reminder of the criticality of secure and stable energy supply and the value of a reliable and customer-focused operator who consistently delivers on its promises to its global stakeholders. Please turn to slide five, where I’ll renew some key operational and financial achievements from the fourth quarter and full year 2023 and introduce our 2024 financial guidance. We generated consolidated adjusted EBITDA of approximately $1.65 billion in the fourth quarter, bringing our full year total to approximately $8.8 billion, at the high end of our most recent guidance range. We generated approximately $1.1 billion of distributable cash flow in the fourth quarter and $6.5 billion for the full year, which is above the high end of our guidance range. Looking back at the original guidance provided for 2023, we beat the midpoint of each of those guidance ranges by over $500 million, once again illustrating the volatile nature of current global natural gas markets and the value of Cheniere’s platform to monetize that volatility last year. For the fourth quarter, we generated approximately $1.4 billion in net income, bringing the full year total to approximately $9.9 billion. Strategically, 2023 was another year marked by significant accomplishments across the entire platform, and I’ll highlight just a few of them here. First and foremost, we continue to execute on the company’s long-term objectives with safety at the foundation of our actions, and in 2023, we once again demonstrated this by achieving a total recordable incident rate of 0.10, which is well within the top decile for industrial producers. We achieved this while simultaneously operating the second largest LNG platform in the world and being deep in construction on a 10-plus million ton per annum expansion project. These safety results are a source of tremendous pride for me and that pride should be felt by all the company stakeholders. We produced and recorded a record 169 LNG cargoes in the fourth quarter, bringing the total to a record 637 cargoes for the full year. Total production was in line with our forecast of about 45 million tons, inclusive of the successful major maintenance turnaround that happened over the summer. Europe remained the premium market for U.S. cargoes across 2023, as 73% of the volume produced at our facilities was delivered to Europe. Five new long-term customer contracts commenced over the course of 2023, representing approximately 3.7 million tons per annum. And earlier this month, we commenced our 1.1 million ton per annum PETRONAS contract, which was tied to Train 6 on the very first day of the DFCD window, holding to our standard of always meeting our customer commitment. On the E&C front, Corpus Christi Stage 3 is progressing on an accelerated timeline and we continue to forecast first LNG production from Train 1 at the end of this year. In 2023, we advanced total project completion to over 50%. I’m extremely pleased with the progress we continue to make together with Bechtel on Stage 3, and I’m optimistic for further schedule improvements over time. We took some important steps last year in preparation for Stage 3 to commence commissioning and operations. Construction on the ADCC Pipeline being built from Agua Dulce to support Stage 3 is progressing well and the pipeline is expected to be in service in the third quarter in advance of Train 1’s accelerated startup. In addition, in the second half of last year, we purchased for approximately $100 million an existing 400-megawatt power plant in Corpus Christi, which is located on our property, in order to help mitigate risks associated with our increased power purchasing needs once Stage 3 commences operations. These milestones, coupled with the construction progress on the project, reinforces my confidence in Stage 3’s timeline, improving over time with first LNG this year and meaningful LNG production added to our portfolio in 2025. Our commercial momentum continued in 2023 as LNG buyers the world over helped get the commercialization of the SPL expansion project off to an incredibly promising start. We have signed long-term agreements with six counterparties across Asia, Europe, and Canada for an aggregate of over 6.5 million tons per annum, effectively commercializing all of Train 7. We are encouraged by the market’s early reception, especially since the majority of these counterparties are repeat customers. I view it as a recognition of the value of Cheniere’s reputation. We are focused on furthering the development of the project in 2024 across commercialization, regulatory, and financing work streams, with a focus on submitting our full permit application with the FERC before the end of this quarter. Throughout 2023, Zach and his team continued to execute on the 2020 Vision Capital Allocation Plan, making significant progress across the key pillars of the plan: debt reduction, capital return, and disciplined growth investments. We’ve paid down over $1 billion of debt and achieved investment-grade ratings throughout our structure. We bought back almost 10 million shares for approximately $1.5 billion and declared dividends of $1.66 per share, and we invested approximately $1.5 billion into Stage 3. We’ve made great strides on the comprehensive plan since announcing it in late 2022. And now, turning our focus and attention to 2024, I am pleased to introduce our 2024 financial guidance of $5.5 billion to $6.0 billion in consolidated adjusted EBITDA, $2.9 billion to $3.4 billion in distributable cash flow and $3.15 per unit to $3.35 per unit distribution of CQP. We, again, are forecasting annual results that are above the midpoint of our run rate 9-train guidance and our expected results this year have a tremendous amount of visibility, given how highly contracted we are. On the CQP distribution guidance, consistent with the prior messaging, we intend to maintain the $3.10 base distribution and adjust the variable component beginning in 2024 in order to begin preserving some cash and fortifying the CQP balance sheet as the SPL expansion project gains momentum. Zach will provide more details on the 2024 guidance in a few minutes. Turn now to slide six, where I will address the DOE news and our response. As you’re all aware, the Department of Energy recently announced it would suspend making determinations on authorizations for LNG exports to non-free trade agreement countries, pending an update to the economic and environmental analysis underpinning its public interest determination methodology. While this decision does not currently impact our expansion projects or our FERC processes at Sabine Pass and Corpus Christi, it does introduce regulatory and permitting uncertainty into the U.S. LNG industry as a whole. I firmly believe that a fair and transparent regulatory framework is essential for the future development of natural gas infrastructure in the United States, particularly liquefaction capacity, given the scale of investment, commercial support, and time required to bring these projects online. With that said, we believe we will secure all necessary regulatory approvals for mid-scale Trains 8 and 9, and the SPL expansion project within our expected timelines, as we have for more than a decade under multiple administrations. To be clear, the DOE action has not slowed down our expansion projects at either site. We are full steam ahead on Corpus Christi Trains 8 and 9 and the SPL expansion project development. We expect to file the FERC application for SPL very soon, and Corpus Christi Trains 8 and 9 are in advanced stages in the FERC approval process. The environmental assessment for Trains 8 and 9 is scheduled for receipt by the end of March, and we just received a letter of determination from PHMSA, a key agency in the FERC process last week. We remain confident that our previous timelines won’t be materially impacted and we will maximize the efficiency with having Bechtel on site already through Stage 3. Having spent the last eight years at Cheniere, I’ve never been more confident in the critical role of U.S. LNG in the global energy market, and I firmly believe the DOE studies will come to the same conclusion given, one, the importance of long-term energy security, two, the opportunities for global decarbonization through coal-to-gas switching for power generation and the critical role that dispatchable gas-fired power plants play in backstopping intermittent renewables, three, low and stable domestic natural gas prices, and of course, four, the incredible economic benefits created in the communities where we live and work. Global energy markets are calling for additional LNG supply. The U.S. is significantly advantaged to answer this call with our abundant and low-cost natural resources, flexibility and affordability of U.S. volumes, and until recently, the reliability and certainty of the U.S. regulatory regime. Gulf Coast LNG positions the U.S. as a leader in facilitating energy security and worldwide emissions reductions. This is a generational opportunity, something we should be proud of and work to maximize, not restrict. With that, I’ll 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. The global LNG market continued to rebalance throughout 2023 as Europe navigated its energy crisis and Asia adapted to the delicate new market equilibrium amid some regional economic headwinds. Global LNG trade grew by approximately 3% from 2022, adding 10.5 million tons of supply to the overall market. Aside from 2020, global supply growth has not been this low since the 2011 through 2015 period. Nevertheless, this increase in supply was broadly matched by an increase in Asian demand, which grew approximately 4% year-over-year to approximately 263 million tons per annum as the region furthers its post-pandemic return. On the supply side, only one new train came online in 2023 globally, the third train at Tangguh LNG in Indonesia. Most of the growth in LNG output last year actually came from the continued ramp-up of existing projects in the U.S. The U.S. exported 86 million tons last year, becoming the world’s largest exporter in 2023, ahead of Australia and Qatar for the first time, and more than half of those volumes were produced by Cheniere. In the fourth quarter alone, U.S. exports reached record highs of nearly 24 million tons, contributing to the global market’s rebalancing. Despite persistent geopolitical unrest globally and the continued phase-out of Russian pipe gas in Europe, spot price levels have decreased this winter compared to last year due to a combination of mild weather, macroeconomic fundamentals, high storage levels, and sufficient LNG supply availability. In the fourth quarter, TTF averaged $13.66 per MMBtu and JKM $14.97, both significantly lower than levels seen in the previous two years and both have continued to trend down through the first quarter of this year. Henry Hub benchmark also decreased in the fourth quarter, falling to an average of $2.88 per MMBtu. For the full year 2023, TTF monthly settlement prices averaged $13.73 per MMBtu, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for JKM decreased by 53% year-over-year to an average of $16.13, while the Henry Hub average settlement price was $2.74, down approximately 59% from $6.64 in 2022 during the height of the energy crisis in Europe. Let’s address the regional dynamics on the next page. With more than 65% of all U.S. LNG volumes in 2023 flowing to Europe, the region’s underground storage inventories remained elevated throughout the year, easing concerns about physical market tightness amid further reductions in all other sources of gas supply to the region. Total gas supply to Europe fell 56 BCM year-on-year due mostly to the continued reduction in Russian flows, as well as heavy upstream maintenance in Norway further affecting pipe gas supply. Nonetheless, storage levels ended the calendar year at 86% full, the second highest level for the period since storage data became available in 2011. Meanwhile, gas demand in the region’s key markets continued to drop, declining by 9% year-on-year in 2023, following a 12% reduction in 2022. The power sector accounted for nearly half of these reductions amid relatively mild temperatures, continued conservation efforts, improving nuclear performance, and growth in renewable generation. And aside from Germany, industrial demand reductions appear to have bottomed out in 2023 throughout the region. In Asia, as I mentioned, LNG demand grew by 4% or 9 million tons year-on-year, thanks to a resurgence in demand from China and other emerging economies throughout Asia. Most of the uptick in Asia’s demand was largely due to a rebound in China’s economy, which resulted in a 7.5% year-on-year increase in gas consumption. It was up 27 BCM. Despite a 13 BCM increase in domestic gas output and the scheduled 7 BCM ramp-up in the Power of Siberia flows last year, China’s reliance on LNG remained high at 25% of total gas supply. The country’s imports rebounded by about 12% to 71 million tons last year, about 8.5 million tons below the peak 2021 levels. We continue to expect gradual but continued growth in gas consumption that will increase the call on LNG going forward. In addition to China, an approximately 8.5-million-ton year-on-year increase in South and Southeast Asia’s imports also contributed to growing global demand last year. Thailand and India led the charge as LNG spot prices moderated and demand for gas-fired power generation reached record levels in India. Additionally, three new receiving terminals started in this region, giving the nascent import markets of the Philippines and Vietnam access to LNG, which we believe will help power their economies for years to come. LNG demand growth in Asia was partially offset by the reduced demand for LNG in Japan due to lower electricity demand and increased nuclear availability. In Japan, two nuclear reactors restarted in 2023, increasing available nuclear capacity to the highest level since the Fukushima disaster in 2011. This is a structural trend in Japan that we expect will continue to impact gas-fired power generation and consequently LNG imports over time. Let’s move to the next slide where we’ll consider the outlook for gas in these and other economies. As discussed, global gas demand in 2023 remained relatively flat, growing by 20 BCM or 0.05% amid tight global supplies and historically elevated prices. In contrast, global demand for coal was up 1.4% on the back of increased use in emerging and developing economies. Given the DOE action related to climate that Jack already discussed, it’s worth highlighting here the simple fact that for the second year in a row, global coal consumption hit a new all-time record. Coal-fired power generation increased in 2023 despite continued coal-to-gas switching in the U.S., notable declines in Europe, and significant growth in renewable generation overall, which rose over 22% globally. As shown in the lower left, more than half of the power demand growth in China and India in 2023 was supplied by coal. Coal-fired generation from these two nations alone increased by 419 terawatt hours, which is roughly equivalent to the total power generation for the entire country of France and more than 80% of the entire growth in renewable power generation seen last year. While China and India remain committed to growing gas as a primary energy source in their respective economies, tight gas supplies and higher-than-normal global LNG prices in recent years have impacted the pace of potential gas consumption growth in these developing economies. More broadly, coal remains the largest source of power generation globally and represents about two-thirds of power sector emissions and about a quarter of total emissions globally. With power demand expected to double by 2050, any hope of achieving global decarbonization and clean energy targets will require further displacement of coal use wherever possible, especially in countries like China and India. As Jack noted, natural gas holds a critical role in helping achieve these goals over the coming decades, which we expect will result in robust increases in demand for natural gas over that period, as shown by the outlooks on the central chart. The fast-growing economies in the Asia-Pacific region are expected to play the greatest role in powering gas demand beyond the 2040s, when demand from Europe and the developed world could possibly be in modest decline and regional gas supplies in Asia further deplete. The outlook for global gas demand should remain robust going into the second half of the century, because natural gas is an affordable, reliable, and sustainable solution that will serve to displace coal and support the deployment of intermittent renewable energy sources. As such, in 2023 alone, we have executed over 6.5 million tons per annum of long-term agreements, representing over 119 million tons in aggregate volume of LNG between 2026 and 2050, the majority of which are with repeat customers and are structured to meet each customer’s unique long-term objectives. These investment-grade counterparties include North American producers, portfolio players, and Asian and European end-users, all of which seek secure, cleaner, and affordable and flexible supply. Our customers sign up for decades of LNG from Cheniere because they believe in the long-term role of natural gas and they believe in Cheniere’s ability to deliver the LNG reliably and responsibly. Looking ahead to 2024, as the market continues to stabilize and achieve the stable pricing necessary to ensure market access and adoption, we anticipate our premium products will continue to have broad-based appeal. With that, I’ll turn the call over to Zach to review our financial results and guidance.

Thanks, Anatol, and good morning, everyone. I’m pleased to be here today to review our fourth quarter and full year 2023 results and key financial accomplishments and introduce our financial guidance for 2024. Turn to slide 12. For the fourth quarter and full year 2023, we generated net income of approximately $1.4 billion and $9.9 billion, consolidated adjusted EBITDA of approximately $1.65 billion and $8.8 billion, and distributable cash flow of approximately $1.1 billion and $6.5 billion, respectively. With today’s results, our full year consolidated adjusted EBITDA results were at the high end of our most recent guidance range and we exceeded the high end of the range on distributable cash flow, mainly attributed to higher margins captured on open capacity and optimization upstream and downstream of the plant. In addition, we have now reported positive net income on a quarterly and cumulative trailing four-quarter basis five quarters in a row. As compared to 2022, our fourth quarter and full year 2023 results continue to reflect a higher proportion of our LNG being sold under long-term contracts with less volume being sold into short-term markets, as well as the further moderation of international gas prices relative to what we experienced in 2022. These impacts were partially offset by certain portfolio optimization activities that our teams were able to achieve throughout the year. During the fourth quarter and full year, we recognized in income 618 TBtu and 2,353 TBtu of physical LNG, respectively, which included 607 TBtu and 2,318 TBtu from our projects, a record for the full year, and 11 TBtu and 35 TBtu sourced from third parties, respectively. Approximately 90% and 87% of these LNG volumes recognized in income were sold under long-term SBA or IPM agreements, with initial terms greater than 10 years, respectively. While we have many significant achievements to highlight from 2023, I’m particularly proud of my team’s focused execution on our 2020 Vision Capital Allocation Plan. We deployed approximately $5 billion towards balance sheet management, shareholder returns, and accretive growth in 2023 alone, while maintaining strong available liquidity going into this year. In aggregate, since updating our Capital Allocation Plan in September 2022 with the target of $20 billion of cash deployment through 2026 and $20 per share of run rate DCF, we have now deployed over $8 billion. Execution under the plan got off to a fast start in early 2023 when we achieved investment-grade ratings at both of our parent entities, bringing the entire Cheniere complex to investment-grade status. And in June, we issued our inaugural corporate investment-grade bond, placing $1.4 billion of unsecured notes at CQP. These milestones follow approximately $8 billion of deleveraging over the last three years, from approximately $32 billion of debt at our peak to now under $24 billion. During the fourth quarter, we repaid $50 million of long-term indebtedness, further redeeming a portion of the senior secured notes due in 2024 at SPL, and bringing our total long-term debt paydown for the year to approximately $1.2 billion. We plan to address the remaining balance of the SPL 2024 notes with cash on hand within CQP early this year, after which point we will have addressed all maturities in the complex for the year. We have already begun strategizing around the 2025 maturities we have at both SPL and CCH, and as always, we will evaluate opportunities to efficiently refinance or delever throughout the year. The buyback plan is working as designed and enabling us to be opportunistic. During the fourth quarter and full year 2023, we repurchased an aggregate of approximately 2 million and 9.5 million shares of common stock for approximately $339 million and $1.5 billion, respectively. As the share price has provided greater opportunities so far this year compared to the fourth quarter 2023, deployment under the share repurchase plan has accelerated. In year-to-date, or in just a month and a half or so, we have already deployed nearly $500 million, which is more than we did in any quarter in 2023, repurchasing almost 3 million shares so far, bringing our total shares outstanding to under $235 million currently. We will continue deploying the now under $2 billion remaining under the plan over the next year or so. With the expectation, we will get to the cumulative one-to-one share repurchase to debt paydown ratio and complete the current $4 billion authorization ahead of its three-year window, at which point the focus will primarily be on updating the buyback plan again with the Board while maintaining our IG balance sheet across the complex as we prepare for our creative growth initiatives at Corpus and Sabine in the coming years. We also declared $1.66 per common share in dividends for 2023, a nearly 15% increase year-over-year, having increased our quarterly dividend by 10% in Q3, consistent with our stated target of 10% annual dividend growth. Over time, we intend to steadily increase our overall payout ratio as our platform grows, while still maintaining the financial flexibility essential to our capital allocation plan and growth objectives. During the quarter, we funded approximately $467 million of CapEx at our Stage 3 project, bringing total spend to approximately $1.5 billion for the year and a little over $3 billion in total for the project. While front-loading the equity spend has enabled considerable interest savings, we still have over $3 billion available on our CCH term loan that we plan to utilize over time as the project progresses towards full completion in 2026, and we expect to spend between $1.5 and $2 billion in Stage 3 CapEx this year. Turn now to slide 13, where I will discuss our 2024 guidance and outlook for the year. Today, we are introducing our full year 2024 guidance ranges of $5.5 billion to $6 billion in consolidated adjusted EBITDA and $2.9 billion to $3.4 billion in distributable cash flow. As we’ve been clear about on recent calls, 2024 represents our most contracted year to date, as all contracts signed to underpin our existing 45-million-ton platform have commenced, as well as some bridging volumes tied to contracts signed in support of our growth projects. It’s likely 2024 will represent a trough year for EBITDA after being down sequentially since 2022, as we expect to move upward post-2024 as Stage 3 commences and eventually reaches run rate in 2026 and beyond. With very little unsold capacity remaining throughout the year, these ranges largely reflect our 9-train run rate guidance adjusted for a higher proportion of volumes sold under long-term contracts or bridging volumes, as well as some forward selling of spot cargoes at higher international gas prices. These positive adjustments are partially offset by the prepayment and cancellation of the Chevron TUA and some incremental O&M costs related to our planned maintenance program. We expect to produce approximately 45 million tons of LNG this year, inclusive of planned maintenance at both sites. We remain optimistic we will achieve first LNG from train one of Stage 3 this year, but that would not impact our revenues or EBITDA in 2024, as it will likely remain in commissioning through year-end. In terms of portfolio optimization activities, we include any such transactions already completed in the guidance, but we do not forecast additional technical difficulties for 2022. We remain on track as we continue to execute on the plan this year and credit those to our commercial team who have sold our 2% open capacity going into this year, which has come down from 50 TBtu to 15 TBtu since the November call, highlighting that despite the recent drop in global gas indices, our EBITDA forecast remains above the $5.5 billion midpoint of our 9-train run rate guidance. As always, our results could be impacted by the timing of certain cargoes around year-end, as well as incremental margin from further optimization upstream and downstream of our facilities. Our distributable cash flow for 2024 could also be affected by any changes in the tax code under the IRA. However, the guidance provided today is based on the current IRA tax law guidance and assumes we qualify for the minimum corporate tax of 15% this year. As the year progresses, we will likely tighten our ranges consistent with what we’ve done in the last two guidance cycles. At CQP, our full year 2024 distribution guidance range is $3.15 per common unit to $3.35 per common unit, which maintains our base distribution of $3.10 and a variable distribution of between $0.05 and $0.25. As we have discussed publicly for the last year, by adjusting the variable component of our base plus variable distribution this year, we are preserving cash and balance sheet capacity at CQP in anticipation of funding the $10-plus billion SPL expansion project according to our disciplined capital investment parameters, which call for financing the project 50% with cash flow, while maintaining investment-grade ratings at both SPL and CQP, all within a traditional MLP structure. This DPU guidance keeps us on our previously assumed FID timeline and should be viewed as an indication of our confidence in the attractiveness and viability of the SPL expansion project. In the near term, deleveraging at CQP or SPL can be considered early investments in the SPL expansion project until we are in a position to formally sanction the project, raise financing, and begin construction, which we plan for in 2026. We expect the accretive SPL expansion project could increase the run rate distributable cash flow at CQP to over $5 per unit, a win not only for CQP unitholders but LNG shareholders as well, since we are in the high splits of the MLP, meaning approximately 75% of the incremental cash flow would accrue to CEI, and further meaningfully increase our run rate DCF per share target over time, as it was not baked into the original 2020 Vision. Looking beyond this year, the Cheniere story remains the same. Our highly contracted business model is built upon long-duration, fixed-fee, investment-grade, take-or-pay-style cash flows, which underpin the $40 billion natural gas infrastructure platform we operate today. As we pursue brownfield expansions, our approach will be consistent with that of the first over 55 million tons, adhering to our disciplined investment parameters so that our cash flows and our value proposition remain insulated from whatever transitory supply and demand imbalances may occur over the next decade plus. Our company provides investors with exposure to LNG, the theme, more so than the commodity, and it is inherent stability and long-term visibility in our contracted cash flows, growth, and shareholder returns that should enable us to continue to deliver meaningful value to our stakeholders 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.

Thank you. We’ll go first to John Mackay with Goldman Sachs.

Hey. Good morning. Thank you for the time. I appreciate the color you guys gave on the 2024 guide and that you’re already above the kind of 9-train run rate, but maybe you could just spend another minute talking through what kind of gets you to the low end of the range versus the high end of the range. It’s about the same $500 million range as you gave for 2023, but there were more open volumes unsold at that point. So maybe just kind of walk through those dynamics? Thank you.

Hi, John. It’s Zach. The $500 million range reflects the same approach we've maintained over the past few years. It remains under 10% of EBITDA. We're starting at the midpoint of that range, and there are a few influencing factors, despite the limited open capacity. A $1 change in CMI margins equates to $15 million, and with most of the year ahead, a $1 shift in Henry Hub can impact EBITDA and lifting margins by approximately $100 million, as can the timing of year-end deliveries, which can also shift around $100 million even if many end-of-year shipments are secured at favorable rates. Regarding the potential for reaching the low-end of our range, it would take an unforeseen operational issue, like an extended maintenance cycle beyond last year or a challenging hurricane season. On the upside, we have consistently stated that we don't provide guidance on optimization upstream and downstream that isn't secured. As conditions gradually improve throughout the year, even with lower margins and moderated volatility in Henry Hub, we expect to see some advantages, and we remain hopeful about dispatching a few more cargoes as the year progresses.

I appreciate all that detail. Maybe just a follow-up and maybe this one’s for Anatol. There’s been obviously a lot of focus in the market on the next three years, three-and-a-half years for the LNG market with U.S. and Qatar supply coming online and the demand picture maybe not warming up as fast as we would have hoped. Understand the kind of long-term dynamics you talked about earlier in the call, but maybe just spend a couple minutes walking through what you see as this kind of medium-term outlook and maybe what the supply-demand balance looks like around the back half of this decade? Thanks.

Thanks for the questions, John. I’ll begin by addressing the points in reverse order. The market's growth is determined by the supply available. The 10.5 million tons reflect the supply entering the market and being allocated where it is most needed. What gives us encouragement are the ongoing commitments to gas and investments in long-term infrastructure. Each month, we see the addition of new regasification terminals, and obtaining gas-fired power plants and turbines has become increasingly difficult due to global infrastructure deployment. We favor a scenario where LNG operates within high-single to low-double-digit return rates, which are attractive for us while remaining affordable for consumers. As highlighted in our prepared remarks, LNG remains competitive with coal and other energy sources. We are optimistic about the situation. You can expect to see increased volumes directed towards South and Southeast Asia, with marginal demand returning to the market. We're already noticing this trend in the early days after the Chinese New Year, and we believe these trends will persist for many years. Our commercial engagements with key counterparties are progressing well. We are confident that the market will effectively absorb this volume, whether it comes online as scheduled or experiences modest delays as seen in the past. Overall, we anticipate robust market growth and capacity to accommodate the upcoming wave of supply.

That’s great. I appreciate the time today. Thank you.

Thank you. We’ll go next to Jeremy Tonet with JPMorgan.

Hi. Good morning.

Good morning, Jeremy.

I just wanted to kind of unpack a little bit more on your earlier comments there. When you talked about beating the midpoint at the prior guidance range, I don’t know if it’s a $0.5 billion or so. Just wondering, what type of quantum of optimization Cheniere has been able to realize because of volatility in the market, both upstream and downstream operations? What’s that number look like?

It’s been in the hundreds of millions of dollars, Jeremy, in terms of the optimization. And I’d say hundreds of millions of dollars, both in the upstream and downstream side. Mind you, Henry Hub was significantly up in 2022, moderated a bit last year and it’s even further down today. So we’ll see how much can be there. And then on the other side, yeah, we have a ton of IPM deals, DES deals. So we’ll optimize those as we see fit and subcharter out any of our length in our shipping portfolio, which in the past has added hundreds of millions of dollars. Mind you, even that market has moderated as well in terms of the volatility. But when you add those two things together, it would really take, yeah, great execution and some opportunistic moments throughout the year for us to get to the high end of the range.

Got it. So just to be clear there, then, hundreds of millions of dollars of synergies or optimization, rather, upstream and downstream, both we’ve seen historically. And that’s not really baked into the guidance as we see it today, because the guidance really just locks in what you’ve already locked down. Is that the right way to think about things?

We have been clear for some time that this year would bring us closer to the run rate. Given our proactive approach, we are currently at 15 TBtu, which remains above the midpoint of the run rate range for nine trains, even without the TUA from Chevron. This aligns with our expectations, reflecting what we had incorporated into our 2020 Vision and the projection of over $20 billion in cash flow through 2026. We will see how optimization unfolds, but that is not included in our current guidance.

Got it. Very helpful. So a lot of upside potential, but not baked into the guide. Very clear there. Thank you very much.

Thanks, Jeremy.

We’ll go next to Brian Reynolds with UBS.

Hi. Good morning, everyone. Maybe to talk about just the distribution cut on the variable side, if you could just help talk about sizing and timing of that, and ultimately, how it relates to translating into the 15 MTPA expansion, assuming like an 850 build. So it seems like there’s still a little bit of variable component in the guidance above that 3.1 kind of run rate. So just kind of curious how you came to that number and how we should think about pre-funding, just given it could be $10 billion to $15 billion for the SPL expansion? Thanks.

Sure. So as we thought about the variable adjustment, I would say, over the last two years, we were incredibly efficient with our cash inside the CQP. And with the distributions, including the variable being over $4 both years, we probably distributed out almost $700 million more than even the run rate DCF per unit guidance that we give. So now it’s time, as we’re getting closer to officially filing with the FERC for the Sabine expansion and are targeting that 2026 FID, that we’re going to start retaining some of the cash and bringing down the variable. We’re saving around, let’s say, $700 million. And a large portion of that will actually just go into paying down a bit of debt that’s coming due, giving us this flexibility financially to add leverage capacity once we FID the project, stay with that, let’s say, 50-50 debt-to-equity during construction, and maintain the base distribution throughout while still being investment grade at Sabine and CQP. So we’re trying to thread a needle there, and to do that, we need to start planning now. Mind you, some of the cash that’s retained is also going into the development of supporting the feed and getting Sabine expansion ready for FID and there’s even $100 million or so baked in there for debottlenecking purposes. We think we’ve found some ways to get to the higher end of the $4.9 to $5.1 range on the first exchange that hopefully can pay dividends to us in the coming years. So there are a few things in there, but it is mainly debt pay down in the near-term to add leverage capacity and flexibility in the long-term. Mind you, it’s still $2 billion of distributions coming out of CQP this year with $1.2 billion of that going to CEI. But if we can pull all this off and build this project and get to that over $5 DPU, we’re talking about almost $2 billion of consolidated EBITDA and we’re talking about almost $1 billion of DCF to CEI. So it’s a win-win for all parties.

Right. Makes sense. Appreciate all that. My second question just around maybe further optimization. I know for the SPL expansion, it seems like there are some capital efficiency and optimization opportunities with boil-off gas and some other things. But as we think about existing asset base, I think, you talked about 45 MTPA being a good run rate. It seems like 2023 was above that. As we look ahead to 2024, have we squeezed out all the optimization on the existing asset base or are there some new technologies or engines that could help further drive efficiencies and optimization on the existing asset base going forward? Thanks.

Brian, this is Jack. While we’re not going to raise our guidance beyond 45 million tons today, I continue to be impressed by what my operations team can achieve. Whether it's optimizing the trains or adjusting our maintenance schedule, they have consistently exceeded expectations. As Zach mentioned, we're now looking at around $100 million for debottlenecking. One aspect I'm particularly excited about is our exploration of new technology for our fin fans, which are the fans used to cool the refrigerant that turns natural gas into a liquid. We see significant potential there, and we plan to test it thoroughly this year. I hope to provide you with more updates in future calls.

Great. Appreciate it. Have a great rest of your morning.

Thank you. We’ll go next to Theresa Chen with Barclays.

Good morning. Going back to Jack’s comments on the evolving regulatory backdrop, with respect to the DOE pause, I’m just curious how this impacted conversations with customers, both within the context of commercializing your expansion projects, but also in relation to the broader commitment that the U.S. Government has to LNG exports and the perception of your global customers and the credibility and competitiveness of the U.S. LNG industry. Any salient commercial color you can provide would be great?

Theresa, I want to start with some general comments before passing it over to Anatol. This isn’t anything new for us. Cheniere has navigated through several administrations and numerous studies regarding the public interest in exporting America’s natural gas. What is surprising is that over the past eight years, Cheniere has demonstrated the advantages of exporting U.S. LNG to America and its allies. It’s troubling that we still require scientists to theoretically discuss the benefits. However, we know these benefits are real, proven, and recognized worldwide. I’m eager to see the results of this study and the comment period that follows so we can clarify the record accurately. I hope that reason will prevail and the facts will speak for themselves, making this pause seem like a distant memory. Now, I’ll turn it over to Anatol for insights on our discussions with customers.

Thanks, Jack, and thanks, Theresa. To continue from Jack's comments, this is the third time the DOE is conducting this study. The first two studies are now behind us as the U.S. moves from mid-90s capacity of millions of tons per year to nearly 200 million tons per year. We firmly believe that the U.S. will be the first market to export 200 million tons and we will work closely with the DOE throughout this process. Our efforts over the past four to five years on our life cycle assessment, environmental science, tracking emission profiles, and providing cargo emission tags are all new factors to consider. Additionally, the increase in LNG exports from the U.S. and the gas allocated for LNG exports is also a new aspect of this situation. As Jack mentioned, we anticipate the DOE’s thorough science-based evaluation and the updates to its profile. We are confident, and we communicate this to our customers, that Cheniere will successfully navigate whatever outcomes arise from the DOE and continue with our planned expansions. This is not a new situation for us; we have been having these discussions for over a decade and are confident in our ability to handle them moving forward, which is the same message we consistently share with our customers.

Thank you. And Anatol, going back to your comments related to the elasticity benefits in the market currently, as price-sensitive buyers increase interest. Can you elaborate on that and what do you think the magnitude of that demand can be if prices remain low?

The market dynamics we are currently facing are quite unique, particularly due to the significant amount of infrastructure developed over the past three to five years. While we often discuss the liquefaction capacity expected in the latter half of this decade, it’s noteworthy that there’s almost always a new regasification terminal being added. For instance, Europe has added five terminals and Southeast Asia four, with Greece planning to add the Alexandroupolis terminal soon. The capacity to consume this increased volume is substantial, and we are nearing a situation where the import capacity could reach almost 1,300 million tons per year compared to the current 400 million tons of exports. Markets like India, which have seen a robust rebound as prices stabilize, are now set to import more than double what they did in 2023. This is a significant change from early 2020, when India was more of a price-sensitive consumer due to lower prices. I anticipate that the demand driven by price sensitivity will surprise us positively as countries like the Philippines, Thailand, Vietnam, and India are ready to accept larger volumes. I am optimistic about this trend, especially as we observe the impending liquefaction numbers, which historically tend to underestimate schedules and utilization. As the world adjusts, it certainly has the potential to consume whatever additional supply is introduced.

Thank you.

Thank you. We’ll go next to Spiro Dounis with Citi.

Thanks, Operator. Good morning, team. I want to go back to the 2020 Vision, if we could, Zach. It’s for about one and a half years into that program, and you mentioned tracking on or even had a plan to-date. But I guess if we just shift the focus to the forward outlook and think about that outlook for 2025, oh, sorry, 2024 through 2026, how does that compare to what you envisioned back in 2022? You sort of set that $20 billion target. I imagine some puts and takes since then, Stage 3 maybe coming on early, not sure where you had the LNG curve then, just trying to understand how much conservatism you imputed there.

We still have over $20 billion in available cash through 2026, with some fluctuations along the way. In the past year, we earned more than expected. This year was always intended to be heavily contracted, and we anticipated guaranteed completion dates for Stage 3, particularly noting that Train 7 won’t be operational until 2027. Overall, we remain above $20 billion, having deployed over $8 billion, which is about 40% of our plan in roughly 30% of the time. The key focus now is the excess cash and our future deployment strategy. As seen with the debt reduction, which will be less than what we accomplished this year, we’re primarily concentrating on catching up with the buyback and finalizing the equity funding for Stage 3. Thus far, we’ve managed over $2 billion in buybacks and reduced over $3.5 billion in debt. There’s still around $1.5 billion needed for the one-to-one catch-up. We intend to prioritize this in the coming year. The buyback program was designed to be opportunistic, which is why the number of shares outstanding is gradually decreasing. By the end of this year or early next year, we might need to increase the buyback plan again, continuing our long-term goal to reach a steady rate of 200 million shares.

Got it. That’s helpful, Zach. Thank you. Second question, just given your, I think, one of the largest buyers of natural gas, just curious how you’re thinking about the supply over the next few years. I think right now, producers understandably retrenching, just given where pricing is. At the same time, we’re hearing from some midstream companies that there are pockets of shortages in the Mid-Atlantic just due to the rise in data centers and other types of electric needs. So curious as you think about that outlook when all this energy capacity comes online in the next few years, do you think the producers are going to be able to stand up and sort of deliver on all that supply?

Thanks, Spiro. This is Anatol. Look, we’re very comfortable with and confident in the resource and the economics of developing that resource in this nation. The challenge we have, which we’ve highlighted multiple times for years, is building infrastructure. And I think it’s going to be a long time before anybody attempts another Mountain Valley Pipeline or equivalent out of what is an incredible resource in the Northeast, in the Marcellus and Utica. That said, you know us and we take very seriously and as sacrosanct gas supply and the infrastructure needed to supply our facilities for decades to come and that’s one of many reasons why the U.S. Gulf Coast is our home and we’re very confident that Louisiana, Texas, Mid-Continent can continue to develop the resource and the infrastructure necessary to get it to us. Jack mentioned the ADCC pipeline that’s moving well, obviously. Permian continues to grow and we’ll need more intrastate infrastructure. We will need more interstate infrastructure as you probably saw we filed for together with our SPL application. So we’re confident that the Gulf Coast will continue to be well supplied, but obviously, would prefer that other resources in the country were able to get to market as well.

Got it. Helpful color as always. I’ll leave it there. Thanks, guys.

Thank you. We’ll go next to Tristan Richardson with Scotiabank.

Hey, guys. Just one for me this morning. Follow up on a prior question about distribution levels of CQP. I mean, I think that the philosophy of a base plus variable is relatively new going back to 2022. But is there a potential here that you could rethink that philosophy with the focus on retaining more cash in anticipation of the proposed SPL expansion?

I think what we planned in 2022 was planned for distributing out a lot of cash efficiently in 2022 and 2023, and then being in a position where we can do a mega project inside an MLP. So when we set the $3.10 distribution as the base, we intend to uphold that. Obviously, this year, we’re actually even above that. We had enough cash to be able to meet our objectives going into developing and preparing for the Sabine expansion. And so we’re going to distribute that out to CEI and our unit holders. But when it comes down to FID-ing the project in the next couple of years, the goal is to maintain the base distribution, stay investment-grade everywhere and fund the project within cash flow. So this all kind of works, which is pretty amazing for an MLP, but one with six trains fully up and running, it works quite well. And then as you think about the $3.10 base distribution or the $3.25 this year, yeah, again, we’re still talking about $2 billion of distribution and an over 6% yield. So we were cognizant of making sure that that was competitive and kept us going in the right direction with our unit holders and our own stake in CQP.

I appreciate it, Zach. And then maybe just to follow up on the 2024 guide, I think in the prepared comments, you highlighted a higher proportion of bridging volumes as one of sort of the upward items in the guide versus the 9-train runway. Can you talk about how maybe mechanically bridging volumes work and how that can kind of contribute more to that upside?

Sure. Those bridging volumes are basically long-term contracts that helped us underpin or FID Stage 3 that have already begun before Stage 3 has begun. So those bridging volumes are in our 200 to 250 range and why we went into this year 97%, 98% contracted. So when we think about the bridging volumes, though, in the context of having some near-term volumes on a 15-year to 20-year deal, if the curve is liquid, we will get value for the curve and blend it over the 20 years or the 15 years. So those margins are incrementally up to a deal that might start with a CP of a train up and running, but we’re only talking about nickels and dimes here.

Thank you. We’ll take our final question from Ben Nolan with Stifel.

Yeah. Thanks. Hey, guys. Well, for my first one, as we think about how the year plays out and appreciating that virtually everything is fixed, is there going to be any sort of cadence to how the EBITDA and the cash flow comes through or should it be pretty linear, do you think?

It’s never perfectly linear. We produce more in the winter months at the sites. So with that, you should expect slightly more EBITDA in the colder quarters versus the summer or the shorter seasons. But basically, it should be a year of $5.5 billion to $6 billion to EBITDA and why we don’t guide on a quarterly basis. But we expect 45 million tons and we are now 99% contracted and the optimization, I’m not forecasting that today. So that’s probably the only thing that could create some variability quarter-to-quarter.

Okay, I appreciate that. For my follow-up regarding the regulatory side, I'm curious if you think the challenges for new projects are becoming more significant, or if you believe that the current discussions are influencing Washington's perspective on the business.

No. Well, first, the hurdle has always been high, right? This is a very capital-intensive business. It takes years to get one of these across the finish line. It’s a balancing act between capital costs and SBAs and contracted amounts and financings and everything else. We make it look easy, Ben, but it’s not. The only positive thing in the past was the regulatory certainty around America and contract sanctity. And while I think this is politically motivated, I’m hopeful that at the end of the day, we go back to where we were before, which is we let the market dictate which projects will survive and which ones won’t. And that’s where we’ve always been and the market’s been extremely efficient at who they’re going to bet on and I would bet on Cheniere every single day.

All right. Well, and I appreciate you guys putting me in. Thanks.

Thank you and thank you all for all of your support.

That will conclude today’s call. We appreciate your participation.