Cheniere Energy, Inc. Q4 FY2021 Earnings Call

Thank you, operator, and good morning, everyone. Welcome to Cheniere's fourth quarter and full year 2021 earnings conference call. The slide presentation and access to the webcast for today's call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere's President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and Zach Davis, Executive Vice President and CFO. Before we begin, I would like to remind all listeners that our remarks, including answers to your questions, may contain forward-looking statements, and actual results could differ materially from what is described in these statements. Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix 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 3. Jack will begin with operating and financial highlights. Anatol will then provide an update on the LNG market, and Zach will review our financial results and guidance. After prepared remarks, we will open the call to Q&A. I'll now turn the call over to Jack Fusco, Cheniere's President and CEO.

Thank you, Randy, and good morning, everyone. I appreciate you joining us today and for your continued support of Cheniere. I'm glad to be here this morning to review our 2021 results and achievements, discuss our improved outlook for 2022, and share my enthusiasm about Cheniere's future. 2021 was a pivotal year for Cheniere. We completed the construction of our initial 9 train platform and increased our production capacity to 45 million tons per year. We also reached a significant cash flow turning point and executed several long-term contracts, positioning Stage 3 toward a final investment decision this year. The contract with EOG we announced this morning effectively completes the commercialization of Stage 3. While 2020 tested our resilience, 2021 highlighted the strength of the Cheniere platform. The competitive advantages I have mentioned over the past almost six years were evident throughout the year, contributing to these results and the increased guidance we are providing for 2022. As we enter 2022, the market for LNG is exceptionally supportive; an extended period of volatility and high prices due to underinvestment in infrastructure and geopolitical issues emphasizes the critical need for reliable, affordable, secure, and environmentally friendly energy supplies over the long term. In the fourth quarter of 2021, we generated a consolidated adjusted EBITDA of $1.3 billion and distributable cash flow of about $540 million, on revenues of approximately $6.6 billion. We exported a record 153 cargoes during the quarter, bringing our annual total for 2021 to 566 LNG cargoes. To date, we have exported over 2,000 cargoes to 37 countries and regions globally. Throughout the year, we consistently raised our full-year EBITDA and DCF guidance after announcing the initial ranges in November 2020, ultimately increasing guidance by $700 million and $600 million, respectively. I'm delighted to report that we met this enhanced guidance, generating approximately $4.9 billion in consolidated adjusted EBITDA and $2 billion in distributable cash flow for the entire year. We are now raising our full-year 2022 guidance to between $7 billion and $7.5 billion in consolidated adjusted EBITDA and $4.3 billion to $4.8 billion in DCF. This significant guidance increase is mainly driven by three factors: the earlier-than-anticipated substantial completion of Train 6, improved market margins since November, and the timing of some cargoes shipped around year-end 2021, as previously noted. In addition, we are raising our distribution guidance range for CQP to between $4 and $4.25 per unit and introducing a revised distribution plan. Today at CQP, we announced the start of quarterly distributions that will include a base amount and a variable amount, and we expect to initiate this with the first quarter distribution of 2022. This approach allows for a more efficient distribution of CQP's cash, justified by the completion of Train 6. Zach will elaborate on the financial results and guidance updates shortly, but we clearly expect to build on our successes from 2021 and achieve even greater results in 2022. In the fourth quarter, our commercial momentum continued as we signed long-term sales and purchase agreements with Sinochem and Foran, which complemented the long-term contracts we secured earlier in the year with Tourmaline, ENN, and Glencore, bringing our total long-term commercial volumes signed in 2021 to around 80 million tons equivalent and over $11 billion of fixed fees over the next two decades. Both agreements with Sinochem and Foran include early or bridging volumes, further highlighting the value of our customized market solutions. Our commercial achievements in 2021, along with the recent EOG agreement and current market dynamics, have intensified the focus on Stage 3, and we remain confident in proceeding with a mid-year final investment decision. Our strong financial performance has allowed us to speed up the execution of our comprehensive capital allocation strategy introduced in September. For the full year, we surpassed our goal of $1 billion in debt repayment by $200 million, and we expect to significantly exceed this target in 2022. We also paid our first quarterly dividend in the fourth quarter of 2021 and repurchased over 100,000 shares of LNG stock since resuming share repurchases last year. Our efforts continue to enhance our market-leading reputation for reliability, which is crucial in light of recent market volatility and the urgent need for energy security globally. We declared substantial completion for Corpus Christi Train 3 in the first quarter of 2021, and recently announced the substantial completion of Sabine Pass Train 6. With these two additions, we have completed our initial 9-train platform safely, ahead of schedule, and on budget. We now process over 7 billion cubic feet per day, which is about 7% of total U.S. gas production, maintaining near-perfect scheduling efficiency. Importantly, our safety metrics have improved year-over-year, especially commendable considering we were commissioning and completing trains at both Sabine Pass and Corpus Christi during the year. Safety is the foundation of our achievements, and I take pride in our ongoing commitment to safety and operational excellence, delivering real benefits to all Cheniere stakeholders. Now, moving on to my key goals for the Cheniere team in 2022, this is not an exhaustive list, but I want to highlight some of my main priorities for the year. Our foremost intention is to meet the upwardly revised financial guidance released this morning. Energy markets remain volatile, but we have strong visibility into our capacity to deliver results within the provided ranges due to our market exposure management. Secondly, we aim to advance the Corpus Christi Stage 3 project towards final investment decision; this project offers competitive expansion that aligns with our disciplined growth and capital investment standards, supporting the accretive growth we target in our long-term capital allocation plan. As I noted earlier, the project is in a strong position for approval, and we are finalizing the engineering, procurement, and construction contract with Bechtel. After successfully initiating Corpus Christi Train 3 and Sabine Pass Train 6 with limited notices to proceed, we plan to replicate this for Stage 3, which could occur soon as we advance towards full final investment decision and full notice to proceed on all seven trains this summer. We are also finalizing the contract portfolio for Stage 3, including potential new long-term agreements and adjustments with existing contracts at CMI. The enhanced EOG-IPM agreement provides essential commercialization support for Stage 3. Furthermore, we have transferred the ENN and Glencore SPAs from CMI to Sabine Pass and aim to further optimize CMI's long-term contract portfolio to support our projects. On the financing front, Zach and his teams are preparing to begin the financing process with the banks. Everything is coming together, and we look forward to executing world-class performance on Stage 3. Finally, I want to stress the significance of ESG as a priority for 2022. We made significant progress on our ESG initiatives in 2021, particularly in climate and sustainability, showcasing our leadership through several major programs launched last year. Our efforts, from our cargo mission tags to our QMRV study with producers and shipping partners, stem from a multi-year commitment grounded in our climate and sustainability principles introduced in 2018. These initiatives reflect our approach to climate and sustainability challenges and opportunities, focusing on transparency, science, our supply chain, and operational excellence. We are pleased to have our efforts recognized by our communities and stakeholders. Earlier this year, we were honored as a JUST 100 leader by JUST Capital, ranking companies on corporate behavior issues such as climate, job creation, and community development. We are proud to be the top-ranked company in our sector and 35th overall out of nearly 1,000 companies. Just last week, we were acknowledged as one of America's most responsible companies in Newsweek's annual ESG performance ranking for the first time. My goal for 2022 is to elevate our leadership position in these essential areas within our industry. Our ESG strategy is designed to be actionable, not merely aspirational. The initiatives detailed in 2021 substantiate this commitment. In 2022, we intend to further embed ESG into our business and strategy, believing it will enhance our competitiveness and the long-term sustainability of our LNG operations. These are not empty commitments; we are acting on them. In 2022, 30% of our annual compensation scorecard, applicable to all Cheniere employees, will be based on ESG metrics and milestones. 2021 was indeed a transformative year for Cheniere, fueled by a dedicated and results-oriented workforce that continues to inspire me. We begin 2022 with significant momentum and look forward to delivering on the high expectations we set for ourselves year after year. Now, I will hand over the call to Anatol for an update on the LNG market.

Thanks, Jack, and good morning, everyone. Please turn to Slide 9. Let's start with a quick look at the full-year numbers for 2021. Last year, we saw 5% growth in LNG imports compared to 2020, taking total trade to 374 million tons. This 18 million tonne year-over-year growth took LNG trade figures to well above pre-pandemic levels. Virtually, all the supply growth came from the U.S., which exported an additional 23 million tonnes year-over-year. Impressively, Cheniere was responsible for over half of that U.S. volume growth. Despite the relatively healthy overall growth in total LNG trade, the increase in supply was more than matched by demand growth in Asia and Latin America, while imports into Europe declined by 9% year-over-year. Low storage inventories in Europe following a period of cold weather early in the year and lower LNG and pipeline imports as compared to 2020 resulted in spot gas prices in Europe and Asia rising throughout the year, as the market became increasingly concerned about the adequacy of storage fuel levels approaching winter in both regions. The rising geopolitical tensions in Europe in the fourth quarter compounded market uncertainty, leading to unprecedented prompt price levels and extreme volatility during what is arguably the most inelastic demand period of the year. As such, competition between Europe and Asia for LNG supplies led to a sharp inversion in the two regional price benchmarks of TTF and JKM, with Europe outbidding Asia to attract LNG cargoes in the fourth quarter. Both TTF and JKM reached record daily highs in December of last year, with TTF trading at $59.60 in MMBtu, more than $10 in MMBtu higher than JKM at $49.30. More recently, an increase in LNG flows into Europe predominantly from the U.S. has helped alleviate some of the extreme market tightness we saw in the fourth quarter. TTF settled January at $28.90, while JKM settled at $35.70 in MMBtu, still, of course, high by historical standards, but well below the peak levels at year-end. Please turn to Slide 10. With the resurgence of LNG imports in the fourth quarter, LNG represented 43% of all Europe's gas imports in December, with the U.S. providing over one-third or 36% of all LNG receipts. That share rose to 45% in January, reflecting the highest share of LNG volumes ever imported into Europe from any single country. European LNG imports reached 22.6 million tonnes in the fourth quarter, up 36% year-on-year, as the storage deficit continued to widen. European storage levels started dipping below the 5-year lows around the middle of '21, with the deficit reaching about 19 billion cubic meters in December, over triple the deficit during the same period last year. This period of low storage levels during '21 was caused by a number of factors: lower domestic production, coupled with lower pipeline imports from Russia into Continental Europe; constrained gas availability for injections and LDC demand throughout the year. In addition, lower renewables output and a drop in nuclear generation further exacerbated the fuel shortage. Nevertheless, countries in Europe pressed ahead with planned coal and nuclear phaseouts last year. Germany, for example, shut down 7.3 gigawatts of coal capacity and 4.3 gigawatts of nuclear power capacity just prior to year-end. We believe these dynamics, along with the recent geopolitical tensions impacting European gas prices, continue to signal that LNG will remain a critical component of Europe's energy mix for the long term. At the same time, Asian LNG demand remained robust throughout '21, while policy and infrastructure investment signals continued to reinforce future demand growth in the region for the long term. Despite increased nuclear generation in Japan, overall Asian imports increased 8% to 273 million tonnes in 2021. Nuclear outages and retirements in both South Korea and Taiwan, along with restrictions on coal burn in the winter, supported LNG import growth, while both continue to show policy commitments to increased use of natural gas as a primary energy source, what we have long described as the structural shift to natural gas. Accordingly, Taiwan cleared the way for a new LNG import terminal, confirmed its plans to be nuclear-free by 2025 and committed to increase its use of LNG in its power mix from 36% currently to 50% by 2025. Similarly, in its 14th gas plan on carbon neutrality roadmap, South Korea pledged to reduce the use of coal and nuclear and designated LNG as a green fuel in its taxonomy, supporting further near-term investment in natural gas infrastructure and underscoring the important role of natural gas as a primary fuel for South Korea in the long term. China was the largest single contributor to demand growth last year, adding over 11 million tonnes of demand year-over-year and overtaking Japan as the world's largest LNG importer for the first time. China's significant economic rebound in 2021, which saw a GDP growth of 8.1%, fueled higher demand for virtually all energy products. Last year, China announced plans to be carbon neutral by 2060 and reinforced its intention to reach peak carbon emissions by 2030. Both pledges are constructive for gas and LNG, as China's plans to grow its gas demand are concrete and already in progress. The country is currently building about 22 gigawatts of gas-fired power generation, adding over 100 million tonnes per annum of LNG import capacity by 2025 and has ramped up its gas and LNG term contract activity in recent months, including our recent long-term contracts with ENN, Sinochem and Foran. Moving on to Slide 11, I'd like to highlight the rise in long-term contracting activity in the second half of 2021 and into 2022, which Cheniere has certainly participated in with the deals we signed last year and the one we announced this morning with EOG, effectively completing the commercialization of Stage 3. There was a notable increase in commercial transactions during the year, with U.S. sourced LNG in high demand, which is intuitive given the relative stability and affordability of Henry Hub versus international gas hubs. International prices began to send that price signal midyear, with U.S. Gulf Coast margins moving above our long-term assumptions in the second quarter. The inexorable upward shift in midterm forward margins has continued to offer a tailwind to our commercial offering, which, as Jack highlighted, often includes bridging volumes. Firm contracts with mid- and long-term tenors increased almost 80% year-on-year, surpassing 50 million tonnes in 2021. U.S. projects made up about 45% of total firm contracts, which is nearly double the amount of U.S. price deals last year. This surge in activity was underpinned by strong demand from Asia, particularly China. About two-thirds of all contracts signed in 2021 were executed with Asian buyers, 45% of which, in turn, were from China. Cheniere is proud to have added several new customers in 2021, including our new buyers in China. The ongoing evolution of the Chinese gas market, including the expansion of non-NOC regas capacity access in China should facilitate terminal access and increase the exposure of emerging buyers to the international LNG market. Cheniere's ability to execute these contracts efficiently, while providing buyers energy solutions tailored to the needs and constraints of their markets, demonstrates the competitiveness and flexibility of our offerings and the attractiveness of our product in providing support to policy decisions and other fundamental drivers impacting the energy landscape of the future. In addition to organic market growth, the LNG market continues to undergo a transformation, as legacy contracts begin to expire, providing additional tailwinds to new contracts. Over 200 million tonnes are expected to expire over the next decade, and we estimate that for the period between 2026 and 2030, roughly 100 million tonnes of LNG contracts will need to be replaced. While some of these could be renewed with existing suppliers, there are significant uncertainties surrounding feedstock availability, price indexation and direction, environmental profile and other geopolitical issues brought to the forefront by the recent market turmoil. We see an increase in opportunities for new demand and long-term contracts emerging, as we believe a portion of these deals will form the basis of the next contracting cycle, and Cheniere continues to be well positioned to capture a segment of this demand, along with new contracts that underpin demand growth. Now 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 2021 financial results as well as our key financial accomplishments, our increased 2022 guidance and our 2022 financial priorities. Turning to Slide 13. During the fourth quarter, we generated adjusted EBITDA of $1.3 billion and distributable cash flow of approximately $540 million, as our marketing and portfolio optimization teams continued to take advantage of our portfolio volumes in a sustained higher margin environment in global LNG markets. Adjusted EBITDA was partially offset by an increase in realized losses from financial derivative instruments used to hedge our exposure to the commodity markets, in which we have contractual arrangements to purchase or sell physical LNG. We recognized an income of 520 TBtu of physical LNG during the fourth quarter, including 513 TBtu from our projects and 7 TBtu sourced from third parties. 87% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements. We generated a net loss of $1.3 billion in the fourth quarter. The net income line continues to be impacted by the unrealized derivative impact mainly related to our long-term IPM agreements, as we have discussed on prior earnings calls. The derivative accounting, coupled with the long-term duration and international price basis of our IPM agreements, result in fluctuations in fair market value from period to period, as LNG curves move. While IPM agreements may contribute to this variability, those agreements provide us with the stable long-term cash flows that help support our infrastructure platform. As such, we will continue to pursue them as part of our strategic growth plans, as we just demonstrated with the EOG-IPM agreement. The EOG agreement effectively completes the commercialization of Stage 3, an accretive project, which meets our disciplined capital investment parameters related to returns, accretion and contracting. For the full year, we generated consolidated adjusted EBITDA of approximately $4.9 billion and distributable cash flow of approximately $2 billion, both exceeding our initial guidance ranges and coming in at the high end of the revised ranges we provided in November. Our outstanding performance in 2021 was a result of the hard work and dedication of the entire Cheniere workforce, despite market volatility and continued COVID-related challenges throughout the year. For the full year, we recognized an income of almost 2,000 TBtu of physical LNG, including over 1,950 TBtu from our projects and just under 50 TBtu sourced from third parties. 83% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements. Before discussing our financial guidance and priorities for 2022, I'd like to also recap some of our key achievements in 2021. First and foremost, we rolled out our comprehensive all-of-the-above capital allocation plan, which was enabled by the near-term completion of our 9-train platform and the meaningful cash flow inflection point we have reached as a company. Since the announcement in September, we have not only executed on the plan, but the timelines for achieving the goals of our capital allocation priorities have been accelerated due to the sustained higher margin environment. Last year alone, we repaid $1.2 billion of indebtedness, strengthening our balance sheet and outperforming our $1 billion annual debt paydown goal. We raised over $5 billion in aggregate financing last year in support of our long-term balance sheet priorities, further demonstrating our access to capital and Cheniere's credibility with capital providers. Among our refinancing transactions in 2021, I'd like to highlight the 2032 unsecured notes we issued at CQP in the third quarter, as this transaction accomplished several key priorities simultaneously. With this transaction, we achieved the lowest price for a 10-year non-coal fired high-yield issuance in energy at 0.75%, which reduced interest expense by approximately $30 million per year; officially migrated project-level debt to the corporate level; and further de-secured our consolidated balance sheet. Through our combined refinancing and debt repayment activity in 2021, we extended the weighted average maturity of our outstanding debt by over a year and lowered our weighted average borrowing rate. One of the primary objectives of the capital allocation plan is to achieve consolidated investment-grade credit metrics, and we are pleased that our accelerated execution on the plan is being recognized by the rating agencies in the form of continued ratings progression. Just last week, S&P upgraded both CEI and CQP to BB+, one notch away from investment-grade ratings, and maintained positive outlooks at both companies. S&P cited improved financial metrics due to the progress we've achieved to date and the expectation of continued execution under the capital allocation plan as primary justification for the upgrade and positive outlook. As I mentioned a moment ago, we expect to surpass our $1 billion debt paydown goal again in 2022, as we have already exceeded over $0.5 billion of debt pay down since the beginning of the year with the redemption of the 2045 converts at CEI in January generating significant cash flow and have the fully drawn freely prepayable credit facility of approximately $1.7 billion at Corpus to flexibly pay down over time. In 2021, we initiated a dividend at CEI for the first time and paid our inaugural quarterly dividend for the third quarter. In addition, we continued to repurchase shares under our newly reset $1 billion share repurchase program. For the year, we repurchased over 100,000 shares for approximately $9 million. Although debt pay down remains our capital allocation priority in the near term, our share repurchase program is designed to be opportunistic and enable us to take advantage of dislocations in the market. As we continue to accomplish our debt pay down goals, we expect to be able to deploy incremental capital to our other capital allocation priorities, including capital return via future repurchase authorizations. Finally, we made significant progress on commercializing Stage 3 to meet or exceed our disciplined growth capital investment parameters during the year. 2021 was truly a transformative year for Cheniere from a financial perspective. But as Jack mentioned, we expect to build on that and have an even better 2022. Turn now to Slide 14, where I'll discuss our significant increase in 2022 guidance. We are increasing the consolidated adjusted EBITDA range to $7 billion to $7.5 billion and distributable cash flow range to $4.3 billion to $4.8 billion. Since announcing our initial guidance ranges for 2022, Train 6 at Sabine Pass reached substantial completion considerably earlier than expected, enabling LNG sales from Train 6 to contribute to both EBITDA and DCF for almost 2 months longer than originally forecast. In addition, the global LNG market continued to strengthen since November, providing an uplift in value to our remaining open volumes. And as we mentioned in November, the timing of a few cargoes around year-end 2021 also provide some tailwind to our forecast for 2022. Thanks to the team's execution and the market fundamentals, this elevated guidance should provide us momentum to achieve record DCF per share levels in 2022 in the high teens as well as be a catalyst to achieving investment-grade credit metrics throughout the complex sooner than previously expected. With respect to EBITDA sensitivity, we have sold over 95% of our total expected production for this year and have less than 100 TBtu unsold. We currently forecast that a $1 change in market margin would impact EBITDA by approximately $50 million for 2022, after accounting for the long-term origination volume placeholders. This morning, we also announced an evolution in the CQP distribution plan, whereby the distribution is expected to be comprised of a quarterly base amount equal to $0.775 per unit or $3.10 annualized, plus a variable amount equal to the remaining available cash each quarter after first taking into consideration amounts reserved for debt repayment and other capital allocation priorities, including anticipated cash funded CapEx and cash reserves needed as part of the ordinary course of business. This plan is expected to commence with the distribution relating to the first quarter of 2022. As a result, we are raising the full year 2022 distribution guidance range at CQP to $4 to $4.25 per common unit. This updated distribution plan is enabled by the completion of Train 6 and is dynamic, flexible and long term. We believe it is an efficient way to accelerate cash returns to unitholders, while retaining flexibility for future debt paydown within CQP as well as growth opportunities at Sabine Pass. In short, a win-win for both CQP unitholders and CEI shareholders. That concludes our prepared remarks. Thank you for your time and your interest in Cheniere.

We'll now take our first question from Jean Salisbury with Bernstein.

My first question is for Anatol. I keep hearing from our European analysts and clients that even with all that's happened, European utilities are really hesitant to sign long-term gas deals above kind of 10 to 15 years because gas contracts are supposed to end by 2049. That duration obviously makes it hard to get financing for new trains. So I guess, my question is, has that been what you've seen in your experience? And how do you see that mismatch shaking out over the medium term?

Thanks, Jean Ann. Thanks for the kind comments. Europe is, we think, evolving in a healthy direction now after some meaningful challenges that were a function of regulatory compacts and the kind of Brussels direction; the inclusion of gas in the green taxonomy is a key issue. As you know, we've had some success with midterm and long-term deals that were on the kind of 10- to 15-year range. We expect to see more of that traction going forward. Whether we will see kind of a foundation customer commitment of 20-plus years out of a European load serving entity, it's too early to tell. But given the recent developments, I think the trend is in the right direction. And clearly, we've demonstrated our ability to meet their objectives in terms of having the right environmental credentials for our product as well.

Great. And then I think my second question is for Zach. Depending on how things go, it's possible that you could hit investment grade and be poised for S&P inclusion sometime next year. Can you talk about what it would take for Cheniere to get into the S&P? And are you actively positioning for that?

We're doing the best we can on that, but it's not really in our control. We had met all the requirements for quite some time in previous years, whether it be market cap, sufficient free float and net income, and it's kind of hard to believe we wouldn't be the most logical energy candidate at this point. Considering, I believe, we're larger than a third of the energy constituents in the S&P 500. However, with some of the unrealized derivative moves mainly related to the IPM agreements that are marketing to marketing those long-term deals based on the curves that keep on going up since last summer, we've had some negative net income quarters in a row. And we'll have to, I guess, wait, to an extent until we're positive net income on a cumulative 4-quarter basis. But at that point, yes, we check all the boxes, and we think it would be logical to happen later this year.

And we'll take our next question from Michael Lapides with Goldman Sachs.

I have a short-term question and a longer-term question. For the short-term, I understand you have significantly less open exposure in 2023 compared to 2022 due to the numerous contracts you have starting this year. With the futures curve fluctuating considerably, are you actively participating in the 2023 market regarding that open position? For the longer-term question, I would like your insights on the FERC policy statement related to the assessment of upcoming gas infrastructure projects, such as pipelines and liquefaction, as well as its implications for greenhouse gas emissions and what it could mean for acquiring new assets, particularly Stage 3 and Stage 4 assets, or for constructing new pipelines to support these types of assets.

Thank you, Michael. This is Jack. So I'll start. And as you know, we don't like to give a lot of guidance beyond 2022 at this point into 2023. But as you say, the market continues to get healthier, but it's extremely volatile. You should expect us to be opportunistic out there, and I'll let Anatol who's biting at the bit to jump in.

Thanks, Jack. Thanks, Michael. I'll just add to Jack's comments that, as you know, one of the more valuable components of our value proposition for long-term commitments are these bridging volumes. So that is a component that is increasingly becoming more valuable and more important in these discussions. So on top of the volatility that Jack mentioned, husbanding those volumes to get us the long-term commitments that support our long-term investment is a top priority.

Michael, I would just add, this is Zach, that with the 100 TBtu open this year and the dollar moved with $50 million, our forecast was assuming, let's say, mid- to high-teens netbacks. So even just this year, and now where the curves are moving all over the place today, we're talking about $1 billion of contribution to EBITDA just this year. Next year, it is clearly attractive to us. But at the same time, for the next decade, we're almost 95% contracted on average. We're really over 90% contracted on 9 trains through the early 2030s, which is really why it's time to FID Stage 3 this summer.

In relation to FERC, Michael, I'm pleased to share that we have already completed our $32 billion infrastructure project and Stage 3 is fully permitted. We believe we have a slight advantage since we have completed our Life Cycle Assessment and our Corporate Sustainability Report. This transparency regarding our emissions profile for LNG gives us a competitive edge as we continue to grow and demonstrate the impact on our life cycle analysis.

And we'll take our next question from Brian Reynolds with UBS.

I was wondering if you can give us an update on your expectations around the $2 billion in additional cash that you guided to at capital allocation day outside of what's accounted for with Stage 3 buybacks and dividends. Just kind of curious if post the guidance update if we should be thinking about this number, as you know, $4 billion to $5 billion through '24, and how potential expansions beyond CCL Stage 3 could impact this to cash.

Sure. This is Zach again. I'll just say, I thought we'd have a break for a couple of years before needing to come out with another capital allocation plan. But at the rate we're going, with $4 billion or more of DCF this year, and that original $10 billion available cash at this point through '24, it's closer to $14 billion. That's literally '22 through '24 is like $12 billion. Our focus right now is really just to think about the $4 billion of debt pay down goal, the $1 billion buyback program, continue with growing the dividend, which we will grow this year, like we guided you all to. And we're already budgeting $800-plus million to kick off Stage 3 this year with FID. So what you have here is we're likely going to finish those capital allocation plans at the very least a year early. From there, we'll likely owe you a plan or an updated plan in the first half of next year or even later this year. It's logical to assume that base annual amount of debt pay down of $1 billion can come down a bit on a relative basis, and that we can be even more aggressive on the allocations to buybacks.

Great. Really appreciate all that color. And just a follow-up on future growth plans. It sounds like CCL Stage 3 is going to be mid this summer, and you know investors will start looking ahead at potentially CCL Stage 4 beyond that. Just kind of curious just from a gas need perspective and, particularly, from the Permian, what ultimately do you need to see from a gas pipe perspective to support the long-term viability of an expansion at Corpus? Is it 1 to 2 pipes? Kind of what are you looking for, what are your customers looking for as you start to perceive plans for further growth beyond Stage 3?

Yes. So thank you, Brian. So when we look at both sites, we think that we're in the pole position. We're in a very, very good position with our brownfield expansion capabilities at both facilities. I would say, with Stage 3, we build even more infrastructure that helps us in our future growth projects, another pipe, another substation for power down there, more water. So I feel very good about our position to grow. As far as additional pipes coming out of the Permian, I'll ask Anatol if he has an opinion of what we would need going there.

Thanks, Jack. Yes, Anatol has opinions. I'll just add to Jack's comments that South Texas is a great place to be regarding the Permian. That is one of the key factors behind these IPM transactions, particularly with EOG. We share a mutually beneficial relationship with our infrastructure partners and producers. In response to the previous question about FERC, the solutions tend to be intrastate, which are much more manageable these days. We are very optimistic. The amount of additional infrastructure will be determined by the market. However, we are hopeful that the producers have the resources, and we have the capability, as Jack mentioned, to expand our brownfield platform.

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

Just wanted to touch somberly on Eastern European geopolitical developments there and wondering any thoughts you could share with regards to how that could impact negotiations over time for your product. Or any other thoughts you could share there?

Yes. Jeremy, I mean, it's tragic what's going on in Eastern Europe. It saddens me to see the satellite images on the news screen as we've all witnessed this morning. If anything, these high prices, the volatility drive even more energy security and long-term contracting. I would say that the fact that there's a scarcity of LNG these days is driving more and more conversation on how to increase our infrastructure and secure monthly contracts for our European customers.

I think that's great, Jack. Obviously, you've seen the moves by, early on, Lithuania, Poland, others in the region to build that infrastructure and avail themselves of the supply. As Jack said, the reliable and flexible product that we put on the water will be a key part of the solution going forward. The human toll and tragedy, obviously, has our thoughts and prayers.

Got it. And then just kind of pivoting towards future growth plans and seeing like CCL 3. Seems like it's in the back pocket after negotiating EPC at this point. As the market is always looking for what's next, just wondering if you could frame out a bit more, I guess, how you think about next steps here. If it seems like there's a lot of acreage in Corpus and maybe you could do more there or looking at other sites for expansion or maybe I'm off base and returning capital will be a greater priority at that point. Just wondering if you could help us think through what could be next there.

Thanks, Jeremy, and I got to say you all are a tough crowd. There is a lot of work to be done between FID and then going operational on Corpus Stage 3. It's over 10 million tonne expansion project, which is equivalent to 2 of our large trains. I'm excited to see my team in action and deliver another quality expansion project to the portfolio. Having said that, Zach, do you want to talk a little bit about...

Sure. Jeremy, it doesn't hurt having $4.3 billion to $4.8 billion of DCF this year, which, just to put in perspective, it's $17 to $19 a share of cash flow. I don't think we thought we'd get there this quickly, but I think it just shows the value of the platform and, honestly, the value of our operations and construction teams to be able to give us this opportunity. With those types of numbers and, clearly, margins above the 200 to 250 range for the foreseeable future, there's billions of dollars to go around. So we've already budgeted for $800 million on Stage 3 for the next 4 to 5 years to get that up and running by 2026 or so. Then there's still billions. You'll see us taking care of the balance sheet. Buybacks will have a large arsenal ready to go and the growing dividend. It's really all of the above. It's just accentuated with a few more billion coming our way.

And we'll take our next question from Sean Morgan with Evercore.

There's been significant success this year, and the markets have been favorable with a wide arbitrage opportunity. I'm curious about the U.S. gas markets and how adaptable they are in relation to exports. What percentage increase in total export capacity from the U.S. Gulf could we expect before it starts to affect domestic pricing?

I think it would be unfair to claim that domestic pricing hasn't been affected as the LNG industry consumes around 13 billion cubic feet a day, with us contributing over 7 billion. The market is currently doing well. One thing we are monitoring is how the production function reacts. We are once again setting records for daily production and are confident in the availability of resources. In response to some previous questions, the supply growth seen in the Northeast may not be the best strategy moving forward. However, we feel reassured by our positioning in Western Louisiana and South Texas, where we believe resources can be accessed at the $3.50 price point. Gas rig counts have now exceeded pre-pandemic levels, and we expect production to adjust. Ultimately, the market will determine whether there is enough competitively priced gas available for dispatch.

Okay. Regarding the EOG IPM, I think you kind of made it clear this helps fill out your total required capacity for Stage 3. But is there sort of a limit in terms of the total notional export capacity that you would want to sign up for IPMs? I mean, is there any sort of puts and takes versus the offtake agreements? Or are they not necessarily mutually exclusive?

I wouldn't say they are mutually exclusive. However, at this point, we have signed up around 4 million tonnes worth of IPM deals, possibly a bit more. This is within the context of eventually reaching a portfolio of over 55 million tonnes, so it still represents a relatively small portion of the overall picture. What you see is that we are working with the most credible producers, which also provides us with a stable gas supply for extended periods and involves strong credit-worthy counterparties. While I don't believe this will ever make up the majority of our activities, I do think Stage 3 indicates that we will have a good mix of FOB, DES, and IPM deals, showcasing the evolution of our commercial offerings.

Just to piggyback on Zach's comments. The gas supply piece cannot be overstated, right? The fact that EOG in partnership with us is going to be delivering over 700 a day to this project, that will be a 25-plus million tonne project and the flexibility that we have, as Zach said, with the operational mix of the 3 products, which allows the operational side of the equation to be as reliable as we've seen in the last 5 years.

Our next question comes from Marc Solecitto with Barclays.

Just with the move up in the forward curve today, effectively extending the $20-plus LNG price environment through 2023, be curious to get your latest thoughts on the medium-term price outlook and just the general price responsiveness you've seen from customers as the forward strip has moved higher since the time of your last call.

Yes. So again, the tragic events of this morning notwithstanding, you've seen a structural shift upwards in that curve that you referenced, right, as we progress through the second half of the year and the logistics of not just refilling European storage but also meeting the inexorable growth out of Asia has been a challenge for the gas market, and that has caused those midterm margins to respond accordingly. So that is obviously a tailwind as we've discussed. And rest assured that we will take advantage of that either in some of the more prompt transactions or more structurally through bridging volumes in our long-term commitments that, obviously, at this point of the cycle are nice tailwinds.

Great. Appreciate the color there. And then recognizing the long-term NPV and strategic considerations in your allocation of bridging cargoes for your open exposure this year, just wondering if there's a certain price point in the forward strip where you would perhaps allocate a greater percentage of the forward spot sales.

Yes, it is a balancing act, and I want to clarify something. When we engage in these bridging volumes, they occur at market prices. While they are part of the long-term deal, they reflect the prevailing market economics at the time of the transaction. We value the strategic advantage of having these long-term commitments and a reliable platform. This is our primary focus. Whenever real-time opportunities arise, our team excels at optimizing the portfolio to capture any additional margin available to us.

And I would say, Marc, that I spent 35 years in the power business, and I've seen this game before in electric power and this type of volatility. What goes up will come down. So all we're trying to do is secure our production for the long term through contracts with creditworthy counterparties and then help us build additional infrastructure without taking risk. So I'm not sold on having an entirely merchant portfolio.

And we'll take our next question from Craig Shere with Tuohy Brothers.

I want to follow up on Jeremy's next question and Michael's question about FERC to see if you can elaborate on opportunities for further train upsizing efforts and whether the timing in the coming quarters might be right to actively pursue carbon capture.

I'm very pleased with our operational excellence program and the results we've achieved. We've significantly increased our reliable production since 2016 and 2017, and I believe there's still potential for further growth, which excites me. Regarding the expansion, we have a positive outlook on Stage 3. As we've indicated today, we're finalizing details and expect to launch full force with full Final Investment Decision later this year. After that, we'll shift our focus to our next growth opportunity. It's well known in this industry that FERC typically takes 2 to 3 years to review an LNG export terminal, and that's transparent in the market. In response to the second question on CCF, we've dedicated considerable effort to engineering and planning primarily at Sabine Pass, which presents the best opportunity for carbon capture at a favorable price. While we're not ready to announce anything yet, we are making good progress. I fully support the administration's aim to improve the economic viability of 45Q for the fossil-fired industry. A better price signal for carbon in America would be beneficial for us. We have options at both facilities, focusing first on Sabine, with more developments to follow.

One quick follow-up. If you have the ability with a little CapEx to increase the 9-train portfolio capacity by say another 0.2, 0.3 mtpa per train, where do you stand on authorizations to do that?

No. Our authorization is currently up to 5.5 million tonnes per annum per train. So that gives us plenty of breathing room.

And we'll be taking our last question from Julien Dumoulin-Smith with Bank of America.

I'll make this one quick. I think a lot has been asked and answered. But Jack, just going back to what you were saying a moment ago about taking some time to move through the process, whether it's CCF 3 or beyond, I mean, how do you think about potential acquisitions of existing sites just to kind of get a jump start on that whole process and/or if you could at least kind of conceptually set kind of a benchmark as to how you think about what you would be able to target mix volumes, right? I mean, are we talking '24, '25 in terms of FIDs for subsequent volumes? Or how do you want to at least kind of set the cadence if that's the right word?

Yes. So I'll take it in two points. One, potential acquisitions. So we're building Stage 3. It looks like it will be around 6x EBITDA. You've seen where some of these LNG terminals have traded out with some of these infrastructure funds, multiples above the 6x EBITDA. So in this case, Julien, just like in power, it would rotate whether it was cheaper to build or to buy. It's definitely cheaper to build than it is to buy and pay somebody else a premium. I would think, initially, at least on my crystal ball, I see us continue to do these brownfield expansions just from how cost-competitive we are today. Now I forgot about the second half of that question. Stage 3 will not occur all at once. For Corpus 3 and Sabine 6, when we achieved substantial completion, that was a total of 5 million tonnes. Now, we will be bringing online a train or two every few months. If we begin construction this year, I anticipate that the first train will be operational by 2026. Following that, we will add another train every few months until we are fully operational with a portfolio exceeding 10 million tonnes by 2027. This represents a significant growth rate, and I expect us to apply for further expansion in the near future.

The goal would be to have these trains coming online from late 2025 to 2027. Ideally, we will see some growth to add to the portfolio in 2027, 2028, and 2029.

At this time, I will turn the conference back to the speakers for any additional or closing remarks.

This is Jack. I just want to say thank you again for all of your support. I feel really good about where we are today. I think, overall, the industry needs to settle down a bit. Like Anatol said, our thoughts and prayers are with Eastern Europe at this point. But I think what's showing is the value of natural gas and LNG around the world, and I wish you all to be safe.

And this concludes today's call. Thank you for your participation. You may now disconnect.