Cheniere Energy, Inc. Q1 FY2023 Earnings Call

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

Thanks, operator. Good morning, everyone, and welcome to Cheniere's First Quarter 2023 Earnings Conference Call. The slide presentation and access for 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 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 2023 guidance. After our prepared remarks, we will open the call for Q&A. I will now turn the call over to Jack Fusco, Cheniere's President and CEO.

Thank you, Randy. Good morning, everyone. Thanks for joining us this morning as we review our first quarter results and improved 2023 outlook. As you can see from the results, we have continued our exceptional performance from 2022 and our improved outlook for the rest of this year is reflected in our increased guidance ranges. The first quarter was highlighted by excellent performance across Cheniere's platform from operations to project execution to capital allocation and origination. While we are not yet able to share specific details, last week, we executed a new long-term SPA with an investment-grade Asian end user that is linked to the SPL expansion project. This is an exciting signal that we are already gaining early commercial momentum on our recently announced expansion plans at Sabine Pass. We look forward to providing more detail on this SPA in the near future. Please turn to Slide 5, where I'll review key operational and financial highlights from the first quarter 2023, and introduce our upwardly revised annual financial guidance. We generated consolidated adjusted EBITDA of approximately $3.6 billion in the first quarter and distributable cash flow of nearly $3 billion. The first quarter benefited from a number of discrete factors which drove EBITDA and DCF higher, which Zach will address in a few minutes. During the first quarter, Zach and his team continued to make excellent progress on our capital allocation plan. We paid down nearly $900 million of debt and solidified investment-grade ratings across the Cheniere complex as we discussed on this past February call. We bought back over 3 million shares for about $450 million and paid our quarterly dividend of $39.5. So in total, almost $1.5 billion in capital return during the quarter, plus another approximately $550 million invested as Stage 3 for our future growth. Operationally, in the first quarter, we picked up right where we left off last year. Further reinforcing Cheniere's status as a leading global operator, reliably producing LNG with safety at the foundation of every action we take. We set a new quarterly record exporting 167 cargoes of LNG in the first quarter, surpassing our prior record, which was set in the fourth quarter of last year. Looking ahead to the balance of 2023, as I mentioned before, our forecast has improved. We are raising full year guidance by $200 million on both EBITDA and distributable cash flow. Our new ranges are $8.2 billion to $8.7 billion in EBITDA and $5.7 billion to $6.2 billion in DCF. The increase is mainly driven by the team capturing and locking in higher margins, both upstream and downstream of our facility. Zach will provide more color on the increase and preemptively answer your questions on guidance in a few minutes. Turn now to Slide 6, where I will update you on the status of our expansion projects, Corpus Christi Stage 3, which is under construction, Corpus Christi mid-scale trains 8 and 9, which is now in the FERC process and SPL expansion, which is in the prefiling with FERC. First, on Corpus Christi Stage 3. Destructions ramping up as its head count on the site, which is now approximately 750 workers, and we expect this to grow rapidly as we begin to transform from site preparation and groundwork into mechanical works over the coming months. Over 7,000 piles have been driven and soil stabilization is effectively complete. The foundations are beginning to be poured. Piping and spools have begun to arrive, and we expect to receive the first coal box at site next month, and its installation is an important construction milestone for Stage 3. Overall, EPC progress is currently 28.7%, which is well ahead of plan. While construction is only 3.4% complete, early construction activities are already tracking ahead of schedule, increasing my confidence in schedule outperformance and potentially having more volumes in 2025 and possibly the entire 7 Train project being completed by the end of 2026, months ahead of the guaranteed schedule. Next, on Corpus Christi, mid-scale trains 8 and 9, in line with what we told you last year when we prefiled this project. We submitted a full application to FERC on trains 8 and 9 in late March. We are optimistic about the permitting process for this project, given its distinct advantages of being identical to Stage 3 trains, being fully commercialized with creditworthy counterparties and not requiring significant supporting infrastructure. We look forward to working with FERC and all relevant stakeholder agencies and regulators on a smooth and transparent review process. Moving on to the Sabine Pass expansion project, which we revealed on our call back in February. I'm extremely excited about developing this major 20 million-tonne expansion, which has the ability to leverage our massive infrastructure position at Sabine Pass for economically advantaged incremental capacity. We have submitted the prefiling documents to FERC. We recently signed a contract with Bechtel for the FEED work related to this large-scale project, including for the carbon capture component. Commercially, the project is already gaining traction. As I highlighted earlier, last week, we're executing SPA of approximately 0.4 million tonnes per annum for over 20 years with an investment-grade Asian end user for LNG volumes delivered through 2047. Most of the volumes associated with the SPA are subject to FID of Train 1 of the Sabine Pass expansion project. We are excited to have already signed an SPA linked to the project and to be building commercial momentum as we progress development. We progressed these project developments in an environment marked by cost inflation, rising interest rates and extremely competitive LNG markets. These realities not only underscore the importance of Cheniere's competitive advantages but also our resolute commitment to the investment parameters that guide our disciplined approach to capital investment. As you have heard me say before, we are not in the FID business. Our focus is on long-term value creation, we are developing these projects with the same discipline, rigor and high standards that form the foundation of our existing infrastructure platform. We are extremely excited about our organic growth prospects, and we continue to target market-leading project returns on a risk-adjusted basis that our investors and stakeholders have come to expect from Cheniere. Thank you all again for your continued support of Cheniere. I will now turn the call over to Anatol, who will provide an update on the LNG market.

Thanks, Jack, and good morning, everyone. Please turn to Slide 8. The LNG production in the first quarter reached new highs as global reliability improved with record monthly exports of 36 million tonnes in March. Following a period of outages across various plants worldwide, year-over-year increases in production were achieved in Norway, Australia and Qatar in particular. In Norway, the Hammerfest facility was offline in Q1 last year, and in Australia, Prelude was shut down after a loss of power in December 21 and did not restart until April of last year. And in Qatar, 2 megatrains were undergoing major planned maintenance in Q1 last year. Exports from the U.S. were broadly flat year-over-year as Freeport LNG restarted production in February after having been offline since June of last year. While the uptick in global LNG production over the past few months has helped to balance the market and further stabilize price levels throughout the first quarter, we expect limited overall supply growth this year as few new projects are scheduled to come online in the next 18 months. Until then, we expect supply and demand to remain precariously balanced and sensitive to supply disruptions, weather and demand shocks. We remain optimistic that the U.S. will continue to be a critical source of flexible supply in the market. U.S. flows to Europe continued to remain strong in Q1, helping ease market pressures and contributing to moderating prices. In fact, approximately 80% of cargoes produced by our 2 sites were delivered to Europe in the first quarter. The TTF monthly settlement prices averaged approximately $19.50 per MMBtu in the first quarter of '23, 35% lower year-on-year. Similarly, the JKM average settlement price decreased by 16% year-on-year to an average of approximately $26 per MMBtu. While both pricing indices are markedly lower than last year, global gas benchmarks remain at elevated levels. Q1 marked an inflection point for average quarterly global gas prices as JKM surpassed TTF for the first time since Russia invaded Ukraine last year. Cheniere's value proposition built on market-leading reliability is, of course, further enhanced by a stable and affordable commodity. In the U.S., in March, the Henry Hub front month contract price fell below $2 in MMBtu for the first time since September of 2020. Henry Hub averaged approximately $3.40 in Q1, and the front month contract is now trading in the mid $2 per MMBtu. Following the elevated pricing in North American gas markets last year, our production response led to a more normalized pricing environment, underscoring the abundance and relative affordability of Gulf Coast LNG. Now let's turn to Slide 9 to address current European dynamics in some more detail. Europe has closed out this winter with gas inventories at or near the high end of its 5-year range, thanks in part to record mild weather and, of course, sustained LNG flows. LNG imports remained robust, increasing 8% year-over-year despite labor strike activity affecting several French terminals in March. U.S. exports to Europe increased approximately 4% year-on-year in Q1 and about 15% quarter-over-quarter. The addition of 5 FSRUs over the past few months across the Netherlands, Germany and Finland, helped increase LNG import capacity and reduce locational price spreads. However, mild weather, coupled with significant demand reduction efforts by European consumers resulted in a 12% year-on-year decline in gas demand in Europe's key gas markets in Q1. Gas burn in the power market remained suppressed in Q1, down 15% year-on-year, although elevated coal and emissions pricing could present opportunities for fuel switching. As mentioned, with storage levels above the 5-year average this year, Europe is positioned well as it looks to replenish supplies ahead of the 2023, '24 winter season. While further reductions in Russian pipe gas remain a risk, much of this volume was already lost in the demand response last year. Nevertheless, despite the European market's advantageous position coming out of the second warmest winter on record. The shortfall in Russian supply should remain an ongoing challenge for the global balance until new supply is dispatched. Longer term, forecasts indicate European LNG imports will remain stable at elevated levels, despite net zero rhetoric and policy induced pressure on the demand outlook for European gas. Leading LNG consultants predict that LNG demand in Europe will increase through the end of the decade before stabilizing above the 100 million-tonne level through 2040 and possibly beyond. Let's now turn to Slide 10 to discuss Asia. Demand in Asia remained stable with overall LNG flows flat relative to Q1 last year and up 4% quarter-on-quarter. The demand decline observed over the last year in certain key Asian markets, India, Pakistan, Bangladesh and China, to name a few, has narrowed considerably as spot prices continued to moderate this quarter. Demand response in these price-sensitive markets, especially with further moderation in prices, normalized weather and a pickup in economic activity will be a key determinant of market tightness in the medium term. As shown in the middle chart, Korea's imports were up 7% in Q1 due to nuclear maintenance, curtailed coal burn and LNG inventory replenishment. However, elevated storage levels and the expected start-up of a new 1.3 gigawatt nuclear plant in Q4 could impact spot buying from Korea in the upcoming months. In Taiwan, imports rose 4% in Q1, driven by reduced coal-fired generation during the winter and the decommissioning of a nuclear reactor in March. Thailand also grew in parts 7% in Q1 in order to cover declines in both domestic output and pipeline imports for Myanmar. In contrast, LNG imports in Japan remained weak amid high inventory levels and improved nuclear availability year-on-year. Nevertheless, lower Japanese imports and reduced demand in China and India balance the gains in Korea and other parts of Asia. In China, Q1 LNG imports were down 3% and or 0.5 million tonnes year-on-year, but we have observed some green shoots and leading indicators for demand growth as economic activity continues to pick up post lockdowns. With GDP expanding 4.5% year-on-year in the first quarter, China's gas demand grew 5.6% year-on-year in March and LNG imports rose 14% year-on-year in March, marking the first positive increase in over a year. A potential increase in industrial gas demand from a 56% month-on-month rise in new home sales could provide further tailwinds for LNG demand later this year. Despite the recent weakness in Chinese LNG consumption, we believe China's long-term fundamentals remain strong, and the nation is on track to become the first 100 million-tonne LNG market before the end of the decade. China's significant investment in natural gas infrastructure from pipelines to regas terminals, to gas-fired power generation capacity, coupled with its active role in the long-term contracting market has demonstrated the region's commitment to natural gas as a long-term solution. As we've discussed before, we expect the immense economic growth and energy evolution forecasted for the Asia region to underpin decades of growth in LNG demand driving the need for substantial investment in new liquefaction capacity. The over 20-year SPA we recently signed with an investment-grade Asian buyer that Jack mentioned is linked to the SPL expansion project and further evidences the global need for long-term reliable gas supply. The SPL expansion project is a major source of prospective new LNG supply, and we look forward to building on this commercial momentum, developing the project according to our high standards and ultimately enhance Cheniere's capabilities to provide the market with reliable, flexible and cleaner burning LNG supply for decades to come. 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 first quarter 2023 results and key financial accomplishments and to update you on our upwardly revised outlook for the full year. Once again, the outstanding financial results we reported today are the product of our team's unwavering commitment to operational excellence, execution and financial discipline as we continue to create value for our stakeholders. Turning to Slide 12. For the first quarter, we generated net income of approximately $5.4 billion, consolidated adjusted EBITDA of approximately $3.6 billion and distributable cash flow of approximately $2.9 billion. As Jack mentioned, our first quarter results were aided by our marketing team's proactive selling forward of some of our first quarter open exposure starting last year at margins higher than current market margins as well as the contribution of 16 cargoes loaded at year-end 2022, but delivered in 2023, the majority of which were CMI spot cargoes and only 11 cargoes in transit at the end of Q1. In addition, we benefited from a higher contribution from certain portfolio optimization activities from our IPM deals as well as vessel subchartering. These benefits were partially offset by a higher proportion of our volume being sold under long-term contracts and lower lifting margin due to lower Henry Hub prices compared to the first quarter last year. During the first quarter, we recognized an income 619 TBtu of physical LNG, all of which was produced at our 2 projects. Approximately 84% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements with initial terms greater than 10 years. As we've noted in prior earnings calls, our reported net income is impacted by the unrealized noncash derivative impacts to our revenue and cost of sales line items, which are primarily related to the mismatch of accounting methodology for the purchase of natural gas and the corresponding sale of LNG under our long-term IPM agreements. The further decline in sustained moderation and volatility of international gas price curves throughout the first quarter served to benefit the mark-to-market valuation of these agreements, driving a negative cost of sales number for the quarter and increasing our net income line item for the second quarter in a row. Excluding the impact of $4.7 billion of total unrealized noncash derivatives, net income for the first quarter would still have been over $2 billion and cost of sales would have been around positive $3 billion instead of negative $1.5 billion. With today's results, we have earned cumulative net income of over $7.7 billion for the trailing 12 months, and have now reported positive net income on a quarterly and cumulative trailing 4-quarter basis 2 quarters in a row. Throughout the quarter, we continued to strategically pay down debt, prepaying approximately $900 million of consolidated long-term indebtedness and bringing our total debt pay down to approximately $7.5 billion since launching our original capital allocation plan in 2021. As noted on our last call, in the first week of January, we redeemed the remaining almost $500 million of outstanding principal of the CCH notes due 2024. And throughout the quarter, we continued to utilize our open market repurchase program opportunistically repurchasing nearly $400 million in principal of outstanding CCH notes with maturities ranging from 2027 to 2039. These transactions represent some of the tools we have utilized to address our consolidated leverage and strengthen our balance sheet over the past few years. And these actions have been recognized by the rating agencies. During the quarter, we received our second investment grade rating of BBB- at CEI from Fitch. And S&P upgraded SPL from BBB to BBB+ with a stable outlook. Thanks to our team's ability to deploy capital to address our leverage both opportunistically and efficiently we are officially investment-grade and index eligible across our corporate structure with our next debt maturity not until next year. After the achievement of IG across our corporate structure during the quarter, we have begun to shift our capital allocation weighting to our buyback program. During the first quarter, we repurchased approximately 3.1 million shares for approximately $450 million as we continue to recalibrate our future cumulative debt paydown to share repurchase ratio from 4:1 to 1:1. As I mentioned on our last call, over the coming year or 2, there's likely a catch-up trade on the buyback since we were so aggressive on debt paydown late last year and into Q1 in order to get to investment grade throughout the complex. Our share repurchase program is designed to be flexible in order to take advantage of dislocations in the market like we saw at certain points these past couple of quarters. We will continue to target the 1:1 long-term ratio we introduced last fall as we deploy the remaining $3.2 billion under our current buyback authorization and in an attempt to buy back over 10% of our market cap in the coming years. We also declared our seventh quarterly dividend of $39.5 per common share for the first quarter last week. We intend to follow through with our previous guidance of growing our dividend by approximately 10% annually into the mid-2020s through construction of Stage 3 with the next step-up planned for later this year. And for the final pillar of our comprehensive capital allocation plan, disciplined growth, we funded approximately $550 million of CapEx at our Stage 3 project during the quarter with cash on hand. As Jack mentioned, construction is well underway, and we're tracking ahead of schedule. Going forward, we will continue to fund Stage 3 CapEx efficiently with internally generated cash flow and the over $3 billion still available on our CCH term loan today. As of March 31, we had over $10 billion of consolidated available liquidity even after the deployment of nearly $2 billion towards our capital allocation during the quarter. The financial strength afforded by our accelerated progress across all 4 pillars of our capital allocation plan has become one of our key competitive advantages as we continue to procure and process over 7 Bcf of natural gas on a daily basis, deliver 45 million tonnes of LNG per year and develop further accretive brownfield growth at both our sites. Turn now to Slide 13, where I will discuss our 2023 guidance and update you on our open capacity for the remainder of the year. Today, we are increasing our 2023 financial guidance by $200 million to $8.2 billion to $8.7 billion in consolidated adjusted EBITDA. And $5.7 billion to $6.2 billion in distributable cash flow. While we don't provide guidance by quarter, obviously, given the full year guidance, we are forecasting lower EBITDA across the second, third and fourth quarters compared to our first quarter results. The guidance increase is enabled primarily due to selling some of our open CMI cargoes opportunistically at higher margins than previously forecast. The release of a couple of the origination placeholder cargoes to CMI to sell into the spot market, higher than originally forecast gas supply lifting margins and further contributions from optimizing our shipping portfolio. These increased guidance ranges continue to reflect current international gas price curves as well as our increasingly limited open position for the remainder of the year. Given the start of several long-term contracts this year and our planned maintenance at Sabine Pass this summer. Currently, we have approximately 35 TBtu of unsold LNG remaining this year, 15 of which are reserved for long-term origination and we currently forecast that a $1 change in market margin would impact EBITDA by approximately $20 million for the balance of 2023. Highlighting how proactive the team has been in securing margin this year to guide 2023 EBITDA into the mid-8 billions. As always, our results could be impacted by the timing of certain year-end cargoes heading into 2024. Our distributable cash flow for 2023 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 in which we do not qualify for the minimum corporate tax of 15% this year. However, as noted previously, both of these dynamics would mainly affect timing and not materially impact our cumulative cash flow generation through the mid-2020s as we think about our overall capital allocation deployment. Despite our limited remaining open exposure this year and moderated international gas prices, our 2023 guidance ranges are well above the $5.7 billion high end of our 9-train run rate guidance, and we remain on track to achieve our 2020 vision of generating over $20 billion of available cash by 2026 and over $20 of DCF per share on a run rate basis. With every dollar deployed by our team, we are positioning Cheniere for a resilient and profitable future. And it is the visibility of our future cash flows that enable us to meaningfully return capital to our stakeholders and pursue further disciplined growth through cycles while continuing to reliably and responsibly deliver affordable, cleaner burning energy to our customers worldwide. 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.

Our first question will come from Jeremy Tonet with JPMorgan.

Just wanted to start off with the, I guess, the SPA contracting market out there. Good to see the contract for SPL expansion as you noted there. But just wanted to get a feeling of what you guys can share with regards to competitiveness. It seems like there's a number of players that are maybe a bit more aggressive in their attempt to get contracts at this point? And just wondering how you see the balance of maintaining your financial hurdles versus securing contracts for the expansion?

Yes, Jeremy, I believe it goes hand-in-hand with our exceptional operational performance. So the fact that we haven't missed a foundation customer cargo is being recognized by the end-user community worldwide out there. Those folks that we've talked about in the past with the trillions of dollars being invested in natural gas infrastructure want to make sure that they have gas to fill up that infrastructure. Those are the folks that we're targeting for our long-term contracts. We're not going to change our business model either. We're going to commercialize the new investments. We're going to lock in the price, the performance, the schedule with Bechtel, and then we'll build the infrastructure. But I'll turn it over to Anatol on what competition he sees in the SPA market today?

Yes. Thanks, Jeremy. Well, as Jack said, over the last couple of years, it's become apparent to everyone the value proposition, as the guys said, built on our reliability and safety and performance. And we have never been and clearly aren't today in a race to the bottom for a commodity product, and we're very selective with whom we transact as Jack already mentioned, the end users, the counterparties that value that reliability, and we extract a premium for that, and we'll continue to do that in what is still a very competitive market, as you know. So we'll stick to our knitting and have this great base business meeting those financial objectives and expose ourselves to the upside as we outperform.

Got it. That's helpful. And maybe just want to kind of level set results today versus your expectations, it clearly beat this street median by a big number, but the guidance didn't move up by the same number and just wondering, I think it's important. How did first quarter stack up versus your expectations and maybe the street wasn't shaping the timing of CMI being open across the year and that kind of led to some of the disconnect, but just to give any of your thoughts there?

Jeremy, it's Zach. And I guess trying to compare a Bloomberg estimate for Q1 with our annual EBITDA guidance is like mixing apples and oranges because by the time we came out with guidance on the last call, which was late February, literally 2 months ago. I would say we're not off $1 billion from what we thought Q1 would be. If anything, Q1 was pretty baked by the end of February for us because going into the year, we locked in a significant amount of our open capacity with those margins well over $20 to create such a robust quarter in Q1. So Q1 was always going to be weighted in terms of our EBITDA, and it's going to be in our guidance around 40% of the EBITDA for the year. And we knew that considering our open capacity or spot volumes for the year. 50% of them were going to be in Q1. Over 50% of our CMI contribution came in Q1. So I think some of the disconnect is basically a lot of folks may be spreading out more evenly our EBITDA quarter-to-quarter. We did have a good amount of in-transit and we do make a bit more production in Q1. But basically, all of those 20-plus, 30-plus, even some 40-plus cargoes that we locked in, in the past year. Those were delivered in Q1 and created that outperformance. And to say in the next last 2 months, we've been able to increase guidance again by $200 million after all of that accounted for on the last call. That's really a testament to the team here that we were able to secure a higher lifting margin upstream in the plants, took advantage of some of our length on our shipping portfolio by delivering more to Europe and subchartered a bit more. And then clearly, we still beat the market on some of the cargoes that we sold in the open market for Q2 and Q3 coming up for the rest of the year.

Got it. That's very helpful. I'll leave it there.

And our next question will come from Brian Reynolds with UBS.

Maybe to follow up on the guidance question based off the quarterly outperformance. Zach, you did discuss the forward sale of cargoes subchartering and optimization. Just kind of curious if you could just break down how much the outperformance was maybe attributable to those components? And perhaps some of the pull forward on some of that optimization. And then in the context of the $200 million guidance raise, should we view that as a base business kind of positive outlook at this time?

Yes, our guidance is around $200 million, and we don't include in our EBITDA projections anything that isn't confirmed or realized at this stage. Currently, we indicated that the available capacity is 35 TBtu, and a $1 change only impacts us by $20 million, representing about 1% to 2% of our total production and 2% of our annual EBITDA. While we monitor the fluctuations in our share price relative to TTF for oil, we are already committed for the remainder of the year. I wouldn't expect any additional upside from optimization at this point, but the subchartering is secured. It's either been realized, or our team has already contracted those charters and locked in profits for us. We feel confident about the new guidance range, and while there may be some potential upside, we'll need to observe how the rest of the year unfolds.

Great. Really appreciate that incremental color. Maybe another question for you, Zach, on capital allocation. Cheniere bought back $450 million this quarter, but reduced another $400 million in debt. You talked about in your prepared remarks that there could be some more cash available for buybacks. Looking forward, how should we think about maybe debt retirement? What are your plans for paper perhaps this year and next, that could maybe impact that share buyback cadence of, call it, $750 to $1 billion quarterly assuming there was no debt pay down this quarter?

Sure. I don't think I have ever said we're going to do $750 to $1 billion quarterly. What we have said is like, look, we have a $4 billion buyback program for 3 years. In the last 2 quarters alone, we bought back almost $1.2 billion. There's going to be even more robust allocation to buybacks, including this quarter and going forward. As we go through that $4 billion ideally within 3 years are well within 3 years. But the deployment is still going to fluctuate a bit. We are not dollar cost averaging on our buyback program. It's more opportunistic. So you can imagine we're active today on the buyback. And then in terms of the debt paydown, we actually bought back in terms of debt, $900 million in Q1 but $500 million of that was in the first week. I think people have to remember, we weren't actually officially investment grade and index eligible until early January. So we went into the year looking to finally finish that up, and we truly front-loaded late last year and early this year, the debt pay down to get there. But now that we're there, yes, there's a green light to go back the other way and reset that 1:1 cumulative ratio, meaning there's quite a bit of catch-up to do on the buybacks going forward, at least $2 billion through the rest of this year and into next. So we're pretty optimistic in terms of the allocation to buybacks. And yes, over time, we'll get back to 1:1 and eventually buy back over 10% of the market cap.

Great. I appreciate all that incremental context.

And our next question comes from Marc Solecitto with Barclays.

Maybe just to pick up on '23 guidance. Obviously, largely locked in at this point with 20 TBtu remaining open. But I wonder if you could just talk about some of the factors that could put you at the upper or lower end of the revised range?

Sure. As I mentioned, we have about $200 million in CMI contribution that isn't locked in today, which means around 2% of the EBITDA is still available. There is potential for upside from selling those cargoes at higher margins depending on market conditions for the rest of the year, despite our decreasing open capacity. Half of our open capacity was in the first quarter. This year, we have new contracts starting, along with major maintenance planned at Sabine this summer. These factors were considered in our guidance regarding open capacity earlier in the year. Additionally, we still have 15 TBtu in reserves for long-term contracts, which, if released to our short-term team over time, could be sold at market prices, creating further upside. We're estimating around 5 million tonnes per train in production, factoring in the major maintenance already. Updates on production increases will take time, so we need to get through the major maintenance turnaround this summer and the hurricane season before evaluating our position later this year for any potential upside. Lastly, we don't account for any optimization in our plans that isn't already secured. Therefore, we are confident that, at minimum, even with potential pressures on margins later this year, we will meet our guidance and overall, we feel positive about our situation.

Got it. I appreciate all the color there. And then gas inventory levels obviously tracking above seasonal averages coming out of the winter. But with LNG price close energy equivalency parity with other fuel sources and green shoots of recovery and price-sensitive demand in both Europe and emerging markets. Curious how you see those factors interplay in terms of the LNG commodity price outlook over the summer?

Yes. Thank you, Marc. This is Anatol. We are monitoring the same factors that you and Zach discussed. Our exposure to those dynamics is quite limited, but we are learning from them. Our goal is to provide our long-term partners with our affordable, stable, and environmentally friendly product, and the amount of infrastructure being added is impressive. The world is set to increase regas capacity by over 120 million tonnes annually just in the first quarter. Europe has added more than 13, as has China, and while European storage is currently at a high point, it is slightly below where it was in 2020, though we do not wish to return to that situation. This indicates that infrastructure should not pose a limitation. Furthermore, we are noticing early signs of increased tenders from price-sensitive markets like India and a highly active market in China. Although the manufacturing PMI was weak last month, we remain hopeful for a significant improvement in the second half. We believe the current price levels are advantageous. Coal prices remain high, as do emissions prices, so we are optimistic about our position.

And our next question comes from Spiro Dounis with Citi.

First question, maybe for you, Zach, just starting with the Sabine Pass expansion. Still early days here, but I just wonder if you could just walk us through a little bit about the general plan to fund that expansion. I don't believe a lot of that CapEx was factored into the 2020 vision you all laid out in the fall. So just curious how should we be thinking about that funding relative to the capital allocation plan in place?

Sure. So the 2020 Vision capital allocation plan really only goes through 2026. And in that, we still had billions of dollars for new developments. That was mainly the incremental mid-scale trains at Corpus, but there was still money above and beyond that, that is baked in, and we'll be spending some money to get ahead of that SPL expansion. But again, it's going to take a couple of years to get everything ready for FID and to officially start deploying meaningful money down at Sabine. And now that we have 6 trains fully up and running there. We have a base plus variable DPU policy. We're set up pretty well to live within cash flows there and continue to pay out at the very least the base and have more than enough equity cash flow there to live within the cash flows. And as we develop these projects and think about CapEx at, say, 6 to 7 times unlevered returns, highly contracted at 10% and 50% leverage, which gets you to under 4 times on a debt-to-EBITDA basis, it all pencils out just fine. So we'll be well placed for that. And I guess it will be in our next capital allocation plan where we're baking that in. It probably just won't be for the third September in a row this year.

Got it. That's good color. Second one, maybe for you, Anatol, you thinking about SPAs. I want to really kind of focus in on the tenor. You mentioned over 20 years on this recent SPA and over kind of caught my ear, just given that this is supplied it's really not starting up until closer to 2030. And so I'm just curious, is that a general trend you're kind of seeing across other commercial discussions, are tenders actually increasing this time around? And then just curious sort of in that context, how much things like or features like carbon capture are playing a role in these discussions now versus maybe a year or 2 ago?

Thanks, Spiro. We never believed that the 20-year deal was off the table. Over the past few years, the market has mostly adjusted to that. However, you can definitely see the average term extending. We've engaged in some 15-year deals and several over 20 years recently, and we appreciate those arrangements, particularly when they involve end users and serve as a foundation for long-term relationships that we anticipate will increase our volume. Additionally, regarding the 20-year aspect starting in the latter part of the decade, there are some early volumes factored in, as Zach mentioned. We reserve portions of our portfolio for such opportunities and are managing it accordingly. This gives us a structure that exceeds 20 years, which we and our dependable customers prefer, and we have completed a significant amount of this in Asia and expect to pursue more.

And our next question will come from Jean Salisbury with Bernstein.

I just have one. I wanted to get your thoughts on the new DOE policy making it harder to get permit extensions if you're not under construction. How do you see this policy affecting the pace and size of the U.S. LNG build-out, if at all? And does that have any kind of secondary impact on Cheniere?

Hi Jean Ann, thank you for your question. I actually see the policy in a positive light, similar to our current approach where we commercialize projects before moving fully into construction or financing. The intention is to ensure that there is a genuine need for what has been permitted. This should benefit some longstanding projects that have yet to progress, possibly expediting their development. Some of these projects have exceeded my tenure at Cheniere, which is seven years, and have been in the pipeline for over a decade. It's time to decide whether to proceed with these projects or not. Overall, I have a positive outlook. In fact, all relevant authorities, including the DOE and FERC, appear to recognize that natural gas will play a crucial role as a transition fuel for clean energy and beyond. We're starting to witness progress on all infrastructure projects.

And the next question will come from Sean Morgan with Evercore.

Regarding the issue with the formaldehyde, I think you guys said that you tested 41 or 44 turbines to be compliant with the government standards. What's the plan for the remaining 3? And are there sort of CapEx ability to sort of remediate any problems you have, if there's anything outstanding?

No, the 3, the remaining reach on are just a matter of, I'll say, supply chain. So we're waiting for some parts from Baker Hughes. And when those parts get installed, during planned downtime, then we'll retest them. But it's our belief, and we've got enough data now that we are well within compliance. And as you know, this is not an issue at all at Corpus. It's only been at Sabine with the water injection. But it will be immaterial and you all want.

Okay. And then I think Zach might have mentioned something about eligibility now for the index. I assume the S&P 500. Have you guys met all of the criteria that's required for inclusion at this point?

The eligibility I was referring to is related to investment-grade index eligibility. In response to your question, yes, we meet the criteria and have done so for the last two consecutive quarters. Our last twelve months EBITDA, net income, is over $7 billion. Our market capitalization is sufficiently large, placing us among the top five largest companies in this country that qualify but are not listed in the S&P 500. It should just be a matter of time, but we obviously need a partner.

And the next question is from Michael Blum with Wells Fargo.

So I wanted to just had a market question. Q1 looks like most 80% of your cargoes went to Europe, which frankly, surprised at least me a little bit, given storage levels in Europe and China reopening. So I wonder if you could just talk to the dynamics there? And then how do you think the rest of the year plays out?

Thank you, Mike. It's Anatol. The pricing in Europe was more favorable than in Asia during the first quarter. We don't have control over most of the volume we produce, and our customers utilized the flexibility in destination options, which we also did. This led to some chartering of shipping routes intended for Asia that ultimately did not happen. The advantage of our product tends to go to the market with the highest returns, and we are currently experiencing a careful balancing act between Asia and Europe, which can change rapidly. The May call can be challenging because it falls during a transitional period globally before demand increases in mid-summer. We anticipate that strength will emerge in Asia later in the year, suggesting that volumes will likely shift towards Asia rather than Europe, given its recovery.

Okay. Great. And then just wondering if there's been any change in the tenor of discussions with Europe? I know politically, it's been more or less call it more challenging to sign long-term contracts. I wonder if there's been any change in that dynamic?

No. I mean the bottom line is that you'll see kind of similar dynamics that you saw last year, and you're absolutely right that most counterparts in Europe have a difficult time going beyond 15 years. Doesn't mean that those are transactions that we would not entertain. But as we've always said, we expect that the fundamental demand driver to be Asia, and we're seeing much more comfort with multi-decade commitments out of that theater than out of our European counterparties, but we expect to see some success in Europe as well.

And our next question comes from Craig Shere with Tuohy Brothers.

First, Anatol, you commented as usual, about not competing for the lowest cost and historically, the last couple of quarters, I think you've pointed out that some at least partially contracted peers may not be able to reach FID due to financing, the competitive pricing of their offtake and other issues. Do you think at this point that there could be 5 or 10 MTPA plus of orphan downstream demand that may be looking for a home in the next year?

I mean the short answer is, yes, there are different types of counterparties that have contracted for projects that are unlikely to move forward and some of that demand is structural, and we would look to meet that. Other demand is opportunistic and that may not materialize. But we do think as the market shakes out, to your point, we did expect more than 2 FIDs in '22. And obviously, Q1 saw a number of FIDs here. We continue to expect more. But to the extent that some of these relatively well-contracted projects at aggressive rates that are difficult to prosecute in the aggregate fall by the wayside, we do think that there is some fundamental demand that could be a good opportunity for us.

Great. That's helpful. And for my second one, now that we're starting to think about the end of the decade and beyond, I thought I had read that the DOE is looking to draw a hard line in the sand about the 7-year export authorization timelines of people haven't actually broken ground and gotten financing. And I'm wondering if there's a thought now that so much in total is authorized for export, though obviously not a good portion of it is not in the works at the moment. I wonder if there's a thought that by the end of the decade, the DOE may be more the governing factor than FERC and those are a little more reliable and consistent in their project development time lines may have competitive advantages.

We haven't seen either agency being competitive to anything that we wanted to do ourselves. So look, I've been here for 7 years, and we have built how many tonnes and it's all in my 7 years. Yes. FID-ed over 20 million tonnes. So it hasn't slowed us down. I don't think it will. I do think it'll help focus the regulators and the stakeholders on projects that are really going to move forward in a timely fashion. So think it's a positive, not a negative overall for the industry.

And the next question will come from Sam Burwell with Jefferies.

I wanted to hit on CapEx quickly. A little over $700 million spent in 1Q, $550 million of that being CCL3, just curious if both of those are good estimates for like a quarterly run rate for the rest of the year? Or anything driving that higher in 1Q? And then with respect to CCL3 funding, I just wanted to confirm that the plan is still to lever that project 50% and what the factors driving the funding it from cash on the balance sheet now might be if that's a function of short-term rates or when we might expect it to be back leveraged?

The capital expenditures for the year were $550 million, which is higher than a typical quarter, as we reached certain milestones. We anticipate that the total capital expenditures for the year will be around, or possibly slightly below, $1.5 billion. When considering maintenance capital expenditures and growth capital expenditures related to development work at the Sabine expansion and mid-scale projects 8 and 9, we expect to remain well under $2 billion in total capital expenditures for the year. Regarding funding for Stage 3, our intention is still to maintain a 50-50 split. With approximately $6 billion of discretionary cash flow, and after accounting for the capital expenditures, we have around $4 billion in free cash flow. After considering debt repayment and dividends, there remains over $2 billion available that could be allocated to the buyback program as we approach the end of this year and into next. We have sufficient funds to cover the equity component of Stage 3, while maintaining flexibility and the commitments from banks, which remain valid for another six years. This allows us to save significantly on interest expenses. We will determine whether we use this leverage to complete Stage 3 or to support the Corpus expansion later on. We plan to utilize these funds, which are convenient and inexpensive to hold onto for now.

And our last question will come from Alex Kania with Wolfe Research.

Just a question, I guess, as we're looking in the back half of the decade with just upstream infrastructure. Just how do you feel like connecting gas pipeline situation is going to look for both Corpus Christi and I guess, looking even further out to Sabine Pass. Do you think the industry is kind of caught up with the expected demand that you're seeing? And does that have any implications about how you're thinking about investment?

No, I think look, Corpus has a little bit of a benefit over Sabine that it's in Texas, and it's close to the Permian, and you probably saw that the Permian just in 2022, went from 15? Yes, from 13.5 to... Jack Fusco: 18.5 Bcf almost 19. So significant growth in natural gas coming out of the Permian, and we intend to take advantage of it. And you can build pipe in Texas these days. At Sabine, it's going to be a little more complicated because we've never wanted to make ourselves overly dependent on 1 basin. So we're going to look for opportunities to tap into multiple basins to take care of the Sabine growth. But as you're seeing from FERC, things are moving. Projects are getting approved, and we're hopeful that we'll be able to move swiftly when the time is right.

Great. Maybe for the last question, are you still receiving significant interest in IPM-type frameworks as opposed to the international offtakers? Recently, apart from a few instances, we haven't seen much of that type of interest, but I'm curious if there is still a demand for it.

Yes. I guess in short, our forward book of business as we look at it very much rhymes with what we have done in recent history. So expect a healthy mix of IPM and delivered and FOB contracts. We like the diversity of that. We like a lot of aspects of IPM deals, the gas supply, the optimization opportunities. So expect to see us do more of that. But as we've always said, it is a relatively finite amount of counterparties that we can transact those with.

And thanks all of you for your support and your kind words and be safe out there. Thank you.

Thank you. That does conclude today's conference. We do thank you for your participation. Have an excellent day.