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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;

Thank you, Randy. Good morning, everyone. Thanks for joining us this morning as we review our first quarter results and improve 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

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 advantage 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 0 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

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 pay down 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 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 the 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 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.

[Operator Instructions]. Our first question will come from Jeremy Tonet with JPMorgan.

Just wanted to start off with the, I guess, the SBA 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 not being unrecognized by the end user community worldwide community out there. To 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 are -- 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

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.

Yes, around the $200 million guidance rate, like we don't forecast in our EBITDA things that aren't locked in, realized at this point. So at this point, when we gave guidance that -- look, the open capacity is 35 TBtu and the $1 move is only $20 million. We're talking about 1% to 2% of our total production. We're talking about 2% of our annual EBITDA. And when this share price that we love to look at fluctuates with TTF for oil, we kind of scratch our heads when we are this locked in already going into the rest of the year. So basically, I wouldn't assume anything is baked in, in terms of further upside from optimization, but in terms of subchartering, that's not -- that's locked in. It's either realized or the team has already sold those charters out and have locked in a profit for ourselves. So we feel real good about the new guidance range. And yes, there could be some upside, but we'll just have to see how things play out for the rest of the year.

Great. Really appreciate that incremental color. Maybe another question for you,

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 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 TBT 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. So again, as I mentioned, with about $200 million worth of CMI contribution not locked in today, we're talking about, yes, like 2% of the EBITDA still floating out there. So what's the upside? There could be some upside from selling those cargoes at higher margins, depending on where markets settle through the rest of the year, even though our open capacity is definitely coming down. As I said before, half of our open capacity was in the first quarter. We have new contracts coming online this year that are starting up, and we also have the major maintenance turnaround at Sabine this summer. So there's a few things there that just were always baked into our guidance in terms of having more open capacity earlier in the year. The other upside could be -- basically, we still have 15 TBtu reserve for long-term contracting. If those over time, are released to our short-term team, they'll be able to sell those at market prices, there could be a little upside there. And then on production, we're already estimating around 5 million tonnes per train and that's with the major maintenance embedded in all of that. So that's going to take some time to give you any update on production increases. Let's get through the major maintenance turnaround this summer. Let's get through the hurricane season. And we'll see where we are later this year on that, that could provide a little bit of upside. And then lastly, we don't bake in any optimization, upstream or downstream of the plants that aren't already locked in. So we'll see how that flushes out through the year. So we feel real good that, at the very least, even with extreme pressures on margins for the rest of the year potentially in a hypothetical, we'll make our guidance. But besides that, we're in a good spot.

Got it. I appreciate all the color there. And then egas 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. Thanks, Marc. This is Anatol. I mean we're watching the same things as you and

And our next question comes from Spiro Dounis with Citi.

First question, maybe for you,

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 SBL 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 7x unlevered returns, highly contracted at 10% and 50% leverage, which gets you to under 4x 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?

Yes. Thanks, Spiro. We were never in the camp that the 20-year deal is dead. Obviously, over the last couple of years, the market has largely absorbed that. And you're seeing -- but that said, you're clearly seeing the average tenor over whatever period extending. So we're -- we've done some 15-year deals. We've done some well over 20-year deals over the last couple of years. And we like those transactions, again, especially when it is an end user and it is a building block to a relationship that we expect will last for decades and will lead to incremental volume. The other component of your question, like since it is starting the sort of the 20-year piece, if you will, is starting in the back half of the decade, there are some early volumes incorporated into that as

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, thanks for the question. So I actually view the policy in a positive way that much like what we do today, which is we commercialize our projects before we fully go into construction or finance. They want to make sure that there's a need basis for what they've permitted. So I think it will help with some of the projects that have been on the books for a while that maybe they have allocated gas flows to that they help them -- help move them along. So some of these projects surpassed my time line here at Cheniere, which is 7 years. Have been on the books for over a decade. And it's quite frankly, it's time to either build a project or not. And so I view it relatively positively. In fact, all the administration, whether it's DOE or FERC have started -- begun to embrace that natural gas is here to stay. It's going to be a very, very important transition fuel for clean energy and beyond, quite frankly. So we're starting to see some movement there on all the 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

So the eligibility I was talking about was the investment-grade index eligibility. But in terms of your question, yes, we meet it, and we've met it now for 2 quarters in a row. Our LTM EBITDA -- net income is over $7 billion. Our market cap is large enough that we're probably in the top 5 largest companies in this country that qualify that are not in the S&P 500. So should be a matter of time, but obviously, had 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?

Yes. Thanks, Mike. It's Anatol. Look, the pricing was more attractive in Europe than it was in Asia during Q1. And it's as simple as that. We obviously don't control the vast majority of the volume that we produce and our customers took advantage of the destination flexibility. And as did we, which, as

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 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 the next question will come 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 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 time lines 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 and 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.

I did over 20.

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 comes 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?

Sure. So on the CapEx for the year, the $550 million was more than a typical quarter. We had some milestones during the quarter, and that was deployed into Stage 3. But Stage 3, I think the CapEx for the year will be around, if not a little less than $1.5 billion. And all in, when you start adding in maintenance CapEx, you add in other growth CapEx, which is mainly just development or this early work and FEED work at the Sabine expansion and with mid-scale 8 and 9, we'll be well under $2 billion in total CapEx for the year. In terms of funding the Stage 3, 50-50, that's still the intent. It's just right now when you think about $6 billion or so of DCF, you account for that CapEx, we're at $4 billion or so of free cash flow. Account for the debt pay down, the dividend. They're still well over $2 billion that could technically be allocated over time to the buyback program going into the end of this year and early next. So we have plenty of money to actually fund the equity component first of Stage 3, retain the flexibility, retain the commitments from the banks that don't expire for another 6 years, save hundreds of millions of dollars on interest expense and keep on plugging away. And we'll see if we use that leverage to finish up Stage 3 or even to help us fund -- yes, the Corpus expansion thereafter. So we do intend to use that money. It's just flexibly there for us and pretty cheap to hold on to for the time being.

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?

13.5 to...

Yes, from 13.5 Bcf to 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 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. And maybe just the last question is with respect to long-term contract against PAs, are you still getting a lot of interest on IPM sorts of frameworks rather than kind of the international offtakers as an option. Just I guess, apart from a couple -- in recent past, we haven't seen a lot of that type recently, but I'm curious if there's still appetite for that.

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 an 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.