CQP - AMEX

Good day, ladies and gentlemen, and welcome to today's Cheniere Energy Q3 2022 Earnings Call and Webcast. Today's call is being recorded. At this time, I'd like to turn the conference over to Randy Bhatia, Vice President of Investor Relations. Please go ahead.

Thanks, operator, and good morning, everyone. Welcome to Cheniere's Third Quarter 2022 Earnings Conference Call. The slide presentation and access to the webcast for today's call are available cheniere.com. Joining me this morning are Jack Fusco, Cheniere's President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and

Thank you, Randy, and good morning, everyone. Thanks for joining us today, and thank you all for your continued support of Cheniere. I'm pleased to be here this morning to highlight our third quarter 2022 results and achievements and discuss our positive outlook for the remainder of this year and into next. All of which continues to demonstrate Cheniere's market leadership and excellence throughout our business. Since our capital allocation update in September, we have remained laser-focused on our operations, ensuring reliable LNG production and supply for our customers amidst global energy shortages and challenges. In fact, just last week, we had a daily production record for the company, producing well north of 7 TBtu of LNG and also a daily record at Sabine Pass of approximately 5 TBtu of LNG. My congratulations to the Cheniere's professionals for a job well done. Additionally, in conjunction with Bechtel's Engineering and Construction, we are off to a great start at Corpus Stage 3. We have rolled up our sleeves, hit the ground running and have already seen some early signs of potential acceleration on that project. Across the LNG market, volatility continues to dominate, driven by short-term supply-demand pressures. Recently, from record-breaking warmer weather, near-term prices have retreated from the highs we saw fairly 2 months ago. Nevertheless, we are largely insulated from these price swings, given the highly contracted nature of our business, and we remain focused on long-term value creation as our priority with short-term market dislocations only serving to accelerate our long-term plans as you heard from me and

Thanks, Jack, and good morning, everyone. Please turn to Slide 8. Despite it being a shoulder season in many regions, the turbulence in the global gas and LNG markets continued throughout the third quarter with only a few brief stretches of relative stability. While geopolitical conflicts and the related curtailment of Russian gas flows are largely responsible for the supply shock in Europe this year, we believe that some cyclical dynamics also played a role in laying the groundwork for today's market conditions of elevated prices and volatility. In fact, we've signaled for some time that the rate of new liquefaction capacity coming online would decelerate significantly during the 2020 through 2024 period, given the lack of FIDs taken in years prior. As you can see on the chart to the left, we estimate current capacity growth rates to be near 2%, a level not seen since 2012 when the market was also out of balance and prices clearly signaled the need for new LNG capacity. As a result, given the long lead time required to develop LNG projects, we expect market balances to potentially remain tight for the next several years, exacerbated by the crisis in Europe and the reduction of Russian supply to the European market. As shown in the middle chart, LNG imports from the U.S. have been the primary resource to offset the removal of over 50 Bcm of Russian gas imports from the European market this year. Further reinforcing Jack's earlier point on the ability of U.S. LNG to respond quickly to market signals. As the primary source of global LNG supply growth for the past 4 years, the U.S. has surpassed Australia and Qatar to become the world's largest supplier measured by installed capacity this year, and this growth could not have come at a more critical time for Europe, given that inherent destination flexibility. The U.S. has become Europe's top LNG supplier, and Cheniere's facilities at Sabine Pass and Corpus Christi have been significant contributors to this growth, helping provide secure and reliable natural gas supply to the European market, which I will detail further in a minute. Despite the steady increase in LNG flows to Europe, TTF continued to rally in the third quarter, hitting an all-time high of about $99 per MMBtu in late August, as concerns surrounding adequacy of supply reach new levels. Since then, TTF prices have come off considerably, settling October at about $54 an MMBtu, despite no sign of Nord Stream flows resuming. JKM Futures have traded at a discount to TTF for much of this year as European buyers have kept netbacks higher into the region compared to Asia in order to fill storage ahead of winter heating demand. In the U.S., Henry Hub prices have generally dropped since late August, settling October at $6.87 an MMBtu as temperatures and forecasts moderated and gas production continued to rise. Let's now turn to Page 9 to address regional dynamics in more detail. As I just mentioned, Europe has been utilizing LNG to try to offset as much of its gas supply deficit related to the Russian gas cuts by increasing its LNG imports by 65% this year with approximately 87 million tonnes imported through the third quarter, making 2022 an all-time high year for LNG imports into Europe. Imports from the U.S. represented 44% of that total. In fact, Cheniere alone was responsible for approximately 1/4 of Europe's LNG imports this year. As the top middle chart illustrates, U.S. LNG volumes surged over 200% year-on-year in the third quarter as Nord Stream flows came to a halt by the end of the quarter. Nevertheless, the European market appears well prepared for winter, as shown, with storage levels exceeding their 5-year average on the back of milder weather, some level of industrial demand management and aggressive buying by European utilities. As such, we have recently seen prices moderate as the market waits for winter demand to kick in. We've also seen the congestion at certain European regas terminals continue to grow, once again, evidencing the need for development of additional import capacity and related infrastructure in order to provide relief and allow greater volumes of LNG to access the market, particularly in Northwest Europe. Fortunately, the new [ N7 ] import terminal in the Netherlands recently began operations. The terminal, one of the few FSRUs expected to start in Europe in the coming months, received its first cargo in September, which was produced and delivered from our facility at Sabine Pass. In Asia, LNG imports declined by 14.5 million tonnes year-to-date with nearly 5 million tonnes of the decline realized in the third quarter. 90% of this decline is attributable to China as a result of reduced industrial sector demand and weak gas burn, which could remain a trend throughout this winter. In China, industrial gas demand decreased by 3 Bcm in the third quarter, representing an 8.7% drop year-on-year and low hydro levels supported thermal use in power generation with coal generation increasing by 11% year-on-year in the third quarter, while gas grew only 4%. However, overall gas-fired power generation dropped 8% year-on-year from January through September as high spot LNG prices and robust renewables generation in the first half of the year disincentivized domestic use and actually encourage cargoes to be redirected to Europe. Much of the demand growth in Asia in the third quarter occurred in Thailand, Japan and Taiwan as a result of inelastic consumption needs. As we mentioned in previous calls, Thailand continues to call on LNG to supplement dwindling domestic gas production. Japan plugged a 2.7-gigawatt deficit in nuclear availability in the third quarter, and Taiwan continues to offset the decline in coal generation. Let's move to Slide 10. Last quarter, we discussed LNG contracting trends and the growing commercial success that U.S. projects were garnering. That contracting momentum continued in the third quarter, reaching a total of 40 million tonnes per annum of long-term transactions signed with U.S. projects year-to-date, that's through mid-October, highlighted by our long-term deals with PetroChina and PTT. As you can see on the left chart, the aggregate volume is approximately 80% higher than what was signed in all of 2021 and represents more than 75% of global contracts signed year-to-date. In fact, the first 9 months of 2022 alone, make '22 a record year for U.S. LNG contracts signed. This commercial success is owed largely to several key advantages of U.S. LNG, destination flexibility, competitive and stable pricing, a mature upstream and midstream footprint and time to market. These advantages, coupled with elevated market prices have provided tailwinds for the development of additional LNG capacity in the U.S. However, most of those U.S. projects still have yet to make FID given the rigorous commercial, financial, regulatory and technical hurdles, projects are required to overcome in order to raise financing and move forward with construction. And those hurdles are only getting higher given the volatility, inflation and rising interest rates. For our part, as we discussed last month, we plan to continue to pursue growth of our 55 million-tonne platform starting with our near-term plans to add approximately 5 million tonnes per annum via the CCL Trains 8 and 9 mid-scale projects and some debottlenecking at Stage 3 along with the long-term potential to add an incremental 30 million tonnes per annum of volume across our 2 sites. Volumes that will continue to ensure security supply and sustainable economic growth for our long-term customers and end-use communities. We're hard at work on these opportunities, and we'll keep you informed on them as they achieve project development milestones. And now I'll turn the call over to

Thanks, Anatol, and good morning, everyone. I'm pleased to be here today to review our third quarter 2022 financial results and key financial accomplishments, all of which continue to reflect our team's tireless efforts to ensure safe and reliable operations and seamless execution throughout this period of prolonged volatility in the global energy market. Turning to Slide 12. During the third quarter, we generated adjusted EBITDA of approximately $2.8 billion, distributable cash flow of approximately $2 billion and a net loss of approximately $2.4 billion. Our third quarter results once again were supported by the sustained higher margin environment across global gas and LNG markets, higher lifting margins due to higher Henry Hub prices across the quarter, and incremental margin achieved from certain portfolio optimization activities. Our quarterly results were achieved despite a couple of CMI cargoes moving into Q4 from Q3. In addition, in the third quarter, we recognized a portion of the payment from Chevron related to the early termination of the regasification TUA, which we expect to receive before year-end. We recognized an income 560 TBtu of physical LNG during the third quarter, including 556 TBtu produced from our Sabine Pass or Corpus Christi projects with 4 TBtu sourced from third parties. Approximately 82% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements with terms greater than 10 years. Once again, the net income line continues to be impacted by the unrealized noncash derivative impact related to our long-term IPM agreements, as we have discussed on prior earnings calls. In the third quarter, we recognized $4.9 billion of these unrealized noncash derivative losses attributable to the continued growth of LNG margins and commodity price volatility. As a reminder, because GAAP requires mark-to-market accounting of these long-term gas supply agreements, but does not permit the mark-to-market of the associated and offsetting sale of LNG, it results in a mismatch of accounting methodology for the purchase of natural gas and the corresponding sale of LNG, which drives this quarterly variability in net income from period to period. That is why we would expect as margins stabilize and price volatility subsides over time that these unrealized noncash derivative moves will become much less pronounced in our quarterly results. Thanks, in large part, to the significantly accelerated progress on our capital allocation plan announced in September of 2021. During the quarter, we rolled out our revised long-term capital allocation plan, our 20/20 vision of over $20 billion of available cash through 2026 as well as over $20 per share of run rate distributable cash flow. Built upon the foundation of our previous plan, this plan is designed to achieve and maintain investment-grade metrics through cycles, further return capital to shareholders over time and continue to invest in accretive growth beyond Corpus Christi Stage 3. As part of the revised plan, we increased our share repurchase authorization by $4 billion for an additional 3 years, beginning October 1, 2022, lowered our consolidated long-term leverage target to approximately 4 times and increased the dividend by 20% beginning in the third quarter of 2022, targeting a 10% annual dividend growth rate through the construction of Stage 3 into the mid-2020. Our accelerated progress in terms of capital allocation, coupled with our revised plan demonstrates the power of the Cheniere platform through market cycles and solidifies Cheniere's position as a leading global LNG operator and a preeminent North American infrastructure company. During the quarter, we repaid over $1.3 billion of consolidated long-term indebtedness, bringing our total debt pay down to over $4.4 billion through the third quarter since launching our capital allocation plan last year. And in the first 9 months of this year, we have repaid over $3.2 billion of debt. Just in the third quarter alone, we prepaid nearly $800 million of outstanding borrowings on the CCH term loan facility. And notably, we repurchased over $530 million in principle of senior notes at both CEI and CCH at price levels under par, under an open market repurchase program that was initiated during the quarter. This past month, we have also redeemed $300 million of the 2023 new secured notes at SPL pursuant to an early redemption notice issued in September. We are clearly demonstrating our commitment to our balance sheet by utilizing multiple avenues to efficiently reach those target leverage metrics, and we'll continue to be opportunistic as we optimize the debt across the Cheniere complex to achieve resilient and sustainable investment-grade credit metrics. Our accelerated deleveraging efforts towards an investment-grade consolidated balance sheet have been reflected in ratings upgrades by multiple agencies recently. In September, Moody's upgraded CEI 2 notches to BA1 and CQP and SBL 1 notch to BA1 and Baa2, bringing all S&P and Moody's ratings in sync across the Cheniere complex. Also in September, Fitch upgraded CQP to BBB- and SBL to BBB flat. Fitch's upgrade of CQP to BBB- is significant as Americas the first-ever unsecured investment-grade rating at one of our corporate parent entities, and it's an important milestone in Cheniere's continued evolution. We will continue to execute on our 20/20 Vision Plan and expect further positive ratings momentum and migration to investment grade over time. In terms of shareholder returns, during the third quarter, we repurchased over 0.5 million shares for approximately $75 million, bringing our total shares repurchased to approximately 5 million shares or a little over $600 million. The upside share repurchase authorization we announced as part of our new capital allocation plan didn't commence until the fourth quarter. And I can tell you we are off and running under the new authorization. Having already repurchased over 1 million shares just in October as we have now recalibrated our debt paydown to share repurchase ratio through 2026 on a long-term cumulative basis from 4:1 to 1:1, to further enhance shareholder returns while further solidifying our long-term investment-grade credit metrics. During the third quarter, we also declared and paid our fourth quarterly dividend of $0.33 per common share, bringing our total dividends paid to $1.32 per common share. Under our new capital allocation plan, we increased the dividend by 20% for the dividend related to the third quarter to $0.395 per common share and maintain our commitment to increasing the dividend by approximately 10% per year through Stage 3 construction, which will grow us into around a 20% payout ratio over time. Turning now to Slide 13, where I'll provide additional detail around guidance and our open capacity for the remainder of the 2022 as well as for 2023. We are reconfirming our full year 2022 guidance ranges of $11 billion to $11.5 billion in consolidated adjusted EBITDA and $8.1 billion to $8.6 billion in distributable cash flow. These ranges were each already increased by approximately $1.2 billion since our last earnings call in September, and we can now highlight that we are currently tracking into the upper half of both ranges as well as to the high end of our CQP distribution guidance of $4 to $4.25 per unit. Our guidance ranges illustrate what an incredible year 2022 has been for Cheniere. Since our initial guidance ranges for 2022 were provided 12 months ago, we have increased the midpoint of our EBITDA range by approximately 85%, DCF by approximately 150% and CQP distribution by approximately 1/3. With respect to the EBITDA sensitivity for the remainder of 2022, we are approaching the end of the year, and therefore, we have sold much of our total expected production for the remainder of the year and have approximately 20 TBtu unsold remaining. We currently forecast that a $1 change in market margin would impact EBITDA by approximately $20 million the balance of 2022 as we have released the remaining volume that have been reserved for long-term origination back to CMI. Our results could also be impacted by those year-end cargoes we mentioned back on our call in September. With the volatility and evolving market dynamics, these cargoes could be drawn to Asia, which would push the timing of recognition of some of these cargoes into 2023. With that being said, as we look to 2023 and our sensitivity to market margin, currently, we forecast approximately 150 TBtu of open volumes in 2023. We expect a $1 change in market margin to impact 2023 EBITDA by approximately $130 million. As a portion of our forecasted unsold volume for next year is being reserved for potential long-term origination negotiation. We do have some term contracts commencing over the course of the year. There is likely a slight weighting of that open volume to the first half of the year. In terms of major capital expenditures, I would mainly highlight we forecast spending approximately $1.5 billion in CapEx related to Corpus Christi Stage 3 in 2023, which is a similar amount to what we expect to have funded this year, including our LNTP payments since the start of 2022. As we mentioned in September, we will provide our full year EBITDA, DCF and CQP distribution guidance ranges for 2023 on the fourth quarter call in February. Our unsold position in 2023 is expected to be lower than 2022 as 2022 benefited from the early completion and ramp-up of Train 6 and the maintenance optimization we disclosed in May. Certain long-term contracts are scheduled to commence over the course of 2023, and we have higher planned maintenance scheduled for the next year at Sabine. Without a new Train coming into service next year, we wouldn't expect a material change to the production forecast from here. The current state of global gas markets, which have featured elevated market margins for nearly a year now, underscore the global call for meaningful investment in natural gas infrastructure, which Cheniere is leading with our recent sanctioning of Corpus Christi Stage 3. During this prolonged period of heightened volatility, we've been deliberate and prudent stewards of capital, accelerating progress on our capital allocation objectives and positioning Cheniere for resilient success in the decades to come. And we expect to lead with a sustainable investment-grade balance sheet, accretive growth projects and meaningful and growing shareholder returns. 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] We'll take our first question from Michael Lapides with Goldman Sachs.

Just real quickly, can I ask a little bit about time line. You hinted at it a little bit for Stage 3 in terms of potentially being able to move things forward a little bit, how much, how material? And then can you talk about the maintenance at Sabine Pass in 2023? I assume it's probably more shoulder month, but let me know if that's wrong. And how should we -- is there a way to quantify the impact on volume?

Michael, thanks. So first, on construction stage 3, extremely pleased at the progress to date. You can tell from my talking points that I perfectly expect my staff and Bechtel to have underpromised and will over deliver on my expectations. And it's a little early at this point for us to revise our schedule. But I would stay tuned if we continue to have this favorable weather and we continue to execute the way the plant has developed. As far as maintenance, you're right. We try to do maintenance in the shoulder months, where LNG prices typically are lowest, a 6-year cycle at Sabine. So it's an unusual year for us where we have 2 trains coming down basically at the same time to do maintenance on them. As far as quantities of the maintenance, I'll turn it over to

Michael, as we think about '22 versus '23, we're going to be slightly up year-over-year on total production, and that's really mainly due to the Train 6. We had about 11 months of production hitting P&L last -- this year with a little ramp-up in Q1. We have a full year of Train 6 for '23, but that will be offset a bit by this major maintenance that is definitively planned for next year. So basically, I'd say we are probably rounding down to 44 million tonnes for the year this year, and we'll be right around 45 million tonnes where the rest of the 7 trains are not -- that won't have the maintenance, will pick up the slack to an extent.

We'll take our next question from Michael Blum with Wells Fargo.

So just wanted to go back to your comments on CapEx in '23. So you flagged the Corpus Christi Stage 3 spending, so that's clear. Anything else you flag major? I know you talked in the past about prep work on mid-scale 9. So I just wanted to see if there are any other major items?

That's about it, Michael. I mean the $1.5 billion is the, let's say, all-in levered costs that we would deploy next year and honestly that's kind of what we expect this year. We spent about $1 billion already pre-FID and post-FID and have another $400 million to $500 million to go this quarter as were like 12% progressed at Stage 3. On other CapEx, we're going to be spending money, let's say, hundreds of millions of dollars across the board on things to continue to optimize but also develop at Corpus and Sabine. And you're just not going to notice it as clearly we'll have billing into DCF next year when we come out with it officially in February.

Okay. Got it. That makes sense. And then just wanted to ask kind of between your debt and equity allocation decisions quarter-by-quarter. Third quarter buybacks are a little bit lower, debt purchase was higher. Clearly, buybacks are picked up in Q4. Just trying to see if there's any patterns we should be aware of or what's behind the decision process there?

Sure. So clearly, you could see in Q2, we bought back over $500 million of stock. And during that June period, specifically the stock had a little pressure on it, and we were opportunistic. And then if you just look at Q3 from 630 to 930, the stock went up like $35. So you can imagine, as the stock is going up. We're obviously getting less opportunistic but when things are a little bit more stagnant or obviously, there's pressure on the stock, we're hitting it harder. And then the another -- the other thing I'd add is we clearly had to wait till the announcement on capital allocation in mid-September. Just with all the [ MMPI ] that came with that to officially set up the 10b5-1 for Q4. And that's why the new plan with the upsized allocations started in earnest in Q4, and we've already bought back over 1 million shares just in October.

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

I just want to kind of reconcile against the last update that we heard from you guys a bit over a month ago with the September update. You gave guidance, lifted guidance. And since then, spreads came in and Europe faced logistical issues, yet you now point to the high end of the EBITDA guide. Just wondering what positive has materialized and will they carry into '23?

Jeremy, it's

Got it. Makes sense. I bet a little Cheniere conservatism was baked in there as well. So always good to see that. And just kind of continuing with this, the European logistics issues carrying forward into 2023. Just wondering if you see that kind of impacting your outlook now? And also just broadly macro question here. Russia is sending much less gas into Europe in '23. How do you think Europe still storage next year?

Jeremy, it's Anatol. Thanks for the question. The good news on the Europe front is it is moving very aggressively to resolve these infrastructure issues. We spoke about our honor to inaugurate in Sabine, that facility will double. We do expect that throughout '23 about 60 million tonnes of additional regas capacity will be added. That number will probably get over 70 million tonnes in '24. But we agree with you. We think Europe is in no way out of the woods without that pipeline flow, it is really for most of this year, it is next winter that we were more worried about because obviously, this winter did have the benefit of a substantial amount of flow even in the first half of this year before Nord Stream was fully shut off. So it will be a challenge. The infrastructure issues will be addressed over the next really 6 to 12 months. You've already seen a dramatic decrease in the amount of floating storage into Europe, and we think that, that was a little bit of weather and this additional infrastructure solutions will get cleaned up quickly. But the molecules for Europe will be very difficult to come by over the coming years.

Got it. So just to be clear on that last point, you're seeing the winter fill next year looks like it could be as tight as it was this year?

Weather-dependent, of course, as always, but in parallel possible that it will be more difficult to reach these 80-plus percent full storage levels.

We'll take our next question from Marc Solecitto with Barclays.

In terms of the liquefaction fee environment and the marginal cost of new supply, it wasn't too long ago where it seemed like the industry might have been trending towards the lower half of that 200 to 250 CMI margin assumption range. So just wondering with interest rates now at the highest they've been at in over 15 years and EPC costs trending higher, where do you see the marginal cost of new supply and liquefaction fees trending today?

Yes. Thanks, Marc, Anatol again. We expect that trend to play out. But I have to tell you kind of in the trenches, you haven't seen much of that. There are -- the competition among U.S. developers is still one that is anchoring expectations -- buyer expectations in that low end of the range. I will say that it has been coming up somewhat, but in the aggregate, between these aggressively priced offtake deals by some of the early-stage developers as well as the EPC inflationary pressures and the interest rate environment, that's a tough equation to solve, and we think that that's, of course, part of the reason why you haven't seen more projects [ plus the FID ].

Sure. So just to acknowledge the inflation out there that's clearly happening for everybody, and we think about our operating expenses or even our SG&A, our SPAs, which we have over 30 of, with different counterparties all over the world. They all have a built-in annual escalator based on CPI for, let's say, approximately, give or take, 15%. And if you just bake that in and with how much we haven't fixed fees, going into the new year, we're more than covering any inflation on O&M and SG&A for the company, which just highlights the stability of that run rate cash flow.

Got it. That's very helpful. And then as it relates to the 150 TBtu open for next year, have you started to lock in some of your open exposure for 2023? And would that be included in that referenced open capacity number?

Yes. So what we acknowledged in the prepared remarks and in the presentation is we actually have 150 TBtu truly open. And of that, we're reserving 20 TBtu for our origination placeholders. So that $130 million, give or take, for a $1 move in margins, that's open today. However, I'd say we have probably sold onwards and locked in fixed margins for around 20 TBtu for 2023 at this point. Clearly, the liquidity is pretty tough with how volatile it's been. But we're making a dent there, and we'll give an even more robust update next year.

We'll take our next question from Jean Ann Salisbury with Bernstein.

Anatol, I wanted to get your view on the medium-term LNG market. Obviously, some large moving pieces and whether more U.S. projects go forward and whether Russian gas keeps flowing. But seeing everything that you can see now, do you think it's more likely that LNG will be overbuilt or underbuilt in the back half of the decade?

I really don't see this overbuild dynamic even in that '26, '27, '28 time frame. There's such an enormous amount of latent demand, if you will. We've been shying away from the term of demand disruption, right? We've termed a demand management even as prices pulled back in Europe modestly over the last 1 month, 1.5 months, you've seen a fairly dramatic resumption in industrial demand, right? So those numbers don't go away for a very long time. And yes, BASF and others may build facilities in the U.S. and in Qatar, but fundamentally, the demand picture in Europe just isn't going to change that much. And we still see a tremendous demand growth story out of Asia and EM in general. So we, of course, as you know, fully believe that the Qatar mega trades will continue to come on. The 4 under construction now, plus 2 more plus 2 more. There just aren't enough solutions and now with this very robust contracting, but relatively slow process to FID U.S. projects, that's just going to make the market that much tighter through the back half of this decade. So we see years and years of this dynamic before you can see a truly balanced market.

Jean Ann, this is Jack. I always track how much capital is being invested in natural gas infrastructure around the world, and there's over $1 trillion right now of nat gas projects around the world with pipelines and power plants and regas facilities. So that, to me, is the signal that gas is here, it's here to stay for the long term and that the LNG side of it will continue to grow.

Great. That's -- I appreciate all that. As a follow-up, I'm just wondering what the waiting time for a new LNG FERC filing is these days? I think earlier this year, you kind of estimated 2 years that said maybe if the U.S. focused on it, it could be a lot faster than that. So I'm wondering if Cheniere is still a good number or faster than that or possibly lower than that?

Yes. No, Jean Ann, I'll tell you, over the last 6 years, we've doubled our business here at Cheniere. And today, more than ever, that permitting strategy I believe, is essential, right, because it's more and more difficult with the current regulatory environment to make any mid-course changes, whether they're on the design or construction. So we filed -- we prefiled from mid-scale Trains 8 and 9 that got accepted not too long ago. There's a 6-month period after prefiling that we need to wait. It's our expectation that we will file immediately thereafter so early next year with 8 and 9 and then -- and hopefully, my goal is to make those trains contiguous. So right after Train 7 is commissioned, I want to go to Train 8 and then to Train 9. So we're trying to move quickly. I think that just strategically the whole permitting strategy part and making sure that you've crossed the Ts and dotted the Is in your application is more important than ever today.

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

Maybe just a follow-up to Jean Ann's question on the first permitting process. Any insights on to whether we could see further growth at Corpus or Sabine? Are there any signposts that we should be looking for in terms of preference? And when should we expect maybe a pre-FERC filing process to begin there?

No, look, you know from our talking points that -- and Anatol's talking points that, that we're looking at 30-plus MTPA of growth across the portfolio. I would expect Sabine to be first. I'd expect sometime next year that we do a prefiling for additional growth there at Sabine. But again, like I said, we're making sure that we understand everything it is to know about that growth and that, that filing is complete. So it gets accepted and moved through the process appropriately. And then right after that, hopefully, Trains 8 and 9 will be done at Corpus, and we can focus on whatever additional expansion plans we have there.

Great. That's super helpful. Maybe as a follow-up, the ability to sell cargoes forward in the market, the time seems shorter and shorter relative to years past just given pricing and liquidity. Can you just talk about how that market is now? Is it improving in terms of being able to sell those cargoes forward? And could you be in a situation middle of next year going into the tight winter that we alluded to earlier -- to where you'll be selling those cargoes basically at spot prices at that time?

Sure. So this is

We'll take our next question from Julien Dumoulin-Smith with Bank of America.

Just to come back to try to quantify some of this. In terms of improving returns, just it only simply because of the higher rate environment. Can you try to speak to that a little bit more in terms of what you're prospectively seeing in your counterparty conversations? Again, I know that Anatol, you try to provide some context in terms of the offtake prices themselves, but maybe reframing that in terms of returns, if you can elaborate on that initially and maybe speak a little bit to the pace of contract? And obviously, you've retained a certain portion in '23, but what are you seeing in terms of your own commitment pace next year as well?

All right. This is

Yes, Julien. So we felt comfortable with this $2 to $2.50 range. As you heard some of the previous Q&A, the market overall for U.S. projects has firmed up a bit, but it is still very much anchored in those early-stage developer proposals. We've always felt like we extract a premium for the operational excellence and the performance that we now have a track record of. We don't participate in the race to the bottom, and we have a lot of components to our contractual agreements like the inflation mechanism that

And it's nice to add that we're not really issuing debt all that much these days. We're just paying down billions of dollars a day. So we're just in a different world than we would have been 10 years ago in a rising rate environment.

Totally. Understood. It sounds like return disclosure that you guys are writing are largely unchanged. Obvious elevated, nonetheless. If I can, just to come back and clarify from earlier on prefiling, should we expect a regular cadence as you think about your regular deployment of new liquefaction out in the decade? As you alluded to a moment ago, you would expect next year some prefiling. Should we expect that to sort of overlap in the similar regular cadence way? Or do you think that because you say you need to dot your Is and Ts that you can't have as much of an overlap? I know that was a little bit of a thought earlier, but just coming back to clarify that.

No, I think, Julien, you should expect some overlap between the 2 sites. We're not going to have overlap on one site.

We'll take our next question from Ben Nolan with Stifel.

I'm surprised that nobody has mentioned this yet, but how about Cristian Javier and those Astros yesterday, my goodness.

Man, thank you for mentioning that because the night before was a bad night and last night [indiscernible]. So we're very excited to have him come back home and bring home the world's series right here in Houston.

Absolutely. I'm with you. So my 2 quick questions here is -- first of all, I'm curious where you stand as it relates to LNG shipping? Obviously, we've seen the shipping rates just explode here recently. And I know a lot of what you do is fully contracted. But maybe just any update on sort of how you're positioned in that respect.

Yes. Thanks, Ben. We operate a long-term business that has long-term commitments and lots of flexibility within that. We learned our lessons really before we started in the market and are not in a position to risk being short shipping. So we're well protected. Our delivered contracts and our producer contracts have a lot of optionality embedded in them that are paid for by our customers, and we take advantage of that, as

Yes. I'll just add. I mean, at this point, we're basically the second largest charter of ships in the world. And we've been proactive on this as we sign up the DES deals or IPM deals, we're typically almost simultaneously locking in long-term charters. So going into this winter, even going into this year, we've had a large portfolio that's well under 100,000 a day when prices have been doubled, tripled, sometimes quadrupled or more. So that's been part of the tailwind to EBITDA this year and even part of how we got to the upper end of the guidance range at this point in just the last month is some of the subchartering that we've been able to do as we haven't used all our ships to get to Asia, but are directing them towards Europe.

That's great color. I appreciate that. And then as my follow-up, it's interesting to hear you guys talk about sort of beyond the next phase of Corpus Christi and looking to potentially do something at Sabine Pass. I'm curious how you're thinking about the way that's done? Obviously, here lately, you're doing the mid-scale versions. Is that just because they happen to be a good fit for what you're trying to do at Stage 3? Or are you thinking that whatever the mid-scale model is probably the way that you're going to be moving forward with all your incremental development going forward?

No. We're looking at all the technologies. So we're looking at gas compression, we're looking at large electric compression. We're looking at mid-scale electric compression. So we're doing a complete evaluation. I like the mid-scale solution for Stage 3. It helped control the inflationary pressures that we see on the large trains with a lot of nickel and precious metals. But it doesn't mean that's where we're going to stay for the rest of the portfolio. So we'll develop a solution that is appropriate for the site.

We'll take our next question from Alex Kania with Wolfe Research.

Can you talk a little bit more maybe just about the broader landscape of these partially contracted LNG projects? Do you think that, ultimately, that a fair amount of those may not end up moving forward? And if so, do those kind of represent commercial opportunities for you to kind of discuss contracting with some of these parties that are already on board, some projects that may end up not moving forward?

Yes, Alex. This is Anatol. I'll try that first and see if anyone else wants to chime in. But look, we -- with the loss of Arctic Russia as a major supply node to meet the LNG demand, U.S. was the next logical choice. You saw this rush to contract, 40 million tonnes year-to-date and 30 million of that has yet to be performed on. And like with all of these -- there isn't a simple answer for these questions anymore as the market becomes large, diverse, has multiple participants, there are a lot of load serving entities in that 30 million tonnes that need the LNG, and there are a lot of opportunistic fires in those 30 million tonnes that are just out there to see what can possibly get over the finish line and offer the kind of attractive economics that were too good to pass up. So there's some of each. We certainly think that we're in a great position to continue to grow our platform, do it judiciously and potentially benefit from some of the buyers that really need the supply over the coming years.

Great. Then maybe just a follow up on the rating agencies. I mean, I know they've had some time to digest the capital allocation plan and they've had already some rating updates. Do you kind of have the sense to broadly about how maybe that trend towards the investment-grade goal may look heading into next year or so just getting a sense of the delivery agents, what else the rating agencies need to get you kind of uniformly into the BBB range?

Sure. This is

We'll take our last question Craig Shere with Tuohy Brothers.

Just kind of picking up a little on the last question about contracting. Note that long-term SPAs from perspective in actual U.S. projects kind of materially trailed off the last couple of months. Given that brief hiatus, wondering at all, if you can opine on your confidence that Europeans will step up to the table again into the first half next year? And if you could give us a sense to the degree you think Cheniere's being shortlisted by the Europeans on prospective new long-term commitments due to a combination of your bridging cargoes, a desire to reward those who help this year and the desire to work with partners that can make clean energy investments in the medium and long term in CCUS and hydrogen a priority?

Thanks, Craig, for the leaving question. If I ever gave you the impression that we feel confident that there will be in Armada European load serving utilities as counterparties, I misspoke. I think that those will be few and far between. We, of course, have done the transactions with Equinor, Engie, as you know, this year, and we are optimistic that European-based buyers will be part of the portfolio and part of the solution going forward. But we do see the Asian market as the primary growth driver and the primary long-term contracting opportunity. Year-to-date, there have been precious view I think what you would call European buyers that have come to the table. You'll see them here and there. We're obviously in those discussions, as you said, we bring a lot to the table, but they are few and far between. And even though we have been a critical part of rebalancing Europe last year and this year, and we'll continue to do our best to support its efforts to meet this energy demand. We don't expect a lot of load serving European utilities to be in that 30-plus counterparty list going forward.

Thank you, everybody. Thanks for your support of Cheniere.