Good day, and welcome to the Cheniere Energy Inc Q1 2022 Earnings Call and Webcast. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Randy Bhatia. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and welcome to Cheniere’s first quarter 2022 earnings conference call. The slide presentation and access to the webcast for today’s call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere’s President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and Zach Davis, Executive Vice President and CFO. Before we begin, I would like to remind all listeners that our remarks, including answers to your questions, may contain forward-looking statements and actual results could differ materially from what is described in these statements. Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix to the slide presentation. As part of our discussion of Cheniere’s results, today’s call may also include selected financial information and results for Cheniere Energy Partners LP, or CQP. We do not intend to cover CQP’s results separately from those of Cheniere Energy, Inc. The call agenda is shown on Slide 3. Jack will begin with operating and financial highlights, Anatol will then provide an update on the LNG market, and Zach will review our financial results and guidance. After prepared remarks, we will open the call 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 today, and thank you all for your continued support of Cheniere. I’m pleased to be here this morning to review our first quarter 2022 achievements and discuss our further improved 2022 outlook. Before we begin, I would like to spend a moment discussing the tragic situation that continues to unfold in Ukraine since we last spoke in February. Our thoughts and prayers are with the people of Ukraine and broader Europe as they navigate these volatile and uncertain times. At Cheniere, we built strong relationships with and support the communities in which we live and work and that includes those who we supply LNG. Since the beginning of the year, over 75% of cargoes produced by Cheniere have landed in Europe. That amounts to over 150 cargoes of LNG, and we are just beginning. As Europe looks to reduce its dependency on Russian energy supplies and the administration looks to support our allies, the relevance and criticality of energy security in the role of LNG and natural gas as a reliable, flexible, and cleaner-burning fuel have never been more evident to customers and governments the world over. We have been active participants in the U.S.-EU task force on energy security. And we believe that increased cooperation around the world is essential to ensure our allies and partners, along with our customers, have access to energy in the months and years ahead. For these reasons, I have challenged our operations teams to do everything possible to safely and responsibly produce as much LNG as possible through our continued operational excellence programs, which we will address in more detail this morning. Now please turn to Slide 5, where I will review some key operational and financial highlights for the first quarter as well as introduce our upwardly revised guidance ranges. For the first quarter, we generated consolidated adjusted EBITDA of $3.2 billion and distributable cash flow of $2.5 billion, both of which benefited from the early completion and accelerated ramp-up of Sabine Pass Train 6, and were further supported by sustained higher market margins throughout the quarter. Looking ahead to the remainder of 2022, I’m pleased to announce that we are once again significantly raising our full-year 2022 EBITDA and distributable cash flow guidance. We now forecast 2022 consolidated adjusted EBITDA of $8.2 billion to $8.7 billion and distributable cash flow of $5.5 billion to $6 billion. Both increases are driven by sustained higher margins on open volumes, higher-than-forecasted global LNG prices across the year, increased expected volumes from both maintenance optimization and the accelerated ramp-up of Sabine Pass Train 6 as well as an increase in lifting margins driven by higher domestic natural gas prices. Zach will address guidance in more detail in a few minutes. Specifically, on our operational excellence program, our efforts there to unlock low or no-cost incremental volume through maintenance optimization or debottlenecking efforts continue to be very successful. Over the last few weeks, our operations and maintenance planning teams have further optimized our planned maintenance activities for 2022 resulting in an increase in forecast production of approximately 30 TBtu or 8 cargoes of LNG, all of which is expected to be sold by CMI. We are pleased to be able to support our customers and leverage our LNG platform and our operations and maintenance expertise to unlock incremental volumes of LNG for a market that so clearly needs it. We appreciate the recognition by the administration and our regulators that U.S. LNG is essential now and in the years to come, and with the support from the DOE and FERC and the recent orders authorizing additional export volumes from our projects. We will continue to pursue further optimization and debottlenecking opportunities to increase our volumes to meet the rising worldwide demand for LNG. During the quarter, our teams continued to achieve milestones in terms of development, execution, operations, and financial results. In partnership with Bechtel, not only did the Sabine Pass Train 6 reach substantial completion over a year ahead of schedule, but following substantial completion, our team was able to bring Train 6 to full utilization and stable operations well ahead of plan, which, along with general production outperformance across the portfolio, also contributed to our financial results this quarter, with a few additional cargos supporting our increased guidance for the year. Shortly after the substantial completion of Train 6, we announced the signing of our fully wrapped lump-sum turnkey EPC contract with Bechtel for Corpus Christi Stage 3. We issued, in fact, a limited notice to proceed to commence early engineering, procurement, and site mobilization and preparation work while we finalize the financing ahead of reaching FID, which we expect to occur this summer. I’m extremely proud of the seamless operations continued excellence achieved by our Cheniere team. During the quarter, we safely produced, loaded, and delivered a record number of volumes across our platform. Thanks to our continued focus on operational excellence and portfolio optimization. On the contracting front, we announced increases in extensions to existing long-term contracts with EOG and ONJ, which both reinforce the value of our commercial platform and the sustained long-term demand for LNG and natural gas in the global energy markets. Just this morning, we announced the new 15-year IPM agreement at Corpus Christi Stage 3 with ARC Resources, one of the largest natural gas producers in Canada. Signing this contract once again demonstrates our ability to provide innovative, flexible solutions for our global customer base. This IPM agreement further enables Canadian gas to reach international markets. Each of these agreements supports the sanctioning of Stage 3 and reflects the urgency in the global market for investments in new LNG capacity, as customers from around the world look to secure long-term supply, which Anatol will discuss in more detail shortly. Finally, in terms of our financial strategy, Zach and his team are executing on our long-term capital allocation plan faster than originally forecast due to the sustained higher margins, accelerating our initial debt paydown timeline, returning capital to shareholders and unitholders, and currently in the process of raising the financing and formal sanctioning of Stage 3. Turning now to Slide 6 for an update on the significant progress we have achieved in our climate and sustainability initiatives. In April, we announced our latest QMRV program that builds upon our existing study with natural gas producers and LNG shipping providers. Now applying that methodology and rigor to examining the greenhouse gas emissions associated with the delivery of natural gas to our facilities. As part of the program, we announced a collaboration with several of our key midstream infrastructure providers, including Kinder Morgan, Williams, MPLX, DT Midstream, and Crestwood, as well as multiple emission detection technology providers and leading academic institutions to improve the overall understanding of greenhouse gas emissions and further deployment of advanced monitoring technologies and protocols across midstream infrastructure that’s part of our value chain. From here, we expect to commence a similar QMRV program specific to our liquefaction equipment. We expect these robust QMRV programs to improve the data and transparency of emissions throughout the LNG value chain to help maximize the climate benefits and environmental competitiveness of U.S. natural gas in Cheniere LNG. These QMRV programs are built upon our climate and sustainability principles and support our broader climate strategy initiatives, especially our cargo emission tags, which will begin providing to our customers this year. Now please turn to Slide 7. While I provide a brief update on Corpus Christi Stage 3, as I mentioned a moment ago, during the quarter, we finalized the EPC contract with Bechtel for Stage 3 and we released them to begin early work under a limited notice to proceed. You can see early visual progress on Stage 3 site preparations in the slide. We are pleased to have the contract finalized and Stage 3 underway with pricing consistent with what we’ve communicated to the investment community over the past few years. We expect to announce the FID of Corpus Christi Stage 3 soon after we finalize the financing of the project, which is currently in process. Once completed, Corpus Christi Stage 3 is expected to provide the global market with over 10 million tons of incremental LNG per year. The development of additional LNG capacity has become even more critical as countries work to secure reliable and affordable energy supplies for the long-term in support of both energy security and environmental priorities. As such, we continue to develop opportunities to leverage infrastructure at both of our existing brownfield sites for further LNG capacity additions. Both Sabine Pass and Corpus Christi possess significant in-place infrastructure that puts capacity additions at those sites at a significant cost advantage relative to greenfield development. We look forward to sanctioning Stage 3 sometime in the summer and coming back to you after that with our plans for further LNG capacity growth, which would be supported by brownfield economics and underpinned by long-term contracts consistent with our investment parameters. With that, I want to reiterate my gratitude to the entire Cheniere team for their work to ensure the reliability of our LNG during these unprecedented times in our industry. 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 9. As Jack noted, the global energy and natural gas landscape has faced significant challenges this year. We find ourselves in uncharted territory as impacts from the war in Ukraine filter through gas markets, sparking extreme price volatility, and a renewed focus on security of reliable long-term natural gas supply. In March, JKM and TTF daily prices were pushed to new all-time highs, with April deliveries reaching approximately $85 and $72 per MMBtu respectively. That being said, since our last call, JKM predominantly traded at a discount to TTF as Europe transitioned from being the market of last resort, which was responsible for balancing the global LNG market, to the market of greatest need with destination flexible LNG available to respond to the market signal. While geopolitical risk premiums have since subsided, front-month settlement prices remain elevated given the structural tightness that has been present in the market since the second half of 2021. As you can see from the middle chart on this slide, LNG supply growth continues to be underpinned by the U.S. with U.S. LNG exports growing 23% year-on-year to 20.4 million tons. This growth has been supported by the strong call on LNG demand in Europe, as well as new capacity additions, including Sabine Pass Train 6. Overall supply grew 6% or 4 million tons year-on-year in Q1 with supply growth from the U.S. and, to a lesser extent, Russia offsetting declines resulting from outages in Indonesia and Malaysia maintenance in Qatar, as well as gas supply disruptions in Nigeria. U.S. LNG represented nearly half of European LNG imports during the quarter, helping meet the needs of our European allies and partners. In fact, Cheniere produced cargos that supplied more LNG into Europe than any other country in Q1, with approximately 75% of volumes produced at our facilities landing in the region, a testament to the market responsiveness of destination flexible LNG, largely pioneered by Cheniere and the U.S. LNG industry. Please turn to Slide 10, where we will look at the regional dynamics in a little more detail. Much like last quarter, the focus in Q1 has been on the European market and how much LNG it can divert from Asia. However, the fear of supply interruptions from the war in Ukraine has only exacerbated the sense of urgency in what was already a tight market, given the strong rebound in post-pandemic demand, low inventory levels in the region, and limited spare LNG production capacity. Russian gas flow into Europe trended downwards throughout 2021, but trended even lower in Q1 of 2022, while the ongoing conflict has raised fears of disputes and flow disruptions. As a result, Europe began relying more heavily on LNG imports rather than Russian pipeline gas for the first time. Pipeline imports from Russia fell 26% year-on-year or 11 BCM as buyers nominated down shipments via Ukraine and reverse flows eastward. Record-high LNG imports were able to plug the gap, representing nearly one-third of Europe’s total gas supply in Q1, up from just 20% a year ago. Fortunately, the 66% year-on-year jump in LNG imports helped ease Europe’s gas storage deficit and brought inventories back within the five-year range. As of April, inventories are finally approaching 2021 levels. More than two-thirds of Atlantic Basin LNG flowed to Europe in the first quarter as Europe bid cargos away from Asia. As a result, LNG imports into Asia dropped 8% or 5.8 million tons, creating increased demand for alternative sources of gas and power supply. Four of the world’s top five LNG buyers, all in Asia, scaled back LNG imports during the quarter, reflecting the impact of higher global prices, deferred consumption, and fuel switching. In Japan and Korea, higher nuclear and coal-fired power generation helped make up for lower LNG imports, with LNG falling 11%, 2.6 million tons and 4%, 0.5 million tons year-on-year in each market, respectively. At the end of Q1, major Japanese electric utilities' LNG inventories were approximately 0.8 million tons below 2021 levels. Taiwan was the only major Asian buyer to post growth, adding 0.4 million tons of LNG demand that’s up 8% relative to Q1 2021, thanks to restrictions on cold burn during winter and reduced nuclear capacity lending support to gas generation. JKT LNG imports returned to growth in March on the back of coal-fired power maintenance and outages in Korea and Taiwan, as well as an increased call on gas-fired generation following a relatively minor earthquake in Japan. In China, LNG imports fell 13% or 2.6 million tons year-on-year in the first quarter, as buyers opted to instead divert high-value cargos to the premium market in Europe. Domestic gas production and imports of Russian piped gas increased in the first quarter, but were not enough to balance domestic price levels. Deregulated prices for domestic trucked LNG roughly doubled in February and March compared with the same period in 2021, indicating a tight gas market despite robust coal-fired generation and, of course, some recent COVID-induced lockdowns. Thailand served as the largest growth market in Asia during the quarter, importing a record 2.3 million tons of LNG, which was up 16% quarter-on-quarter. Thailand procured spot LNG cargos to continue providing gas to the power and industrial sectors, amid declines in both domestic gas production and pipeline gas imports from Myanmar. Please turn to slide 11. While it is likely too early to draw conclusions around the long-term impacts of the current geopolitical uncertainty, the war in Ukraine is already having a significant impact on energy policy thinking globally, with long-term security of supply at the top of the priority list for utilities and governments alike. Europe is now fast-tracking additional LNG infrastructure throughout the region, which, coupled with the inclusion of natural gas within the EU green taxonomy last fall, reinforces the critical role of natural gas in the region’s energy mix for the long term. How quickly and how orderly Europe is able to fulfill its stated objectives to reduce its reliance on Russian gas will have a meaningful impact on global market conditions for natural gas over the next few years. Despite the ongoing conflict in Ukraine, Russian gas has continued to flow. However, last week, Russia halted exports to Poland and Bulgaria over refusal to pay for gas supply in rubles, marking an escalation between Russia and Europe, specifically concerning energy supply. Regardless of how quickly and orderly Europe produces its dependence on Russia, supply-demand signals suggest a tighter and potentially volatile near-term gas market, at least through the current LNG supply cycle, especially with the Asian demand growth story remaining firmly intact. As a result, we believe the market will see a shift in LNG procurement strategies as more buyers seek the stability, security, and reliability of long-term LNG contracts. As Jack mentioned, the demand for our flexible and reliable LNG on a long-term basis has only been amplified this year given the outlook for continued market volatility and our ability to structure tailored solutions for our customers. Our recently announced deals with NG, EOG, and ARC Resources not only evidence the long-term view of the role of LNG and natural gas in the global energy mix, but also highlight the criticality of reliable and flexible long-term energy supply. And now I’ll turn the call over to Zach to review our financial results and guidance.

Thanks, Anatol, and good morning, everyone. I’m pleased to be here today to review our first quarter 2022 financial results, our key financial accomplishments, and our increased 2022 guidance, which is a testament to the value of our platform and the effectiveness of the entire Cheniere team. Turning to Slide 13. During the first quarter, we generated adjusted EBITDA of $3.2 billion and distributable cash flow of approximately $2.5 billion, both record quarterly amounts. Our first-quarter results benefited from the drivers of our guidance increase back in February, namely the early completion and accelerated ramp to full utilization of Sabine Pass Train 6 combined with a sustained higher margin environment across global LNG markets. Additionally, the contribution of a few CMI cargos loaded at year-end 2021, but delivered in 2022, as well as incremental lifting margin based on higher Henry Hub prices further contributed to first-quarter results. We recognized an income of 592 TBtu of physical LNG during the first quarter, including 581 TBtu from our project and 11 TBtu sourced from third parties. Approximately 82% of these LNG volumes recognized in income were sold under long-term SPA or IPM agreements. We generated a net loss of $865 million in the first quarter. The net income line continues to be impacted by the unrealized non-cash derivative impact related to our long-term IPM agreements, as we have discussed on prior earnings calls. Turning to our progress on capital allocation. We are executing on the plan we laid out in September of last year at a significantly accelerated pace, as higher than expected marketing margins and production are providing a meaningful tailwind to the timeline we previously laid out. During the first quarter, we redeemed or repaid over $800 million of long-term indebtedness, bringing the total now to over $2 billion out of the $4 billion we targeted to pay down by the end of 2024. During the first quarter, we also repurchased nearly a quarter of a million shares for approximately $25 million and paid our second quarterly dividend of $0.33 per share for the fourth quarter of 2021. While we have prioritized that paydown thus far given our consolidated leverage targets, the share repurchase plan is in a good position to meaningfully repurchase shares on an opportunistic basis, including in the present quarter as our cash balances have continued to grow. Commercialization of Stage III was completed with the EOG transaction and further enhanced by the NG deal, as well as the ARC Resources IPM transaction we announced this morning. In addition, we have officially signed over the Glencore, ENN, and Tourmaline contracts to Sabine Pass now that Train 6 is up and running, which leaves our long-term contracts with CPC, PGNiG, Sinochem, Foran, Apache, EOG, and now ARC. Deals available to underpin this Stage III financing, a truly global contract portfolio with a mix of FOB, DES, and IPM deals. The fixed-price turnkey EPC contract with Bechtel was executed during the first quarter and Stage III is underway with Bechtel working under an LNTP. We officially launched the financing process in April with our bank group and expect to finalize a widely syndicated financing ahead of a full FID, which we expect to announce this summer. Turning now to Slide 14, where I’ll provide some more detail around our second consecutive significant increase in 2022 guidance. We are increasing the midpoint of our guidance ranges for full-year 2022 consolidated adjusted EBITDA and distributable cash flow each by another $1.2 billion, bringing expected consolidated adjusted EBITDA to $8.2 billion to $8.7 billion and distributable cash flow to $5.5 billion to $6 billion. This increase can be attributed to a few factors, summarized simply as more volume and higher margin. First, the incremental volume we’ve added to our forecast from the continued success in maintenance optimization is driving an increase in the production forecast of approximately 30 TBtu or roughly eight cargos. In addition, the faster-than-expected ramp-up of Train 6, along with general production outperformance across the portfolio, contributed a few extra cargos to the 2022 forecast. All told, this incremental production accounts for over half of the increase in forecasted EBITDA and DCF for the year. Second, market margins secured on our previous opening capacity were up by approximately $8 per MMBtu compared to our late February call. This increase in margin contributes about another $400 million in the EBITDA and DCF forecast. The balance of the increase is predominantly attributable to higher lifting margins on higher Henry Hub pricing. With respect to the EBITDA sensitivity from here, we have sold over 95% of our total expected production for this year and have approximately 70 TBtu unsold. This is based on the revised production forecast inclusive of the incremental volume, mainly from the maintenance optimization. We currently forecast a $1 change in market margin would impact EBITDA by approximately $40 million for the rest of 2022. Under our revised capital allocation plan announced last September, we’ve already repaid or redeemed over $2 billion of long-term debt and repurchased over 0.25 million shares through Q1, with the expectation of growing our deployment to both capital allocation initiatives further this quarter and through the rest of the year. Including our recent dividend declarations for Q1, we have also declared nearly $1 per share in dividends and began paying a base plus variable distribution at CQP. All of which has strengthened our balance sheet, accelerated our path to investment grade credit metrics and delivered value to our shareholders. Accelerated progress on our plan continues to be recognized by the credit ratings agencies. Just last week, S&P upgraded SPL to BBB flat from BBB minus, considering the completion of Train 6 and the consistency and resiliency of our cash flows as catalysts for the ratings action. With CEI and CQP rated BB plus with a positive outlook at S&P, we view this upgrade of SPL as a meaningful step towards reaching investment grade ratings at the corporate levels. Given our accelerated progress on this front, we anticipate coming back to you with updated capital allocation goals in early 2023 or potentially later this year. Until then, we’ll continue to execute on our comprehensive plan, prioritizing debt paydown, opportunistically repurchasing shares, paying our dividend, and investing in Stage III. While we do not have any debt maturing for the balance of 2022, we do have our existing term loan at CCH, which is fully prepayable. We’ll focus our debt paydown on this facility in the near term with an eye to the SPL maturity next spring as we expect to approach sustainable consolidated investment grade credit metrics across the company in the coming quarters. 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.

Yes, thank you. We will take our first question from Jeremy Tonet with JPMorgan.

Hi, good morning.

Good morning, Jeremy.

Thanks for taking my question here. Just wanted to start off with the guidance in the raise here. I was just wondering if you could maybe help us parse through a bit here. Was the guidance raise, if you think about which quarters contributed to it, is that just reflecting the benefits in the first quarter being higher? Or should we think about the next three quarters being a little bit higher than your original forecast? Just trying to understand some of the drivers there?

Hey, Jeremy, it’s Zach over here. I’ll just say in the February call, we were pretty much two-thirds of the way through the quarter. So we anticipated then with Train 6 already up and running that we would have around $3 billion of EBITDA for Q1. So what that’s saying is that this $1.2 billion increase is actually going to be spread out more so over Q2 through Q4. Clearly, with $8.2 billion to $8.7 billion of EBITDA, $22 to $24 of cash flow, and honestly we’ll be under four times debt to EBITDA this year at this rate. We’ll be capitalizing on capital allocation for the rest of the year. But to give people a sense of the numbers around the drivers of the $1.2 billion increase. As I mentioned, the 50 TBtu that were open going into the last call with an $8 increase selling those cargos through the volatility in the mid-20s, let’s say in terms of net backs, that was $400 million, and then all this optimization on maintenance and the incremental cargos that added over $600 million. Yes, higher Henry Hub better lifting margin was about the rest. So really it’s coming now, you’ll see it in the future quarters this incremental plus billion.

Got it. That’s very helpful there. Thanks for that. And maybe just pivoting towards the long-term guidance. I keep hearing you guys optimize and squeezing out more production. I’m just wondering your kind of existing long-term run rate EBITDA guidance. Is that still current or should we be thinking kind of an upward bias to that just given all the incremental capacity that you guys keep squeezing out here?

Yes, Jeremy. First, I’ll take some of that. I am so proud of my maintenance and operations teams for what they’ve been able to do with these trains. Their focus on maximizing the efficiency and effectiveness of the trains to get them to optimal performance has just been fantastic and world-class. But as far as the actual run rate guidance, I’ll turn that over to Zach.

Sure. So yes, for the rest of this year, and I’ll say even next year, we’re seeing netbacks in the mid to high teens in our forecast. We’re going to stick with the existing forecast for you all where we had CMI at 200 to 250 because we can honestly make a very good living building new infrastructure like Stage III with long-term contracts in that range. Just to put into perspective for Stage III, it’s $7 billion unlevered, six times CapEx to EBITDA, and pretty much fully contracted at this point. We’re talking about double-digit unlevered returns. So for now, we’re holding tight with our long-term guidance for nine trains and then with Stage III, but with this extra cash, I mean at this point from 2021 to 2024, it’s about $16 billion of available cash. The number’s getting a little silly, so we’ll get you back to this year, which is only, let’s say, $5 billion plus. We’ll be bringing down the share count. We’ll be reducing interest expense, and ideally, eventually yes, increasing that guidance, but we’ll stick with what we got today.

Got it. Going with beat and raises is a good way to go about it. So I thank you for all the color there. Really helpful. Thanks.

Thanks, Jeremy.

We will now take our next question from Brian Reynolds with UBS.

Hi, good morning, everyone. And appreciate all the color on the potential capital allocation update later in this year. So maybe to pivot to CCL Stage III, it appears that you guys are targeting a late 2025 in-service date. But just given that you’ve given, backed all the thumbs up to start construction effectively. And just given that you guys have brought on a few of your previous trains on nearly a year early, was curious if these mid-scale modular trains have the potential to come online in late 2024 versus late 2025 to take advantage of some of the market dynamics, just given that the global natural gas market is expected to stay tight through the mid-2020s. Thanks.

Yes. Thanks, Brian. I’m always impressed with what David Craft and his team at E&C have been able to do with Bechtel and bring our trains in significantly ahead of schedule. My expectation is still that way. As you know, we tend to be fairly conservative in our guidance and we’ve guided you guys to the guaranteed delivery dates from Bechtel. As we get closer to that FID, I will keep you informed to let you know our expectations. But right now, that plan is to have the first train producing LNG and in commercial ops by the end of 2025. Every three to four months afterward, another train will start up. But I think the world of my team and I’m pretty confident we will hit the plan.

Great, appreciate that feedback. Maybe as a follow-up, curious if you could just provide some commentary on the QMRV program to monitor GHG emissions. I was curious if you could share some of the early results of the program and whether the data that you were effectively collecting is helping counterparties and customers get comfortable with signing up the SPA contracts, specifically those counterparties that were a little bit more hesitant to sign up for long-term deals given the ESG concerns before. Thanks.

Thanks, Brian. This is Anatol. It’s still relatively early days. We’re very optimistic. We’re learning a lot, obviously, kicks off the third leg of the stool at Gillis, and we will continue, as Jack said, to drive that and implement our own facilities as well. One of the things that we’re doing, as you know, is partnering with universities and academic institutions to ensure that all data is verified, properly collected, and vetted. It’s too early to comment on any output, but the effort and commitment, and the obvious engagement that we have with the entire supply chain is critical to move forward and continue to drive engagement with counterparties. I think that’s the way the world is going to go, and this will continue to keep us in a great position, leading the charge on all of these fronts and ultimately reducing our lifecycle emissions. So it’s too early to give you any specific findings, but we are learning a lot and we’ll have a lot more to say over the coming quarters.

Great. Looking forward to it. That’s all for me. Have a great day, everyone.

We’ll now take our next question from Michael Lapides with Goldman Sachs.

Hi, guys. Thank you for taking my question and congrats on a great quarter and guidance raised. I’m going to come back to the maintenance optimization, and I want to tie this into the debottlenecking that you’ve talked about a little bit. Is what you’re seeing a pull-forward of the debottlenecking a little bit, meaning the extra 1 million to 2 million tons a year that you’ve talked about? Or is this simply delaying some maintenance work from 2022 and maybe doing it in 2023? So kind of just pushing out that maintenance work so maybe volumes this year are a little bit more elevated, but you kind of lose a little bit of that when we think about next year.

Yes, Michael, this is Anatol. It doesn’t have anything to do with debottlenecking. Our maintenance optimization program is a continuous process. My ops and maintenance teams are constantly working to ensure that they can maximize production through, I’ll call it, a reliability-centered program. As we enter the year, we start doing more diagnostics on the actual equipment that we’re going to maintain and looking at its performance. We found out this year we had scheduled maintenance based on a time-based schedule from the original equipment manufacturers. Now, we’ve moved to a reliability-centered program, which allowed us to extend the useful lives of those components. That ended up allowing us to produce, as Zach mentioned, over eight cargos of additional production. I just think it benefits everybody that we continually challenge ourselves and maximize performance of those components before we change them out. So that’s what we mean by maintenance optimization.

Got it. And there is a little bullet in this in the queue. I’m just curious, do you see now that you’ve got all 6 trains fully running at Sabine, that there are some cost savings, cost synergy opportunities over the next year or so or even longer term, where kind of an average cost per train might come down on the O&M side?

Yes, absolutely. You should think of us as a southwest of liquefaction trains, right? We have 9 trains that are the same design, and there should be significant synergies now on parts and labor and operational effectiveness.

I’ll just add that if you look at our O&M results and compare them to Q4, compared to Q1 last year, now that we’re producing a lot more, that dollar per MMBtu is coming down, and you should expect that for the full year.

Got it. Thanks, guys. Much appreciated.

Thanks, Michael.

We’ll now take our next question from Spiro Dounis with Credit Suisse.

Thanks operator. Good morning, guys. Jack, I would appreciate your thoughts on the regulatory landscape and U.S. energy policy here more broadly. I think we’ve seen a few branches and positive developments from this administration to support more U.S. LNG into Europe, but feels like that’s kind of stopped short of a comprehensive policy to really foster more development. So curious what you’re seeing and hearing from regulators and policymakers both here and in Europe.

Well, needless to say that the EU has been very, very helpful and very grateful for what we’ve been able to do and the 150 cargoes that were produced at Cheniere and sent to Europe. Our relationship with the regulators, FERC, FEMSA, the administration has always been strong. We’ve talked about it before that the Obama administration approved our ability to export and our permits to build the facility. We continue to work collaboratively with all of them. I was very pleased that we got tank one back in service and that we’re working closely with them on tank three. We’ve got the additional capacity from FERC on our debottlenecking efforts, and we’ve received the DOT non-FTA approval. So we’re getting what we need. They’re very busy these days. We’re having to be patient, but we’ll continue to work collaboratively with the bunch.

Great. That’s helpful. Second question, just moving upstream and working more with E&Ps, seeing a lot more upstream companies express interest in LNG and tapping into that market. Your announcement, of course, with ARC is another great example of that. We do have some E&Ps talking about taking on equity interest in LNG projects directly. So curious your thoughts on your interest levels from here to take on more E&P customers and if you’d be open at some point even jointly developing something going forward.

Thanks, Spiro. This is Anatol chiming in. We love these IPM deals for a number of reasons. Obviously, it’s very much in line with our risk tolerance and the fees that we collect from them. But it’s also the gas supply that comes with it, the operational flexibility that comes with it. As Zach mentioned, in the portfolios of the projects, having a mix of FOB, DES, and IPM transactions is a very elegant composition. As you know, we’ve always been limited by the pool of potential counterparties. We’ve expanded that pool, fortunately, to include now two Canadian producers, and the idea that we would do more of this is at the center of our fairway. Especially as credit quality improves for the E&Ps, that pool continues to increase. You should expect more of that from us, and we think that that’s part of our balanced diet, if you will.

And then on the partnerships and equity with new contracts, just to reiterate what was said before, but with $16 billion of available cash, 10-plus million tons of contracts already raised pretty much for Stage III, yes, we’re not going to need many contracts contingent on project equity. We’re focused on simplifying the structure as much as possible. So happy to do more IPM deals with creditworthy counterparties, and we’ll leave it at that.

Got it. Helpful color, guys. Thanks for the time.

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

Hi, good morning. Is the run rate for volume that you’ve been at year-to-date, like if you’re looking at gas prices and stuff, a good proxy for the year for steady state or do you anticipate that there’s more maintenance, kind of not in the wintertime that might bring down the average a little?

Hey, this is Zach. I’ll just say, I think we produced around 11 million tons across the portfolio in Q1. At the rate we’re going accounting first, Train 6 coming online in February will be in our run rate range for all the trains this year on an annualized basis. It might be slightly up just with the colder weather in Q1, but it’s a decent proxy.

Great, thank you. And I know we’re all focused on getting CC Stage 3 to FID but could you talk about the steps that would be required to get a train beyond that to market and whether you’d be comfortable contracting volumes on this theoretical train while it’s still in the FERC process?

Yes. I’ll start, and I’ll ask Anatol if he wants to jump in on it. We’ve got very strong relationships with our customers, and we have the ability for us to continue to grow this business. I feel very comfortable that Cheniere will grow for many, many years hereafter. I think the brownfield aspects can’t be matched. You can see from our Stage 3 that the economics are extremely strong, and I think there’s more run rate left.

Thanks, Jean Ann. In terms of contracting, obviously you’ve seen the activity. It’s been a very strong three and even six months. This is the time when the U.S. product and Cheniere’s product in particular, given its reliability and performance that we’ve talked about, stands out. We have a range of offerings, and as the market continues to absorb those volumes and continues to afford us incremental opportunities, we can engage on future projects as well. We have the ability to serve customers with volumes right now, with volumes from Stage 3. Given the strength of the market, there are discussions on further opportunities as well.

Great. Thank you and congrats on the guidance.

Thanks.

We’ll now take our next question from Sean Morgan with Evercore.

Hey guys. So it’s a bit of a continuation on that same theme, but if we see this rapidly changing market where a lot of Russian market supply to Europe might be up for grabs and sort of a market share shift, is there one part, how long would it take to get FERC approvals on an expansion for beyond Stage 3 in terms of whole months? And if it’s going to take a long time, you have potentially this, and not trying to minimize the 10 mtpa that is coming on with Stage 3, but if you have this, maybe unique opportunity, would potentially buying a FERC approved project, that’s stalled out, be on the table?

Look, you heard from Zach, Sean, that we’re building Stage 3 at six times EBITDA, which creates a significant amount of long-term value. So I do think there’s a build and buy situation. I’ve seen it in my whole career, and for the foreseeable future, I think we can build it faster, better, and cheaper than buying it from someone else.

Okay, great. And then the news on the Import/Export Bank potential involvement, I mean, is that you guys have traditionally been able to finance everything that you wanted to develop on your own. How do you think about the involvement potentially by the Federal government on building this? Is that an opportunity to reduce the cost of capital? Is it advantageous for Cheniere, how do you think about that?

Yes, I can only speak for Cheniere, but I’ll just say we’re quite confident that with our bank group, which is a mix of 30 to 40 project finance and investment banks, that in the next couple months, we’ll get binding commitment for $3.5 billion to $4 billion spread, let’s say 1.5% or so, and that’s not going to need any government agency funding support whatsoever or XM support. We have a bank process that’s already kicked off, and we’re going to get what we need really efficiently and quite attractively from the regular bank market. So can’t really speak to those that may need that.

Okay. All right. Thanks a lot, Zach and Jack.

Thank you.

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

Hi, good morning. Just one on my end. As the largest domestic buyer of natural gas, curious is there any insight you have on the recent strength in domestic gas prices and as more LNG export capacity is added, if you think $3 Henry Hub is still the equilibrium point, or does this call on U.S. LNG kind of change that at all? Recognizes a multitude of variables that factor into that with domestic production and international pricing. Just curious about any thoughts you might have on that dynamic.

Thanks, Marc. This is Anatol again. We still see the U.S. gas market – U.S. and Canadian gas market as structurally a $3 to $4 market. We do think that there’s a bit of a latency in responding to these price signals, as the curve continues to move up. You’ve seen an increase in activity; you’re seeing record production of natural gas that lagged after we had that record production number into late 2019 that has lagged the recovery in LNG exports. But we think that will catch up in the coming quarters and feel very good about this $3 to $4 level long-term. In the short term, much like there’s not much of a switching capability globally because commodity prices are elevated across the board. The similar dynamic is playing out domestically, right? That we have very high coal prices domestically. So fuel switching bans are at a point of inelasticity. We think there will be a supply response, which we think is well underway, and the curve is pricing that as we get into the $4 range as we get into the back half of next year and beyond.

Great. Appreciate the time.

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

Yes, thanks. Hey guys. So obviously, Corpus expansion is next on the list, and the same I’m sure would be true of the FERC process, but I’m just curious, there’s been a lot of activity in the market around Louisiana and other projects and so forth. How are you thinking about being past? Is there any possibility that you might consider sort of simultaneously developing or expanding both facilities, or is it just really Corpus into the foreseeable future?

No. I’d say, we have two great sites and two great assets. We have additional real estate at both sites, and it’s not out of the question to see us pivot either to do them both or pivot back to Sabine. The third berth is coming along very well. I know there haven’t been any questions on it, but we expect to receive our first shift there sometime at the end of this year. We’ll have more infrastructure there to load additional ships, so we’re very excited about our prospects. But I – Ben, if you can, I’ve got to keep my team focused on making sure we execute what’s in front of us, and we get Stage 3 across the finish line. That’s first and foremost for all of us here. Then we’ll look at additional growth potential.

Okay, I absolutely understand that, Jack. And then if I could just real quick for Anatol. You’d mentioned a little bit in your prepared remarks that a number of the Asian markets were sort of down a little, is more the volume, more the LNG was moving to Europe and the prices better. Do you think there are possibly any long-term implications there? Do you think as a function of what’s happening at the moment, that there might be some long-term demand destruction? Just because prices are as high as they are and Europe is buying as much as they are.

Yes. Great and very valid question. We keep as close an eye on that as possible. We don’t see anything. In part, it is again going back to the previous discussion. It’s a competing fuels issue. Australian coal is $16, $17 an ounce, right? So that’s no bargain either. In fact, it is much more expensive than the long-term contracted supply that we and others bring to the table. We’re not seeing any pivots away from the commitment to natural gas. We still see Asia as the driver of gas demand. Obviously, what’s going on in Europe will change the supply portfolio, but it is not going to meaningfully change the overall gas demand profile in Asia, we believe will. To your part – partly to your question, the contracting activity that you’ve seen over the last three, six months has still been very Asia-driven, right? So we expect that to continue. We are keeping a very close eye on that. At this point, I don’t see any structural shifts in the demand profile going forward.

All right. I appreciate it. Thank you, guys.

And we’ll now take our last question from Michael Blum with Wells Fargo.

Thank you. Thanks for greeting me in here. I’ll just combine my questions into one really. The question is just given the commodity price environment and the geopolitical tensions that you referenced. Can you just talk kind of broadly how you think that all might shape the duration and structure of contracts going forward? And the second part of that, just in light of all your comments earlier about Europe, why are we seeing most of the new LNG contracts getting announced come out of Asia? I’ll stop there. Thanks.

Yes. Thanks, Mike. It’s Anatol again. The fundamental driver to the second part of your question is going back to the previous question; that’s where the demand growth is, right? So if you’re going to underpin your load-serving entities that have growing demand, it makes perfect sense to us. We’ve always seen and said that the majority of the long-term contracts are going to be driven by those structurally short Asian players. The European issues, obviously, a little too early to call right now. What’s happening and what should be happening is a tremendous focus on infrastructure solutions like that has to come first. We’ve seen these record numbers of imports into Europe, and their constraint, right? There’s only so much that can be brought into the existing infrastructure. The EU is dedicating a lot of resources to solving these bottlenecks. So we’ll see more our ability to bring volumes into Europe, but how that is commercially underpinned still has yet to shake out. We’re in unprecedented times and challenges; Asia’s going to continue to be the growth driver. The majority of contracts signed this last quarter were for 20 years or longer. We’ve always believed that the demise of the 20-year contract was greatly exaggerated. You’ve seen that in the last few quarters, really come back again, as you said, driven by the Asian players.

Thank you.

We’ll now take our last question from Matt Taylor with Tudor, Pickering, Holt & Co.

Yes, thanks for taking this last one. Zach, like you said, your cash flow is starting to look a bit silly here. So with that backdrop, but Jack has your thinking changed at all on broadening your organic development lens? What I mean by that is extending the value chain a bit and developing shorter cycle opportunities. Well, obviously, you focused would still be on long-term contracting. But I’m wondering if you guys are thinking through on how to potentially develop beyond just production capacity.

I’ll go first as CFO, and then let Jack chime in if he wants. But I think we enjoy the sweet spot that we’re in right on the Gulf Coast of Texas and Louisiana with Corpus and Sabine. As I’ve mentioned before, we like our debt metrics in the 4x to 5x, not our valuations. So we’re going to stick with just liquefaction on the coast and not go too far upstream. And then downstream, I think we’re the biggest fans of anyone creating more demand for our product. But we’ll let others do that because that’s a very different risk-adjusted return prospect.

Very well, Zach.

Yes. Thanks for that.

All right, everyone. It does conclude our question and answer session. Thank you for your participation. You may now disconnect.