Cheniere Energy Inc (LNG) 2021 Q3 法說會逐字稿

Good day, and welcome to the Cheniere Energy, Inc. Third Quarter 2021 Earnings Call and Webcast. Today's conference is being recorded.

At this time, I would like to turn the conference over to Randy Bhatia, VP of Investor Relations. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to Cheniere's Third Quarter 2021 Earnings Conference Call. The slide presentation and access to the webcast for today's call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere's President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and Zach Davis, Senior 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'll now turn the call over to Jack Fusco, Cheniere's President and CEO.

Thank you, Randy, and good morning, everyone. Thanks for joining us today, and thank you for your continued support of Cheniere. I'm pleased to be here this morning to review our third quarter results and our increased financial guidance for 2021 as well as introduce our financial guidance for 2022.

We are in the midst of an exciting and pivotal time in the global LNG market as the world continues its transition to a cleaner energy mix. I'm excited about Cheniere's prospects and advantaged position to compete and win in this market for years to come.

Before we begin, I'd like to spend a minute discussing Hurricane Ida, a deadly Category 4 hurricane, which impacted Louisiana during the third quarter. While the center of the storm made landfall well to the east of our facilities at Sabine Pass, many of our coworkers, neighbors and other members of the Cheniere family were impacted with lost or damaged homes and property. Once again, I am pleased with Cheniere's response, and I am proud of how quickly and impactfully we supported those in need in the communities where we live and work in Southwest Louisiana.

In addition to providing direct financial assistance to disaster relief organizations, we once again partnered with the Astros Foundation to lead a 3-day supply drive in Houston led by Cheniere's employee volunteers. We collected, sorted and loaded 6 semi-trucks with emergency supplies for our neighbors in need in Southwest Louisiana while many employees from Sabine Pass traveled to the affected communities to help with the cleanup efforts. Fortunately, the Sabine Pass facility was spared by the storm, and we maintained continuous and stable operations throughout the weather event. I'd like to recognize our teams from production, operations, planning, marine operations, gas supply, meteorology and many others for their tireless effort through this hurricane season and demonstrating safety as a core value at Cheniere.

Now please turn to Slide 5 where I will review some key operational and financial highlights from the third quarter as well as introduce our 2022 guidance ranges. For the third quarter, we generated consolidated adjusted EBITDA of $1.1 billion. And for the fourth consecutive quarter, we are raising our full year 2021 EBITDA guidance.

We now forecast 2021 consolidated adjusted EBITDA of $4.6 billion to $5.0 billion. This increase in EBITDA guidance is driven primarily by higher netbacks on open volumes due to increased global LNG prices as well as increased lifting margins driven by higher domestic natural gas prices. While we are currently tracking to the upper end of this upwardly revised range, the specific timing of a few high-value CMI cargoes scheduled to be loaded or delivered at the end of the year, which could slip into the beginning of 2022, drives a slightly wider range.

Distributable cash flow grew to approximately $390 million, and we are reconfirming distributable cash flow guidance of $1.8 billion to $2.1 billion for 2021. During the quarter, we generated a net loss of approximately $1 billion. As we have discussed in prior quarters, our net income is impacted by the realized and unrealized gains and losses due to the derivative accounting treatment required on our natural gas and LNG hedges as well as on our long-term integrated production marketing or IPM transactions. Zach will discuss the impact on our third quarter results in more detail in a few minutes.

Now looking ahead to 2022, I'm pleased today to introduce full year 2022 guidance of $5.8 billion to $6.3 billion of consolidated adjusted EBITDA and $3.1 billion to $3.6 billion of distributable cash flow, reconfirming that our inflection point has arrived.

Our guidance range slightly wider than what we've historically provided is necessary due to the higher LNG margins and considerable volatility in the market today as well as the specific timing of delivery on some DES cargoes scheduled at or near the end of 2021 and early 2022. We expect the LNG market to remain tight and to continue to provide a constructive backdrop for our business well into next year. The higher netbacks are complemented by higher expected volumes next year driven by the substantial completion of Sabine Pass Train 6 expected during the first quarter as well as the continued execution in our operational excellence program at both of our sites. We are truly excited about what next year holds for Cheniere, and we look forward to once again delivering results within the guided ranges.

The third quarter was particularly meaningful for our company as it features the announcement of our comprehensive long-term all-of-the-above capital allocation strategy, which was enabled by our team's relentless focus on execution and operational excellence, which has placed Cheniere at a decisive cash flow inflection point.

Our capital allocation plan centers around 3 primary principles, which include a strong and sustainable balance sheet, funding financially disciplined growth and returning significant amounts of capital to our shareholders over time. To achieve these goals, we have committed to paying down at least $1 billion of debt annually through 2024 or until we achieve investment-grade credit metrics, declared our inaugural quarterly dividend for the third quarter, reset our $1 billion share repurchase program for the next 3 years and laid out a plan to invest in Corpus Christi Stage 3 next year with internally generated cash flow. In line with these plans, we have repaid $750 million of debt across the structure in the first 3 quarters of 2021. So we are on pace to meet or exceed the $1 billion target this year.

The third quarter was also an extremely productive one for us in terms of operations and execution, and we once again achieved milestones across our business. On the production side, for the third quarter, we set a cargo record this time with 141 cargoes of LNG exported from our 2 facilities. Our production and marine teams at both Sabine Pass and Corpus Christi have continued to maximize asset availability and LNG production at both facilities while maintaining our focus on safety.

Last month, we reached a significant milestone at Sabine Pass Train 6 when feed gas was introduced for the first time as part of the commissioning process. With the project approximately 97% complete and substantial completion expected in the first quarter of next year, Bechtel continues to progress against an accelerated schedule, approximately 1 year ahead of the guaranteed completion date. We look forward to a successful commissioning process. We expect to have the first commissioning cargoes around the year-end and a smooth ramp-up of Train 6 to stable operations.

During the third quarter, we reinforced our leadership position on climate and sustainability with the publication of our peer-reviewed LNG life cycle assessment study. This study is the first of its kind in the LNG industry as the analysis utilized greenhouse gas emission data specific to our supply chain and will, therefore, enable us to better assess greenhouse gas emissions across our LNG operations. I am proud of the continued progress we have made on this front across so many different aspects of the company. We will continue to integrate climate and sustainability throughout our business to improve environmental transparency and performance. This is especially important given the global focus on the LNG market presently.

Barely a year ago, we were in a market environment of low prices and pandemic-impacted demand. Today, however, it's clear the absolute critical role natural gas and LNG have to play in a global energy transition and the viability of LNG and natural gas as a key source of reliable energy supply for decades to come.

Now turn to Slide 6 where I'll highlight Cheniere's significant commercial momentum and the market dynamics supporting our increased financial guidance and confidence in the FID of Corpus Christi Stage 3 in 2022.

We kicked off the third quarter with the announcement of our newest long-term IPM contract with a Canadian natural gas producer, Tourmaline. Just after the quarter ended, we announced 2 long-term SPAs with ENN and Glencore. The SPAs with ENN and Glencore are approximately 13-year contracts executed with CMI and done on an FOB basis. The signing of these long-term contracts extends our percent contracted of the 9-train portfolio to over 90% through this decade, and we maintain the flexibility to assign the ENN and Glencore deals to a specific project.

Looking ahead, we estimate another 3 million tons or so is needed to fully sanction Stage 3. And with our origination team as busy as they are, I'm confident we'll get that required commercial support in the coming quarters.

In the short-term market, we have witnessed significant volatility and record prices for LNG and natural gas across the globe. With storage level and key demand centers below historic levels as we approach the winter season, we expect demand and prices to remain elevated into 2022, which gives us confidence in our guidance for next year.

On the long-term side, LNG market fundamentals are as constructive for long-term contracting and the construction of new liquefaction capacity as I've seen at any point since I joined Cheniere. Anatol has a lot of good information to share with you in a moment, but we are seeing LNG consumers recognize the importance and the value of securing long term natural gas supply and price visibility, both of which a contract which Cheniere provides. And we market to those consumers now as the second largest producer of LNG in the world. This is a major competitive advantage as it demonstrates our ability to execute and fulfill our promises to our customers, something they value significantly in today's market.

We are responsible for providing our customers with flexible and reliable energy supply, and the size, scale and hard-earned reputation of reliability of the Cheniere platform enables us to be a dependable partner for our customers. In addition, being able to offer flexible solutions that are tailored to the unique needs of our customers is a competitive advantage that is virtually impossible to replicate in the near term.

Our commercial momentum, coupled with the significant tailwinds in the long-term LNG market, underscores our progress towards FID of Corpus Christi Stage 3. While our confidence in our 2022 FID grows, we remain committed to our disciplined capital investment parameters to ensure the risk and return profile is consistent with that of the first 9 trains we've built. You've heard me say this before, but it's worth repeating. We aren't in the FID business. We're in the value creation business.

With that, I'll turn the call over to Anatol, who will provide more detail around current market dynamics.

Thanks, Jack, and good morning, everyone. Please turn to Slide 8. As Jack just mentioned, we maintain an increasingly constructive view of the global LNG market for the balance of this year and well into 2022. Higher demand for our product driven by the need to replenish gas and LNG storage inventories after the cold winter last year, coupled with higher year-on-year demand due to improved economic activity around the world, resulted in a significant run-up in prices through the summer. Because of this imbalanced market, we've witnessed unprecedented price spikes across all gas and LNG benchmarks. Global natural gas and LNG prices remain above seasonal norms, stocking concerns about sustained tightness in LNG supplies ahead of a potentially colder-than-normal winter once again.

TTF settled September at over $15 an MMBtu and touched an all-time high of $55 an MMBtu in early October. JKM settled October at over $19 an MMBtu and hit a new intraday all-time high of over $56 an MMBtu in October after averaging around $4 an MMBtu in 2020.

While our long-term customers are largely insulated from these dramatic price swings and our CMI business can capitalize on these dislocations in the short term, sustained market volatility could be disruptive for our industry as it potentially incentivizes end-use customers to utilize cheaper, higher polluting fuels in the short term.

The rapid economic recovery in key LNG markets paired with some of the structural factors impacting Europe and Latin America helped the LNG market achieve higher growth levels this year. LNG consumption increased 7% in the third quarter amid intense competition for supplies between the Atlantic and Pacific basins. This tug of war has certainly exposed the supply constraints facing the industry in the wake of the pandemic.

Global LNG supplies grew 8.7 million tons year-over-year in the third quarter, while exports from the U.S. grew approximately 10.7 million tons during the same period. The consistent gains in U.S. exports have been instrumental in providing much-needed supplies to the market, offsetting the declines from legacy facilities. In fact, 28 million tons of new LNG capacity, most of which is U.S.-based, has come to the market in the past 2 years, which has more than offset the approximately 19-million-ton decline in production from legacy plants in the same time period. This new supply has played a critical role in alleviating some of the global supply shortage while helping mitigate some of the underlying volatility.

Let's turn to Slide 9. Having covered the supply side of the equation, let's now look at some of the demand side factors driving the market's sustained in balance through the third quarter. As mentioned, demand in some key Asian markets has been driven by end-user buying in order to refill storage ahead of winter, in many cases, bidding volume away from Europe. Weather has also played a meaningful role in volumes during the third quarter with severe droughts in Latin America earlier this summer and last year in China, having reduced the availability of hydroelectric power generation sources, increasing demand for gas and further exacerbating the seasonal storage deficit.

In Latin America, for example, third quarter demand was up over 100% compared to last year, primarily from the traditional hydro markets of Brazil and Argentina. These factors, coupled with efforts to replenish supply levels ahead of winter, intensified the interbasin competition with Asia for incremental LNG volumes throughout the third quarter.

In Asia, China's LNG imports increased 13% in the third quarter and made significant growth in the power and city gas sectors as the focus on switching to cleaner burning fuels continues to grow. China's gas-fired power demand increased 23% on the year, and its city gas demand grew 18% year-over-year, resulting in widespread power rationing in October amid gas and coal supply shortages.

In South Korea, nuclear outages in July and August also boosted demand for gas-fired power generation by approximately 25%, leading to a 58% increase in LNG imports year-over-year in the third quarter as this impact was incremental to higher demand from replenishing low gas storage inventories.

In Europe, storage levels remained at multiyear lows, around 22 BCM below the 5-year average. The perfect storm or unfortunate combination of lower LNG imports, lack of wind in the North Sea and low incremental pipeline supplies from Russia, coupled with rising coal and carbon prices, have driven gas prices in Europe to record highs. Despite having been responsible for balancing the market for much of the pandemic, Europe relinquished volumes to more priced inelastic markets in Asia and Latin America, with LNG imports lower by 19% year-over-year in the third quarter, as illustrated in the chart on the lower right-hand side of the slide.

While U.S. LNG imports to the region during the third quarter were up 97% versus the third quarter last year and 76% versus 2019, a strong call on U.S. supplies to meet regional demand in Asia and Latin America meant that U.S. LNG exports to Asia rose 215% versus prepandemic levels of 2019, and those to Latin America climbed 52%. These regions sent very strong price signals to attract higher U.S. flows in an effort to avoid shortages due to fewer pipe gas alternatives and constraints on coal and hydropower availability.

Please turn to the next slide. The market's significant volatility in the last 18 months has unquestionably placed a strain on energy systems around the world, signaling the need for additional investment in new LNG capacity. As discussed previously, we have expected the market to tighten starting this year due to the historically low volume of FIDs taken between 2015 and 2018 despite the substantial growth in global demand forecasted across developed and developing regions, which is driven by the structural shift to natural gas, as we've discussed on these calls for several years.

Based on our assessment of the market, the FIDs taken back in 2011 through 2014 contributed to a softer market from 2015 through 2020 as the market digested the rapid addition of significant new supply. But the market has now reached a cyclical inflection point and is calling for new capacity to be added. While much of the current tightness has been exacerbated by a confluence of short-term factors impacting supply and demand, we do expect the underlying market to remain tighter as a result of the pandemic, which reset the supply cycle and forced companies to employ stricter capital allocation parameters and deferred many project FIDs. We now estimate that this tight market could extend well through 2025 and potentially tighter seasonal swings over the midterm period, especially if production from legacy plants remains inelastic and the current constraints on the coal supply cycle persists.

Recall that just last year, stakeholders in our industry were more concerned about security of demand than security of supply. That perspective has certainly been reset by the current market conditions, which we believe create tailwinds for long-term contracting of reliable and affordable LNG sources like our Corpus Christi Stage 3. Our plan to expand our Corpus Christi facility is part and parcel of our strategy to invest in accretive growth projects, to deliver value to our shareholders and provide flexible, reliable LNG supply for our customers. And we believe the visibility on price certainty that's central to the structure of our long-term contracts will be increasingly attractive to LNG buyers under current market conditions.

We're beginning to see this manifest in the market with long-term contracting activity clearly increasing in the last few months. As Jack mentioned, we're very excited about our newest long-term customers, ENN and Glencore, and look forward to building on this momentum as we continue to commercialize our growing platform.

The meaningful engagement we're having with both existing and prospective customers gives us great confidence that we're marketing solutions valued by the market, and we expect to maintain that commercial momentum into next year and reach FID on Stage 3.

The current market volatility, coupled with the environmental and economic attributes of our product, lead us to remain quite sanguine about the critical role LNG and natural gas have in the global energy market, both as a destination fuel as well as a key enabler in the global transition to lower carbon energy sources.

Thank you all for your time. I'll now turn the call over to Zach, who will review our financial results and guidance.

Thanks, Anatol, and good morning, everyone. I'm pleased to be here today to review our third quarter financial results and our increased full year 2021 EBITDA guidance as well as provide you with some more detail regarding our full year 2022 guidance.

Turning to Slide 12. For the third quarter, we generated revenue of approximately $3 billion, consolidated adjusted EBITDA of approximately $1.1 billion, distributable cash flow of approximately $390 million and a net loss of approximately $1 billion. Our net income results for the quarter were negatively impacted by the accounting treatment for our realized and unrealized gains and losses from derivative instruments, which includes our long-term IPM agreements. As we have discussed in prior quarters, our IPM agreements, certain gas supply agreements and certain forward sales of LNG qualify as derivatives and require mark-to-market accounting, meaning that from period to period, we will experience gains and losses as movements occur in the underlying forward commodity curves. This accounting treatment, coupled with the significant volumes, long-term duration and volatility in price basis for certain contracts and, most notably, our IPM agreements will result in fluctuations in fair market value from period to period.

While operationally, we seek to eliminate commodity risk by matching our natural gas purchases and LNG sales on the same pricing index, our long-term LNG SPAs do not currently qualify for mark-to-market accounting, meaning that the fair market value impact of only one side of the transaction is often recognized on our financial statements until the sale of LNG occurs.

The unfavorable pretax impact from changes in the fair value and settlements of our commodity and FX derivatives during third quarter 2021 was approximately $3.5 billion, $3.1 billion of which was noncash, including approximately $2.5 billion directly related to our IPM deals, which were the primary driver of our recognized net loss for the third quarter.

I want to highlight that the impact is substantially all noncash and tied to the significant volatility we have experienced in the global LNG market, which is otherwise served as a significant tailwind for our businesses from both the financial and commercial perspective.

The tailwinds are reflected in our increased guidance for 2021 and the 2022 guidance we are rolling out this morning above our normalized run rate ranges.

For the third quarter, we recognized an income of 499 TBtu of physical LNG, including 489 TBtu from our projects and 10 TBtu from third parties. Approximately 78% of these LNG volumes recognized in income were sold under long-term SPAs or from volumes procured under our IPM agreements. We received no cargo cancellations and had no impact to revenue recognition timing related to cargo cancellations in the third quarter.

As Jack mentioned, we are proud to have announced our long-term comprehensive capital allocation plan in September. Thanks to the success achieved by the Cheniere team over the past 5 years, we have certainly reached a cash flow inflection point that supports our capital allocation priorities of balance sheet management, financially disciplined growth and returning capital to shareholders via dividends and buybacks.

As you may recall, we initially targeted $500 million of debt reduction this year, which we have exceeded by approximately $250 million through the third quarter alone. In line with our capital allocation plan, year-to-date, we've extended the weighted average maturity of our outstanding debt by over a year, lowered our weighted average borrowing rate by over 15 basis points, reduced the percentage of our outstanding debt that is secured by approximately 10% and lowered our LTM leverage by over a turn.

During the third quarter, we issued $750 million of fully amortizing 2.742% public senior secured notes due 2039 at CCH and used the net proceeds to refinance a portion of the borrowings under the CCH's credit facility due 2024. This transaction, the lowest yielding bond ever secured by Cheniere, not only extended the maturity of our borrowings, but also better matched our contracted cash flows with the timing of debt repayment.

In September, we issued $1.2 billion of 3.25% senior notes due 2032 at CQP. This transaction executed on every aspect of our capital allocation strategy. We used the proceeds to refinance CQP's 5.625% senior notes due 2026, and a portion of the 6.25% senior secured notes due 2022 at SPL were refinanced with the indebtedness migrated to CQP. Not only did we achieve the lowest pricing for a 10-year high-yield issuance in energy, we efficiently migrated debt from the projects and further de-secured our consolidated balance sheet.

Pro forma for the payment made in October with a portion of the proceeds from the CQP 2032, along with cash on hand, there's approximately $700 million currently remaining on the 2022 SPL notes. We expect to redeem approximately $500 million of this amount via committed long-term amortizing fixed rate notes at SPL we entered into on a private placement basis, which are expected to be funded this quarter. The remaining approximately $200 million is expected to be paid down with cash flow.

In October, we amended our existing $1.25 billion CEI revolving credit facility, with 23 financial institutions extending the maturity to 2026 and lowering our borrowing rate. Perhaps most notably, the amended facility includes bespoke ESG loan features that provide economic incentives related to defined ESG milestones. Specifically, these incentives include potential reductions in interest rate and commitment fees for certain sustainability-linked expenditures such as expenses to support our QMRV programs and the achievement of specified climate-related milestones like establishing the cargo emissions tags in the coming year.

In addition to our progress on managing our maturities, during the quarter, we resumed share repurchases under our original share repurchase authorization. In the third quarter, we repurchased approximately 77,100 shares for approximately $6 million. Our new 3-year $1 billion share repurchase program commenced October 1.

Turning now to Slide 13. As previously mentioned, today, we are again increasing our guidance range for full year 2021 consolidated adjusted EBITDA and reconfirming the range for distributable cash flow. Our revised guidance range for 2021 consolidated adjusted EBITDA is $4.6 billion to $5 billion. So the low end of the range remains unchanged, but we are raising the high end by $100 million.

The high end is moving up due mainly to the higher margins we expect to capture on our CMI volume, though the low end is staying the same simply due to the variability around the specific delivery dates on a number of high-valued DES cargoes sold by CMI, which are scheduled to be delivered right around year-end and early next year. We'll earn the EBITDA associated with these cargoes either way, but it may end up weighted into 2021 or 2022, depending on the specific logistics of those cargo deliveries.

The DCF guidance range for 2021 remains at $1.8 billion to $2.1 billion. While the range is unchanged, we are now tracking to the high end as the factors moving up our EBITDA forecast are also positively impacting our DCF forecast.

While on the subject of DCF, we have made an important update to our financial reporting and guidance with respect to this metric. Starting with 2022 guidance, we have adopted a new definition for distributable cash flow that we believe better reflects the consolidated cash flow of each of our wholly owned subsidiaries as well as CQP. Currently, without this change, our DCF is calculated based on only distributions declared at CQP, which are impacted by CQP's capital allocation decisions, including debt paydown and capital spend at Sabine Pass.

Rather than have capital allocation decisions made at our subsidiaries impact consolidated DCF, we have revised our calculation to properly reflect the consolidated cash flow of the entire Cheniere complex, less amounts attributable to noncontrolling interests. The new definition accounts for 100% of CQP's distributable cash flow being distributed to Cheniere Energy, Inc., or said differently, assumes a 1x coverage ratio at CQP, which will incorporate all cash flow generated in CQP before capital expenditures, retained cash flow and distributions.

Please note, this change does not affect our run rate DCF guidance as we have always assumed a 1x coverage ratio for CQP in our run rate forecast to reflect this dynamic.

Looking ahead to 2022, we expect to have another outstanding year and are guiding to $5.8 billion to $6.3 billion of consolidated adjusted EBITDA and $3.1 billion to $3.6 billion of distributable cash flow. The market today is well above our long-run CMI margin assumption of $2 to $2.50. So 2022 should be a landmark year for Cheniere, with all 9 trains up and running and a financial forecast well above our run rate guidance.

At CQP, we are forecasting a significant step-up in distributions, with guidance ranging from $3 to $3.25 per unit. Like our upwardly revised 2021 guidance, our figures for 2022 are largely driven by the continued strength of the LNG market and our ability to capture higher netbacks on our open volumes, which will be higher in 2022, thanks to the accelerated schedule for substantial completion at Sabine Pass Train 6 and continued production optimization at both of our sites.

As we enter 2022, we expect to have approximately 150 TBtu of open or unsold capacity at CMI. Our EBITDA sensitivity to a $1 move in market margins is less than $150 million. While we have assumed some of that 150 TBtu at the current curve, we've also reserved a portion of the open volume strategically as bridging volume for long-term origination transactions, similar to the ENN and Glencore SPAs. And that volume is therefore marked at prices that blend the near-term curve with the long-term market price.

There is a wider guidance range for 2022 than we've provided in previous years due to a number of related factors. Though our open capacity for next year is only approximately 7% of our total forecasted P&L production, the higher margins in the market means the EBITDA that each TBtu of LNG contributes is higher, and therefore, the impact from each cargo is amplified. In addition, the specific timing of Train 6 substantial completion as well as the trajectory of that train reaching stable operations and the timing of delivery of the CMI cargoes scheduled for the very end of this year and early next year, all help justify starting with a slightly wider guidance range than we have historically provided for initial guidance 2 months ahead of the year.

That concludes our prepared remarks. Thank you for your time and your interest in Cheniere. Operator, we are ready to open the line for questions.

(Operator Instructions) Our first question comes from Christine Cho with Barclays.

I thought maybe we could start with '22 guide. The range is pretty strong out of the gate, but your open capacity would indicate that you guys have put away a decent amount of cargoes in the last several months for next year. Can you just provide a little more color on what's assumed in the low and high end of the guide other than what you already told us, Zack, about timing of the year-end cargoes? The 150 TBtu that's open, what does that assume for Train 6 start? Is there anything in there for 1Q? And are you using the forward curve for the open capacity in your assumptions?

Thank you, Christine, and we'll have Zach answer the question.

Christine, so we're pretty excited about 2022. It will be our first year with 9 trains operational, and we should have record production of around 43 million tons for the year or over 2,200 TBtu. So when you think about 150 TBtu open, that's less than 7% of our total P&L production next year. And then I'd say that open volume is going to contribute, give or take, around $1 billion. And that's after accounting for the fact that though the curve next year is around, let's say, $10 or so, we reserve a portion of the cargoes of this open capacity for some additional long-term origination deals with bridging volumes similar to how we structured the ENN or Glencore deals. So that's basically how it's set up.

We assume Train 6 is coming online at the end of Q1, and there's some flexibility in there in terms of some of those high-priced LNG cargoes. We literally have a couple of cargoes that are close to almost $100 million of value to us, either being delivered late this year or early next. So with some flexibility on exactly when substantial completion can occur and some of that timing that just forced us to think about a $500 million range. When margins are around at $10 versus last year when we came into the year, they were around $0.50, even though we had even more capacity open at the time.

Okay. Great. That is helpful. And then can you guys give a little more color on the contracts that you've signed in the recent months around the short-term and medium-term deals? It looks like the long-term 10-year-plus deal terms have not really changed, but I would imagine the terms for the 1- to 3-year deals have gone up, especially after the reset in the supply cycle that Anatol discussed. What are the market rates for something like that? And if the long-term deal -- the terms have not changed, and customers are maybe realizing that they can't rely on the spot market for their firm needs, what would you say is the biggest sticking point in negotiations for long-term contracts right now?

Anatol?

My turn. All right. Thanks, Jack. Christine, the -- so as Zach mentioned, we -- the market for those midterm transactions is the market. So we reserve them as volumes for the origination efforts. We think having the right solutions, the flexibility to start volumes without a condition precedent, start them before additional capacity comes on is all very important and has been a key differentiator for us. So those volumes are blended into the contract either commercially or the way we account for them either way. But in the front, for the liquid part of the curve, we include those economics in that long-term transaction on an NPV neutral basis to us. So that's very important to us. And as you've seen with ENN, Glencore and others that maybe haven't seen explicitly, that's a key differentiator, and we will earn that curve over the life of the deal.

I'll just -- sorry. I was just going to add that it was literally a year ago, we were around 85% contracted as a company. And Jack said the goal was in the next few years, it'd be 90% contracted. We're now 90% contracted on the 9-train program through the early 2030s with all the work that's been done. And with all the deals that we signed, midterm deals, long-term deals that Anatol and the commercial team have signed this year, that's over $6 billion of fixed fees, just to give you a sense of how much de-risking has occurred.

Christine, it's a little (inaudible) So there's some DES deals. There's IPM. There's FOB. It's all of the above because we participate on the whole value chain.

Our next question comes from Jeremy Tonet with JPMorgan.

Just want to pick up with that a bit more, particularly as it relates to the medium term. As you laid out, there's really a few other plants that are under construction in the near term, and there's others facing delays such as Mozambique and LNG Canada. Also, you have European Union carbon prices have doubled year-to-date. Just wondering if you think this sets us up for kind of a stronger for longer LNG pricing into the kind of more of a medium-term time frame there and how CMI could benefit from that.

Yes. Like we said, this was supposed to be, to us, a transition year that was difficult to call, and everything that we've talked about has created a much more rapid transition. And as you said, the volumes that are coming into the market, '22 through '25 delays on upstream FIDs delays on liquefaction FIDs, some of both actually being canceled, as you've seen in recent history, gets us well through the mid-20s. And on the demand side, we just see a continued commitment to natural gas. I mean you see these numbers out of China, which is, through the -- through 3 quarters, leading -- is the leading market. It surpassed Japan. It's about 2 million tons higher now on the year, most likely will be the largest market, and we don't see that market slowing down. And its commitment to natural gas is unwavering as is India's, as Vietnam's, as is Taiwan's. So we're quite sanguine about the midterm as well as the long term, right? We think if we do our job correctly and have the right environmental bona fides and the right economic value proposition, it is decades and decades and decades of runway.

And Jeremy, I have to say, from an operational excellence perspective, I'm so proud of the 2 sites, both Sabine Pass and Corpus Christi. They have performed well above my expectations, and that team continues to impress me. So I -- it's more than just market prices. It's -- you have to make the product and deliver the product.

Got it. That makes sense. That's helpful there. And then maybe just pivoting towards CCL Stage 3 here. Just wondering if you could refresh us with the recent term deals that you've signed up here as far as where, I guess, contracting stands relative to FID moving forward and just kind of updated thoughts on how you think that could progress over the course of this year.

Sure. So we mentioned in the prepared remarks that we think it's around 3 million tons. But in terms of how these new contracts that we've signed help us build Stage 3, I think you have to just realize at this point the company's commercial and financing strategy is no longer just on an isolated or separate project finance basis because at this point, we're a 45 million-ton operating company in the next few months. So it's all one portfolio, and everything helps us firm up, not just the existing 9 trains, but this next 10-plus million tons in Stage 3.

And keep in mind at this point with the work that Anatol and the team have done, we have 7 at least publicly announced long-term contracts, over 7 million tons, and that's CPC, ENN, Glencore and the 3 IPM deals with Apache, EOG and Tourmaline. So we're getting close. But at this point, some of those contracts, maybe a couple will end up at Sabine. The rest will be perfectly able to underpin the financing, the economic, thresholds that we require to FID Stage 3 next year.

Next, we will go to Spiro Dounis with Credit Suisse.

Wanted to start off with the MLP actually, if we could, and just revisit your thinking there. The valuation spread has really kind of moved closer in favor of maybe combining the entities, and I know that was discussed maybe a year or 2 ago and seems like we're gravitating closer to that level. So I just wanted to get your latest views on whether or not we're getting close. I know cash flow accretion was a big point that you want to sort of make there and what your appetite is on that front to simplify the structure.

This is Zach again. And I'll just say, we've been very consistent in our openness in simplifying the structure over the years. And at the same time, we're pretty happy being patient and waiting for the right ratio of the stocks. But at this point, we don't see any need to do anything to an extent.

2 months ago, we came out with capital allocation and said we had about $10 billion of available cash, just with the curves and the momentum we have. That's maybe $2 billion higher, right? So there's nothing holding us back from achieving all of our goals regardless of the structure and are definitely not interested in using any leverage to solve any of the accretion dilution issues with such an exchange or an IDR simplification of that sort.

What we're mainly focused on for the LNG shareholders is at least the $11 of run rate cash flow for 9 trains growing to $16 on a sustainable basis. And if there's a way to simplify the structure and maintain that, yes, we'd be open to it. But at this point, we're pretty content with how things are going.

Yes. Makes a lot of sense. Second question, few weeks ago, you all got approval from the FERC to expand some of the nameplate capacity at Sabina Corpus. And I just wanted to dig in there a little bit and find out exactly what that relates to. I think some of my math suggested that gets you sort of beyond the optimized 5 million ton per annum run rate for each of those trains, but I realize there might be some nuance there. So I just want to get some color there and understand if there's anything incremental in that approval.

Yes. That approval was in the making for a while and went through all of the necessary regulatory processes. But I'll tell you, I am more and more pleased with our debottlenecking and optimization that we -- program that we've been able to do at the 2 sites. And if you're asking -- if I think there's more room to go, I do. And we'll be sure to underpromise and overdeliver on that aspect of it.

Our next question comes from Brian Reynolds with UBS.

Just given the '22 guidance range and comments from the previous capital allocation announcement of $1 billion to $2 billion in additional cash available, I know you just said that could be $1 billion to $2 billion higher on Spiro's response. Just wondering how we should think about capital allocation as we head into 2022 and if any of that excess cash will be deployed in '22 or if that will be more of a '23 and '24 event.

Sure. So yes, when we speak to around $2 billion more of available cash through '24, that'll really come over the span of the entire period of time because just in this '22 to '24 time frame, I'd say margins have moved up over $3. So just take that into account with a company that's 90% contracted. That's how you almost get there in terms of overall cash.

What you'll see us do with this momentum, though, is, to an extent, we'll probably pay down more than $1 billion of debt just this year in our first year of capital allocation, but then you can see meaningful increases next year, not just debt paydown, but allocations to the buyback program, and obviously, some flexibility to not only FID Stage 3 at some point in the middle of next year or later, but even do some LNTP to start locking in prices and some of the schedule earlier in the year. So there's a ton of flexibility there.

But the main tailwind from this extra cash flow I see as we came out saying that we hope to get to IG by 2024. It's looking like we'll be able to pay down that $4 billion of debt by 2023. And with that, obviously, we can ramp down the amount of debt paydown. We'll be doing post getting to IG, and that means we can ramp up some of those capital returns while still funding Stage 3. So you could see us being even more aggressive on the buyback eventually and then obviously reconsider what the right payout ratio is for the dividend over time.

Great. Appreciate the color. To pivot back just to the 150 TBtu of open capacity, just want to clarify, does that include all of Train 6 capacity at this time assuming late 1Q start date? And then also, you talked about the debottlenecking initiatives, I think 1 to 2 mtpa on the Capital Allocation Day. Is that also included in the guidance? Or is that kind of fed through the 3 years just continued optimization?

Yes. When we give guidance today for next year, that's literally the budget that we just went through and the forecasted plans. So there's no debottlenecking work that needs to get done to achieve our plan for next year, which is over 2,200 TBtu. And that's not including any commissioning cargoes. So the production related to Train 6, that should gear up later this year and obviously in Q1 next year.

And just to give you some perspective on that commissioning because it's turning on at a pretty good time with where market prices are. We could have over 10 commissioning cargoes over the winter, and that alone could be over $0.5 billion of extra cash not baked into any of our forecasts for EBITDA or DCF. And to put it in perspective what that number means, to finish Train 6 and the third birth at Sabine, that's around $300 million. So we actually are more than covered for the rest of our CapEx for the 9-train program.

Our next question comes from Michael Lapides with Goldman Sachs.

Congrats on a strong year. I want to think longer term, and I think the first thing is when you're talking to customers, and many of your customers -- the utility customers in Asia own very diverse power generation fleets. We've seen a ramp in gas this year, probably early next year, although pricing can move things around. What are folks saying to you when you talk to them about whether there is a potential coal power plant retirement cycle ahead, probably not in the next year or 2 given what's happened, but thinking 5, 10, 15 years down the road in Asia? And how material that could be if I kind of want to think and compare it to the U.S. and European ones?

Yes. Thank you, Michael. So I'll start, and then I'll turn it over to Anatol. As you know, just in China alone, there's over 1,000 gigawatts of coal-fired generation currently in operation, and I always relate that back to Calpine. And when I ran that company, it was around 25,000 or 25 gigawatts, and China has got over 1,000 gigawatts of coal. So just a dramatic number that is multiples of Cheniere's if they really need a reliable supply of natural gas like we believe they do.

I actually think the demand for nat gas and for LNG has been constrained because of the lack of availability of the product. Had we had more product, the demand would have just been in double digits, significantly higher. So I worry at these high prices. There's a lot of substitution going on, and that tends to be a lot more coal and oil being used for power generation. So we need to get back in balance longer term, and then I think folks will actually appreciate that nat gas is here to stay and part of the solution for a cleaner energy mix around the world.

Yes. Michael, just to add a little bit to Jack's comments. China is committed to peak coal. It is still adding coal capacity, but it is retiring older plants, and that will, we expect, only accelerate. The numbers you're seeing now are really the -- just the start of a power conversion to natural gas. It's still only 4% of total power capacity in China is natural gas, but we're seeing, especially in the coastal provinces, more and more commitments to that with thousands of gigawatts being added. And it's not just coal. It's a commitment to phase out nuclear in Taiwan, in Korea going forward. It is probably peak nuclear in Japan in the coming years. So we're seeing natural gas -- still an unwavering commitment to natural gas.

Jack mentioned the high prices and the volatility, that could cause a recalibration of those commitments. We haven't seen that yet. And as long as again we do our job of providing stable, affordable and reliable supplies with almost perfect reliability to our customers, their economics are, of course, well within these prompt prices. So that is clearly helpful in the equation over the longer term.

So if I wanted to think about a really long-term outlook for Cheniere, can you remind us how much real estate or how many incremental tons you could potentially add after Stage 3, meaning how much real estate at Corpus is still available? And are you even thinking about Stage 4 at this point?

Yes and yes. So we just finished our acquisition of the old Sherwin Alumina facility that's contiguous to Corpus Christi. So it's a little over 500 acres, and it contains a birth. We believe we could probably add another 4 large trains, which should be about 20 million tons of additional liquefaction after Stage 3. And then as you know, Michael, we're just completing -- we will complete next year birth 3 at Sabine Pass. So we -- again, we -- I guess at Sabine, it's a long-term lease, a 99-year land lease, but it's another 500 acres and plenty of room to grow at Sabine, especially with the third birth being completed. It eliminates one of the bottlenecks for us.

Our next question comes from Craig Shere with Tuohy Brothers.

It seems like there's really a lot of unrestricted cash at the MLP. I believe CQP's operating cash flow less distributions and even CapEx was positive in 3Q. And to Zach's point, commissioning cargoes alone should be more than the cost of all remaining SPL T6 CapEx. Any thoughts about applying excess MLP liquidity towards a further train upsizing and/or carbon sequestration? And would FID on a Sabine Train 7 makes sense at all before you reconcile simplification and cost of capital issues?

Yes. So Craig, first, this is Jack. First, in our guidance, we fund all the capital projects that we need at Sabine. And in that funding is a continued effort to do the necessary engineering and design work for CCS for Sabine Pass.

Additionally, as Zach said, we don't feel constrained with the MLP structure to not continue to expand and grow that facility. So you should expect us to continue to want to leverage all of the infrastructure that we have there, which could include building a Train 7.

And Craig, I'll just add, though you see about a $1.7 billion of cash on the balance sheet at CQP, about $500 million of that was just the bond proceeds from the CQP bond we did in September. That actually paid off the previous debt on October 1. So there was an incremental $500 million on the books and incremental $500 million of debt that went away October 1.

And on top of that, with this excess cash, we're already going to pay over $400 million down of the SPL bond that's coming due in '22 through our capital allocation. So we're taking advantage of it there. And then we're increasing into over $3 on the DPU, making that commitment today for next year. So the money is putting -- is being put to use for sure. And again, we bake in quite a bit of development capital to ensure that we're progressing Sabine, maintaining Sabine and setting ourselves up for some opportunities for expansion or for CCUS.

And for my last question, I'm just a little confused about '22 hedges in that they could arguably be thought to be weighted more towards first quarter given proximity and the desire to have recent very high pricing or it could be more weighted towards the remainder of the year given uncertainties around actual T6 timing. Can you kind of walk us through how that kind of ratably moves through the year in terms of hedging?

You probably know the answer to that we're not going to walk you through that in much detail. And I think we actually give quite a bit of detail here today that we have 150 TBtu open, but -- and then you can bake that into the fact that we are already 90% or so contracted going into this year with all of our long-term contracts. But to get to this almost 95%, that is a little bit of hedging. That's just forward sales that we normally do, and there's bridging volumes for some of the long-term deals that are in place as well like ENN. So it's a little a mixture of everything.

I will say more of the open capacity over time is in the last 3 quarters of the year versus the first quarter, and that's just because we'll be ramping up Train 6 during that period of time.

Our next question comes from Ben Nolan with Stifel.

I wanted to go back to Corpus Christi a little bit. It sounds like things are very, very close to a Stage 3 going FID. And Jack, appreciate the color that you gave the 4 more large trains and 20 million tons. But not wanting to put the cart before the horse here, but just in terms of the timing of the process, from where we sit now, what is at least realistic or practical in terms of thinking about, okay, well, when do we move on to the next thing past Stage 3? And when does that actually could become operational?

Ben, right now, we are 100% focused on Stage 3. So I don't want to divert our attention on to any further growth until I get Stage 3 up and built or at least commercialized. So I -- the thought that we would sit on our haunches after Stage 3 is interesting to me because, as you know, about 100% of the gas at Corpus Christi right now is coming out of the Permian Basin. And we're a good credit and a good buyer and a reliable customer of producers to take that gas and convert it and sell it to the global markets. So we're pretty excited about it. The other aspect of this is this is probably one of the most transparent industries I've ever been in to where when we make the filing, you all will know about it. It'll be filed publicly on a docket and reviewed. And so you'll have forewarning that we've shifted gears.

Right. Well, and I was going to see if I could get a little forewarning there, I guess. But the next question actually does relate to Stage 3. I've seen in other places some things actually already with numbers above 10 million tons being sort of quoted in terms of its capacity. You talked about debottlenecking on the first 9 trains, but are you starting to get more confident already that you were conservative on the 10 million tons for Stage 3?

Yes. We like to do things with a full wrap. So -- and Bechtel will guarantee the performance as well as the budget and the schedule. And for them to get comfortable with the guarantee, they're going to darn well make sure they can meet or exceed that number. And our permit, though, is for 11.5 million tons, just to give you some insight.

Our next question comes from Mike Webber with Webber Research.

I know we spent a bunch of time this morning already talking about medium-term pricing and CMI. But primary question is for Anatol. And just curious if you can give some color around whether or not you all have been able to actually start to push fixed pricing yet. We've heard feedback across different parts of the space that you're starting to see people start to inch up SBA pricing. I'm just curious on your end have you been able to do that yet? Or is that something we'd expect for an expansion?

Look, we -- the answer is for us to maximize value for ourselves and to come up with a solution that is attractive to our customers. So in today's environment, the most attractive way to bridge that is to have a product that's differentiated that has these early volumes. And as we touched on earlier, those volumes are priced at the curve. So the economics are influenced by those molecules that are in '22, '23, '24, and that has been moving prices for long-term commitments higher as a result. So that's clearly playing out, and we're on the beneficiary end of that. But that said, we're perfectly content with having an NPV-neutral solution that allows our customers to put that into the long-term commitment that they are making to us.

And it depends, Mike, right, on what -- which parts of the value chain they want. If they want us to deliver it to their dock, then shipping is a pretty critical and valuable component of that transaction. So -- but the market is competitive and also...

And you guys have obviously -- you've executed your butts off, and Zach and his team have been able to really drive down your cost of capital. But to replicate those kind of per unit returns, being able to drive that SBA price up, it probably more difficult now than it was in 2011 to 2015. But I guess to the extent that having that -- I'm trying to get a little bit more -- a little sense of on a relative basis or, well, on an absolute basis, but to what degree you're actually able to leverage those immediate CMI volumes to actually drive that CMI -- or that SBA price back closer to the mid-2s or into the high 2s or even beyond 3 where you were in kind of 2011 and 2015, I think some context there and some sense of scale in terms of what you think is realistic as we head into what should be a pretty decent period between now and, say, the middle of the decade.

So Mike, I'll say this. I think you will be pleasantly surprised when you see the financial metrics when we FID Stage 3, and it's a combination of everything. So we get paid a premium for reliable -- for being a reliable producer. We get paid a premium for handling shipping and marketing. And all of that adds up to a very nice price back -- netback back to us. And it works its way through CMI because that's where all of our skills and our people are that -- handle that for us. But at the end of the day, it's a combination of all of the above. If you're asking for the plain vanilla FOB, CP contract, it's very competitive.

Right. I guess I want to ask you that premium, whether that's widened out to any degree and if I think about the valuation that's predicated on that kind of vanilla (inaudible) price point.

It's absolutely widened out. Shipping is at an all-time high. And as you know, the Panama is congested. So it takes a lot longer to get to Asia, and the shipping prices are a lot higher. So it all translates into higher overall prices.

We will take our final question from Sean Morgan with Evercore.

So I noticed earlier in the call, I think Zack talked about the hedges, primarily being noncash. And in the press release, you talked a little bit about how the IPMs tend to have a higher amount of hedging associated with them. So I was kind of wondering, just structurally, aside from the longer duration and the international pricing, is there anything that's driving that? And what percentage of the hedges that we saw being -- flowing through the income statement this quarter were related to the new IPM business versus kind of the more historical business that you guys were on?

Sure. So this is Zach. And I'll just say on total derivatives, we had a $3.5 billion loss on an unrealized basis. So anything forward-looking, noncash, it was $3.1 billion. And on the IPM transactions alone, which is literally just 3 deals with Apache, EOG and Tourmaline -- and Tourmaline started in Q3, at least we signed it in Q3. That was $2.5 billion. So just to put into perspective how big that is. And the reason for it is that they actually have to look out the entire length of that contract, and it's treated almost like a regular hedge because instead of buying gas at Henry Hub, we're buying it at a Gulf Coast LNG netback, less our fixed fee and every quarter where margins improve like they had going from to like over $10 now and expanding even in the outer years, it makes a big move. And honestly, we kind of joke here, we hope to never see a major unrealized derivative gain because we'll have the opposite of what we're seeing in the market these days and going forward.

Okay. That's interesting. And then just really quickly one follow-up. So I noticed the margin deposits were broken out, and it went up. And it's pretty small relative to the massive company built, but I'm just wondering, is that indicative of any stress of customers with these kind of high spot prices we're seeing in terms of their liquidity? Are you guys requiring more in the way of bank letter of credits? Or how do those margin deposits sort of function?

In terms of margin requirements, clearly, when we do a little hedging, we don't go all that far, but we did some hedging even going into next year. So those are some of the unrealized derivative losses. Cash collateral is often called for those. But at the same time, we have like 15 or so, if not more, is the counterparties on hedging and have hundreds and hundreds of millions of dollars of open credit there. And then as you could see in our balance sheet, when we talk about over $2 billion of cash, untapped revolvers everywhere, it was a pretty minimal move for the overall company. And that's how we like it, and that's honestly why we prefer these long-term deals on a Henry Hub plus basis. There's no cash collateral, and we lock in the cash flows for even longer periods of time.

Thank you. That will conclude today's question-and-answer session. I will now turn the conference back to the management team for any final remarks.

This is Jack. I just want to say thank you again for all of your support. It's exciting times for us at Cheniere, and we look forward to a strong finish in 2021 and a great start to 2022. Thank you very much.

This concludes today's conference call. Thank you for your participation. You may now disconnect.