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Cheniere Energy Inc
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Good day. And welcome to the Cheniere Energy Q4 and Fiscal Year 2022 Earnings call and Webcast. This call is being recorded. At this time, I'd like to turn the conference over to Mr. Randy Bhatia. Please go ahead.
Thank you. Operator. Good morning, everyone. And welcome to Cheniere's Fourth Quarter and Full Year 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; Zach Davis, Executive Vice President and CFO, another members of the Cheniere management team.
Before we begin, I'd like to remind all listeners that our remarks, including answers to your questions, may contain forward-looking statements, and actual results could differ materially from what is described in these statements.
Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix to the slide presentation.
As part of our discussion of Cheniere's results, today's call may also include selected financial information and results for Cheniere Energy Partners LP, or CQP. We do not intend to cover CQP's results separately from those of Cheniere Energy, Inc.
The call agenda is shown on Slide 3. Jack will begin with operating and financial highlights, Anatol will then provide an update on the LNG market, and Zach will review our financial results and 2023 guidance. After 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 this morning ad we will review an incredibly rewarding and transformational 2022 and provide our outlook for what we expect to be another very busy and successful year for Cheniere in 2023. To say 2022 was an incredible year for Cheniere would be an understatement. Disruption and volatility dominated energy markets the world over as geopolitical tension and the weaponization of energy supply turbocharged already volatile markets suffering from years of underinvestment in infrastructure. The criticality of reliable natural gas supply in a normally functioning energy system and the vital role natural gas plays throughout a developed economy was put on full display as the world watched some of the wealthiest nations in the developed world scramble to ensure reliable energy supply for their populations and economies.
And while it appears now that a severe energy crisis in Europe over the winter has been narrowly avoided, the situation there only further reinforces the vital need for a reliable, affordable, secure and diverse energy mix. At Cheniere, we were proud to play an important role in helping balance global energy markets at a time when it was needed most. With the early completion and advanced startup of Train 6 at Sabine Pass, as well as optimizing our maintenance schedule, we produced approximately 44 million tons of LNG during 2022, 72% of which was directed to Europe, further illustrating the value of destination flexibility which Cheniere pioneered.
And of course, over the summer we reached FID on Corpus Christi Stage 3, which will bring an additional 10 million tons of much needed LNG to the global market and our long term customers beginning in 2025. Over the course of 2022, the focus of the global natural gas industry for both suppliers and consumers, crystallized for the trilemma of energy security, affordability, and long term environmental performance. On each of these critical points, Cheniere offers a market leading solution which instills my confidence in our growth potential, which I'll speak to in a few minutes.
Please turn to slide 5 where I will review key operational and financial highlights from the fourth quarter and full year 2022 and introduce our 2023 financial guidance. We generated consolidated adjusted EBITDA of approximately $3.1 billion in the fourth quarter, bringing our full year total to approximately $11.6 billion above the high end of our guidance range. We generated approximately $2.3 billion of distributable cash flow in the fourth quarter, bringing the full year 2022 DCF total to approximately $8.7 billion, also above the high end of our guidance range.
Looking back at the original guidance provided in November of 2021, we beat the midpoint of each of those guidance ranges by over $5 billion, illustrating the extraordinary nature of the global gas markets and the value of our ability to be a reliable operator and supplier during the year. For the fourth quarter, we generated over $3.9 billion of net income, and our annual total is a positive $1.4 billion. Our net income continues to be impacted by noncash unrealized derivatives, which worked in our favor in the fourth quarter as global gas markets moderated.
During the fourth quarter, Zach and his team made excellent progress on our capital allocation plan, deploying billions of dollars into capital return via debt repayment, share repurchases, and increased dividends as well into disciplined accretive growth at Corpus Christi Stage 3. He's sitting here next to me, anxious to cover capital allocation in more detail, so I'll stop there before stealing too much of his thunder. Operationally, the fourth quarter and full year 2022 were exceptional. Fortifying Cheniere status as a leading global operator, reliably producing LNG with safety at the foundation of every action we take. During the quarter, we exported a record 166 cargoes from our facilities, bringing our annual total to a record of 638 cargoes. I'd like to recognize Cheniere’s approximately 1,550 professionals who worked tirelessly in 2022 for demonstrating Cheniere’s execution and operations leadership to the global marketplace and helping enable the outstanding results we reported this morning, all while achieving record safety metrics throughout the year.
Now, shifting our focus to 2023, I'm pleased to introduce our 2023 financial guidance of $8 billion to $8.5 billion in consolidated adjusted EBITDA, $5.5 billion to $5.6 billion in distributable cash flow and $4 to $4.25 in per unit distributions of CQP. I am pleased to provide 2023 guidance figures that are significantly higher than our more normalized 9 Train run rate, and I believe that the stabilization of both prices and volatility in the international gas markets will support stronger and faster demand growth, ultimately, this should support my long-term health conviction and the structural shift to natural gas worldwide.
Turn out to slide 6, where I'll cover my key priorities for 2023. First and foremost, we have an established track record earned over multiple years of delivering on our promises, and I expect that to be maintained in 2023. We have set ambitious but achievable guidance ranges for the year, and our focus will be on strengthening that track record by delivering on our financial guidance. In 2023, with less CMI volume and without the variable of new capacity entering service, we have a higher degree of visibility on our metrics than we did a year ago to hit our forecasted production estimates and continue to progress on our 2020 vision capital allocation plan.
Second, we expect to lead with organic growth and have over 30 million tons currently under development or under construction. Our 40 plus billion in infrastructure investments is one of the biggest competitive advantages we have, as it enables economically advantaged capacity expansions such as Corpus Christi Stage 3. Construction activities at Stage 3 is progressing. And while it's too early to say we are ahead of schedule, since we are about 2% complete on construction, Bechtel was beginning to execute on some aspects of early construction ahead of plan.
On the growth front beyond Stage 3, we are progressing through the prefiling process on midscale Trains 8, 9 at Corpus Christi, and we expect to submit the full filing to FERC before the end of the first quarter. Over at Sabine Pass, I hope you saw our announcement this morning that we have just initiated the permitting process for a significant capacity expansion there by submitting pre filing documentation to FERC. I'll discuss this project in more detail on the next slide, but we are extremely excited about developing this expansion of Sabine Pass, which could add approximately 20 million tons of additional capacity at the site. Moving this project through the engineering and construction and permitting process will be a major priority in 2023. Anatol, Ramzi and the team are actively commercializing this new potential investment.
Third, we'll further advance our climate and sustainability initiatives, which we'd like to describe as actionable, not aspirational. Despite the industrywide focus on energy security in 2022, improving environmental performance remains a long-term goal and establishing and maintaining environmental competitiveness is critical for continued natural gas adoption and therefore the long-term resiliency of LNG. The programs we have discussed on recent calls such as our QMRV program, our cargo emission tags, and joining the UN's oil and Gas Methane Partnership are all efforts on which I expect continuous focus, improvement and refinement to further reinforce genre's leadership position on these crucial efforts.
Now turn to slide 7 where I'll share some details about our next major capacity expansion at Sabine Pass. We've just commenced the permitting process on this large scale project by submitting the prefiling documentation to FERC. We expect to submit the full filing before the end of the year and look forward to working with FERC on permitting this major brownfield capacity expansion. The Sabine Pass expansion project is being designed for approximately 20 million tons of LNG. The project is expected to consist of up to three large scale Liquefaction trains utilizing the same Liquefaction process technology that's deployed on the six operating trains at SPL. Each train is expected to have a nominal production capacity of approximately 6.5 million tons. The project is also expected to include a Boil-Off Gas Re-Liquefaction Unit which would add almost a million tons of production, and two full containment LNG storage tanks. You can see the rendering of the project on the slide. We have been hard at work on early stage development of this project and have Bechtel already engaged on front end engineering and design work and are excited about transforming the engineering drawing on the slide into reality at Sabine Pass.
We will develop the Sabine Pass expansion project utilizing the same rigorous and financially disciplined approach to project development and capital investment you've become accustomed to from Cheniere. The SPL expansion project is consistent with the significant growth plans we laid out in our capital allocation presentation in September. We showed a potential 90 million ton platform across the Sabine Pass and Corpus Christi. Our infrastructure platform is an enormous competitive advantage which this project is expected to capitalize on in order to deliver Brownfield economics. As the world calls for more LNG capacity, Cheniere is in an economically and environmentally advantaged position to provide that incremental capacity.
We look forward to updating you on this large scale growth project at Sabine Pass as well as the developments at Corpus as we move through this process. Thank you again for your continued support of Cheniere. I'll 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. An accelerated post pandemic recovery followed by the curtailment of Russian gas flows into Europe made for a sharp increase in LNG demand in 2022, with limited new liquefaction capacity and several production outages, the LNG market remained extremely tight throughout the year as we saw prices reach all-time highs and remain elevated. Despite the supply side challenges, global LNG trade grew by approximately 5% from 2021, or an additional approximately 19 million tons. Overall, US exports increased 9% year-on-year, up 6.3 million tons to 76.5 Mtpa in 2022 despite the freeport outage during the second half of the year. US LNG represented nearly 40% of the growth in global LNG supply, and the early completion of our 9 Train meaningfully contributed to that growth. As Zack noted, our increase in production enabled Cheniere to help answer Europe's call for reliable, flexible natural gas supply. Having lost Russia as a significant supplier, Europe became a substantial demand center for LNG, attracting approximately 70% of all US LNG in 2022 as prices reached record levels and redirected destination flexible US LNG volumes to address the deficit.
The TTF monthly settlement prices averaged around $40 per MMBtu in 2022, over 180% higher than the $14 average in 2021. In the fourth quarter, TTF monthly settlement prices averaged $42 per MMBtu or 46% higher year-on-year, but significantly lower than the peak of nearly $100 in MMBtu in late August. Similarly, the 2022 JKM average settlement price increased by over 125% year-on-year to an average of $34 per MMBtu with the fourth quarter average price increasing 38% year-on-year to an average of $38, but well below the summer peak of nearly 70. In the US, Henry Hub price averaged nearly $7.22, but has moderated considerably since the peak in September and is now trading well below $3 per MMBtu. This rapid correction, driven by North American production growth, again demonstrates the relative attractiveness of Cheniere’s Henry Hub denominated long-term FOB and DS contracts and underpins producers desire to diversify away from solely domestic indices. Despite the retreat of global gas prices to prewar levels beginning in the fourth quarter and into 2023 on the back of a mild winter and demand reduction efforts in Europe, the overall market remains volatile. And we expect volatility to remain elevated as Europe sorts out its near and long term gas supply strategies and the impact of a post COVID China on the market becomes more apparent.
Let's now turn to slide 10 to address regional dynamics in some more detail. As noted, much of the flexible LNG in the market was directed to Europe and was able to offset a large part approximately 84% of the 74 Bcm, or 55 million ton reduction in Russian gas supply. Europe's LNG imports totaled over 120 million of which 110 million tons went to EU plus UK, which is a 69% increase year-on-year. US LNG to the block plus the UK totaled 48 million tons, a 165% increase year-on-year. Clearly, destination flexible US LNG was able to answer Europe's call for natural gas supply in 2022.
Throughout the year, the EU implemented several extraordinary measures to mitigate the potential impact of a complete cutoff of Russian gas and a potentially cold winter amid low nuclear and hydrogeneration output. As Zack noted, the challenges that European nations faced were significant. But these measures, along with mild weather and demand price response, enabled Europe to replenish its inventories and avoid a potentially crippling energy crisis in the near term. Some of the coordinated initiatives included a regulatory push to immediately increase LNG import infrastructure, diversify supply sources and reduce natural gas demand. To date, five new regasification terminals have commenced service in Europe since September, a key enabler of Europe's ability to grow LNG imports to record levels in the fourth quarter. Demand reduction efforts have also been made across Europe. Residential, commercial and industrial customers were able to reduce aggregate demand by an estimated 12% during the year as power generation resorted to increase coal usage, a trend that we think will reverse in 2023 given elevated gas storage levels and again, a mild weather outlook.
At present, it appears the European gas system will make it through this winter without the enforced supply restrictions many had feared. Amid historically high LNG prices, the global inflationary environment, lower economic activity and lower market liquidity, some of the more price sensitive Asian buyers withdrew from the spot LNG market. Imports into Asia declined by 20 million tons, or 7%, year-on-year, with nearly 16 million tons of the drop attributable to China. This was the first substantial annual decline in LNG imports since the country began importing in 2006. China's economy faced extended COVID restrictions, a property sector crisis and severe drought, all of which led to a drop in total gas demand of 4 Bcm in 2022, with a decline led by the industrial and power generation sectors. Similar to parts of Europe, low hydro output and high gas prices supported increased coal generation in the second half of 2022. However, with JKM and TTF prices moderating, we expect to see price sensitive Asian LNG demand resume on indications of higher industrial activity in China as COVID restrictions are lifted. The latter, of course, could have a potentially material impact on next winter's global balance.
Let's move to slide 11. Europe shift away from Russia created an immediate supply gap of approximately 70 Bcm in 2022, which will likely rise to approximately 110 Bcm in 2023. Assuming Russian pipeline supplies are eventually fully curtailed, the gap created of 100 Mtpa is equivalent to around a quarter of the current global LNG market. The magnitude of this supply shock stressed the global LNG market in 2022, resulting in some demand destruction in certain regions during the year. More important, however, as Zack noted, the market dynamics of ‘22 highlighted the critical role of LNG in ensuring energy security, underscoring the importance of long-term contracted reliable LNG supply in the global energy mix. While short-term dynamics have dominated headlines and narratives over the last year, the long term fundamentals are central to our strategic planning and positioning, and the need for further investment in LNG capacity was again laid bare last year.
Over the next few decades, both the supply and demand side are supportive of new liquefaction infrastructure. In addition to high project development hurdles, capital intensity and long construction timelines for new LNG facilities, legacy plant utilization rates worldwide continued to decline as a result of outages, feedstock limitations and fleet inefficiencies, as well as competing domestic demand in some markets. Since 2010, the volume produced from these legacy projects has declined by 23%, or over 25 million tons, further contributing to the need for more capacity. While these facilities produced about a quarter of all total volume last year, their contribution will likely decline over time as feedstock resources deplete, their ability to export declines and their performance potentially degrades.
Meanwhile, investment in downstream LNG infrastructure continues to grow, not only in Europe, but also in other parts of the world. Over 370 million tons of regas capacity is under development, which is equivalent to about 80% of global LNG trade today. Furthermore, nine new markets are expected to enter the LNG trade in the next two years, including Vietnam, the Philippines, and Ghana, just to name a few. Investments in new LNG supply are critically needed not only to address the current market imbalance and meet the expected long term demand growth, but also to offset declining production from certain legacy production facilities. To this end, Cheniere is doing its part with over 10 million tons under construction and another 20 plus million tons in the permitting process we aim to leverage our many advantages to economically contribute to the overall reliability, security, affordability and scale of the global LNG market.
With commercial support for capacity beyond Corpus Christi Stage 3 in hand, the team is well positioned to leverage that success as we develop and commercialize the SPL expansion project. With that, I will turn the call over to Jack to review our financial results and guidance.
Thanks Anatol and good morning, everyone. I'm pleased to be here today to review our fourth quarter and full year 2022 results and key financial accomplishments and 2023 financial guidance. As Zack and Anatol have noted, 2022 was quite a year for our company, our stakeholders and our industry as a whole. And the financial results we reported today once again reflect the Cheniere team's unwavering commitment to operational excellence, execution and financial discipline, which is especially important throughout this period of prolonged volatility in the global energy markets.
Turning to slide 13, for the fourth quarter and full year, we generated adjusted EBITDA of approximately $3.1 billion and $11.6 billion, respectively, and distributable cash flow of approximately $2.3 billion and $8.7 billion, or approximately $35 of annual cash flow per share. With the full year results exceeding the high end of our latest guidance ranges provided in September. Thanks to these full year results ending up close to $5.5 billion higher than our original 2022 guidance. We've been able to transform our capital allocation objectives now as an investment grade company with Stage 3 construction fully underway and a sharpened focus on more robust shareholder returns in the form of our upsized $4 billion buyback program and our competitively growing dividend.
During the fourth quarter and full year, we recognized an income 591 and 2,317 TBtu of physical LNG, respectively which included 581 and 2,288 TBtu from our projects and 10 and 29 TBtu sourced from third parties, respectively. Approximately 80% of these LNG volumes recognized in income in both periods were sold under long term SPA or IPM agreements with terms greater than 10 years. Our fourth quarter and full year results once again were supported by increased margins realized on our LNG delivered, which were primarily driven by the elevated market pricing throughout the year and higher volumes produced at both of our sites, thanks to the early completion and ramp up of SPL Train 6 and the maintenance optimization announced in May. Our total margins also benefited from portfolio optimization activities in addition to the proceeds from the early termination of the Chevron TUA.
In addition, I would like to highlight that we generated net income of $3.9 billion and $1.4 billion for the fourth quarter and full year, respectively. As we've noted in prior earnings calls, our net income line is impacted by the unrealized noncash derivative impact, primarily related to the mismatch of accounting methodology for the purchase of natural gas and the corresponding sale of LNG under our long term IPM agreements. While this resulted in unfavorable changes throughout most of 2022 as international gas prices rose, during the fourth quarter, the moderating of international gas price curves provided a significant benefit, allowing us to hit an inflection point with cumulative positive net income for the preceding 12-months for the first time in a few years.
Before discussing our financial guidance and priorities for 2023, I'd like to recap some of our key financial accomplishments for 2022 and how effective we've been in allocating the capital back into the business and to our shareholders. First and foremost, I'm pleased to highlight that our commitment to achieving and maintaining a sustainable balance sheet was recognized by the rating agencies, with 13 distinct upgrades to our credit ratings across our corporate structure over the last year, including the achievement of two investment grade ratings at each of our parent entities. solidifying Cheniere as officially investment grade. In November, S&P upgraded Cheniere and CQP by two notches to BBB, with a stable outlook marking Cheniere's first and CQP second investor grade rating not long after Fitch initiated its coverage of Cheniere with a BBB minus rating and a stable outlook. As you all know, achieving investment grade has long been a goal of ours, as we believe it best positions Cheniere for the future and validates the long-term value and sustainability of our platform. During the quarter, we prepaid approximately $2.2 billion in consolidated long-term indebtedness, bringing our total debt paydown to just over $6.6 billion through the fourth quarter since launching our original capital allocation plan in 2021, with over $5 billion of debt reduction in 2022 alone. Since our third quarter call in November, we also issued $500 million of senior secured amortizing notes due 2037 in the public and private debt capital markets, the proceeds of which were used along with cash on hand to redeem the remaining SPL 2023 notes.
In December, we also repurchased over 750 million of the outstanding 2024 notes at CCH pursuant to a tender offer. And in January redeemed the remaining nearly $500 million outstanding with cash on hand. We also continued to utilize our open market repurchase program and in the fourth quarter repurchased over $400 million in principle of outstanding CCH notes with maturities ranging from 2025 to 2039. With all that said, today we have almost $10 billion of consolidated available liquidity, including our bank facilities, investment grade balance sheets throughout the Cheniere structure, and our nearest maturity is not until next year. I'm very proud of what our team has accomplished at such an accelerated pace, as each of these transactions reflects our focus on managing our debt across the corporate structure, opportunistically and strategically for the long term.
As we mentioned back in November, now that we've solidified our balance sheet and reached our initial investment grade goals, we have balanced out our priorities, recalibrating our debt pay down to share repurchase ratio from four to one, to one to one as outlined in our revised capital allocation from last September. In fact, in the fourth quarter, we repurchased approximately 4.4 million shares for over $700 million, bringing our total shares repurchased during 2022 to 9.3 million for approximately $1.4 billion. Given our one to one cumulative goal over time, you can expect that we will continue the share buyback momentum with growing relative buyback allocations for 2023. In order to achieve our cumulative one to one target ratio with debt paydown.
We also paid $1.0385 per common share in dividends last year, inclusive of a 20% increase for the third quarter, and declared and paid our 6th quarterly dividend of $0.0395 for the fourth quarter this past month. We intend to follow through with our previous guidance of growing our dividend annually by approximately 10% into the mid-2020s through construction of Stage 3.
Turn now to slide 14, where I will discuss our 2023 guidance and update you on our open capacity for the remainder of the year. For 2023, our guidance is $8 billion to $8.5 billion in consolidated adjusted EBITDA and $5.5 billion to $6 billion in distributable cash flow or over $20 of cash flow per share. These ranges reflect current international gas prices curves as well as our significantly smaller open position relative to 2022, given the start of several long term contracts this year and our planned maintenance at Sabine Pass. 2022 was an unprecedented year, with EBITDA and DCF approaching double and triple our respective 9 Train run rate guidance levels for those metrics. 2023 is shaping up to be another incredible year with guidance ranges multiple billions of dollars above the run rate levels for both, thanks to proactive management of our open capacity despite a higher contribution from long- term contracts in 2023.
Our focus remains on achieving the 2020 vision of generating over $20 billion of cash and over $20 DCF per share, and our expectation on accomplishing that plan hasn't wavered despite the moderation in near-term prices highlighting the stability and visibility of our long-term cash flow profile. With regard to open capacity, we have less than 70 TBtu of unsold LNG remaining 20, which are reserved for long term origination, and we currently forecast that a $1 change in market margin would impact EBITDA by approximately $50 million for the balance of 2023. The marketing team has done an excellent job proactively selling our open capacity since November from 150 TBtu, which has allowed us to come out with this guidance range of over $8 billion today and keep us on track with our 2020 vision.
In addition, our results could be impacted by the timing of certain year end cargoes heading into 2024. Our distributable cash flow for 2023 could also be affected by certain contemplated changes in the tax code under the IRA. However, the guidance provided today is based on the current IRA tax law guidance, in which we would not qualify for the minimum corporate tax of 15% this year. However, both of these dynamics would mainly affect timing and not materially impact our cumulative cash flow generation through the mid-2020s as we think about overall capital allocation deployment.
Looking back on 2022, the year was filled with uncertainty across global energy markets, but the Cheniere team remained focused on what we could control the reliable, safe and seamless operations of Sabine Pass and Corpus Christi, which enabled us to achieve extraordinary results across our business, accelerate our follow through on our commitment to capital allocation by deploying over $8 billion towards our all the above plans, including our growth objectives with Stage 3. Our conviction and the critical long-term role of natural gas across the globe to address the trilemma of energy security, affordability and long-term environmental performance has only grown in the wake of energy market volatility last year.
We are positioning Cheniere for the future in everything that we do, including our accretive growth projects, our investment grade balance sheet, and our long term commitment to generating meaningful and sustainable shareholder returns. That concludes our prepared remarks. Thank you for your time and your interest in Cheniere. Operator, we are ready to open the line for questions.
[Operator Instructions]
Our first question comes from the line of Brian Reynolds with UBS.
Good morning, everyone and congrats on now qualifying for S&P 500 eligibility. Maybe to start off just on the macro, we see a much different headline TTF and JKM price versus our time together on the last conference call. That said, we are starting to see some green shoots on demand recovery in both Europe and Asia. And I was curious if you could broadly discuss perhaps what are you seeing in terms of near term demand coming back, supporting the spot market and then as a follow up, perhaps on a longer term basis with a more normalized headline price. Are you seeing a pickup in contracting activity from counterparties? Thanks.
Thanks Brian. I'll turn it over to Anatol. He can talk about the demand growth that we're seeing across the globe.
Hey, Brian. Good morning. Thanks. We've had very good engagement throughout ‘22, as you can imagine, as we've discussed in the prepared remarks and throughout the last few years, the value of that long term contract, the stability, reliability and getting these volumes at a quarter or a third of that headline price has never been clearer than it was throughout ‘22. So we're very encouraged by what we're seeing. While we obviously saw short term demand destruction, to your point, most countries remain very committed to gas, continue to invest substantially in infrastructure, whether that's China, India, other Southeast Asian markets, et cetera. Europe, of course. And we're very encouraged by a very brief mix of committed interest to our product. So feel very optimistic about the hand we're dealt and obviously very excited that now the SPL expansion is out there for us to really hit the ground running.
Great. Thanks. And as a follow up on just capital allocation, recent investment grade upgrades by two agencies and growth CapEx and dividends seems to be spoken for the next couple of years. Should we view Cheniere through the lines of a return of cash story via buybacks? Or are there any moving pieces that we should think about for use of excess cash flow and the excess balance sheet capacity that you have now? Thanks.
Hey, this is Zach, and I think you got it right. But the over $700 million of buybacks and Q4 was the most we've ever done strategically as we were thinking about late last year and early this year. We were really just trying to take care of the ratings. And then we overloaded the debt pay down to get there once and for all with Fitch and S&P. So though the guidance is one to one, we did pay down a bit more debt in the last quarter or so. So it is time to catch up this year and going forward to get back to one to one on a cumulative basis. And as you think about how much debt paydown we did over the last year was like $5 plus billion just in 2022, there's probably about $2 billion plus buybacks on a relative basis to debt pay down that needs to happen over the next year or two. So we'll be keenly focused on that and obviously not a bad time to be buying back for at lower levels than we thought we would be at this point. And it will just help us solidify the 2020 vision that we remain on track for.
And we'll take our next question from the line of Jeremy Tonet with JPMorgan.
Good morning. I just want to start off here on Sabine Pass. At the risk of putting the cart ahead of the horse here, just wondering if we could get any more color about how this commercialization process could look down the road. And specifically, if you're looking for gas sourcing, would this likely come from the Permian new pipe there? We think about financing, would CQP be issuing equity? What type of timeline for contract commercialization will be thinking just any bits of information you could provide as far as thoughts on what this could look like would be super helpful.
Thanks, Jeremy. As you can tell from our prepared remarks, we are so excited about the Sabine Pass expansion. If you look at trying to see what slide number it was, Randy 7 of ours, you can see the rendition from Bechtel of what it would look like. That property is currently being utilized right now as lay down area. So it's primed and ready to go, which is one of the advantages that we have as a brownfield site. The infrastructure is there at the facility and there's a huge push and pull from the customer base worldwide. So you all remember back in 2016 when I started. We had 13 foundation customers; we now have over 33. Those are customers that take at least a cargo a month and have a tenure of over 20 years. And that customer diversity has grown dramatically as our contract structures have grown between FOB, DS, IPMS, et cetera, and who knows what's next but that Anatol and Ramzi have in their back pocket. But I will turn it over to Jack to talk about some of the more specific details.
Sure. And then I'll hand it off to Anatol, can give you a little update on how he's thinking about contracting the project going forward. But basically we're just starting that permitting process and engineering work with Bechtel, and it's going to be quite some time before we spend even more than $100 million as we develop that over the coming year or so. But obviously, since it's brownfield, it should be cost advantage, but it is 20 million tons. So you can imagine we'll approach it like we've approached everything, likely even in stages, as we've done on previous projects, just to be more efficient with the bank debt, capital raises and spreading out the equity over time. But the key component for us as we think about financing it is the fact that we now have this base plus variable distribution policy at CQP. So we can go through a major expansion at Sabine, maintain the base distribution, which is over $3.10 and live within our cash flows and stick to the same amount of 50% give or take of leverage and make it work which is a pretty neat place to be. So CQP works as is, and obviously it goes without saying that we'll hold to our investment parameters, make sure that it's accretive not just on a value basis, but a credit basis, too. And have all the other bells and whistles that you're accustomed to having with us when we FID a project, Anatol?
Yes, just to dive in a little bit to your question, as you know, the integration of upstream infrastructure solutions and gas supply has been a key success factor of ours and be one of our main kind of structural advantages. So we take that extremely seriously and we'll have robust solutions for that. And the customer mix, the crystal ball is fairly similar to what we have experienced over the last three to four years in a very healthy, credit worthy mix that does include producer customers, which partially includes not only the liquefaction fee but also the gas supply component and the opportunities to optimize those volumes flexibly downstream. So you are going to see from the commercial side producers, you are going to see European and Asian buyers and I think everyone is excited about this opportunity to continue to serve the market with this growth.
Got it. That's very helpful. Thank you. And just want to kind of touch on some of the other points you listed on that slide as far as it relates to the Boil-Off Gas Re-Liquefaction Unit and accommodation for waste heat removal and CCS. Just wondering if you could talk a bit more about these projects. What type of economics to these CapEx, do these projects have? Does it compete versus the facilities themselves? And did things such as 45-Q, I guess, possibly help economics here?
Yes. Jeremy. So on the Boil-Off Gas, right now, the Boil-Off Gas is the facility gets redirected back into the trains and gets reprocessed, and that takes up space in the train. So our production numbers look the same, but our feed gas flows aren't as high as they otherwise would be. And we have run the math and figured that the Boil-Off Gas Re-Liquefaction Unit would substantially help us increase the production throughout the rest of the facility. So that's an added benefit that we don't currently have at either of the sites.
And then secondly, you mentioned some of the heat recovery units. As you know, I've been in power my whole life, and I think being able to capture the hot flue gas out of the end of the gas turbines, run them, produce steam, use that to make power, just makes the whole process more efficient, makes us much more competitive overall. So we need to utilize that waste heat, and it helps with our environmental profile. So you should expect us to do what's right, and that would be utilizing that waste heat and reinjecting or sequestering the AGRU stream that comes off the gas stream efficiently.
Got it. That's great to hear about further optimization and squeezing every penny out. Zack, thank you.
We will take our next question from the line of Marc Solecitto with Barclays.
Hi, thanks. Good morning. With the formal upgrade to IG, could you talk about some of the benefits that come with that either commercially and or on the operational side with respect to either working capital management or collateral requirements related to hedges or forward sales?
Sure. So getting to IG is more than just symbolic. We actually have lower pricing now on our working capital facilities and revolvers. And both the corporate revolvers are now officially unsecured, which gives us even more flexibility going into the future. So that's all helpful. In addition to that, all the optimization that CMI does sometimes even sourcing from third parties. We're not posting nearly as much as we used to with LCS and things like that. We can just use a parent guarantee considering CMI is wholly owned by CEI. So that's pretty helpful. And then in terms of open credit, we're getting more that's a work in progress as we speak. But basically, when it comes to financial derivatives and hedging, that's still all about liquidity. Yes, we might have a little open capacity, but as we saw with the volatility this past year, that's still a liquidity thing. And what I mentioned on the call, we literally have $10 billion of total liquidity with the term loan that's available, the revolvers and the cash on hand.
So we have legged in a bit on financial hedging. And that's been helpful partially to why we're down to only 50 TBtu really open going forward.
Great. That's helpful. And then following up on a potential expansion at SPL, how should we think about the key potential cadence there? Could you do that one train at a time? And then for the 20 million tons of expanded capacity, is there the potential for some additional debottlenecking on the existing capacity with some of the investment in the ancillary infrastructure?
My operating team never ceases to stop amazing me with what they're able to do as far as our debottlenecking and optimization efforts. So I would say yes and yes. It's our intent that we would commercialize these trains like we have in the past and, as Jack said, could potentially build them individually or in stages.
We'll take our next question from the line of Jean Ann Salisbury with Bernstein.
Hi. Good morning. Just one more follow up on the commercialization of the Sabine Pass expansion. Anatol, can you give some color on how much of a disadvantage it is to not have the FERC approval in hand when you're out trying to commercialize versus all these other approved but untested operators in the market today? Maybe it doesn't matter because Cheniere's reputation is so strong, but just wondering.
What you said, Jean Ann, so we -- very fair question. And we've thought about a lot, as you know, and we've discussed over the years what that opportunity could potentially buy us. And as you saw last year, as we were commercializing Corpus Stage 3, we ended up commercializing things that were well beyond Stage 3 and are sitting in an enviable position of having that portfolio of offtake in hand with almost 3 million tons at our option to convert to SPA. So it's great to have this maps and renderings, of course help, but as you said, that reputation and what the Cheniere platform has armed us with on the commercial side is that great track record and execution that really is unmatched in the LNG market. So it's great to have this in hand, but it is not, we don't see it as a disadvantage that don't have the full 20 million tons approved today.
Great. Thank you. And can you kind of discuss the pros and cons that you weighed in your decision to return to full size trains for your next project rather than mid-scale?
Yes. So, Jean Ann, now we have all the tools in our toolkit. And when we looked at Sabine Pass and looked at potential different power solutions, the most economical trains there are the large scale ConocoPhillips trains versus the smaller midscale units. And as you know, when you look at your life cycle analysis from start to finish, you have to consider what the power mix is and could be. And unfortunately, at Sabine Pass, the power would come from Texas, which is, as you know, a predominantly coal fired power generation most of the year. And that's not , that’s more, not quite as clean on a life cycle analysis as having gas fired turbines do the compression for us there. So that's what led to our decision on larger trains. It just made sense for Sabine.
And we'll take our next question from the line of Spiro Dounis with Citi.
Thanks. Operator. Good morning, team. First question is just on EPC costs, seen escalation, I guess, abroad, just given all the inflation, seeing labor shortages as well lingering theme here and really across the rest of energy. Historically, you and B Bechtel have a great track record there, managing costs and timelines. So just curious, as you guys think about those challenges on some of your upcoming projects. Are you balancing the ability to offer a competitive liquefaction fee while also maintaining your target returns on these future projects?
Now, look, we have a very strong relationship with Bechtel. It's been built over the last decade. They, with us, have gotten together. We've used limited notices to proceed. We've paid at risk money early to lock in materials and supplies, and we've been able to manage the inflation and escalation very effectively to meet our returns that we all have told you about in the past. So I would expect us to be able to do the same here. In regards to labor shortages, we haven't seen it. We alluded to the fact that Bechtel is ahead of schedule on Corpus Stage 3. It's my expectation that they continue to deliver well ahead of the guaranteed dates that are in the contract.
I'm witnessing it again as we look at Stage 3. So I think for the right employer for the right cost and Bechtel is a great employer on the Gulf Coast that they're able to attract and retain some very productive Gulf Coast workers.
Great. Second question is just on spot volumes. You put away quite a bit on that side since the last update, so I'm just curious if that level of activity has continued. And as you think about placing the remaining 50 TBtu open for spot, do you see value in waiting a little bit longer or just given some of those green shoots you mentioned? Or could we actually see you close out that remaining book even before the next earnings call?
Spiro, it's a great question and I have Corey Grindal, sitting next to me, Corey and the team. As you know, Corey is our new Chief Operating Officer as of this year, but prior to that, he was in London and Corey and the London team have done a great job at putting away some of these cargoes for us. I'll let Corey answer the question.
I think the simplest answer, Spiro, is we're going to have to wait on some of them because with our operational track record and the reputation that we try to keep, we're going to have to keep some behind for later in the year, possible activities like hurricanes, as well as we have some planned maintenance that we're going to do this summer that we've been very clear about, we keep some behind just in case our maintenance takes a little bit longer. So as we have opportunities and cargoes get firmed up, we'll continue to sell them. But what we've sold is pretty much all of our firm cargoes right now, and we'll just continue to place it throughout the year.
And I'll just add Spiro, as people think about the guidance and clearly people were pretty focused on how much did we proactively sell going into this call. The CMI team did an incredible job selling probably over $20 last year going into this year and still over $10 this year. And as you think about the $8 billion and $8.5 billion of EBITDA with only 50 TBtu really outstanding. That's priced right now on the curb sub $10 dollars. So it's less than a $0.5 billion in the whole grand scheme of things. So it just shows how locked in things are right now and I imagine Corey and the team will sell that as they can efficiently and we'll come up with a smaller number than 50 on the next call and the call after that.
We'll take our next question from the line of Sean Morgan with Evercore.
Hey, thanks guys for taking the question. So I think one thing that obviously the market's been a little bit surprised by the scale and scope of Sabine Pass and I think that's going to be a positive surprise as we kind of go through the next couple of weeks in terms of people sort of reevaluating CQP growth. But CQP has historically been very attuned to the investors. They're attuned to sort of the distribution. It looks like with the guidance now, you're basically maintaining most of this variable distribution component along with your sort of base distribution. So how do you sort of thinking about how you're balancing future CapEx to scope out and grow Sabine Pass with kind of the distribution mandate that you have?
Sure I mentioned it a little earlier on, but the fact that we came out last year with the base plus variable DPU was for this purpose to give us the flexibility at some point down the line, we can go back to the base distribution and decide how much is variable that we're willing to distribute out and hold on to the rest as we build accretive projects that clearly meet all our investment parameters. So right now we're talking about a four to $4 to $4.25 DPU for ‘23. Our base distribution is $3.10. So there's at least a $1 or so in there of variable distribution. And that's because look, we're not going to be spending all that much money on this project during development, maybe 100 plus million dollars. And if you count for a few hundred million dollars of debt pay down, yes, we can to pay over $4. But when it comes down to it, in a few years, say ‘25, ‘26, ‘27 timeframe, yes, we would ramp down that dollar of incremental variable distribution so that we could live within cash flows and just fund the project steadily over time with that cash flow and the debt.
Thanks, Jack. That's really helpful. And then on the expansion, I think this is going to be pretty exciting for LNG investors as well. Sort of puts that growth catalyst back on the table that's maybe been a little bit lacking since Stage 3 kind of went in everyone's model. So question on the existing CMI marketing agreement between SPL and CMI, will that be enforced for the 20 million Sabine Pass expansion as well? And sort of if that's the case, what are we looking at in terms of sort of incremental volumes to CMI on a run rate basis, that'd be like three to five Mtpa per year once it's sort of commercialized and done and dusted.
A few things there in that question, but the agreement between CMI and both projects are consistent, and it would be the same for the expansions at Sabine and the expansions at Corpus that would pay up to $3 to take the volumes around the world. So that's answer number one. And then the second question was how much volume this year? Yes, in terms of how much volume, we're going to stick to our parameters. We're not going to FID if we don't hold ourselves to the same parameters we've done in the past. So we're talking about 90% contracted when it's all done and dusted. Meaning that, yes, there's going to be a couple of million tons, two to three, let's say, of open capacity added to the CMI coffers to manage over time, but that's about it.
Okay, thanks. Obviously, we don't want to over promise, but future debottleneck is kind of where I was getting to that higher range. But understood that you guys don't like to over promise, so we'll just leave it at that.
And we'll take our next question from the line of John Mackay with Goldman Sachs.
Hey, thanks for the time. Maybe just thinking about the, I guess, new kind of boil-off unit proposed for this expansion and then also the CCS that you're going to tie into it. Is this -- are both of those options at Corpus on the existing footprint and kind of once the Stage 3 is online, or if not, maybe, why not maybe difference between two sites or something.
They are at Corpus. Corpus is a little bit different. It's not currently in our plans, neither the CCS or the boil-off gas unit right now. So it would require us to file with FERC and get approval for those. But we hope to get the technology down at Sabine, get comfortable with it, all aspects of it, and then roll it out to the rest of our facilities and Corpus would be our next choice.
Thanks for that. And you touched on this a little bit earlier, but just going back for getting all this gas to Sabine going to kind of require longer, higher pipeline access. Just are your customers and I know it's early days, but are your customers kind of looking at that, at your ability to secure that feed gas before they're willing to commit to it? Or is that track record kind of good enough there.
John, today we bought 7.5 Bcf from 70 different producers throughout all of North America, including Canada, and we delivered it to our facilities and it will be processed and loaded up on two tankers and shipped off. So this is a blip in the grand scheme of things. We, as you know, we're the largest purchaser of physical gas in the US and the largest holder of gas transport pipeline. We like touching all of the basins. Because we have to deliver the molecule, so you should expect us to come up with a creative solution.
And the last question comes from the line of Craig Shere with Tuohy Brothers.
Hi. Thanks for fitting me in. I just have one. As we think longer term about this one to one ratio for capital allocation, when you're an FID-ing projects at perhaps 3x EBITDA, which should be further balance sheet stabilizing, does that particularly if there are large projects, does that alter the longer term need for the one to one ratio?
Want to correct the 3x EBITDA first. Well, it is around 3x, give or take, when we can build on a CapEx to EBITDA at 6x, and we do 50:50. But again, that alone is, yes, going to be pretty helpful to delever the story over time as we get through construction. But mind you, construction is going to take four to five years where we're going to have the debt before the EBITDA shows up. So we're going to be pretty mindful of that, that we continue to look just as good on a Bloomberg screen as we do today as we build these projects. So the one to one is going to continue. Clearly, we need to catch up on the buyback over the coming quarters and year plus to get back to one to one. And then you could see us follow through with that cadence through that 2026 time frame that was the capital allocation guidance in September, and we'll go from there. But this way we can build these multibillion dollar projects accretively and still look pretty darn good on an LTM basis.
Got you. And I guess as a follow up, you mentioned, Zach, about four to five years. Given these are larger size trains than you've ever built before, even though it's brownfield. Can we see the first liquefaction and still under four years, or would it naturally take longer?
I would imagine the technology is the same, Craig, it's just a little bit bigger. So I would imagine that the ENC team can deliver like they have in the past and where the guarantee dates may be four years, the actual first LNG will be significantly faster than that.
And thank you, everybody. We appreciate all the support and we hope to see you all soon.
This concludes today's conference. Thank you for your participation. And you may now disconnect.