Good day and welcome to the Cheniere Energy Fourth Quarter and Full Year 2019 Earnings Call and Webcast. Today’s conference is being recorded. At this time, I’d like to turn the conference over to Randy Bhatia, VP of Investor Relations. Please go ahead.

Thanks operator, good morning everyone. And welcome to Cheniere’s fourth quarter and full year 2019 earnings conference call. The slide presentation and access to the webcast for today’s call are available at cheniere.com. Joining me today are Jack Fusco, Cheniere’s President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and Michael Wortley, Executive Vice President and CFO. Before we begin, I would like to remind all listeners that our remarks including answers to your questions may contain forward-looking statements, and actual results could differ materially from what is described in these statements. Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP financial measure can be found in the appendix of 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 Michael will review our financial results and guidance. After prepared remarks, we will open the call for Q&A. I will now turn the call over to Jack Fusco, Cheniere’s President and CEO.

Thank you, Randy, and good morning everyone. I’m pleased to be here today to review our results from 2019, a year marked with significant achievements in milestones across every phase of our business and operations, and to share my continued optimism at the opportunities ahead of us. Slide 5 shows key financial and operating highlights from the fourth quarter and full year 2019. I’d like to highlight a couple of key achievements here. In the fourth quarter of 2019, we generated consolidated adjusted EBITDA of $987 million, and distributable cash flow of approximately $270 million on revenue of just over $3 billion. We generated net income attributable to common stockholders of $939 million, which benefited from the release of a significant portion of the valuation allowance previously recorded against our deferred tax assets. Operationally, we produced and exported a record 130 cargoes during the quarter, for almost 1.5 LNG cargoes per day across our two facilities. For full year 2019, we generated net income of $648 million, consolidated adjusted EBITDA of $2.95 billion, and distributable cash flow of approximately $780 million on revenue of $9.7 billion. We produced and exported over 1.5 quadrillion Btus of LNG from Sabine Pass and Corpus Christi and delivered financial results within the guidance ranges we provided for the year. Our vision is to provide clean, secure, and affordable energy to the world. In 2020, we’re off to a great start, as we recently celebrated the production of our 1000th LNG cargo. Cheniere employees worldwide commemorated this landmark operating milestone, which we achieve faster than any other LNG producer in history. As we look ahead to the balance of 2020 short-term market headwinds notwithstanding, today we are reconfirming our full year guidance, a $3.8 billion to $4.1 billion of consolidated adjusted EBITDA and distributable cash flow of $1 billion to $1.3 billion. Turn now to Slide 6. 2019 was an extraordinary year filled with accomplishments that helped to elevate Cheniere as the standard against which other operating companies in this industry will be measured. I want to leave some time for Q&A. So I can’t go through everything we accomplished in 2019, but I’ll touch on a few of the most impactful achievements. In 2019, we placed three trains into service, all on budget and on an average of nine months ahead of schedule. There have been many examples of Cheniere developing and reinforcing our reputation for excellence in execution, but this may be the most notable one yet. This unprecedented results would not have been possible without the focus we have on execution for all phases of our projects in the application of that focus in our relationships with our EPC partner, Bechtel; and our technology providers, ConocoPhillips and Baker Hughes. In addition to completing new trains, we onboarded seven long-term customers in 2019, the most recent of which were related to the contracts associated with Train 5 at Sabine Pass, which commenced in September. Through year-end 2019, we had onboarded 13 of our long-term creditworthy customers. And in 2020, we expect to onboard several more including those with contracts associated with Train 2 at Corpus Christi, which are expected to commence in May. Continuing with the execution theme, in 2019, we successfully executed two major turnarounds at SPL. These turnarounds involved over 500,000 man hours and were completed on time, within budget and most importantly safely. In securing our growth, during 2019, we made a positive FID on Train 6 at Sabine Pass, our ninth liquefaction train, and achieved significant project milestones related to Corpus Christi Stage 3. The addition of our ninth train, coupled with increased run rate production guidance resulted in an increase in our run rate consolidated adjusted EBITDA guidance to $5.2 billion to $5.6 billion. At Corpus Christi, we continue to leverage our platform and site location to deliver innovative solutions signing our first ever integrated production marketing transactions with two domestic gas producers. These commercially innovative agreements enabled domestic producers to access international prices for their gas, while providing Cheniere with gas supply visibility and additional long-term investment-grade take-or-pay style cash flows, which will help support our future expansion. In late 2019, Corpus Christi Stage 3 cleared a major regulatory hurdle when the project received FERC authorization. We expect to finalize EPC contracting with Bechtel for Stage 3 in the near future and are pursuing the additional commercial support required in order for us to FID. And finally, one of our key priorities entering 2019 was to deliver a comprehensive capital allocation plan, which we did in June. That plan prioritizes accretive growth projects, puts the company on a path to enterprise-wide investment-grade metrics and allocate excess capital in a flexible responsible way. And Michael will give you an update on the progress we’ve made in his comments in a few minutes. Now, turn to Slide 7, where I will spend a few minutes on our sustainability and ESG efforts. ESG is a topic of growing importance among our stakeholders including investors, lenders, advisers, rating agencies, operating partners, employees, and many others. The primary focus of our stakeholders is on the E, as there is an increasing call for energy infrastructure companies to demonstrate their businesses done in a responsible, environmentally conscious manner. Cheniere’s business certainly is, and you’ll hear from us telling our positive ESG story more vocally starting this year. Cheniere is on the right side of the discussion around the environment, as one of the most impactful ways to reduce greenhouse gas emissions worldwide is through coal-to-gas switching for power generation, especially in large emerging markets like China and India, where small percentage changes in energy consumption can make a significant difference and total carbon emissions. As one of the largest operators of liquefaction capacity worldwide, Cheniere is a leading global enabler of the transition to a sustainable lower carbon future to put the environmental benefits of LNG into perspective. As I mentioned a moment ago, we recently celebrated our 1000th LNG cargo. If all 1000 LNG cargoes had been utilized for gas-fired power generation in place of coal, it would equate to a reduction of an estimated over 200 million metric tons of CO2 emissions. We have made significant investments in resources focused exclusively on our ESG effort, which supported the executive leadership team and our Board of Directors, we adopted our climate and sustainability principles as part of our long-term sustainability strategy. Our principles, science, transparency, operational excellence and supply chain guide our sustainability efforts and help reinforce the strength of our business model in a new energy economy with natural gas leading a lower carbon energy transition. Our climate and sustainability team is leading the development of our inaugural corporate responsibility report, which we expect to publish in the next few months. This report, which is a cross functional effort involving the input and coordination from across the Cheniere workforce will cover six themes and approximately 70 key disclosures. We intend to update this report annually and it will serve as a cornerstone of our ESG related disclosures. Before turning the call over to Anatol who will discuss the LNG market in more detail. I would like to say a few words regarding current LNG market dynamics as there is obviously some weakness, which has been caused and compounded by a number of factors including weather, supply additions and more recently the public health situation in China and this has been a focal point in our investor discussion over the past few months. Due to the highly contracted nature of our liquefaction projects, volatility in the short-term LNG market has limited impact on our business. This is especially true in 2020, we have presold over 95% of the expected production, thereby limiting our exposure in short-term market prices. This company is designed to build highly contracted long list infrastructure that enables us to deliver long-term energy solutions to customers worldwide, not to be overly exposed to the short-term markets. Our business model, it’s not based on speculating on global commodity markets, rather on our risk management framework that is positioned Cheniere such that short-term market volatility has limited impact to our economics. We do not view our marketing volumes as speculative. We view it as strategic to our long-term growth. Cheniere is an infrastructure business that succeeds in growth with excellent and project development and operations, and with contracted project returns secured prior to construction. The fundamentals of our long-term business remain extremely strong. From 2016 when I joined Cheniere through the end of 2019, the LNG market demand has grown by about 100 million tons. That demand is forecast to grow another 100 million tons by 2025, and a further 100 million tons by 2030. But this growth will be cyclical as a necessary infrastructure is required to be built. The LNG market is a dynamic one, undergoing significant growth and evolution and Cheniere is ideally positioned the leverage our world-class platform to enable growth at very attractive returns as well as manage the volatility that may appear in the short-term market from time to time. But that being said, we find ourselves in a unique time in the LNG market, and we do acknowledge market headwinds and our customers’ needs. Well LNG market prices are at a historic lows, don’t have a material impact on our short-term economics, it can impact long-term project development and long-term customer urgency. Also, well, the Phase 1 trade agreement with China, it’s subsequent opportunity for short-term LNG tariff waivers are positive steps. We await clarity on implementation and enforcement, especially in light of the coronavirus and what impact that may have on our Chinese foreign trade in the near-term. And now, I’ll turn the call over to Anatol, who will give additional insight on the market.

Thanks, Jack, and good morning everyone. Please turn to Slide 10. Over 24 million tons per annum of new LNG capacity came into service in 2019 globally adding to the over 40 mtpa that came online in 2018. This newly operational capacity resulted in nearly 40 million tons of incremental LNG in the market in 2019 as compared to 2018, which is roughly on par with the industry’s previous largest single year growth recorded in 2010. The significant increase in LNG supply occurred not only amid warmer-than-normal weather across most of the LNG importing world, but also amid some growing concern about economic growth in Asia’s key economies and ongoing trade discussions. In addition, increased nuclear availability with an Asia’s key LNG importers contributed further downward pressure on total gas and LNG demand. The combination of warm weather, economic concerns and competing fuel factors resulted in lower than expected LNG growth in Asia, which increased less than 7 million tons in 2019. Europe has continued the market balancing role it has played since the second half of 2018. Europe absorbed most of the incremental LNG supply in 2019 for the majority of incremental volumes going to the continent’s most liquid markets in the Northwest and to the Iberian market. Soft market conditions persisted into the fourth quarter and led to record levels of destination flexible U.S. LNG flowing to Europe. U.S. LNG flows to Europe in the fourth quarter were almost 6 million tons more than twice the previous peak in the first quarter of 2019 and approximately half of all U.S. LNG volumes in the fourth quarter flowed to Europe. Strong inflows of LNG meant that gas prices in Europe remained muted and well below the same period in 2018. TTF dropped to an average of just under $4.50 in MMBtu fourth quarter versus over $8.50 in the fourth quarter of 2018. Similarly, JKM prices for LNG and Asia decreased an average of $5.50 MMBtu in fourth quarter 2019 versus $10.70 in the previous year. The strong supply growth, warm weather and slowing economic growth that we saw in the fourth quarter of 2019 have continued into early 2020 and have recently been compounded by the impact of the novel coronavirus outbreak. since the start of 2020, we’ve seen JKM spot prices decreased by approximately 50% with prices for March falling below the previous record low of $3.65 recorded in may of 2009. What’s currently too early to gauge the potential impact of the coronavirus on the near-term market balance decreased short-term LNG demand in China is putting additional pressure on a market still working to absorb the wave of incremental supply into the market over the past two years. I’ll speak more about our 2020 outlook in a few moments. Please turn to Slide 11 for additional details regarding LNG demand in Asia. As I mentioned a moment ago, Asia saw only modest demand growth in 2019. overall, Asia’s LNG demand grew roughly 3% in 2019, gaining approximately 7 million tons well below the growth figures seen in the previous two years. Weaker total electricity demand and stronger nuclear availability in 2019 in Japan, South Korea and Taiwan, the JKT region, placed downward pressure on thermal generation in that region, particularly on gas-fired power. nuclear generation in the JKT region increased by nearly 20% year-on-year in 2019 while LNG demand in these markets dropped by over 7% or approximately 10 million tons. JKT LNG imports as a percentage of overall Asian LNG demand has continued to decrease, falling by 6% over the past year to 54%. growth markets in South and Southeast Asia compensated for most of the market share loss by JKT, with the regions representing about a fifth or 21% of total Asian LNG demand in 2019. LNG imports into the region surpassed 50 million tons in aggregate, increasing by about 22% or over 9 million tons year-on-year, all but one market, India, within the South and Southeast Asian region, registered double-digit growth rates in 2019. A rising supply-demand gap, depleting domestic reserves, rapid infrastructure build-out and emerging price-sensitive buyers all help provide support to LNG demand in the South and Southeast Asian regions. As you can see on the top right as LNG spot prices dropped in the second and third quarters of 2019, imports in South and Southeast Asia hit new seasonal highs as a result of improved LNG affordability. in China, slower economic growth and higher year-on-year domestic gas production in 2019 reduced the growth rate of LNG imports to 14% compared to 41% in 2018. piped gas imports into China were flat compared to 2018 while LNG imports continued to expand, albeit at a slower pace. LNG imports into the country reached 62.5 million tons in 2019, adding nearly 8 million tons year-on-year. market sentiment in China was lifted at the beginning of this year as a result of improved economic indicators and the phase 1 trade deal reached in mid-January. The recent actions by China’s ministry of finance to provide short-term exemptions to the tariffs on U.S. LNG is also a positive step. That being said, we await clarity on the impact of coronavirus on Chinese economic and foreign trade priorities. While the impact of the outbreak on China’s economic growth is uncertain, we she potential for Chinese gas demand to decrease in the near-term, followed by a rebound with the resumption of normal industrial activity and as a result of stimulus measures already being implemented by the Chinese government. Longer-term, we believe that the U.S. and China are natural partners on energy trade and are hopeful that the tariffs can be removed permanently to facilitate new long-term agreements. for Asia overall despite near-term challenges, we remain optimistic about long-term gas and LNG demand growth underpinned by growing economies, rising prosperity, a drive toward policies for cleaner air and better energy access, and a growing focus on sustainability within its energy mix. Please turn to Slide 12. European LNG import levels continue to increase in the fourth quarter despite record seasonal amounts of volume in underground storage. Imports reached a record 9.5 million tons or more than 145 cargoes of LNG in December. European imports for the total year grew by 74% surpassing 87 million tons and exceeding the previous records of 67 million tons, set in both 2010 and 2011. the incremental LNG flows into Europe were enabled by a combination of additional gas being placed into underground storage, coal-to-gas switching and a reduction in other gas supply sources. Preliminary estimates suggest that a production decline in the Netherlands of about 6 Bcm and a drop in pipe gas supplies of a combined 19 Bcm helped accommodate approximately 50% of the increased LNG receipts. The push of LNG into the European market and resulting drop in spot gas prices and tight gas burn in power generation, an important factor that helped balance the market and that we believe will continue to be important in the European power market over the medium-term. gas-fired power generation in the EU increased by 12% in 2019 while coal-fired power generation decreased by 24%. this trend alongside strong renewable generation resulted in a 12% reduction in carbon dioxide emissions from the power sector in 2019, a reduction of 120 million tons year-on-year. We believe the decline in indigenous gas production and the commitment to environmental targets are structural elements that will likely provide upside European gas demand and thus LNG imports in the near to medium-term. In the next few years, Europe plans closure of over 44 gigawatts of coal capacity and almost 18 gigawatts of nuclear capacity. in Germany alone, 11 gigawatts of nuclear and lignite capacity has been scheduled to close by 2022. We expect these closures to increase gas demand in the power stack in Europe and drive LNG demand growth during that period. To put it in context, if all of this solid fuel capacity were to be replaced with gas-fired generation, it could be equivalent to approximately 40 million tons per annum of potential LNG demand. As Jack mentioned, we have received an increasing number of questions regarding short-term LNG market pricing and supply demand balancing dynamics, particularly given the warmer than average winter weather, additional LNG supplies scheduled to come online in the first half of the year and the recent near-term market uncertainty in China. While much attention is given to the possibility of supply curtailments particularly in the U.S., there are a number of factors, which could help balance the market including price-elastic demand response, weather, maintenance intervals, and changes in supply levels of competing fuels and sources of gas. While we acknowledge that some LNG on the margin may not be listed from the U.S. this year, we do not view significant or prolonged curtailment of U.S. LNG production as a likely scenario. Thank you for your time and attention. I will now turn the call over to Michael, who will review our financial results.

Thanks, Anatol and good morning everyone. Turning to Slide 14 for the fourth quarter, we generated net income of $939 million, consolidated adjusted EBITDA of $987 million and distributable cash flow of approximately $270 million. For the full year, we generated net income of $648 million, consolidated adjusted EBITDA of $2.95 billion and distributable cash flow of approximately $780 million. as Jack mentioned, both consolidated adjusted EBITDA and distributable cash flow were within our full-year guidance ranges. during the fourth quarter, net income was positively impacted by releasing a significant portion, $542 million, of the valuation allowance we previously recorded against our deferred tax assets resulting in a tax benefit of $517 million for the fourth quarter and full year 2019. We exported 462 TBtu of LNG from our liquefaction projects during the fourth quarter, an increase of 79 TBtu or 21% over the third quarter, primarily due to a full quarter of volumes from Corpus Christi Train 2, which was placed into service in late August and higher seasonal production at Sabine Pass. for the full year, we exported over 1,500 TBtu or approximately 29 million tons of LNG from Sabine pass and Corpus Christi. For the fourth quarter, we recognized an income 460 TBtu of LNG produced at our liquefaction projects and 9 TBtu of LNG sourced from third parties. For the full year, we recognized an income 1,458 TBtu of LNG produced at our liquefaction projects and 40 TBtu of LNG sourced from third parties. Approximately 72% of the 469 TBtu recognized an income during the fourth quarter was sold under long-term agreements and the remaining 28% was sold by our marketing affiliate either into the spot market or under short and medium-term contracts. Volume sold under long-term agreement increased by 73 TBtu compared to the third quarter, driven primarily by full quarter of volumes under the SPAs related to Sabine pass train 5, which reached DFCD in September. For the full year, 71% of the volumes recognized an income, were sold under long-term agreements. For the full year, 51 TBtu of commissioning related volumes from our liquefaction projects were recognized on our balance sheet as an offset of $301 million to LNG terminal construction and process. No commissioning volumes were exported or recognized in the fourth quarter. Income from operations in the fourth quarter was approximately $1 billion, an increase of over $700 million compared to the third quarter. The increase in income from operations was primarily due to increased total margins, partially offset by an increase in total operating costs and expenses primarily related to a full quarter’s impact of Corpus Christi Train 2. Total margins or revenues less cost of sales increased by almost $800 million in the fourth quarter, that’s compared to the third quarter due to increased volumes of LNG recognized in income, increased margins per MMBtu of LNG recognized in income and net mark-to-market gains from changes in fair value of commodity and FX derivatives, primarily related to agreements for the future purchase of natural gas and future sale of LNG. income from operations for full year of 2019 was approximately $2.4 billion, an increase of over $300 million compared to 2018, driven primarily by increased volumes of LNG recognized in income as a result of additional trains in operation and net mark-to-market gains from changes in fair value of commodity derivatives partially offset by decreased margins per MMBtu of LNG recognized in income and increased operating costs and expenses as a result of additional trains in operation, and certain maintenance and related activities at the SPL project. Net income attributable to common stock holders for the fourth quarter was $939 million, or $3.70 per share basic and $3.34 per share diluted, compared to a net loss of $318 million or $1.25 per share and basic and diluted for the third quarter. The increase in net income was driven primarily by increased income from operations, the tax valuation allowance release mentioned previously. net gains related interest rate derivatives and increased other income partially offset by increased interest expense and increased net income attributable to non-controlling interest. Net income attributable to non-controlling interest increased due to an increase in net income recognized by CQP, in which the non-controlling interests are held. For the full year of 2019, we generated net income attributable to common stockholders of $648 million, or $2.53 per share basic and $2.51 per share diluted, compared to $471 million or a $1.92 per share basic and a $1.90 per share diluted for the full year 2018. the increase in net income was driven primarily by increased income from operations, the tax valuation allowance release and decreased net income attributable to non-controlling interest, partially offset by increased interest expense, increased net loss related to interest rate derivatives and increased other expense primarily related to an impairment of our equity method investments in midship. Finally, in support of our capital allocation framework, for full year 2019, we repurchased an aggregate of 4 million shares of our common stock for a total of $249 million under our share repurchase program and prepaid $153 million of outstanding borrowings under the corpus credit facility. Please turn to slide 15 for our 2020 financial outlook. As Jack mentioned today, we are reconfirming our full-year 2020 guidance ranges for consolidated adjusted EBITDA $3.8 billion to $4.1 billion, distributable cash flow of $1 billion to $1.3 billion and a CQP distribution of $2.55 to $2.65 per unit. However, given the drop in LNG market prices since our Q3 call in November, we’re currently tracking to the lower end of EBITDA guidance range. On that call, we noted that we had sold approximately 95% of our production for 2020, leaving us with full year EBITDA variability of approximately a $100 million for every $1 change in market margin. We’ve continued to sell forward marketing volumes into the physical and financial markets and today, that EBITDA variability is approximately $80 million or a $1 change in market margin. given the limited amount of volumes, which were unfold for the remainder of 2020 relative to our forecast total production for the year, we remain confident in the guidance ranges despite the soft short-term LNG market environment. The take-or-pay nature of our long-term contracts along with the sale of a significant portion of marketing volumes for the year leaves limited risk to the achievement of results within our guidance ranges even if a scenario with decreased LNG liftings were to occur. With respect to the Corpus Christi holdco converts, we have entered into an agreement with EIG to redeem $300 million of the outstanding balance of the Corpus Christi holdco convertible notes due 2025 for cash. The outcome of this transaction is reduction of notional debt and the prevention of over 6 million shares of equity dilution. Pro forma for this transaction, there will be approximately 1.3 billion of the CCH holdco convertible notes outstanding and we will be prudent in managing the balance of these notes. We maintain the option to utilize cash to further reduce the outstanding balances of the notes over the next months. Turning now to Slide 16. As we progress toward a positive FID for Corpus Christi Stage 3, we also remain dedicated to capital discipline and to the capital allocation priorities we announced last year. We will remain disciplined in our investment decisions and are focused on securing sufficient long-term fixed fee cash flow to support our required returns and the approximately $1 billion incremental EBITDA contribution Stage 3 can provide, which we showed you last June. The investment parameters we have previously shared with you have not changed regarding our approach to Stage 3 or any future growth projects. We’re targeting a 2020 FID of Stage 3 based on the commercial opportunity set Anatol’s team is pursuing, but we will remain disciplined and not move forward with the project until we have sufficient commercial support to meet or exceed our investment parameters. Any potential shift in the timing of the Stage 3 FID would impact the amount of cash we could apply to our other capital allocation priorities, achieving investment-grade credit ratings across our corporate structure by reducing leverage to a target consolidated debt-to-EBITDA in the mid to high four times range and returning excess capital to our shareholders via our buyback program. 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.

Thank you. [Operator Instructions] And our first question will come from Spiro Dounis with credit Suisse. Hey everyone.

Hey, everyone. Good morning. It’s John Mackay on for Spiro. Just wanted to start with a macro question. Like we knew 2020 was going to be hard, coronavirus has kind of made it little worse. But I'm wondering if you could talk a little bit about whether you're seeing a pickup in demand elsewhere outside of China, given the low pricing? And maybe whether that could drive a faster snapback once we see a recovery?

All right. Thanks, John. Anatol, you want to take that one?

Thanks, John. Good morning. Thanks, Jack. Yes. We certainly are. So, the main price-elastic demand we saw in 2019, as we discussed, was Europe, Northwest and Iberian Peninsula. We're continuing to see that, continuing to see further penetration of gas into those markets. And again, we think a lot of that is structural. But we're also seeing other tiers of response. One of the more active markets over the last couple of months has been India, has shown very good appetite at these price levels. And yes, you can say, hey, these are levels which demand is stimulated, but again, I would say that all of this builds an amount of muscle memory that will create structural demand that we don't think will be transient. And then you're seeing some very interesting responses, especially in Southeast Asia, where you're seeing active decisions to curtail domestic production and import LNG at the margin. So, you're seeing a lot of the issues that we've kind of anticipated, especially in these, what we call, displacement markets where you have good regional gas economies with challenging domestic production profiles perhaps shifting and increasing LNG imports more rapidly now that the price signal is in place. So yes, there's certainly a lot of room for optimism.

All right, that’s great. Thanks. And then switching gears quickly. On the EIG, and it's repurchase coming in March, does that take away from maybe buyback capacity you are thinking about in 2020? Or are those two separate conversations for you?

Hey, it’s Michael. Yes. I mean you can – we calculate total liquidity for the year, and this would come out of that. We've said we're going to pay down debt and buy back stock, and this really accomplishes both of those things for us. So, it doesn't count against our $1 billion authorization, but it certainly draws down some of our liquidity.

All right. Thanks a lot.

Our next question will come from Michael Lapides with Goldman Sachs.

Hey, guys. Just curious, this may be an Anatol question. How are you thinking about when the LNG market globally comes back into balance? Meaning, some folks think that starts to happen in about 2023, other folks are looking at it saying it's beyond 2025. Just curious for your macro view. And then tie that to, if I think about your nine train run rate assumption, what's embedded for kind of the commodity margin on contracted sales for the nine train run rate?

Thanks, Michael. Yes. I – so as Jack mentioned in his remarks, the LNG market has experienced very healthy growth, ballpark doubling every decade. We're at 400 million tons. And nobody, not even us with relatively optimistic outlook, have a doubling over the coming decade, which may prove conservative. Whatever the case is, we know that supply – this supply wave is over now effectively. We have a couple of more trains out of the U.S. left to come on. And then in 2021, 2022, 2023, the amount of volume coming into the market is less per annum than it has been per quarter since late 2018. So we're in the camp that the market will rebalance much sooner than that. Then once you get to the back half of this decade, you will have the result of the FIDs that we saw last year and expect to see this year. So you will have another supply wave. But we think this very much rhymes with what we saw in the 2010, 2011 period, where you had the big Qatari push of supply, coupled with financial crisis and U.S. shale production, you kind of have the same triple whammy playing out now with U.S. and Australian supply wave, two winters that didn't exhibit strong demand, and of course, coronavirus adding on top of that. But we think today, the market is, let’s say, imbalance by single-digit millions of tons per annum run rate. So in a 400 million ton market, that’s a pretty small number, and we think that to the previous question, as we see the supply met with incremental demand functions globally, there’s, again, very good reason to be optimistic over the next six to 12 months. In terms of the assumptions in run rate, once we get up to the 85% contracted, nine train case, we have $2.50 as the assumption for the CMI piece.

Got it. And so is that assumption, how you think the futures market will come back into some sort of balance by the time – and I recognize this is multiple years out. It’s 2023 and beyond. Is that assumption is that spreads will widen relative to what the 12 or 24-month kind of futures curve implies?

Well, again, by definition, the answer is yes. I would just like to point out that in late 2018, the forward market, to the extent that there was liquidity sort of three, four years out, was pricing in the mid $3 range. So these things change, as you know, relatively rapidly certainly for the short to medium-term portion of the curve.

Got it. Thanks guys. Much appreciated.

Thanks, Michael.

Next question will come from Jeremy Tonet with JPMorgan.

Hi, good morning. Just wanted to come back to Corpus Christi Stage 3 here and as that relates to your capital allocation framework. You’ve said growth comes first in the past, but just wondering if it makes sense to kind of delay a decision here, given where the share price trades right now and maybe allocate a little bit more incremental capital towards buybacks as opposed to CapEx there? Just wondering if anything on the margin has changed there, if you could share with us.

Yes. Thanks, Jeremy. So just on Stage 3, as Michael said in his comments, that it’s our intent, and it always has been, to make sure that we fully meet our investment criteria before we go forward with FID. So that – the implication there is that we continue to get long-term contracts to support the investment in that facility. I do think that market, because of a whole host of issues that Anatol mentioned, whether it be the coronavirus or a warm winter, the whole sense of urgency from the customers who signed long-term contracts has dropped. And so I do think that market will be tougher for us to go – to continue to get our fair share of those contracts and be able to commercialize Stage 3 at this point. But our capital allocation framework is not based off of Stage 3 per se. It’s based off of our available liquidity and what we feel comfortable putting to work at any given time. So it’s a living active allocation. So you should expect us to modify that as we see the market either get faster or slower on the long-term contracts.

Got it. That’s helpful. Thank you. And just want to touch on the topic of potential cancellations here, if I could, real quick. And if there were to be cancellations, would that be something you might let the market know in advance without identifying the customer? And just if you could walk us through kind of the mechanics of how much notice they have to give you and how you handle that, that would all be helpful.

Yes. So it’s not our intent. First off, the beauty of U.S. LNG is the fact that we give our customers a lot of optionality. So they have the option to pick up their LNG FOB at our docks and deliver it anywhere in the world. No other place is like that other than the U.S. The other aspect of it is we do allow our customers to cancel physical cargoes after they have been ADP’ed and scheduled with appropriate notice. The notice ranges somewhere between 40 and 70 days. We always say 60 days because that’s kind of the average notice. And it will not be our practice to describe to the market what our customers’ books are or what individual customers are thinking. Having said that, there’s been a lot of debate and conversation in the media lately on customer cancellations. So I’ll tell you this one time that we had two customers elect to cancel one cargo each, one cargo from Sabine Pass and one cargo from Corpus Christi in the month of April. So out of the 40 cargoes that we are forecast to produce, it’s a pretty insignificant number. That gives us a great option for CMI. If CMI elects to sell the physical cargo back into the market and also they have to pay our fixed fees, the customers. So – but that’s the magnitude of it, Jeremy.

That’s helpful. Thank you.

Next question will come from Michael Webber with Webber Research.

Hi good morning, guys. How are you?

Good, Michael. How are you?

Good. A lot of macro headwinds right now. And obviously, the fact that you’re able to reiterate your guide and kind of have a stable and, frankly, boring results kind of stands out in a pretty positive way right now. But I do want to follow-up on the last question around customer cancellations. And specifically, maybe a question for Anatol, but – when that happens and the notion of retrading that cargo back into the market, is that – how does that slide in with the rest of the uncommitted capacity at CMI? Because you’ve got a captive freight book, your variable costs there are just going to be forward costs and maybe some ancillary fuel or demurrage if you’re going to use floating stores for it. And the margin there into Europe would still be about $1 on those costs right now. So it’d still be wide open. I’m just curious, where does that cargo then slide in relative to the rest of your CMI book, if it does get – if a customer chooses not to lift it?

Thanks Michael. Yes. So as Jack said, it is at our option. Clearly, these are cargoes. As you know, CMI plans on lifting its share, which was substantially higher before the DFCD of May 1 for the Corpus Christi Train 2 contracts. And there is some ability to lift those additional volumes, which would be additional volumes for CMI, sort of, a free option, if you will, if the stars align. But you’re absolutely right. The stars aligning means that we need to have shipping in place, and we need to have the ability to take that to market profitably considering the full range of costs and margins that we would incur upstream of the plant and downstream of the plant. So that’s the option that we now have for, as Jack said, those two additional cargoes. And when the time comes, we’ll see if we can make a little bit more money on it. But in the grand scheme of things, it will not be a needle mover.

Fair enough. Maybe just a bigger picture question on that kind of business. When we look at – 95% of 2020 is already booked up. Can you give us some sense of what 2021 and 2022 look like right now? I know that math is a little bit fuzzy because your denominator is going to be moving around a little bit. But how you think about adding coverage to that 2021 and 2022 number? And then maybe specifically, Anatol, to go back to the demand response answer you gave a bit earlier. What kind of demand response are you seeing right now to low commodity prices? I would imagine you see immediate cargoes kind of evaporate, but you – interested in 18 to 24 months commitments for recaptured, maybe even two peak seasons, would ratchet up? So it maybe kind of speaks to what that CMI backlog looks like for 2021 and 2022, if it’s kind of intermediate term business. So just curious how you think about covering 2021 and 2022, where they stand and what that business will probably look like?

So Michael, it’s Jack. So I’ll start off. So in February of 2020, we’re not willing to give guidance for 2021 or 2022. So, I appreciate your long-term view of our markets and our business. But you’re probably an outlier as far as that’s concerned. But you all will have to wait for our financial guidance in November of 2020. Hopefully, you see from our actions, not necessarily our words, that we tend to try to underpromise and overdeliver, and we’re very conservative on how we run our book. So with that context in mind, see if Anatol has anything he wants to add.

As Jack said, boring is beautiful, and we are, as you would expect, managing those 2021 and 2022 exposures. The issue, as you well know, the single biggest factor for 2021 is the timing of Corpus Christi Train 3, which is, we said, first half of 2020 business, but as that moves around by months here and there, that will add or take away volumes, which are difficult to manage. But as you also know margins for 2021 and 2022 are much healthier than they are currently, so we are prudently engaged on that front but won’t give you any specifics until later this year.

Just maybe thinking, from an industry perspective, any particular wrinkles you’re seeing from like early in terms of the demand response, maybe kind of people – any interesting wrinkles in terms of the term you think you’ll look for?

Well, I think it’s very positive when you read that India has lowered what they’re going to charge at their city gate for natural gas at the city gate. You saw the same demand response at China, where they’re going to lower what they charge their industrial customers at the city gate. Those were all very, very positive. So unlike the U.S. and the UK, which those price signals happen daily, in China and India and most of the south – most of Asia, it happens every six months. So those are really positive signs. And hopefully, that will create more demand product.

Yes, bit of a lag on it. No, that’s helpful. I appreciate the time, guys.

[Operator Instructions] Next, we’ll hear from Shneur Gershuni with UBS.

Hi, good morning, everyone. I recognize that the virus is sort of overshadowing the progress that’s been made in the U.S.-China trade dispute. But I was wondering sort of given the macro backdrop, how do you think about weighing the return profile of FID in CCL Stage 3, going for a faster FID versus delaying an FID, sort of, do you look at trading returns? Do you lower your return profile to accelerate an FID versus delaying it and getting the benefits of deleveraging? Just kind of wondering how you sort of think about that interplay, just sort of given the current macro environment?

So first, just to be clear, right, we would not FID until we got enough commercial contracts to support a bank financing to make that investment in that facility. So just – because the implication that we’re going to accelerate it, I don’t quite understand it. So I just want to make sure that we’re all clear on that aspect of it. But Michael, do you want to?

No, I mean, I don’t have much of saying there. If it meets our hurdles that we reiterated today, it’s a great project. Given where the stock is and all of that, I mean, I think we would try and FID it as late as possible and just give us – free up as much interim cash flow to kind of take advantage of the situation today. Every – I think every six months or so that it’s delayed, it frees up $0.5 billion. So – I mean the ideal scenario for us is to commercialize it, but build it as late in the schedule as we can while maintaining our EPC contract and our cost certainty and all of that. So certainly, it has an effect on how quick we move.

Okay. So that makes total sense. So there would be no changing in your hurdle rate to achieve the contract. Okay. Maybe as a quick follow-up here. I was just wondering if you can talk about force majeure process. Are there any scenarios where a customer can claim a force majeure? I realize you couldn’t claim force majeure because of operational issues at your own facility, but is there a scenario where a customer can claim a force majeure of say storages while in their home markets? Or can we assume, generally speaking, you’re pretty insulated from attempts by customers to force majeure?

No. I mean from – in regards to force majeure, right, it’s very, very difficult for a customer to claim force majeure on an FOB product, right, because they’re picking it up from the dock and they can send it wherever they want to send it to the world. So even if they’re full, they still don’t have a force majeure event against lifting at one of our facilities. I don’t know if Michael or Anatol have anything to add.

The contracts are clear. You can read them. They’re on file. It’s really – if the customer has an issue on an FOB deal with a very specific ship coming in, that’s really was the only window for force majeure. But no other facility in the world, apart from SPL or CCL, as the case may be, can cause FM to be invoked on FOB contracts.

And just to add to what Jack said. The FM in the LNG business is a very serious event that is not entered into lately. You don’t see many of them declared. And as you know, through all of the issues that Cheniere has faced whether it was freeze-offs or fog events, et cetera, we have not missed the foundation customer cargo. So it is a very serious issue, unlike in, I think, a fair amount of North American businesses, FM is invoked relatively frequently as an operational management issue, that is really not a feature of the global LNG market.

Okay. So if I can recap all of your responses here. So no change to hurdle rates, lot of deleveraging opportunity and low risk to a force majeure type of event. Is that a fair characterization?

No.

Yes, it is. Thank you very much.

Perfect. Thank you very much. Appreciate the color guys.

Our next question will come from Julien Dumoulin-Smith with Bank of America.

Hey, this is Anya filling in for Julien. So I guess, first question on 2020 EBITDA guidance. You revised the sensitivity to $80 million impact to EBITDA from $1 change in marketing margin. It was $100 million before. Can you talk about some of the other drivers for this change aside from selling forward marketing volumes as you just mentioned? And then, could you also discuss assumptions for pricing that are implied in guidance relative to what we’re seeing in the forwards today?

Sure. This is Michael. So yes, I mean what brought the sensitivity down significantly is just placing more physical business into the market, either prospectively – mostly prospectively, right? We’re only in February. So that brought it down. What brought it up is production crept up a little bit, our production forecast for the year. So that added to the variability. And then as margins went negative, inclusive of shipping, we lifted some hedges and redeployed that hedge capacity into 2021, where we see much fatter margins and opportunity to lock in. And so that affected the sensitivity a bit. But those are really the moving pieces of that number. In terms of implied – what margins are implied? I mean for CMI’s book, I guess, keep in mind, CMI has got a lot of term business in it now with the deals that’s done with Vitols and Trafis in early cargoes, so that term business is obviously well north of $2. But then the balance inclusive of hedging is still north of $1 in our book, just given how much we forward sold and how much financial hedges we had in place. So those are the assumptions there.

Okay. Thanks. And then second, you narrowed your estimate for – or it seems like you narrowed your estimate for contracted offtakes to 85% from the 80% to 95% range that you had before in the last update. Can you talk about some of the specifics that drove this change in guidance? And what gives you more confidence in that figure?

So Anya, thanks, this is Anatol. I wouldn’t characterize it that way. What we said, you’re probably referring to the K, is that we’re approximately 85% contracted. That’s on our existing platform. That is distinct from the issue that we’ve been discussing about the contractual support we would need incrementally to move forward with Corpus Stage 3. So we haven’t varied our principles on investment, whether that’s Shneur’s question on return hurdles, contracted volumes, the tenor over which we expect to get our capital out of the project, all that remains in place. But if you look at what we have contracted to date on the current nine train portfolio, that’s the approximately 85% number.

Yes. And I would just say one more thing that I’m extremely proud of Aaron Stephenson and the operating team because they continue to work on and deliver operational excellence, which some of that is going to be a little bit variable because our production numbers and our debottlenecking efforts have gone so well at our existing facilities.

Okay. Thanks a lot.

Our next question will come from Danilo Juvane with BMO Capital Markets.

Well, thanks and good morning. One quick one for me. To the extent that you are seeing margins sort of stand out for both 2020, 2021 and so forth, is there any way that you can perhaps increase your volumetric capacity to offset that margin squeeze going forward?

No. It’s Michael. I mean, as Jack just alluded to on Aaron’s performance, I mean the plants are scheduled to run full out and there’s no really turning them up. I mean our production plan is our production plan. Now we had a huge tailwind last year because we figured out some ways to debottleneck the facilities and our production came in much higher than we expected last year, which did make up for a lot of margin erosion that we saw last year. But probably not an opportunity for that magnitude of move this year, so we’ll see some – a little bit of production increase probably like we’ve already seen, but not a huge magnitude at this stage.

Great. That was my only question. Thank you.

Thank you.

Our next question will come from Craig Shere with Tuohy Brothers.

Good morning. Congratulations on the strong quarter. Michael, you mentioned $0.5 billion liquidity benefit for every half year delay in FID of Corpus Stage 3. Fully understand that the economics of the contracts applied to that project will dictate FID. But to the extent the upsized nine train portfolio can support the CMI contract signed, isn’t there some wiggle room on when to FID, even if the project could meet hurdle rates? And one final kind of question about liquidity kicker. Since your June 2019 guidance long-term run rate guidance, we now have the early completion of Corpus Christi Train 3 coming up. And I wonder if you can opine on how much flexibility that provides in the budget?

Well, we’re not putting that one in the bank just yet. But okay, yes, it’s probably earlier than we thought. But remember, we’re having the margin headwind, too. So there’s a lot of things that go into that. I think we’re probably still generally comfortable with the numbers that we put out a year ago with some puts and takes, right, lower margins, more volume, like you mentioned. So we’re probably in generally the same spot. So your first question on contracting is a good point. You make a good point. It’s how we look at it. We look at the entire company’s capacity to serve the contracts that we have, not just – not ignoring the fact that we have some length on the nine train platform, we’re just going to put every new contract at Stage 3. You’re absolutely right. And so we do look at it that way. And we do have some wiggle room, and that’s part of our ability to maybe delay an FID a little bit on the Stage 3 project that is otherwise commercially successful.

Great. Thank you.

Last question will come from Ben Nolan with Stifel.

Yes. Hi, this is Frank Galanti on for Ben. I wanted to focus on Stage 3 – Corpus Christi Stage 3. I know the focus to keep long-term contracts at reasonable hurdle rates with an eye to keep – an eye to get bank financing. But would you guys be willing to take shorter duration, somewhere around 10 years or lower to your counterparty to underwrite Stage 3?

No. We don’t see a necessity to change any of our terms or counterparty metrics at this stage of the game to get Stage 3 across the finish line.

Okay. And then kind of second question on, with lower Henry Hub prices and lower gas prices generally, have you been having more conversations seeing increased demand for producer pushed contracts?

Thanks, Frank, this is Anatol. So as we’ve said in previous calls, we have very good interest in the producer push construct, but it is a limited sphere of opportunities, precisely because of your first question. We will not be able to achieve our objectives if we let the investment grade aspect of our counterparty slide. And that, as you well know, is a very limiting factor in engaging with the producer community. So there’s a tremendous amount of interest. But by the time you filter through what we need to extract from that contract, you get down into single-digit opportunities, and we are actively pursuing those, and expect that there will be more IPM-type transactions that ultimately support Stage 3.

Great. That’s very helpful. Thanks very much.

Thank you, and I want to thank everybody for all of your support of Cheniere.

And ladies and gentlemen, this will conclude the conference for today. Thank you for your participation. You may now disconnect.