Cheniere Energy (LNG) Q4 2019 Earnings Call Transcript

Cheniere Energy (LNG 0.96%)
Q4 2019 Earnings Call
Feb 25, 2020, 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

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.

Randy Bhatia -- Vice President of Investor Relations

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 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 Michael will review our financial results and guidance. After our 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.

Jack Fusco -- President and Chief Executive Officer

Thank you, Randy. Good morning, everyone. I'm pleased to be here today to review our results for 2019, a year marked with significant achievements and 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 a valuation allowance previously recorded against our deferred tax assets. Operationally, we produced and exported a record 130 cargoes during the quarter or 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 are off to a great start as we recently celebrated the production of our 1,000th LNG cargo.

Cheniere employees worldwide commemorated this landmark operating milestone, which we achieved 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 of $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 really 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 9 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 result we would not have been possible without the focus we have on execution through all phases of our projects and 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 so 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 we 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 the 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 will enable 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 upon 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 enterprisewide investment-grade metrics and allocate excess capital in a flexible, responsible way. And Michael will give you an update on the same 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, advisors, 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 really demonstrate their business is 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 the large emerging markets, like China and India, where small percentage changes in energy consumption that we can make a significant difference in 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've recently celebrated our 1,000th LNG cargo. If all 1,000 LNG cargoes have 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've made significant investments in resources focused exclusively on our ESG effort.

With support of 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 in 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, we 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. And 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 that 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 discussions 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, also thereby limiting our exposure to short-term market prices. This company is designed to build highly contracted long-lived 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 is not based on speculating on global commodity markets, rather on our risk management framework that has positioned Cheniere such that this 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 and grows with excellence in 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 and through the end of 2019, the LNG market demand has grown by about 100 million tonnes.

That demand is forecast to also grow another 100 million tonnes by 2025, and a further 100 million tonnes by 2030. But this growth will be cyclical, as the necessary infrastructure is required to be built. The LNG market is a dynamic one, undergoing significant growth and evolution. And Cheniere is ideally positioned to 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 here 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. And so while LNG market prices are at 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, while the Phase 1 trade agreement with China and subsequent opportunity for short-term LNG tariff waivers are positive steps, we will 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.

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Thanks, Jack, and good morning, everyone. Please turn to Slide 10. Over 24 million tonnes 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 tonnes 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 we recorded in 2010.

This 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, the increased nuclear availability within 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 tonnes 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 supplied in the year 2019, with 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 our fourth quarter were almost 6 million tonnes, 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 remain muted and well below the same period in 2018. TTF drops to an average of just under $4.50 an MMBtu in the fourth quarter versus over $8.50 in the fourth quarter of 2018.

Similarly, JKM prices for LNG in Asia decreased to an average of $5.50 an MMBtu in fourth quarter '19 versus $10.70 in the previous year. This 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 have seen JKM spot prices decrease by approximately 50%, with prices for March falling below the previous record low of $3.65 we have recorded in May of 2009. While it'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 that grew roughly 3% in 2019, gaining approximately 7 million tonnes, 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 tonnes. JKT LNG imports as a percentage of overall Asian LNG demand 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 region representing about 1/5 or 21% of total Asian LNG demand in 2019.

LNG imports into the region surpassed 50 million tonnes in aggregate, increasing by about 22% or over 9 million tonnes year on year. All but one market, India, within the South and the 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 helped provide support to LNG demand in the South and Southeast Asian regions. As you can see on the top right, as our 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 lower pace. LNG imports into the country reached 62.5 million tonnes in 2019, adding nearly 8 million tonnes 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 also 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 see 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 the 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 some 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 continued to increase in the fourth quarter despite record seasonal amounts of volume in underground storage. Imports reached a record 9.5 million tonnes or more than 145 cargoes of LNG in December. European imports for the total year grew by 74%, surpassing 87 million tonnes and exceeding the previous record of 67 million tonnes 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.

The preliminary estimates suggest that a production decline in the Netherlands of about 6 bcm and a drop in piped 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 our 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 tonnes year on year.

We also believe the decline in indigenous gas production and the commitment to environmental targets are structural elements that will likely provide upside to 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 some 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 tonnes 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 this 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 the sources of gas. While we acknowledge that some LNG on the margin may not be lifted from the U.S.

this year, we do not view significant or prolonged curtailment of U.S. LNG production as a likely scenario. So thank you for your time and attention and I will now turn the call over to Michael, who will review our financial results.

Michael Wortley -- Executive Vice President and Chief Financial Officer

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, and 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 with 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 tonnes 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 in income during the fourth quarter was sold on the 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. Volumes sold under long-term agreements increased by 73 TBtu compared to the third quarter, driven primarily by a 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 in 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. And so 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. The total margins or revenues less cost of sales increased by almost $800 million in the fourth quarter as 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 2019 was approximately $2.4 billion, which is 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 stockholders for the fourth quarter was $939 million or $3.70 per share basic and $3.34 per share diluted also compared to a net loss of $318 million or $1.25 per share on basic and the 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 to interest rate derivatives and increased other income, partially offset by increased interest expense and increased net income attributable to our noncontrolling interest. Net income attributable to noncontrolling interest increased due to an increase in net income recognized by CQP, in which the noncontrolling interest are held. For the full-year 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 $1.92 per share basic and $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 noncontrolling interest, partially offset by increased interest expense in the 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. Now 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 of $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 are currently tracking to the lower end of our 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 $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 for $1 change in market margin. Given the limited amount of volumes which were unsold for the remainder of 2020 relative to our forecast total production for the year, we remain confident in our guidance ranges despite some 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 a reduction of the 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 six months. Turn now to Slide 16. As we progress toward a positive FID for our 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 really shared with you, have not changed regarding our approach to Stage 3 or any future growth projects. We are targeting a 2020 FID of Stage 3 based on the commercial opportunity set Anatol's team is also 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 the 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. So, operator, we are now ready to open the line for questions.

Questions & Answers:

Operator

Thank you. [Operator instructions] Our first question will come from Spiro Dounis with Credit Suisse.

John Mackay -- Credit Suisse -- Analyst

Hey, everyone. Good morning. It's John Mackay on for Spiro. I 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 are 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?

Jack Fusco -- President and Chief Executive Officer

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

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

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 are 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 are also seeing other tiers of response. One of the more active markets over the last couple of months has been India. It has shown very good appetite at these price levels.

And yes, you can say, hey, these are levels at 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 are seeing some very interesting responses, especially in Southeast Asia, where you are seeing active decisions to curtail domestic the production and import LNG at the margin. So you are 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.

And so yes, there's certainly a lot of room for optimism.

John Mackay -- Credit Suisse -- Analyst

All right. That's great. Thanks. And then just switching gears quickly.

On the EIG niche and the 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?

Michael Wortley -- Executive Vice President and Chief Financial Officer

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 are 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 from our liquidity.

John Mackay -- Credit Suisse -- Analyst

All right. Got it. Thanks, everyone.

Operator

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

Michael Lapides -- Goldman Sachs -- Analyst

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?

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Thanks, Michael. Yes, I -- so as Jack mentioned in his remarks, the LNG market has experienced very healthy growth, ballpark doubling every decade. We are at 400 million tonnes. 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 more of trains out of the U.S. left to come on. And then in '21, '22, '23, the amount of volume coming into the market is less per annum than it has been per quarter since late 2018.

So we are in the camp that the market will rebalance much sooner than that. Then once you get to the back half of this decade, and 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 this 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. And we think today, the market is, let's say, imbalance by single-digit millions of tonnes per annum run rate. So in a 400 million tonne 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, 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 our CMI piece.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. And so is that assumption, A, hey 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 -- does that spreads will widen relative to what the 12- or 24-month kind of futures curve implies?

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Well, again, by definition, the answer is yes. I would just like to point out that in late '18, 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.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Thanks, guys. Much appreciated.

Jack Fusco -- President and Chief Executive Officer

Thanks, Michael.

Operator

Next question will come from Jeremy Tonet with JP Morgan.

Jeremy Tonet -- J.P. Morgan -- Analyst

Hi. Good morning. I just wanted to come back to Corpus Christi Stage 3 here and as it 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 for a bit more incremental capital toward buybacks as opposed to capex there? Just wondering if anything on the margin has changed there, if you could share it with us.

Michael Wortley -- Executive Vice President and Chief Financial Officer

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 that FID. So that's -- the implication there is that we continue to get long-term contracts that 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 we are our capital allocation framework is not based on Stage 3 per se. It's based on 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.

Jeremy Tonet -- J.P. Morgan -- Analyst

Got it. That's helpful. Thank you. And I 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.

Thank you.

Jack Fusco -- President and Chief Executive Officer

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 that 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. And having said that, there's been a lot of the 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. So 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, but that's the magnitude of it, Jeremy.

Jeremy Tonet -- J.P. Morgan -- Analyst

That's helpful. Thank you.

Operator

Next question will come from Michael Webber with Webber Research.

Michael Webber -- Webber Research -- Analyst

Hey. Good morning, guys. How are you?

Jack Fusco -- President and Chief Executive Officer

Good, Michael. How are you?

Michael Webber -- Webber Research -- Analyst

Good. A lot of macro headwinds right now. And obviously, the fact that you are 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 wanted to follow up on the last question around customer cancellations and specifically, maybe a question for Anatol.

And when that happens and the notion of retrading that cargo back into the market, is that -- so 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 are 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 your customer chooses not to lift it?

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

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 1st for the Corpus Christi Train 2 contracts. And there is some ability to lift those additional volumes, and which would be additional volumes for CMI, sort of, a free option, if you will, if the stars align.

But you are 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 plan and downstream of the plant. So that's the option that we now have for, as Jack said, those two additional cargoes. So 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.

Michael Webber -- Webber Research -- Analyst

Fair enough. Maybe just at 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 imagine you see immediate cargoes kind of evaporate, but you -- the interest 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?

Jack Fusco -- President and Chief Executive Officer

So, Michael, it's Jack. So I'll start off. So in February of 2020, we are not willing or -- to give guidance for 2021 or 2022. So I appreciate your long-term view of our markets and our business, but you are 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 are very conservative on how we run our book. So with that context in mind, see if Anatol has anything he wants to add.

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

As Jack said, boring is beautiful, and we are, as you would expect, managing those '21 and '22 exposures. The issue, as you well know, the single biggest factor for '21 is the timing of Corpus Christi Train 3, which is, as we said, in the first half of 2020 business, but as that moves around by months here and there, that we'll add or take away volumes, which are difficult to manage. But as you also know margins for '21 and '22 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.

Michael Webber -- Webber Research -- Analyst

And just maybe thinking, from an industry perspective, any particular wrinkles you are seeing from like early in terms of the demand response, maybe a benefit to people? Any interesting wrinkles in terms of the term you think you'll look for?

Jack Fusco -- President and Chief Executive Officer

Well, I think it's very positive when you read that India has lowered what they are going to charge at their city gate for natural gas at the city gate. You saw the same demand response at China, where they are 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 U.K., 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 for our product.

Michael Webber -- Webber Research -- Analyst

Yes, bit of a lag on it. No, that's helpful. I appreciate it. Congrats.

Operator

[Operator instructions] And next, we will hear from Shneur Gershuni with UBS.

Shneur Gershuni -- UBS -- Analyst

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?

Jack Fusco -- President and Chief Executive Officer

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 I -- because the implication that we are going to accelerate it, I don't quite understand it. So I just want to make sure that we are all clear on that aspect of it. Michael, do you want to?

Michael Wortley -- Executive Vice President and Chief Financial Officer

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 -- and to 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 -- and 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. Certainly, it has an effect on how quick we move.

Shneur Gershuni -- UBS -- Analyst

OK. So that makes total sense. So there would be no changing in your hurdle rate to achieve the contract. OK.

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 to, say, storages in their home markets or can we assume, generally speaking, you are pretty insulated from attempts by customers to force majeure?

Jack Fusco -- President and Chief Executive Officer

No. I mean from -- in regards to force majeures, right, it's very, very difficult for a customer to claim force majeure on an FOB product, right, because they are picking it up from the dock and they can send it wherever they want to send it to the world. So even if they are 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.

Michael Wortley -- Executive Vice President and Chief Financial Officer

The contracts are clear. You can read them. They are 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 an FM to be invoked on FOB contracts.

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

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, etc., 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.

Shneur Gershuni -- UBS -- Analyst

OK. 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?

Jack Fusco -- President and Chief Executive Officer

Pass the note.

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Yes, it is. Thank you very much.

Shneur Gershuni -- UBS -- Analyst

Perfect. Thanks very much. Appreciate the color, guys.

Operator

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

Unknown speaker

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 are seeing in the flow rate today?

Michael Wortley -- Executive Vice President and Chief Financial Officer

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 and mostly prospectively, right? We are 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 it 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 the 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.

Unknown speaker

OK. 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?

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Yes. So, Anya, thanks. This is Anatol. I wouldn't characterize it that way.

What we said, you are probably referring to the K, is that we are 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 tenure 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.

Jack Fusco -- President and Chief Executive Officer

Yes. And I mean -- 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.

Unknown speaker

OK. Thanks a lot.

Operator

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

Danilo Juvane -- BMO Capital Markets -- Analyst

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

Michael Wortley -- Executive Vice President and Chief Financial Officer

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.

Danilo Juvane -- BMO Capital Markets -- Analyst

Great. That was my only question. Thank you.

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Thank you.

Operator

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

Craig Shere -- Tuohy Brothers -- Analyst

Good morning. Congratulations on the strong quarter. Michael, you mentioned the $0.5 billion liquidity benefit for every half year delay in FID of Corpus Stage 3. I fully understand that the economics of the contracts applied to that project will dictate FID. But to the extent the upsized 9 train portfolio can support the CMI contract signed, isn't there some wiggle room on when to FID, and even if the project could meet hurdle rates? And one final kind of question about liquidity kicker.

Since your June '19 guidance, long-term run rate guidance, we now have some 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?

Michael Wortley -- Executive Vice President and Chief Financial Officer

Well, we are not putting that one in the bank just yet. But OK, yes, it's probably earlier than we thought. But remember, we are having the margin headwind, too. So there's a lot of things that go into that.

I think we are probably still generally comfortable with the numbers that we put that out a year ago with some puts and takes, right, lower margins, more volume, like you mentioned. So we are probably in generally the same spot. Yes -- so your first question on contracting is a good point. You can -- 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 and -- really not ignoring the fact that we have some length on the 9 train platform, we are just going to put every new contract at Stage 3. You are 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.

Craig Shere -- Tuohy Brothers -- Analyst

Great. Thank you.

Operator

Last question will come from Ben Nolan with Stifel.

Frank Galanti -- Stifel Financial Corp. -- Analyst

Yes, hi. This is Frank Galanti on for Ben. I wanted to focus on Stage 3 -- on 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 tier counterparty to underwrite Stage 3?

Jack Fusco -- President and Chief Executive Officer

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.

Frank Galanti -- Stifel Financial Corp. -- Analyst

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

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

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 on 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 to what we need to extract from that contract, you get down into single-digit opportunities. And we are actively pursuing those, and we expect that there will be more IPM-type transactions that ultimately support Stage 3.

Frank Galanti -- Stifel Financial Corp. -- Analyst

Great. That's really helpful. Thanks very much.

Jack Fusco -- President and Chief Executive Officer

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

Operator

[Operator signoff]

Duration: 65 minutes

Call participants:

Randy Bhatia -- Vice President of Investor Relations

Jack Fusco -- President and Chief Executive Officer

Anatol Feygin -- Executive Vice President and Chief Commercial Officer

Michael Wortley -- Executive Vice President and Chief Financial Officer

John Mackay -- Credit Suisse -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Jeremy Tonet -- J.P. Morgan -- Analyst

Michael Webber -- Webber Research -- Analyst

Shneur Gershuni -- UBS -- Analyst

Unknown speaker

Danilo Juvane -- BMO Capital Markets -- Analyst

Craig Shere -- Tuohy Brothers -- Analyst

Frank Galanti -- Stifel Financial Corp. -- Analyst

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