- North America accounted for 70% of the total global long-term liquefied natural gas (LNG) contracts signed in 2022. The majority were linked to natural gas, and we believe the majority of North American long-term contracting will continue to be gas-linked.
- Sales and purchase agreement (SPA) tenors got longer, with over 80% in 2022 signed for 16-20 year ranges.
- U.S. LNG pricing is no longer exclusively linked to Henry Hub prices, but also to indices such as the Japan-Korea marker (JKM) and the title transfer facility (TTF). We view these contracts as riskier because they retain the risk of cryo-spread (the price difference of LNG and natural gas.
- U.S. upstream producers are emerging as customers and investors due to their robust cash flows and growing risk appetite, as well as the rising correlation between Henry Hub and international gas prices.
H. Jackson Brown Jr. once said, "When lending people money, make sure that their character exceeds their collateral." That aphorism can also apply to lending in the LNG market, where the character of a counterparty can influence perceived risk in contracts. When a commodity price moves dramatically, it can send ripples through underlying derivative contracts, even when the commodities are sold through long-term contracts, which are meant to mitigate market risk.
In this second of a two-part commentary we discuss how contracting for North American offtake capacity is changing, and how that influences our credit considerations for LNG project-financed transactions. (For the first part, see "From Lots To Lack: Liquefied Natural Gas' Wild Ride," published Jan. 23, 2023.)
Counterparty Exposure And Offtake Arrangements
We consider material exposure to counterparties--whether they're gas suppliers or LNG offtakers--in our credit assessments. We broadly see five types of offtake arrangements.
Gas-cost indexations are either tolling arrangements or SPAs. Because the LNG producer is largely insulated from commodity exposure in these arrangements, operational factors are the key influence in cash flow. We typically see cash flow volatility within a 5% band between the base-case and downside scenarios. Also, as LNG demand increases again, we see SPA tenors lengthening back toward longer contracts, insulating projects from market risk.
A key difference from the first wave of contracts and the latest has been the emergence of upstream producers as both customers and investors. These players look to diversify and take on higher-risk profiles with LNG-indexed deals in the medium term. In IPM contracts, the cryo-spread risk is passed from the LNG offtaker to the gas supplier, holding the project largely harmless. However, newer contracts may include material counterparty dependence to both the LNG offtaker and the natural gas supplier.
In oil-linked contracts, pricing is linked to Brent. Under our long-term oil price assumptions, we typically see cash flow volatility of 30%-50% for projects that rely on these contracts. As a result, we consider them riskier.
The trend to price LNG against spot gas rather just oil continues apace, with the TTF and JKM acting as two key price markers. JKM especially has shown significant growth over the last five years and is now the key marker for spot and short-term LNG in Asia, and it is also increasingly used in long-term contracts. We view these contracts as riskier than oil-indexed because of the larger volatility in these markers and indexes that could top more than 50% between peak and trough prices.
Merchant or short-term contracted cargoes
Merchant cargoes are primarily delivered ex-ship (DES) contracts, which are set against the highest netback of either the JKM or TTF after accounting for the cost of shipping, boil off, and source gas (typically Henry Hub). We see these commitments as an equity upside and significantly haircut cash flows from these arrangements from our credit assessments.
As Contracts Evolve, So Do Credit Risks
Demand for LNG has grown, with the LNG fleet increasing to 675 vessels from about 360 in 2010. Market consultants estimate another 150 will be added by 2025. As a result, North American sponsors are increasingly using LNG benchmark indexes to ink contracts. But as the contract landscape evolves, the credit risks are evolving too. (For an overview on the traditional contracts used within the LNG market, see "Contract Structures In The LNG Market" below.)
Natural Gas Procurement
Although current LNG facilities have had no trouble procuring gas, increasing environmental regulations have made it costlier to take on this responsibility in LNG investments in the Gulf Coast and western Canada.
Permitting from the Federal Energy Regulatory Commission (FERC) remains a challenge for interstate pipes and modifying or extending LNG permits because it increasingly seeks to control greenhouse gas (GHG) and methane emissions. As a result, breakeven gas prices will likely be higher for new LNG investments. For instance, significant North American pipeline constraints (outside of supportive states like Texas, Oklahoma and Louisiana) would force drilling to higher-cost basins, which could drive up the Henry Hub prices to $5.0 per million Btu (/MMBtu) and higher. Building the concomitant LNG export capacity could drive up gas prices even further. Through 2026, we think Haynesville and Mid-Continent supply can take advantage of this stranded capacity to flow from the Barnett Shale to the Perryville and Carthage hubs. However, in the long term, LNG exports will need more new builds in the Gulf Coast.
While tolling arrangements insulate LNG projects from commodity risk, many offtakers are not natural incumbents in North American gas production. They often do not want to suffer the increasingly tight energy infrastructure associated with gas transportation. As a result, we expect SPAs to dominate gas-price indexation contracts.
We see procurement risks for new investments that enter SPAs if a project takes on natural gas procurement obligations, and we would need to review plans comprehensively to determine the adequacy of gas procurement strategies over the life of the contract
Market exposure measures the expected volatility of a project's cash flow available for debt service (CFADS) from our projected base case to the market downside case due to price changes and volume fluctuations. Contracts that minimize market risks--such as Freeport LNG's tolling structure or the Sabine Pass SPA--typically score the best on our operations phase business risk assessment (OPBA). Their risks are meaningfully lower than projects with oil-linked contracts.
For instance, in two oil-linked transactions in Qatar and Australia, cash flows declined about 25% under market downside stress compared with base-case outcomes. We use real, long-term oil prices of about $55 per barrel (/bbl; both West Texas Intermediate and Brent) for our base case and a $35-$40/bbl assumption under our market downside stress. We also applied market downside for a limited time--two to three years for investment-grade entities. For these assessments, our OPBA assessments tend to be two to four notches weaker (on a 1-12 scale) for projects with market exposure than for tolling contracts or SPAs.
However, LNG revenues are still tied to crude oil prices and exposed to commodity price movements, even if a project with Brent or Japan Custom Cleared (JCC) exposure has fixed-volume commitments. This means a project's cost of gas is still tied back to oil prices, and therefore only mitigates--but does not eliminate--market risks.
Market risks also emerge from volume variability. Although we normally incorporate volume risks in our downside stresses, if a project has already experienced volume swings, we factor such a possibility in our base-case assessment instead. Over the past five years, buyers have gained greater leverage in contract negotiations, asking for quantity flexibility, cargo cancellation rights, back-end ramp-down rights, and more. We see these contractual terms as riskier for a project than the take-or-pay provision in legacy contracts.
Some buyers also want seasonal delivery schedules, which causes volumes to fluctuate. Seasonal deliveries significantly strain long-term production because LNG facilities typically produce the gas on a ratable basis. These requests often ask for a disproportionate quantity of the average annual contract quantity (AACQ) in a defined three- to five-month season (typically winter), disrupting a facility's ability to market its gas in the long term. Therefore, in our view, long-term contracts that expect LNG delivery from seller to buyer at reasonably equal rates, intervals, and quantities and that are ratable throughout each contract year are less risky than seasonal contracts.
Counterparty risks arise from two specific concerns. First, the credit quality of offtakers could constrain ratings on the LNG project. Second, should the contract become substantially out of the money, a counterparty could attempt to force a renegotiation.
A lower rating on an offtaker could constrain the project ratings, even if the stand-alone credit profile (SACP) on the project is stronger. We have seen some newer buyers with lower ratings than typical buy shorter contracts than the traditional 20-year LNG SPA.
However, contracts can mitigate this risk if we consider them replaceable, such as under the following scenarios:
- We can substitute prevailing market pricing dynamics around the contract without any effect on cash flow.
- The contract is out-of-the-money and does not allow the offtaker to simply renege on it, forcing it to be replaced with a new contract to another counterparty (with any mark-to-market differences settled with the new offtaker outside of the contractual arrangement with the LNG project).
- We evaluate the project as if the contract does not exist and use our assumptions of market-based pricing.
Using this methodology, we had assessed FLNG Liquefaction 3 LLC 's (BBB/Stable/--) credit concerns with Toshiba Corp.'s offtake obligation during the Westinghouse bankruptcy. Because 50% of FLIQ3's cash flows were exposed to counterparty risk, we had assumed full market risk on 50% of its offtake, essentially assuming that Toshiba was unable to fulfill its contractual obligations under its offtake agreement. While FLIQ3 had indicated that it expected Toshiba to honor all of the terms of its liquefaction tolling agreement (LTA), as market price assumptions were lower than the Toshiba contract, the sponsor had infused more equity into the transaction to strengthen credit metrics, which had offset the increased market risk. Eventually, Toshiba transferred the 2.2 million tons per annum (mtpa) FLIQ3 contract to TotalEnergies SE and paid $800 million to Total to take over the above-market contractual obligation.
This settlement is just one example of mitigating counterparty rating risks, especially in a falling price environment. We also note that early in the pandemic, counterparties continued to pay their fixed fee (which is the majority of the cash flow to the project) even though they were not lifting cargos, which provides further evidence of the contract's enforceability and a counterparty's willingness to honor them.
As evidenced in recent contract renegotiations and novations, we concluded that long-term LNG contracts are replaceable without significant cash flow consequences, even when these contracts are material for a project. Still, we continue to assess this assumption jurisdictionally (Asia has seen some renegotiations) or when there is evidence of a contract reneging.
One of the inherent risks with long-term contracting is that over time, it can become significantly out (or in) the money, raising the prospects of a contract dispute. We usually do not factor contract negotiations in our base-case assessments. However, in jurisdictions with a history or likelihood of it, we account for it in our downside assessment.
From a credit perspective, a divergence between spot prices and long-term contract prices raises risks for debt-financed LNG transactions. In theory, this divergence provides an economic incentive for buyers to turn down long-term oil-indexed contractual volumes toward take-or-pay levels, instead purchasing spot LNG cargoes. Many Asian buyers resist signing new long-term contracts when spot prices remain low.
We are uncertain how much Asian buyers will seek to renegotiate LNG prices in long-term oil-linked contracts with higher slopes. For example, the slopes in Asian LNG contracts signed with Australian LNG projects are likely declining from 14.5% of the JCC price that was struck back during 2010-2015. Many include price review provisions, although buyers often must wait at least five years after LNG supply commences to trigger price negotiations. We note that many of these contracts were renegotiated in 2022 (see "Oil-Linked Slopes In Contracts By Year"). The average 2022 slope is a blend of new contracts and several renegotiated contracts that had high slopes signed 2010-2014.
As an example, recently, Tohoku Electric Power Co. Inc. completed its price review for its approximately 1 mtpa offtake on a DES basis with Wheatstone LNG at a 13.3% slope of the JCC price, plus 60¢-75¢/MMBtu. The previous price for the 20-year deal was at a 14.75% slope of JCC plus 65¢/MMBtu. In most recent price negotiations, Japanese buyers are pushing for Australian projects to agree to a 13.3% slope of JCC plus a flat fee, a new benchmark after earlier price reviews concluded at Australia's Northwest Shelf and Pluto LNG.
We also note that contract renegotiations threaten long-term offtake arrangements. For instance, in February 2018, Korea Gas Corp. (Kogas) announced it entered into arbitration with North West Shelf Gas over the oil-linked pricing on its term LNG contract.
Still, our base-case analysis does not assume that an out-of-market contract would be renegotiated. It can be difficult for offtakers to succeed in revising pricing terms through arbitration merely because they do not like the pricing in legacy contracts. Additionally, even if a contract is renegotiated, it is usually coupled with incremental volumes from the facility to preserve the net present value (NPV) for the sponsor.
Example: Petronet LNG Renegotiation
In late 2017, Petronet LNG, India's largest importer, announced that it had renegotiated pricing terms of an original transaction signed back in 2009, under which it agreed to buy around 1.5 mtpa of LNG from ExxonMobil's share of the Chevron-operated Gorgon LNG project on Barrow Island in Western Australia for 20 years. The transaction preserved the NPV because, in exchange for reduced pricing (lower oil linkage) and significantly improved shipping terms (now DES; previously FOB), Petronet agreed to increase its offtake volume 1.2 mtpa. The incremental volumes preserve the NPV of the contract for the sponsor.
The parties agreed to the following revisions:
- Slope for the existing 1.5 mtpa reduced to 13.9% from 14.5%.
- Shipping terms for the existing 1.5 mtpa now DES from FOB, saving Petronet $0.50-$0.75/MMBtu.
- Additional DES contract for 1.2 mtpa at 12.5% oil linkage for 15 years.
We believe oil-linked contracts are at higher risk of renegotiations when spot crude prices decline. That said, while many projects entering service in the U.S. in 2026 are sanctioned in a higher-price environment for LNG and crude oil during 2022 (peak TTF price is $90/MMBtu), we note that U.S.-based projects can offer diversification in Henry Hub-linked contracts and free on board (FOB) cargoes, free of destination clauses. These provide increased offtaker flexibility to divert or resell cargoes as needed.
Market-based LNG pricing can potentially reduce incentives for a counterparty to renegotiate pricing terms during a contract's term. In fact, the emergence of a rapidly growing derivative market--such as on an LNG price benchmark like the JKM--potentially allow parties to hedge physical positions as they settle derivatives against physical spot price. Spot pricing represents a constantly evolving LNG market, so from a lending perspective, we view long-term contracts as friendlier to credit that spot pricing. This is because long-term contracts provide more predictability to cash flows in an otherwise volatile market price environment.
We note that strategic offtakers, such as investment-grade utilities or entities with long-term load-serving obligations, signed early contracts. Now that prices are higher and the global balance tips toward undersupply, buyers are more forthcoming to sign up for long-term new supply (the recent decline in contracting reflects the financing uncertainty and do not reflect a wider trend).
However, smaller contracting markets (by volume) are emerging due to the uncertainty in Japan about the future of nuclear generation; the advent of portfolio traders; and the startup of smaller LNG importers, like Bangladesh and Jamaica.
Additionally, with Europe unsure about its longer-term gas usage and favoring shorter-term contracts for the most part, we expect to see recontracting risks in new LNG transactions, under which contracts will mature before debt is fully amortized.
While we have no such projects in our rated universe, we expect to make assumptions on the pricing level that can be reasonably expected at recontracting. Based on current trends, slopes in oil-linked contracts that had declined to mid- to high-11% and 12% in 2020-2021 are back up to 13.0%-13.5%; fixed liquefaction fees in gas-linked contracts rose to $2-$2.25/MMBtu. To evaluate recontracting risks, we use a slope of 12.5% and a $50/bbl crude price as our base-case recontracting assumption.
|Implied Oil-Indexed Contract Price|
|Oil index (slope, %)|
|Crude oil price ($/Barrel)||Contract price ($/MMBtu)|
|Note: The matrix is representative and ignores the typical s-curve where prices decline less linearly at low crude prices or increase at high. MMBtu--Millions of Btu. Source: S&P Global Ratings.|
Similarly, our assumptions for gas-linked contracting are about $2.0-$2.25/MMBtu of liquefaction costs (unless new contracting shows significant affect from recent engineering, procurement, and construction cost escalations) and include a base-case Henry Hub assumption of $4.5/MMBtu through 2024 and about $3.0/MMBtu thereafter.
|Implied Gas-Linked LNG Price|
|Liquefaction/tolling fee ($/MMBtu)|
|Henry Hub price ($/MMBtu)||Gas-linked LNG price ($/MMBtu)|
|LNG--Liquefied natural gas. MMBtu--Millions of Btu.|
Traditional Contract Structures In The LNG Market
The LNG market uses several types of contracting structures. From a credit perspective, these contracts largely differ from each other in terms of their exposure to market prices, as we assess business position based on the volatility in a contract's cash flows under base-case and downside market prices.
Free-on-board (FOB) and delivered ex-ship (DES)
Used in long-term contracts, this specification assigns who pays shipping costs. In FOB contracts, the seller fulfills his obligation to deliver when the goods pass over the ship's rail at the named port of departure. This means the buyer bears all costs and risks of loss or damage to the goods from that point. In DES contracts, the LNG project retains the risk of shipping, but factors in that cost in the netback price. We consider DES contracts riskier as the project now has to subsume shipping cost risks in its netback assumptions.
As the LNG business has evolved over the last 10-15 years, more volumes are being traded on a shorter-term basis and with more FOB sales. This is because many leading offtakers now typically have a core of vessels under long-term charters--usually five to seven years, with options to extend.
Long-term charter rates are relatively stable as they reflect the cost of new build vessels. Market experts estimate long-term charter rates of about US$65,000 per day. However, over the past 10-15 years, rates have varied from a low of $25,000 per day to a peak of $275,000 per day. It is therefore important for LNG projects to manage risks around any DES contracts as netback prices include shipping costs.
Gas-cost indexation contracts typically in two forms. In a tolling arrangement, offtakers procure the natural gas and provide it the LNG facility to liquify. In an sales and purchase agreement (SPA), the LNG facility operator procures the gas, which is linked to a hub price. Historically, these contracts are FOB. However, these contracts could also be constructed as DES.
A traditional SPA takes the following form.
Long-term oil-indexed contracts are priced as a percentage of a benchmark crude oil known as the slope. This percentage is an indexation of Brent or Japan Custom Cleared (JCC, a cocktail of crudes delivered into Japan). The formula also adds a flat value to cover shipping. This number is now often the point at which trading occurs, as some buyers have started to mandate the slope itself in their short-term tenders. Historically, these contracts are DES.
To protect buyers and sellers from sharp price swings, LNG under most long-term contracts is indexed to oil with s-curves. When oil prices rise quickly, the s-curve grants buyers a slope once oil reaches a predefined level at which the price for LNG rises more slowly and with a time lag. Sellers of LNG are granted a similar slope, which slows a price fall in oil, once crude has fallen to a certain level. Buyers prefer a flatter slope at high oil prices, while LNG producers and sellers prefer a flatter slope at low oil prices.
Most contracts written in 2009-2014 applied a slope of around 14.25%-14.75% of oil prices under a time lag against crude of several weeks. Buyers pushed down these slopes to 11%-12% in 2015-2020 period. At long-term price expectation for Brent crude oil of around $55 per barrel (/bbl), an increase of the slope to 14.5% from 11.5% leads to a LNG price of about $8.0 per million Btu (/MMBtu) on a delivered basis.
As of the end of August 2022, this LNG price was around $16.6/MMBtu, or less than one third of the JKM spot price of $53.9 on Aug. 31, 2022.
Integrated production marketing (IPM) contracts
While they currently comprise only 4-6 million tons per annum (mtpa) signed in 2022, we highlight growing interest among exploration and production (E&P) companies, such as EQT Corp. and Chesapeake Energy Corp., in getting involved on the equity side, likely driven by the favorable medium-term prospects for LNG and the growing correlation between Henry Hub and international gas prices. These upstream players are looking to diversify and take on higher-risk profiles with LNG-indexed deals, as opposed to more traditional Henry Hub-linked deals, because of their ability to produce gas.
An IPM contract allows the LNG operator to transfer the cryo-spread risk to the natural gas supplier (who could also be a customer or equity investor). An IPM takes the following form.
The market hub indexation reflects a fixed link to a liquid European hub. The U.K.'s National Balancing Point (NBP) used to be the most liquid hub in Europe and gained favor as the pre-eminent index for those favoring a hub-linked pricing formula. LNG trades at a discount to hub gas prices because it factors in the cost of regasification and system entry costs, but also includes a flat fee, which is the fixed hub link. This means all negotiation takes place around this fee, as it provides sellers the space to make back their storage, reload, shipping, and opportunity costs.
This type of pricing was historically used for northwest European contracts. Although the NBP had a head start to dominate the markets, the TTF in the Netherlands has gained prominence. As the pricing point for reloads out of both GATE and Zeebrugge terminals, it is the more natural European index point because of its deeper liquidity.
Contracts that index the JKM or TTF are designed to cover the actual percentage of LNG that boils off (BOG) on a round trip from an LNG facility to the offtake destination in Asia or northwest Europe. A flat fee is added to cover the balance of the shipping cost to Asia but excludes BOG and regasification costs. While the price can equally weigh both JKM and TTF prices, this contract can adjust the proportion depending on where the destination is likely to be.
This report does not constitute a rating action.
|Primary Credit Analysts:||Aneesh Prabhu, CFA, FRM, New York + 1 (212) 438 1285;|
|Stephen R Goltz, Toronto + 1 (416) 507 2592;|
|Secondary Credit Analysts:||Kimberly E Yarborough, CFA, New York + 1 (212) 438 1089;|
|Viviane Gosselin, Toronto + 1 (416) 5072542;|
|Luqman Ali, CFA, Toronto + 1 (416) 5072589;|
|Emmanuel Dubois-Pelerin, Paris + 33 14 420 6673;|
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