Third and last in a series.  

In the report "There And Back Again: Evolving LNG Markets Bring Higher Volatility To Spot Prices", published April 19, 2018, S&P Global Ratings explored the current market for global liquefied natural gas (LNG) trade and supply-and-demand factors influencing spot LNG prices. In our second report ("Capacity, Contracting, And Counterparties: Navigating Global LNG's Choppy C's", which accompanies this one), we explain how LNG contracting evolved historically, how we see it developing, and how that affects our views on risks.

In this commentary, we examine the credit risks in transactions that we rated and how we would assess evolving risks in the industry. Our focus remains on the credit implications for LNG transactions and sponsors.

S&P Global Ratings rates LNG transactions financed either on corporate balance sheets or as project financings (PF). A sponsor typically finances a transaction as a PF if it is too large to be supported on its balance sheet, or if through PF the sponsor allocates risks more efficiently to parties most capable of managing them.

Under our PF methodology, we assign an operations-phase business assessment (OPBA), which evaluates major factors such as market risk, re-contracting risk, and counterparty exposure of the project, to arrive at an anchor rating. The OPBA is scored on a scale from '1' through '12', with '1' being the lowest risk. This assessment is then informed by market and operations downside scenarios that could notch the anchor rating up or down based on the decline in cash flow coverages (or the number of years the project survives) under these downside conditions. Finally, we may employ a comparable rating assessment (CRA) to acknowledge unique relative advantages/disadvantages of the project that could influence our final rating assessment.

Current Outstanding Ratings

We rate several project financed LNG transactions (listed below). Transactions such as Sabine Pass and Corpus Christi have been assigned only one rating, even though they are multitrain (i.e., identical yet independent) LNG facilities. On the other hand, Freeport LNG and Ras Laffan are assigned independent ratings on each train even though the trains are similar, if not identical, in transaction structure and financing.

The projects are:

• Cameron LNG LLC
• Sabine Pass Liquefaction LLC
• Cheniere Corpus Christi Holdings LLC (CCH)
• FLNG Liquefaction 2 LLC
• FLNG Liquefaction 3 LLC
• Ras Laffan Liquefied Natural Gas Co. Ltd. (3)
• Ras Laffan Liquefied Natural Gas Co. Ltd. (II)

Business risks, as reflected in the OPBA, vary across these rated entities based on commodity exposure. However, in all rated transactions thus far, we have not seen meaningful counterparty risks--as offtakers are usually investment-grade--or re-contracting risks as debt is fully amortized before supply contracts expire. We note that because rated transactions tend to be stronger in transaction structure, contractual terms, and counterparty credit quality, these have not experienced the credit issues that have emerged in the industry in the recent years (e.g., contract renegotiations, etc.).

These briefs on the rated universe of credits underscore the fact that the transactions are on the lower end of the risk spectrum.

Cameron LNG 

Cameron has the most derisked financing structure in our portfolio. Due to the very comprehensive nature of the offtake agreement, we apply our credit substitution criterion under which the rating of the project is governed by the lowest-rated offtaker. Effectively, its construction and operations phase risk is taken by the offtakers by credit substitution at the 'a' level. Mitsui & Co. Ltd. (A/Stable) and Mitsubishi Corp. (A/Stable) are the lowest-rated offtakers. Tolling payments include fixed payments that cover debt service, fixed operational costs, and variable payments that cover variable operation costs, regardless of the plant's actual production capacity. The offtakers would be responsible for satisfying all debt obligations if construction were to run more than two years beyond the guaranteed completion date. There is no market risk. Cameron takes only the operational risk of converting natural gas to LNG. It is not responsible for procuring any gas as feedstock for the project (other than during commissioning) or the lifting, transporting, or marketing of LNG cargoes.

Freeport LNG 

Our 'BBB' rating on FLNG Liquefaction 3 LLC (FLIQ2) and 'BBB-' rating on FLIQ3 are constrained by construction risks. The OPBA on FLIQ2 is '5' and the stand-alone credit profile (SACP) 'bbb+', indicating that ratings will rise once construction is completed. This results from the allocation of LNG price and volume, fuel, and cost of power risks to the counterparties. This leaves FLIQ2 exposed primarily to availability and operations and maintenance (O&M) cost risk. Debt service coverage ratios (DSCR) in our base-case scenario are a minimum of about 1.6x and average about 1.7x. Our assessment on FLIQ3 is similar (base-case DSCR of 1.97x and minimum of 1.68x), but ratings are a notch lower due to potential market risks because of a weaker revenue counterparty in Toshiba Corp. (BB/Positive). That results in an OPBA assessment of '6' and incremental construction counterparty exposure relative to FLIQ2.

Sabine Pass Liquefaction 

We assigned our 'BBB-' rating to developer Sabine Pass Liquefaction's (SPLIQ) $13.65 billion senior secured notes. SPLIQ is building an LNG production facility for up to six trains in Louisiana (although we rate five). Construction is progressing well in terms of schedule and budget. Bechtel Oil, Gas & Chemicals Inc. is building the trains under fixed-price, date-certain engineering, procurement, and construction contracts. Trains 1-4 are operational. Completion of train 5 is planned for the first half of 2019. One of the benefits of this multitrain financing approach is that lessons learned on the initial trains were implemented on later trains, expediting the schedule.

The OPBA of '4' for Sabine benefits from the diversity provided by its multitrain financing compared to Freeport's approach to financing its trains. Our operations-phase SACP of 'bbb-' reflects the modest performance risk of the trains and minimal market risk due to the sales and purchase agreements (SPAs) with BG Gulf Coast LNG LLC, Gas Natural Aprovisionamientos SDG S.A., Korea Gas Corp. (Kogas), GAIL (India) Ltd., Total Gas and Power North America Inc., and Centrica PLC. The SPA mitigates market risks as revenues comprise a fixed fee regardless of offtake and additional revenues for offtaken LNG based on a fixed margin over the Henry Hub benchmark natural gas price.

Our base-case assumptions result in DSCRs of about 1.5x minimum and 1.8x average.

We think plant production will exceed SPA requirements but that O&M costs will be slightly above SPLIQ's forecast. Our downside case results indicate DSCRs will be greater than 1x over the debt's tenor. In the downside-case scenario, we assume higher O&M costs and increased debt refinancing rates; we also stress availability, but doing so has no impact in this case because of the project's significant operating headroom.

Corpus Christi 

Our 'bbb-' operating-phase SACP on CCH's $10 billion senior notes financing is similar to our assessment on SPLIQ. The operations-phase SACP reflects generally 20-year SPAs that provide Corpus Christi Liquefaction LLC (CCLIQ) a fixed price for LNG, including a fee for natural gas feedstocks generally equal to the cost of gas plus 15%. However, the 'BB-' ratings are capped by the exposure to parent (and irreplaceable financial counterparty) Cheniere Energy Inc.'s (CEI) unsupported equity contributions for completing the first two trains, as well as its unsupported equity contributions for train 3 of about $1.13 billion.

Ras Laffan II and 3 

The 'A' issue-level ratings on Ras Laffan's senior secured debt have the highest risk of all rated LNG transactions as reflected in the '9' OPBA. RLII and RL3 are both owned 70% by Qatar Petroleum (QP; foreign currency AA-/Negative/--) and 30% by Exxon Mobil Corp. (AA+/Negative/A-1+). The two entities guarantee each other's debt and are operationally linked. Accordingly, we calculate all ratios on a consolidated basis.

Ratings reflect RL's moderate market risk due to its exposure to inherently volatile commodity prices, which is partially mitigated by medium- and long-term take-or-pay SPAs that provide about 70% of total revenues. The SPAs cover virtually all of RL's 30 million tons of annual LNG production and help mitigate the risk of short-term price fluctuations due to the rolling oil and gas benchmark price indexation. The weak OPBA is offset by strong financials. The ratings reflect the strength of RL's financial performance, both under our base- and downside-case scenarios. We forecast robust annual debt service coverage ratios (ADSCR) under our base of 3.3x minimum and 10.6x average, based on our long-term Brent crude oil price assumption of $55 per barrel (bbl) and Zeebrugge hub gas price of $4 per million Btu (mmBtu). The minimum occurs in 2019, the year in which RL repays RL3's $879 million bullet maturity. RL does not have a track record of refinancing debt at maturity, and our rating does not factor in new debt issuance.

Credit Considerations

Lately, some sponsors have considered the use of LNG benchmark indexes for inking contracts. This was fueled by pricing disputes on long-term commodity linked contracts and increasing demand for LNG in non-oil-dominated economies. We think that with increasing commoditization of LNG markets, the trend toward benchmark index-based pricing could endure. On one hand, it is likely that given the trend toward shorter-term and smaller volume contracts, sponsors will prefer to take on more balance-sheet risk or infuse more equity when making their final investment decisions. However, we also expect that a number of sponsors will continue to consider PF as an attractive financing option if they can contract long-term. Given the evolving contracting landscape, we highlight some key credit risks that we expect to evaluate and our views on these risks:

Market risks 

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 or volume fluctuations, or both.

We consider contracts that derisk market risks such as tolling structures including Freeport or SPAs including those made by Sabine Pass as deals that score the best on our business risk assessment. These transactions have market risks meaningfully lower than those for projects with oil-linked contracts. This is because even though projects with Brent or Japan Custom Cleared (JCC) exposure may have fixed volume commitments, LNG revenues are still tied to crude oil prices and exposed to commodity price movements. The fact that the project's cost of gas is also tied back to oil prices, mitigates, but does not eliminate, market risks. For instance, in the oil-linked transactions we evaluated, cash flows declined by about 25% in the market downside stresses compared to base-case outcomes. We use (real) long-term oil prices of about $55-$60/bbl (both West Texas Intermediate, WTI, and Brent) for our base case and a $35-$40/bbl assumption under our severe market downside stress. (Market downside is applied for a limited time, i.e., five years for investment-grade entities). For these assessments, our OPBA assessments tend to be 2-4 notches weaker for projects with market exposure than for tolling contracts or SPAs.

Market risks also emerge from volume variability. In recent months, buyers gained greater leverage in contract negotiations. They are asking for more quantity flexibility, cargo cancellation rights, back-end ramp-down rights, etc. We see these contractual terms as riskier for a project than the take-or-pay provision in legacy contracts. Volume risks are normally incorporated in our downside stresses. However, in instances where a project has already experienced volume swings, we will factor such a possibility in our base case assessment.

We also noticed that some buyers want seasonal delivery schedules. These are usually delivery requests for a disproportionate quantity of the average annual contract quantity (AACQ) in a defined 3- to 5-month season (typically winter). However, because a facility will produce LNG on a reasonably ratable basis throughout the year, seasonal deliveries put significant strains on its ability to market all of its production on a long-term basis. In our view, contracts that expect LNG to be made available for delivery from seller to buyer at "rates and intervals and in quantities reasonably equal and ratable throughout each contract year" are less risky than seasonal contracts.

Counterparty risks 

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.

Counterparty ratings 

We note that some newer buyers are rated lower than traditional LNG buyers and are buying on shorter contract durations than the traditional 20-year LNG SPA. If the credit ratings on the offtaker are low, the project ratings could be constrained by the counterparty's credit quality even if the SACP on the project is stronger. Alternatively, we could evaluate the project as if the contract does not exist and impose our assumptions of market-based pricing.

This is the methodology we applied in our assessment of FLIQ3 (BBB-/Stable) due to credit concerns relating to Toshiba's offtake obligation. Based on the rating on offtaker Toshiba (BB/Positive), 50% of FLIQ3's cash flows are exposed to counterparty risk, should a replacement for Toshiba be required. We assess these risks by assuming full market risk on 50% of FLIQ3's offtake, assuming that this counterparty does not fulfill its contractual obligations under its offtake agreement as soon as commercial operations commence. Specifically, for purposes of our base-case analysis, we assumed that merchant replacement values for gas offtake prices, i.e., the fixed liquefaction fee of a replacement toll, are $1.75/mmBtu through 2021, $2.125/mmBtu from 2022 to 2025, and $2.50/mmBtu thereafter. We applied these assumptions based on evolving market prices and with recent comparable transactions (see table 1). While FLIQ3 indicated that it expects Toshiba to honor all of the terms of its liquefaction tolling agreement (LTA), given lower market price assumptions relative to the Toshiba contract, the sponsor infused more equity into the transaction to strengthen credit metrics, which helps offset the increased market risk.

Table 1

Contract negotiations 

One of the inherent risks with long-term contracting is that over time it can become significantly out of (or in) the money, raising the prospects of a contract dispute. While we see the potential for contract renegotiation as a possibility, we do not factor such situations in our base-case assessments. However, in jurisdictions with a history (or likelihood) of such occurrences, we will factor such a scenario 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, and instead purchase spot LNG cargoes. Many Asian buyers resist signing new long-term contracts when spot prices remain so low. The slopes in Asian LNG contracts also look like they are coming down from 14.5% of the JCC price to perhaps as low as 11.75%-12% of JCC (table 1). (In oil-linked contracts, LNG is priced as a fraction of the prevailing crude oil price, and the slope represents that fraction of the crude price.)

The big question is whether Asian buyers will seek to renegotiate LNG prices in long-term contracts with higher slopes. The large number of long-term contracts signed in 2011–2014, particularly with Australian projects, could come under pressure. Many include price review provisions, though buyers must likely wait at least five years after LNG supply commences to trigger price negotiations. If this is the case, there could be a wave of price renegotiations in the early 2020s should spot prices remain low and there is continued downward pressure on oil indexation in new long-term contracts. We think this will largely depend on how Asian demand holds up.

We note that contract renegotiations are indeed a real threat to long-term offtake arrangements. For instance, in February 2018, Kogas announced it entered into arbitration with North West Shelf Gas, relating to the oil-linked pricing on its term LNG contract. A recent market report identified nearly 80 such arbitration cases in which pricing was the most frequent subject of dispute. Still, our base-case analysis does not assume that an out-of-market contract would be renegotiated. First, it is not always easy for the offtaker to succeed in revising pricing terms through arbitration merely because it does not like the pricing in the legacy contract. Second, even if a contract is renegotiated, it is usually coupled with incremental volumes from the facility in an attempt to preserve the net present value (NPV) for the sponsor.

We believe oil-linked contracts are at higher risk of renegotiations. While many projects entering service in the U.S. over the next 12-18 months were also sanctioned in a higher LNG and crude oil price environment during 2012-2014 (peak JKM price of $20.20/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.

Re-contracting risks 

Over the duration of a term contract, market-based LNG pricing can potentially reduce incentives for one of the counterparties to renegotiate pricing terms. In fact, the emergence of a rapidly growing derivative market--for instance, on an LNG price benchmark such as the S&P Platts Japan Korea Marker (JKM)--can potentially allow parties to hedge physical positions as derivatives can be settled against physical spot price. Even as we acknowledge that spot pricing is more representative of a constantly evolving LNG market, from a lending perspective, we view long-term contracts as more credit friendly. This is because long-term contracts provide more predictability to cash flows in an otherwise volatile market price environment.

However, we note that the early contracts were signed by strategic offtakers like investment-grade utilities or entities that had long-term load serving obligations. Now, with prices lower, and the global balance tending toward oversupply, buyers are hesitant to sign up for new supply over the long term, reflected in a drop in the number and scale of new contracts. For instance, the uncertainty in Japan about the future of nuclear generation, the advent of portfolio traders, and the startup of smaller LNG importers like Bangladesh, Jamaica, etc., result in the emergence of this shorter and smaller contracting market.

We expect this to manifest itself in re-contracting 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 re-contracting. Based on current trends, slopes in oil-linked contracts have already declined to mid- to high-11% and 12%, and the fixed liquefaction fees in gas-linked contracts to $2-$2.25/mmBtu (see tables 2 and 3). To evaluate re-contracting risks, we will use a slope of 11.75%-12% and a $55-$60/bbl crude price as our base-case re-contracting assumption.

Table 2

Similarly, our assumptions for gas-linked contracting will be in the $2.25/mmBtu liquefaction cost area and include a base-case Henry Hub assumption of $3/mmBtu.

Table 3

We also received inquiries as to how we will assess transactions with spot price risks or those that contract on market price benchmarks. We are in the process of developing these market base-case and downside price assumptions.

It's Getting Interesting

We frequently receive inquiries and expect to rate additional LNG transactions over the next year. While we see long-term Asian contracting still preferring oil-related pricing, we expect that as the LNG market becomes more transparent and liquid, we will also see rated transactions that employ hybrid and market based benchmarks in contractual arrangements.

We also note that in 2018 there is a rebound for Henry Hub-linked pricing, which fell out of favor after oil prices decreased in 2014. U.S.-based LNG sellers have been willing to work with buyers, with liquefaction charges or tolling fees declining as low as $2-$2.25, compared with the $3-$3.50 common in 2013 and 2014, when the first round of U.S. LNG contracts was signed.

Other U.S. projects are offering different approaches of securing gas supply to make their projects more competitive. For example, Tellurian Investments, sponsor of the Driftwood LNG project, offered a range of alternatives that include fixed prices of $7.50-$8/mmBtu delivered to Asia. The company is also marketing a plan under which buyers will pay upfront money for fixed delivered quantities of LNG. Even if the market propositions of new LNG projects are not realizable, they may lead to buyer confusion and delay more realistic deals being concluded. Winning over buyers reluctant to sign long-term deals will be critical if there is to be an adequate supply of reasonably priced LNG in the mid-2020s.

Related Research

• There And Back Again: Evolving LNG Markets Bring Higher Volatility To Spot Prices, April 19, 2018
• How Nord Stream 2 Will Reshuffle The CEE's Gas Pipeline Business, Oct. 1, 2018
• Capacity, Contracting, And Counterparties: Navigating Global LNG's Choppy C's, Oct. 3, 2018