Second in an ongoing series.  

In "There And Back Again: Evolving LNG markets bring higher volatility to spot prices", published April 19, 2018, we explored the market for global liquefied natural gas (LNG) trade and supply-and-demand factors that are influencing spot LNG prices. Here, we break down how LNG contracting evolved historically, how we see new contracting developing, and what risks arise from this changing market landscape. The upcoming third installment will focus on the credit implications for LNG transactions and sponsors.

Before discussing the evolving contracting structures, we'll take a brief detour to explain how legacy contracting emerged over the past decade.

The Long-Term Contracting Phase

Pre-2013, LNG mostly traded as a point-to-point sale, with terms governed by long-term take-or-pay contracts. Most contracts in the first wave were linked to the price of oil (see "Price-Indexation In Long Term Contracts: Oil Indexation", below), which was considered an alternative fuel. These were relatively inflexible contracts transacted between limited LNG sellers and buyers.

Oil Indexation Was The Main Indexation Method In Asian Supply Contracts

These contracts dominated legacy Asian LNG procurement, partly because oil represented the substitute fuel to LNG in most countries' energy mix. Strong growth in world demand for energy (with a short hiatus during the financial crisis) resulted in a strong sellers' market, buoyed further by the Fukushima nuclear power plant disaster in Japan that increased demand for global LNG.

The tight market before and through 2013 created a favorable environment for sellers, and buyers were relatively eager to sign up new long-term commitments. For instance, about 30 new principally oil-linked long-term contracts were concluded in 2013 for about 50 million tons per annum (mtpa) of supply. Indeed, it appears that in several cases buyers were tempted to overcommit to supply long-term without necessarily having firm offtake arrangements in place.

Terms on these contracts were generally standard. LNG buyers received fixed monthly volumes. Even if a buyer cancelled cargo due to unusually low demand, payment was still due under the "take-or-pay" obligation. Most Asian long-term supply contracts contained "destination clauses" (point-to-point) that prevented buyers from onselling LNG to third parties.

The convenience of dealing with the oil-linked formula is that it provides a liquid market against which to hedge risks for both buyers and sellers. Notwithstanding efforts in recent years to break the link, the in-depth nature of oil markets and oil's global point of reference for energy dictates in our view that oil indexation likely still has many years of life left in it.

U.S. Henry Hub Natural Gas Indexation Emerges As An Alternative

The rise of Henry Hub-linked contracts was facilitated by a combination of crude prices above $100 per barrel and rising Asian demand (Japan, South Korea, China, and Taiwan account for over 60% of global LNG demand), increasing access to cheaper shale gas, and the limited availability of flexible LNG supplies. Because crude was elevated, gas-linked contracts became more competitive than oil-based contracts. Moreover, in countries such as China and India, non-oil fuels are often alternatives for power generation. For these countries, oil-linked contracts are likely less important (see "Gas Supply-Cost Indexation", below). Buyers now have actual "gas-on-gas" pricing competition with the introduction of significant U.S. Henry Hub-indexed supplies.

We note that in a persistent low natural gas price environment, LNG sponsors looking to sign up new long-term contracts face competition over the liquefaction or tolling fees they charge offtakers. We note that current brownfield capital expenditure (capex) proposals of $600 per ton represent a significant savings from the last wave of sanctioned U.S. liquefaction projects, which averaged capex costs of $750-$1,100/ton. As a result, while some of the earliest U.S. sales and purchase agreements (SPAs) were executed at $3-$3.50/mmBtu (for liquefaction services, Y), recent lower cost, midscale projects (or brownfield projects that expand on existing shared infrastructure) can economically introduce lower liquefaction or tolling fees (Y) as low as $2-$2.25/mmBtu.

European Gas-On-Gas Competition Pushes LNG And Pipeline Contracts Toward Hub Pricing

The inherent risk of pricing long-term LNG contracts against a different commodity is that it creates a disparity between expected delivered prices when the contracts are signed and market prices when deliveries begin. We saw this in Europe in 2009-2012, when--as a result of increased liberalization of gas and power end markets, combined with a prolonged economic downturn--spot prices decoupled from long-term oil-indexed contract prices. Long-term contract prices were in the region of 11% of the Brent price and European spot gas prices were around 25% lower. This triggered two things: a big wave of price renegotiations between buyers and sellers of long-term oil-indexed gas contracts (with a higher share of hub-linked pricing), and a fairly rapid development of liquid traded gas hubs based such as the National Balancing Point (NBP) and Title Transfer facility (TTF) on strong gas-on-gas competition (see "Market Hub Indexation", below).

Moreover, rising LNG capacity made the market more flexible, with larger volumes available at spot, shorter-duration contracts, and emerging spot indices. This process even forces pipeline gas producers to renegotiate a significant share of their contracts from oil-indexed to spot gas price-based to ensure they remain competitive. As LNG volumes rise, competition in markets where both pipeline gas and LNG are available is increasing, driving growth in spot gas trading. In Europe, spot hubs and spot gas trading increased. The share of spot-linked trading volumes as a percentage of total consumption is increasing gradually, reaching about 54% in 2017, from less than 5% in 2006.

An illustrative example of how the gas market is evolving, and how pricing is increasingly spot-based, is provided by Europe's largest gas supplier, Gazprom, which supplies about 34% of Europe's natural gas needs. Buyers that had the capability nominated down long-term contract gas under the terms of their take-or-pay clauses, and in turn looked to procure any needed replacement volume on the spot market. As this happened, it threatened Gazprom's gas sales volumes on its core market. A decade ago, essentially all Gazprom's export sales were linked to oil products. In recent years, on the back of customer pressures from utility offtakers (in some cases even litigations and antitrust cases), Gazprom gradually increased the spot component in its contract mix. In its February 2018 analyst day presentation, Gazprom said that about one-third of its gas sales was oil-linked, one-third was hub-based, and one-third was based on a mixed formula, with caps and collars (see Chart 1). Gazprom demonstrated a much more flexible pricing approach, with a large price drop in 2016 that helped the company maintain its market share. This suggests that the natural gas market is becoming more commoditized.

Chart 1

Can Asian LNG Markets See A Shift To Hub- Or Spot-Based Gas Indexation?

In the latter half of 2014, oil prices collapsed following OPEC's decision not to curb its supplies despite large excess of supply over demand stemming from the stimulus to U.S. shale oil production of the run of high prices in 2010-2013. Initially, most market experts we spoke to expected prices to recover as low prices slowed upstream investment. However production proved surprisingly resilient, particularly U.S. shale oil production. Low prices instead stimulated efficiency improvements, allowing production to increase despite low prices--resulting, it seems, in lower prices still.

This oil price crash affected spot LNG prices. The fall in average Asian LNG prices is directly linked to the fall in oil prices, as most supply is on long-term contracts with the LNG price directly indexed to the oil price. Also, since 2013, the global LNG supply–and-demand situation has moved much more into balance, as new LNG supply came on stream. Despite strong growth in LNG supply in both 2016 (8%) and 2017 (10%), markets absorbed the available supply without major disruptions. Those two factors mean that spot LNG prices remained weaker than pre-2014 levels. In 2013, the average differential between Japanese-delivered LNG prices and the U.S. Henry Hub price was around $12.5/mmBtu; in 2017 this fell significantly to about $5/mmBtu. Similarly, the margin of European gas prices over Henry Hub averaged about $6.90/mmBtu in 2013, compared with $2.90/mmBtu in 2017.

Asian spot prices also dropped substantially over 2016-2017 for two main reasons. First, spot prices tend to follow long-term prices, as a significant proportion of spot trading comes from resale of cargoes from the long-term contracts. Second, the spot market weakened due to periods of relatively weak Asian demand, particularly in 2015, and more recently because of increased supply from new projects coming on stream. With the exception of a two-month winter peak in December 2016 and a three-month period this winter, the Japan Korea Marker (JKM), the major spot index for Asian LNG, was below the U.S. Henry Hub natural gas-linked LNG contract prices for most of 2015-2017 (see the LNG netback of JKM to U.S. Henry Hub in Chart 2). Netback prices in Asia were below full operating costs most of the time since the start of 2015 through the third quarter of 2017, except for a winter peak in Asian prices in December 2016. Asian prices, however, were consistently above the variable costs of U.S. exports. We note that long-term oil-linked contracts show higher volatility against spot pricing.

Chart 2

The weakness of JKM spot prices in 2016-2017 raised increasing interest from Asian buyers to index long-term LNG contracts to gas pricing rather than oil. Asia is by no means Europe, but continued low LNG spot prices could trigger further market evolution. Yet, the big difference between Asia and Europe is the lack of liberalized and interconnected gas markets that could stimulate gas-on-gas competition and traded gas/LNG hub development. As a result, on its own, we do not expect the continued differential between long-term contract prices and spot LNG prices to be enough to move long-term contracts away from oil-indexation and toward hub- or spot-price-indexation. Still, we note a meaningful increase in Asian LNG derivative trade on the JKM, underpinned by increasing hedging of market-based LNG pricing as market participants increasingly manage their physical pricing exposure in the financial markets.

Contrary To The Narrative Of Excess Supply, The Market Takes A Turn, But Will It Last?

However, since late 2017 Asian spot prices showed significant recovery, ending 2017 above $10/mmBtu (see charts 2 and 4). Despite a meaningful increase in supply of LNG capacities this year, the price increase was due to a combination of a surge in Northeast Asian gas demand, seasonal factors, and the recovery in oil prices. We note that Northeast Asian countries account for about 60% of global LNG, and each of the four major Northeast Asian LNG importers increased their annual LNG imports in 2017. In particular, China dramatically prioritized re-gasified LNG use over coal-fired generation.

Several factors led to this unexpected run-up. Some are more macro and long-term, while others have shorter-term effects. The shorter-term factors comprise higher than anticipated counter-seasonal outages and other supply issues. Somewhat unnoticed is the decline in supply from countries such as Algeria, Indonesia, Papua New Guinea, Nigeria, and Malaysia. At this point it is unclear if these supply declines are temporary or chronic, but they are reflected in the spot pricing that registered an uptick as demand continues to be strong.

In addition to recovery in oil prices, the structural drivers behind the LNG price increase this year are the considerably greater than expected Chinese demand, increased European short-term (coal-fired displacement) and long-term demand (shutting down nuclear units etc.), and simply ever growing concern over continued lack of final investment decisions (FIDs) of new trains. Most incremental demand (about 20-25 mtpa) in 2018 comes from Asia. We estimate that about half of this growth will come from China and the remainder largely from Japan, South Korea, and India. This demand arose in tandem with increased destination-flexible U.S. Gulf LNG supply, most of which was diverted from Europe to the higher-priced Asian market. We expect this demand growth will likely slow by 2020-2021, when Japan restarts its ninth nuclear plant and a Russian pipeline starts to supply gas to China. Many analysts we spoke to now expect the surplus to last through 2021-2022, and even that is beginning to be called into question. The unknown factor remains the sustainability of Chinese demand, especially against the backdrop of a growing trade dispute.

There Are Structural Changes, Too

China implemented a "blue skies" initiative, which should increase reliance on natural gas fired power generation. However, since 2013 there are structural changes in the LNG market. The three Chinese national oil companies--China National Offshore Oil Corp. (CNOOC), China National Petroleum Corp. (CNPC), and Sinopec--each made big offtake commitments from new Australian projects. With national oil companies out of the market for new volumes, Chinese power and gas utilities are entering offtake commitments, but of smaller scale.

On the demand side, important developments affect gas and power companies in Japan, the traditional high credit quality buyers in the LNG trade for decades. Faced with languishing growth, advancing liberalization, and/or restructuring of their markets, utility buyers in Japan are somewhat reluctant to enter into firm long-term contracts that have underwritten many of the investment-grade liquefaction projects over the years.

Another important development is the emergence of buyers in new LNG importing countries, whose entry into LNG was facilitated by the availability of floating storage and regasification (FSRU) technologies. These reduce the capital requirement and time scale needed for the development of new import projects. Seven new LNG importers started since January 2015. In most of these countries--Pakistan, Jordan, Egypt, Jamaica, and Malta--LNG imports directly offset oil imports, making LNG increasingly attractive as oil prices rise and help stabilize the JKM relative to Brent.

Finally, trading companies such as Vitol, Trafigura, and Gunvor play an increasingly important role in smaller deals, drawing on their experience in managing trading risk and on the increasing availability of short-term volumes. The portfolio players are increasingly important intermediaries in the LNG trade, as they can absorb the risk between long-term SPA commitments and the increasingly diverse and uncertain LNG markets.

Shorter-Term And Smaller-Volume Contracts Gain Traction

The divergence in spot LNG and legacy contractual prices influenced contracting trends over the past two years. With major recent capacity additions and the risk of oversupply through 2022, buyers are likely to have more options. From the start of 2016 through September 2017, spot LNG was meaningfully below pricing in longer-term contracts. As a result, a trend toward smaller volumes and shorter tenures for LNG contracts accelerated. With many options for supply and uncertainty over future prices, buyers signed short- and medium-term contracts rather than commit to long-term deals. According to energy consulting firm Poten And Partners, the average contract lengths for deals signed in 2017 fell to 6.7 years from 11.5 years in 2016. Suppliers responded by proposing smaller-scale liquefaction trains to match these evolving buyer requirements, most notably Woodside Petroleum's Pluto expansion in Australia and Sempra's Costa Azul in western Mexico. Dominion's Cove Point is another example, while Freeport started to develop smaller scale trains.

Pricing also came down as buyers took advantage of the abundantly supplied market and secure outlets for their supplies. Most contracts shorter than five years were priced as a percentage of dated Brent, ranging from 11.75% to 12%, down from well above 13% in 2016.

However, there was also a move in favor of Brent and away from a variety of other benchmarks popular in recent years. Of the 20 short- to medium-term contracts signed in 2017, 14 were Brent-linked, three were against a European gas index, two were hybrids (Brent and Henry Hub), and one was against Platts JKM. The stickiness toward oil-linked contracts indicates, in our view, that market participants have yet to gain confidence in alternative benchmarks. While there was a significant increase in liquidity in the Asian spot LNG swaps market, it is far less liquid than Brent paper markets.

Chart 3

We Now See A Return To Longer-Term Oil-Indexed Contracts, Albeit At Reset Price Level

In 2018, pricing continues to be heavily weighted toward oil links, with 15 of 23 deals priced against Brent or JCC. Oil-related pricing ranged from mid-11% to slightly higher than 12%. Importantly, eight of the 23 transactions signed in 2018 involved developers working to build new capacity, according to Poten And Partners. Now there is a growing concern that the market may be undersupplied in the medium term. Specifically, with only one FID in 2017, there may be a dearth of commitments, as buyers believe that prices may yet decline more and are reluctant to sign long-term contracts that will enable project sponsors to finance new capacity. (We note for U.S.-based facilities, the bid-ask spread is narrowing between sellers and buyers for long-term gas-based contracting.) Without long-term contracts, the construction of new capacity may lag demand growth and set the stage for tighter markets and higher prices, at least temporarily, until these long lead-time constructions can respond to favorable pricing signals.

As spot pricing remains above long-term levels, long-term contracts with developers looking to build new LNG capacity also came back into favor in 2018, and developers have signed FIDs in 2018 with an eye toward expected shortages around 2023. The average length for all deals signed during the first six months of the year also increased to about 14 years (see Chart 3). Yet, average contracted volume has declined. In particular, the downward quality tolerance (DQT) is widening. This is likely because a substantial amount of U.S. produced volumes is held by aggregators and traders who can price volume flexibility from the U.S. tolling contracts.

As we noted before, the risk in long-term contracts signed on an oil-linked basis creates a disparity between expected delivered prices when contracts are signed and LNG market-based pricing when deliveries begin. With spot pricing increasing and slopes in new oil-linked contracts at 11.75%-12%, we see a realigning of long-term contracts and spot pricing that will obviate arbitration issues, at least for the time being. As Chart 4 shows, the long-term average on a hypothetical 11.8% slope oil-linked contact is fairly close to spot LNG pricing, assuming that the long-term contract was struck in 2014.

Chart 4

Notwithstanding this year's surge in the spot price, we still believe that Asian spot LNG prices could weaken again through 2022. First, large new capacities that commenced operations in 2018 have resulted in the global LNG market slipping into oversupply (albeit strength in Chinese demand is upending this view). Importantly, there is additional downward pressure on spot LNG prices as nearly 53 mtpa of new liquefaction capacity continues to ramp up in Australia (55%), the U.S. (25%), and Russia (16%) through year-end 2019. As an aside, in late breaking news, Qatar announced that it is increasing its planned expansion to a fourth train that will take its production to 110 mtpa (albeit by 2025), suggesting that the supply side is responding to evolving market demand.

Market Volatility Can Result In Counterparty Risks

As Chart 2 shows, spot LNG prices were substantially below long-term contracted prices between 2014 and the third quarter of 2017. In 2015, following the rapid fall in oil prices, many Asian buyers in both India and Korea nominated down their long-term contract gas under the terms of take-or-pay clauses. For instance, in 2015 India's Petronet imported significantly less than the contractually agreed 7.5 mtpa contract with Qatar's RasGas. This was partly due to the inability of the downstream market to absorb this high-priced oil-linked contracted LNG while spot LNG traded much lower. Petronet since re-contracted the price down to a lower oil-linked floor and as a concession agreed to an additional 1.0 mtpa of deliveries through 2028. Other conspicuous examples (see "Example Of A Recent Renegotiated Contract", below) include Gas Authority of India Ltd.'s (GAIL) revised contracts with Gazprom and Kogas's arbitration with Woodside Petroleum (owner of the North West Shelf project).

We note that the renegotiations seemed more aimed at winning better terms for future contracts, such as price, flexibility pertaining to volumes in take-or-play clauses, and destination restrictions. For instance, in GAIL's renegotiated transaction while the pricing remains linked to oil, the contract provides additional flexibility to the offtaker by allowing the diversion of a part of the 2.5 mtpa volume, originally contracted on a delivered ex-ship (DES) basis, to other markets.

As The Market Evolves, So Do Credit Risks

The reconfiguration of supply and demand in the LNG industry is changing the nature of global LNG trading. This poses new challenges for sellers, traders, and offtakers. We believe that the expected incremental supply will give buyers more options. While we think that oil-linked contracts will continue to be the mainstay in LNG contracting, we see spot volumes, shorter duration contracts, and different indexations as part of the future contracting mix. In particular, we clearly see a shift in the market to more gas-on-gas pricing, and a desire of offtakers to have this reflected in long-term contracts.

In our third installment, "Our Views On Emerging Credit Risks In Rating LNG Transactions", we assess these market, re-contracting, and counterparty risks, and include our pricing assumptions.

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
• Our Views On Emerging Credit Risks In Rating LNG Transactions, Oct. 3, 2018