The implications of the International Maritime Organization’s (IMO) revised rules for marine sector emissions will undoubtedly have far-reaching consequences, but how the new mandates may impact pricing for liquefied natural gas (LNG) remain unclear.
The new regulations beginning Jan. 1 are to limit the sulphur content of marine fuels by up to 0.5% worldwide. Although other alternatives can meet the IMO requirements, LNG may be the most viable in reaching the goal of reducing greenhouse gas emissions by 50% by 2050.
However, the IMO’s rules directly impact the price of sour crudes, including those that make up the Japan Crude Cocktail (JCC), the index to which close to half of all global LNG contracts are linked, according to Wood Mackenzie. The JCC is the weighted-average price of a mix of crude oils imported by Japan, mostly composed of sour Dubai and Oman crudes.
Between 2020 and 2030, Wood Mackenzie expects JCC to be, on average, US$1.20/bbl cheaper than Brent. This differs from a trend observed prior to the IMO 2020 announcement in October 2016, when JCC was priced at a premium to Brent.
“Besides value reduction due to equity ownership in LNG projects heavily contracted on JCC, portfolio players also lose revenue on contracts linked to depreciated JCC,” Wood Mackenzie analyst Otavio Veras said.
The firm said seven of the 10 most devalued LNG projects are in Australia, with an aggregate US$7.6 billion in unearned revenues potentially lost from assets whose LNG volumes are contracted under JCC.
Gorgon LNG, in particular, is said to be the most affected project, although its sponsors earlier this year kicked off the second stage drilling campaign that would include drilling 11 additional wells in the Gorgon and Jansz-Io gas fields to maintain long-term supply to the 15.6 million metric tons/year (mmty) LNG and domestic gas plants on Barrow Island.
Wood Mackenzie expects LNG contract renegotiations to take into account the depreciation of JCC in relation to Brent, and sellers may try to push for higher JCC indexation slopes. “However, this may be difficult to achieve in today’s oversupplied market,” Veras said.
Energy Aspects said it’s the makeup of the JCC that may actually prevent it from seeing major impacts because of the IMO 2020 rules. In theory, Dubai sour crude should have been affected by the fall in high sulphur fuel oil demand, but in practice there is a dearth of sour crudes at the moment because of Iran and Venezuela sanctions, analyst James Waddell said. Furthermore, the commissioning of new conversion capacity and new refineries is boosting demand for sour crude.
“This reinforces the view that IMO should not change the JCC-linked LNG price level much,” Waddell said.
That’s not to say there is robust appetite in continuing to price LNG off the Japanese benchmark. Wood Mackenzie, Energy Aspects and some other analysts project that JCC-linked contracts will likely decline over time.
Energy Aspects views oil-indexed LNG contracts as being out of the money at the moment, a trend seen continuing at least through 2020 barring extreme cold and or a Russia-Ukraine transit disruption this winter.
“Buyers on an oil-indexed basis have every incentive to renegotiate their contracts” to introduce other hubs like Henry Hub, the Dutch Title Transfer Facility or other LNG price indexes in order to guard against similar price divergences occurring in the future, Waddell said.
Firms that have to sell oil-indexed cargoes on the spot market are chalking up big financial losses, according to Waddell, amid a downturn in spot LNG pricing and relatively stable oil prices.
In October, Tokyo Gas, Japan’s largest natural gas utility, joined a growing list of companies to renegotiate long-term LNG contracts. The utility has also upped its efforts to diversify supply sources and price formulas by using different types of pricing indexes in an effort to improve competitiveness.
Osaka Gas, one of Japan’s largest utilities, in July said it had begun a price review arbitration against the PNG LNG project, marking the first time a Japanese buyer made such a move. And in August, India’s top gas importer Petronet LNG said it was considering renegotiating long-term supply deals if spot prices remained weak.
Meanwhile, Asian buyers with oil-indexed contracts are starting to face increasing competition from other firms that are able to source spot cargoes because their domestic markets are liberalizing.
“The liberalization means LNG buyers are increasingly less able to simply pass through their LNG supply costs to a captive domestic retail market,” Waddell said. “Sellers will continue to want to sell on an oil-index as this exposure is easier to hedge and gives them better access to financing. But with a lot of export projects looking for buyers for the mid-2020s and spot prices where they are, buyers are in a good position to negotiate a gas market-indexed contract.”
Wood Mackenzie expects Brent to remain favored for buyers that want oil-indexed LNG. Many LNG buyers “will have much to cheer” as the JCC-Brent differential means cheaper LNG, according to Veras.
“Japanese buyers stand to benefit the most, with up to US$8.3 billion worth of savings from JCC depreciation when the IMO 2020 regulation takes effect,” he said. South Korea’s national gas company Kogas and Japan’s Jera Co. Inc. top the list as the biggest savers with a combined US$6.1 billion saved.
Analysts are also unsure about the level of increased LNG bunkering market demand stemming from the new sulphur restrictions on marine fuels.
Wood Mackenzie forecasts a 23% annual growth in LNG demand for marine bunkering, reaching 22 mmty by 2030. “This represents about 11% of marine fuels globally by then, up from only 1.1% in 2019,” Veras said.
Several companies across the globe have already moved to add marine bunkering to their suite of services. Malaysia’s state-owned Petroliam Nasional Berhad, aka Petronas, is seeking to become Southeast Asia’s premier LNG bunkering hub, with a subsidiary in October chartering a 7,500 cubic meter bunker vessel.
In September, natural gas giant Qatar Petroleum and the No. 1 gas seller, Royal Dutch Shell plc, said they were partnering to provide global marine bunkering services, calling them a “promising solution for the shipping industry in light of a continuously evolving regulatory environment.”
Meanwhile, Atlantic Gulf & Pacific Co. has signed a memorandum of understanding with Chart Industries Inc. to develop small-scale solutions for the LNG sector that include bunkering for marine vessels in the Philippines.
The use of LNG in the marine shipping industry has also caught on in Canada, where potential marine engine demand for up to 2.4 mmty, or 122 Bcf, of LNG as of 2025 has been identified by two studies of ships on the country’s Atlantic and Pacific coasts and the Great Lakes.
Canadian gas distributor Gaz Metropolitain and provincial government agency Investissement Quebec last spring completed a C$120 million ($90 million) project that tripled Port of Montreal LNG fuel supplies to about 9 Bcf/year. Merchant marine conglomerate Groupe Desgagnés launched an LNG-fueled, 135-meter (440-foot) oil, asphalt and chemical tanker, the Damia Desgagnés.
However, Poten & Partners is a bit more cautious in its projections. The consultancy’s estimates for LNG bunker demand fall short of Wood Mackenzie’s forecast, with demand potentially rising to only 10 mmty by 2025, or even later.
“At present, there are fewer than 200 LNG-fueled ships, and it will take years for the number of LNG vessels to rise,” Poten analyst Kristen Holmquist said. “There also is a lot of development to do with regard to bunkering infrastructure,” including barges, jetties and other facilities needed to support the additional bunkering.
Ship owners won’t order ships until they are sure they can bunker where they need to, and bunker operators will not invest in the infrastructure until they know there will be ships to sell to, Holmquist said. “It’s almost a chicken-and-egg problem.”
While cheaper LNG could support greater demand for the super-chilled fuel in shipping, it would have to be cheap enough to justify the capital expenditures required to build new infrastructure and LNG-fueled ships, according to Poten. “It’s not enough that LNG will be cheaper on a cash basis. It has to pay back the higher entry costs.”
Earlier this year, the U.S. Energy Information Administration (EIA) said the shortage of equipment and high development costs initially could prevent vessel operators from switching to LNG as a fuel source.
“In the medium and long term, this infrastructure barrier decreases, and LNG’s share of U.S. bunkering grows to 7% in 2030 and to 10% by 2050,” EIA said. Many ships are being built today with LNG-ready engines, which it said could be configured to switch at a later date.
“Overall, however, we have not seen a lot of price elasticity in LNG,” Holmquist said. “Lower LNG prices have not spurred a big increase in demand, at least not yet.”
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