Japan’s nuclear power restarts could hit LNG imports hard [Gas in Transition]

Japanese demand for LNG could fall by up to 15% (15bn m3/year) if its newly established Green Transformation Council gets its way in 2023. The new “GX” council, chaired by prime minister Fumio Kishida, wants to maximise power generation from fission, by restarting as many of Japan’s idled reactors as possible.

The day before the Fukushima tidal wave in 2011, Japan had 48 reactors available for operation. The disaster took Fukushima’s six reactors out of service immediately, and permanently. The rest were shut down soon after. New safety standards were written which effectively ended the lives of 16 more, because they were too expensive to upgrade for their (short) remaining operating lives, even with extensions.

Fukushima left 26 reactors practically available for use

And then there were 26. With a combined nameplate power capacity of 25,000 MW, but out of service. Japan filled the generation gap mostly with oil and coal. Central government badly wanted that 25,000 MW back online, but approvals from the newly established nuclear regulator were painfully slow to arrive, and when they did local government and local residents blocked restarts all over the network. Two reactors (Sendai 1 and 2) were back up and running by 2015, but others dribbled onto the network painfully slowly. In 2019, Japan’s nuclear fleet produced 63.8bn kWh – about 6% of total power production for the year, and displaced the equivalent of 16bn m3 of LNG-to-power.

Some of the restarts then dribbled slowly off again as local opposition mobilised, and upgrading work also began. Today Japan has only seven reactors in production with an eighth (Mihama 3) hovering on the edge of restart. With frequent outages for maintenance and upgrade of even that small operating fleet Japan’s nuclear power production in 2022 should come out at about 50bn kWh – around 5% of total production.

Japan has filled the nuclear gap with a combination of cheap coal, expensive LNG, and continued use of oil. Oil’s future is troubled because of the G7’s decision to impose a unilateral price cap on Russian crude. That will hit Japan twice – once with Moscow’s public announcement that it will not supply price-capping economies at all, and a second time if Moscow shuts in a couple of million barrels per day of output and global crude prices start rising.

If all the idled reactors were restarted they would displace 36bn m3 of gas imports

The missing nuclear reactors create a material gap in Japan’s power production. If the idled fleet (just over 18,000 MWe in all) went into production at 90% utilisation it would generate 146bn kWh – 14% of Japan’s annual needs. That would displace an equivalent 36bn m3 of gas, or 650,000 barrels/day of oil.

Japan’s gas-powered electricity production is overwhelmingly thermal – great for scale and sunk capital costs but not for thermal efficiency. With all of its reactors back online, Japan’s annual gas demand (102bn m3 in 2021) could drop by just over a third. That will not happen in 2023, but the question is how many of its reactors will Japan restart in 2023.

The GX council may be pressing hard but the Nuclear Regulating Authority (NRA), local authorities and local opposition have learnt to press back too. For example, in May 2019, the NRA ordered Kansai Electric Power to prepare seven of its reactors to cope with volcanic ash from a potential eruption of the long-dormant Mount Daisen volcano. The order potentially affected the four Takahama reactors, but was effectively neutralised by the Nagoya district court in March 2022. Kepco, owner of Takahama, is building a new ash-proof backup control bunker for Takahama 1 and 2, which should be ready by the end of this year. Genkai 3, Ohi 3, Shimane 2, Takahama 1 and 2 and Mihama 3 all look very likely to be running by mid-2023. With a combined 5,300-MWe capacity that group can displace 10bn m3/yr of gas demand on an annualised basis (half that for 2023 as a whole).

The government is slowly winning its arguments

However the government is slowly managing to get its way. If it wins the argument for another third of the idled fleet (6,000 MWe), LNG demand may drop by another 10-12bn m3. The commercial arguments are compelling. At the time of writing Japan’s LNG buyers are paying in the region of $27/mmBtu – or just under $1/m3

Japanese consumers may be happy too. At $1/m3, and with thermal plant conversion rates, LNG-to-power is an expensive strategy – before depreciation, distribution costs and margins LNG power enters the grid at around $0.25/kWh.

LNG is not just expensive, but also strategically high-risk

Cost is not the only issue. LNG is a strategically vulnerable commodity – with a limited number of large suppliers, one of whom is Russia, easy to interdict at sea and hard to store, LNG-to-power is probably the riskiest fuel in Japan’s power portfolio. The Ukraine war has increased those risks, threatening oil imports, oil prices and LNG sources. Coal is currently not a sanctioned commodity but that could change overnight, and in any case, coal-to-power is a big step away from Japan’s stated 2050 carbon neutrality target.

Nuclear power does come with some geopolitical risks attached, usually in the form of access to uranium. Japan has covered this well with a broad uranium sourcing strategy that includes Kazakhstan and Uzbekistan (not ideal), but also Australia and Namibia (both comfortably reliable). Added to that uranium is easy to stockpile, and Japan has a modern domestic fuel processing facility in place, though most enrichment services are currently contracted abroad

Whichever way one looks at the problem, restarting as many reactors as possible as soon as possible remains a good answer to a nest of wicked problems.

Livermore’s fusion ignition news is not a factor, any time in the next lifetime or so

The same cannot be said for fusion. Lawrence Livermore National Laboratory this week announced that it had achieved “fusion ignition.” Cutting through the breathless hype surrounding the story, Livermore’s achievement does not “… put[s] us on the precipice of a future no longer reliant on fossil fuels but instead powered by new clean fusion energy” (in the words of US senate majority leader Charles Schumer). In fact, very far from it.

Using the process of inertial confinement fusion (basically, firing lasers at a fusion fuel target) Livermore used 0.5 kWh of energy to output 0.7 kWh. The target was a pin-head sized pellet containing a minute quantity of (probably) deuterium and tritium. The official announcement was mute on the exact fuel mix.

In this type of “shot” the input laser energy is used to heat a container called a Holhraum (made of some dense metal, details not disclosed by Livermore). The Hohlraum emits X-rays which heat the fuel capsule, turning the case into an exploding plasma whose expansion compresses the fuel in the pellet (something like an implosion fission bomb) to a density many times higher than that of water. The resulting heat triggers fusion.

The Livermore “shot” yielded less than 1% of the energy required to run it

That 0.5 kWh conveniently excludes the energy required to generate the laser beams in the first place – around one hundred times as much again – reducing the shot’s output to a rather small 1% of input energy.

Almost innumerable challenges lie between Livermore’s “shot” and a usable power generation system, including the engineering of a sustained flow of fuel, dealing with the high-intensity neutron flux created by the shot, the problem of extracting generated heat, the scale-up of the process from half a kWh to the 300 kWh/second generated by a 1,000-MW reactor, and reduction in the cost of fuel (Tritium is one of the most expensive elements on the planet, coming in at around $500,000/gram) to list a few. In short, inertial confinement fusion is not going to upset the supply/demand balance for LNG within any rational planning horizon.

Another fusion solution is much closer to realisation, but still too far for LNG to lose sleep

Less noisy, but much closer to realisation, is a magnetic plasma fusion system being developed by privately-owned Helion Energy in Seattle. Helion’s reactor uses Deuterium and Helium 3. Two plasma beams of De/He are fired at each other from opposed plasma chambers at 0.1% of the speed of light, and fuse in the reaction chamber where they collide. Energy is extracted by direct electromagnetic induction, which has the benefit of removing a whole suite of heat exchange, steam-raising and steam turbine plants from the engineering problem. Helion closed a funding deal in November 2021 which saw an initial $0.5bn invested, with commitments of another $1.7bn on milestones achieved.

Helion is currently forecasting energy breakeven in 2024, but even if that is achieved (and fusion research is littered with broken promises of breakeven) much time and distance remains to be covered before Helion produces its first commercial kWh of power. The stages to be passed include moving from occasional “shots” to sustained power, perfection of the fuel preparation cycle and sourcing of Helium 3 (almost as hard as Tritium), then the permitting, design and build of a small-scale test plant which would run for two years. After that, and a period of reflection, the design, permitting and build of a commercial-scale plant. Connecting those dots, with diversions for funding, design dead-ends and unexpected problems, suggests that Helion’s first commercial kWh might flow some time around 2035 at the earliest.

China’s molten salt reactor technology, though, is a near, clear and present danger to LNG

Fusion power wins the headlines, but a much more mundane replacement for Japan’s pressurised water reactors (PWRs) is already operating in a test plant in China. The plant is a molten salt reactor (MSR). First tested in the US in the 1950s and abandoned largely because they contributed nothing to the production of nuclear weapon stockpiles, molten salt reactors have now re-entered the race for low-carbon power generation in a significant way. China has been allocating substantial resources (nearly 1,000 development engineers employed) to MSR development for over a decade.

Earlier this year the Shanghai Institute of Applied Physics (SINAP) won approval from the ministry of environment to start up its experimental thorium-powered MSR in Wuwei about 800 km north of Chengdu. Construction of the 2-MW reactor began in 2018, and it is now believed to be operating.

The new reactor uses molten thorium fluoride as its fuel source in place of enriched uranium, but will start operations with a mainly Uranium fuel load (20% U235), gradually replacing it with thorium as operating experience builds. The initial startup will include 50 kg of thorium fuel. Initially 20% of fission will be sourced from thorium, working up to 80% over the test period.

The nuclear physics of thorium reactors are well understood. The test reactor’s purpose is to test and prove other aspects of the reactor design (for example, how the flux and temperature of the new reactor cause graphite embrittlement inside the reactor vessel). With test data in hand by the end of 2023 a market-scale thorium reactor design will be only a few years away from commissioning.

Molten salt reactors will appease Fukushima-driven paranoias too

Molten thorium reactors may appeal strongly to Japan’s anti-nuclear lobbies. Unlike PWRs, a MSR operates at atmospheric pressure, does not need multiple redundant cooling systems for safe operation, and cannot melt down because fission requires a constant flow of new fuel salt. To stop the reactor it is only necessary to switch off the fuel flow.

MSRs are also fitted with a “freeze plug.” If the reactor overheats the freeze plug melts, draining the molten salt into a cooling pan below the reactor where fissile elements spread out and fission stops.

With the first commercial MSR likely to come into operation by 2026, and with construction costs much reduced by the lack of pressure containment, large duplicated pumps and a high pressure cooling loop, the reactors present a material and near-term threat to the growth of LNG-to-power demand not just in Japan but elsewhere. Each 600-MW unit would displace approximately 1.5bn m3/yr of gas (at thermal plants) and 1bn m3/yr at combined-cycle gas turbine plants. With MSR power likely to cost in the region a few US cents/kWh, the case for switching will be compelling.

If Japan is reluctant to utilise a technology owned by China, it may have an alternative – India is also investing substantial sums in MSR technology, though it is well behind China on the development trail and following a slightly different track.

In Japan’s case, costs might be cut substantially by re-using the steam/power side of existing and retired fission plants with MSRs replacing PWRs as the energy source.

But for the practical present, PWRs, oil and coal will displace LNG in Japan’s fuel mix

However, for at least the next fifteen years Japan’s choices will be limited to restarting its idled PWR fleet, or continuing to spend billions of dollars/month on additional imported LNG or imported crude oil or coal. Oil at $70/b (landed) implies a cost per “raw” kWh of around four US cents. Gas at $27/mn Btu is just over double that. If power companies cannot restart their reactors then restarting their oil-fired plant is likely to displace LNG demand too. 2020 saw 117bn kWh produced from oil – 11% of production. That number is likely to be considerably higher when 2022’s data emerges.

Whichever way the power plant mix pans out, the net result seems to be lower LNG demand from Japan for several years to come. Japan’s LNG import figure for November – 5% down yr/yr – may be a harbinger of more falls to come.