Japan’s Energy Sector: LNG’s Future in a Nuclear Restart

May 4, 2017


Following the global recession in 2008-2009 and the 2011 Tōhoku earthquake and tsunami, the Fukushima accident cast a long shadow over the Japanese energy sector. Japan’s sudden need for alternative sources of energy following the nuclear shutdown forced a shift in energy imports.  LNG imports surged to replace the loss of nuclear power generation.  In 2015, nuclear reactors began to restart, and as of January 2017, twenty-six reactors had applied for permission to restart operations, signaling another shift in Japan’s energy mix. Nuclear restarts will ease Japan’s dependence on LNG as well as facilitate global LNG demand creating a more flexible “buyer’s market”. In Rystad Energy’s base case analysis, we expect 18 reactors to come online by 2025 and Japan’s LNG imports to fall to 69 mtpa, down from 85 mtpa in 2015.  This article highlights the challenges LNG will face as nuclear power resumes operations, Japan’s energy mix outlook and its role in shaping the global LNG market. 

2005 – 2015: Nuclear shutdowns shift energy demand to LNG

After a period of slow growth from 2005 to 2010, Japan’s power sector experienced a substantial change following the 2011 Tōhoku earthquake and tsunami. The resulting nuclear emergency at the Fukushima power plant led to a suspension of all nuclear operations for safety inspections.  In 2010, nuclear operations were producing 288 TWh (~25% of Japan’s energy usage) from fifty-four reactors.  Oil and gas were primarily utilized to make up the immediate shortfall from the nuclear shutdowns.  Oil demand for power generation doubled between 2010 and 2012, increasing from approximately 99 TWh in 2010 to 197 TWh in 2012, accounting for 36% of the 272 TWh lost from nuclear. Gas-for-power generation also increased 100 TWh (to 461 TWh), covering 37% of power demand previously filled by nuclear. In contrast to oil and gas, Japan did not experience any significant increase in coal demand for power generation as coal-fired plants had already been running base load at a high utilization rate. The remaining loss in nuclear power generation was covered by power conservation policies and efficiency gains, leading to an overall decline in power consumption. While oil and gas were the primary contributors to making up the shortfall, oil consumption has retreated to 2010’s level while gas consumption has stayed at the post-nuclear shutdown level of approximately 460 TWh.

Despite little growth in city gas consumption in Japan, gas for power rose, leading to a surge in LNG imports. The country increased LNG imports by 27% within two years, from 70 mtpa in 2010 to 87 mtpa in 2012. Over the same period, Japan’s average LNG import prices climbed from 10.5 USD/MMBtu in 2010 to 16.1 USD/MMBtu in 2012 (while Brent oil prices increased from US$80/bbl to US$111/bbl over the same period). LNG imports peaked in 2014 at 89 mtpa declining in 2015 as nuclear reactors returned to operations. 

2015 – 2025: Nuclear restart resets Japanese energy sector

For the next ten years, Rystad Energy expects growth in the city gas sector and a decline in total power generation. The resumption of nuclear operations will shape Japanese power sector and be the main driver for the country’s LNG imports.

We expect city gas consumption to reach approximately 31 mtpa in 2025 from 27 mtpa in 2015, mainly within the industrial sector as natural gas has gained share from oil products in industrial energy consumption. Total city gas consumption grew by 1% year-over- year between 2005 and 2015. While gas demand in the household and commercial sectors is on a declining trend, industrial demand has been growing, leading to a moderate overall increase in city gas consumption.

Total power generation in Japan has been falling due to power conservation policies, a shrinking population, and weak economic growth. Japan’s power generation mix going forward is highly dependent on the pace and magnitude of its nuclear restarts. The resumption of nuclear operations will reverse the surge in usage of natural gas and oil for power generation that the country experienced in recent years. However, with a lengthy nuclear restart process, we do not expect a rapid decline in gas consumption. Before restart approval, nuclear plants must go through a risk and safety reassessment – “stress test” – carried out by the Nuclear Regulation Authority (NRA). The assessments include simulations on the effects of potential tsunamis, earthquakes and loss of off-site power events. After passing the reassessment test, the restart must be approved by the prime minister and then the local government. Local opposition to restarts is strong as public trust in the safety of nuclear has eroded. 

In Rystad Energy’s base case, Japan will see 12 out of the twenty-six reactors initially under review become operational by 2020. Three of these reactors are already online. Furthermore, we see another six reactors likely to restart by 2025. In our analysis, we have assessed the plant’s geographic position, distance to populated areas, age, status of stress tests as well as political opposition. The restart of 18 reactors by 2025 would add 15.3 GW of nuclear capacity. This equates to power generation of around 100 TWh, or 10% of Japanese power generation in 2025, assuming a 70% nuclear capacity factor. In our high case scenario assuming faster restarts, we expect 26 reactors to come online by 2025, adding 25 GW of capacity. This equates to power generation of about 160 TWh (16% of power generation in 2025). We do not expect the remaining reactors to return by 2025. 















According to the Japanese Government’s Long-Term Energy Supply and Demand Outlook, 22-24 % of electricity will come from renewables by 2030, up from 13.5 % in 2016. The strategy also pushes for nuclear to supply 20-22% of Japanese power generation in 2030 to meet their Greenhouse Gas (GHG) target under the UN’s Intended Nationally Determined Contribution. The restart of nuclear power plants is, however, being strongly challenged by public opposition. Delays in restarting nuclear reactors would require longer-term reliance on LNG, coal, and renewables. In order for Japan to meet their GHG target, renewables would ideally fill the supply gap, but cost considerations may give LNG an advantage over renewable energy sources. 

















In our base case, we expect Japan’s LNG imports to be 69 mtpa by 2025, falling from 85 mtpa in 2015. Our high case scenario, in which nuclear resumes faster, estimates that Japan’s LNG imports could fall to 62 mtpa by 2025.

This fall in LNG imports would mean that Japan is overloaded with long-term contracts. This over-contracted position, combined with inflexible destination clauses could force the country to absorb these contracted volumes and be shut out of the spot market. In an oversupplied market where Japan is unable to renegotiate destination-clauses in long-term contracts, we will see a drop in U.S. LNG flows to Japan. With tolling agreements, no destination clause and a Henry Hub price link, U.S. LNG is the most flexible term supply to Japan (Figure 4), accounting for 20% of total contracted volumes by 2019.

Managing the LNG Market:  global, local, and contract uncertainty converges

Concurrent with its shifting energy mix, Japan is pushing for market reforms and liberalization. In mid-2016, the country’s Fair Trade Commission initiated an investigation into whether destination clauses in LNG contracts impede competition laws. Over 70% of long-term contracts to Japan have destination clauses. If these contracts are found to be in violation, this would significantly strengthen Japan’s negotiating position. The Japanese government is also making efforts to support and increase spot LNG trading. In 2016, the Singapore Exchange and Tokyo Commodity Exchange entered into a cooperation agreement to develop spot LNG market in Asia. In addition, the Japanese government is attempting to break up monopolistic utilities and encourage more third-party power suppliers. Success of these initiatives may simplify the country’s energy burden, reduce price shocks, and help meet GHG emission standards.

According to cost of supply analysis in Rystad Energy’s bottom-up field by field Upstream Database, we forecast Brent crude prices to reach 107 USD/bbl by 2025. This is equivalent to long-term LNG contract prices (14.85% indexed to oil) of 16 USD/MMBtu. We expect Henry Hub prices to fluctuate between 3 and 5 USD/MMBtu towards 2025, mainly based on the breakeven level required to balance US domestic gas production with consumption and export. Asian spot LNG and NBP prices are expected to remain low until the early 2020s as the market is oversupplied. Rystad Energy sees the LNG market rebalancing in the early 2020s as well. New projects will need to be sanctioned then in order to meet demand as existing supplies begin to deplete. 





















Given anticipated rising oil prices, long-term oil-linked LNG contract prices would climb substantially above spot prices. This will lead to strong pressure for contract renegotiation and spot trading.

View from the LNG Exporters Side

Out of countries currently exporting LNG to Japan, the primary suppliers are Qatar, Malaysia and Australia. LNG imports from Qatar, doubled from 2010 to 2012, but have fallen by 25% from 2013 to 2016.


















Given a scenario in which contract renegotiations and spot trading are critical, exporters with lower breakeven costs will be the most flexible and open to new terms. Being one of the suppliers with the lowest breakeven costs and largest available volumes, Qatar is expected to play a key role in shaping a spot LNG market in Japan.

Figure 7 shows short-term marginal cost of various LNG suppliers in 2016. The short-term marginal cost includes all variable costs related to the operation of a project and royalties.  Transportation to market is not included. In an oversupplied LNG market, Qatar recognizes its competitive advantage lies in its low breakeven prices and flexibility. It may be more difficult for other suppliers, like Australia, to accept renegotiations.

















In mid 2020s, Japan may require additional LNG supplies as existing contracts begin to expire. Japanese buyers will certainly prefer exporters that offer flexible short-term contracts. This means countries with the lowest full cycle production costs and large available resources will be preferred providers compared to their competitors. Rystad Energy´s UCube shows that Iran has the lowest breakeven prices for unsactioned LNG projects. The breakeven price is the minimum flat gas price needed to cover the full cycle costs of a project excluding transportation to market. However, whether or not Iran supplies LNG to Japan depends on how quickly LNG projects are sanctioned and developed.  



Overall, the pace and magnitude of the resumption of nuclear operations will be the primary factor in how the Japanese energy sector matures. By lowering gas-for-power generation demand, nuclear will put downward pressure on Japanese LNG demand and consequently long-term contract prices. Concurrent to this will be a need to encourage a more transparent gas trading market. As we have seen the LNG market go through a significant period of expansion, there will need to be change as well.  Regardless of the shift in domestic demand related to nuclear, Japan will continue to rely on LNG as its safest, cleanest, and best option for power generation over the long-term.  But with an increase in the number of importers, exporters, cargoes, and contract options, the LNG market is undergoing a generational shift as well.  As the world’s largest consumer of LNG, Japan must take the lead in modernizing the global LNG market to fit this new reality, both global and domestic.  

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