1. What Is Merit Order? The Core Mechanism of JEPX Price Formation
Prices in Japan's electricity market (JEPX) are not set by any single authority but emerge from competitive bidding by all generators. The key concept for understanding this mechanism is the "merit order" — a supply curve that ranks power sources from lowest to highest variable cost (marginal cost).
Under the merit order framework, each generator's rational bidding strategy is to offer at its own variable cost as a floor price, since any clearing price above variable cost covers fuel expenses and contributes to fixed cost recovery. Consequently, JEPX spot prices theoretically equal the variable cost of the "marginal unit" — the last generator dispatched to meet demand.
METI 2024 Variable Costs by Power Source (Marginal Cost)
| Power Source | Variable Cost (yen/kWh) | Notes |
|---|
| Solar / Wind / Hydro | 0 | Zero fuel cost, priority dispatch |
| Nuclear | 1.9 | Must-run, fuel + CO2 cost |
| LNG Thermal | 15.2 | Primary marginal source, fuel + CO2 |
| Coal Thermal | 22.0 | Baseload, high CO2 cost |
| Oil Thermal | 30+ | Peak hours only |
Source: METI Power Generation Cost Verification WG, 5th Meeting (December 2024). Variable cost = fuel cost + CO2 compliance cost.
The table reveals that under normal supply-demand conditions, JEPX spot prices are typically set by LNG thermal generation (15.2 yen/kWh) — which is why fluctuations in JKM (Japan LNG spot benchmark) directly feed through to JEPX prices. When renewables generate heavily (especially on sunny afternoons), solar's zero marginal cost pushes spot prices toward zero or even negative territory. Conversely, during nighttime or cold-winter peak demand, coal or oil thermal becomes the marginal source, and prices can spike above 30 yen/kWh.
2. Power Mix Characteristics of Japan's Nine Electricity Areas
Japan's electricity market is divided into nine wide-area balancing areas, each with a markedly different power mix that directly shapes its price level and volatility profile. The analysis below draws on ISEP's FY2024 Natural Energy White Paper and METI official data.
Hokkaido: Coal-Heavy, Interconnection Constrained
Hokkaido's primary power source is coal thermal, with a variable cost of approximately 22.0 yen/kWh — among the highest baseload sources nationally. Wind and solar capacity has grown rapidly, but the DC interconnection to Honshu (HVDC, approximately 600 MW) limits southward export of surplus renewables, resulting in frequent price splits between Hokkaido and Honshu areas. Hokkaido also records the highest VRE (Variable Renewable Energy) curtailment rate nationally, reflecting grid absorption constraints.
Tohoku: Highest Renewable Ratio Nationally (41.5%)
Tohoku achieved the highest renewable energy ratio of any area in FY2024 at 41.5%, far above the national average of 26.5%. Hydro, wind, and solar dominate, with LNG thermal as a supplement. This high renewable share makes Tohoku prices highly weather-sensitive: sunny or windy periods push prices near zero, while nighttime or calm overcast conditions restore LNG thermal as the marginal source at around 15 yen/kWh.
Tokyo: LNG-Dominant, Largest Demand Area
Tokyo is Japan's largest electricity demand area, with LNG thermal (JERA and others) as the dominant source and coal thermal as a supplement. The high LNG share makes Tokyo prices most sensitive to JKM movements. The Tokyo–Chubu frequency converter (FC) is the principal East–West transmission bottleneck: in October 2024, the FC splitting rate exceeded 90%, with a daily average price differential of 6.5 yen/kWh.
Chubu: LNG and Coal in Balance, Hamaoka Nuclear Offline
Chubu's power mix balances LNG thermal and coal thermal, with meaningful hydro capacity. Hamaoka Nuclear Plant remains offline pending safety reviews, keeping Chubu's nuclear share low. As the East–West power exchange hub, Chubu's FC capacity constraint directly affects national dispatch flexibility.
Hokuriku: High Hydro Share, Surplus-Prone
Hokuriku has one of the highest hydro ratios nationally at approximately 50%, giving it a structurally low marginal cost profile. However, prices are highly sensitive to precipitation: during wet seasons, surplus power generation can push Hokuriku prices well below neighboring areas.
Kansai: Nuclear Restart Advancing
Kansai is the area with the most active nuclear restarts nationally — Ohi, Takahama, and Mihama plants have all returned to service. Nuclear's variable cost of just 1.9 yen/kWh means that abundant low-marginal-cost supply keeps Kansai prices structurally below eastern areas, which is the primary driver of the "East-high, West-low" price differential. LNG thermal serves mainly as a peaking supplement in Kansai.
Chugoku: Coal-Heavy, Shimane Nuclear Restarting
Chugoku's primary source is coal thermal (22.0 yen/kWh). Shimane Unit 2 restarted in December 2024, and Unit 3 is expected online in 2025. The Shimane restarts will gradually improve Chugoku's marginal cost structure.
Shikoku: Balanced Hydro and Nuclear
Shikoku's power mix centers on hydro and nuclear (Ikata Plant), with LNG thermal as a supplement. Ikata's operational status has an outsized impact on Shikoku prices: when the plant runs, costs are low; when it is offline, LNG thermal dominates and costs rise.
Kyushu: Massive Solar Deployment, Highest Curtailment Rate (4.7%)
Kyushu has one of Japan's largest solar deployments, and its FY2024 VRE curtailment rate of 4.7% far exceeds the national average of 1.5%. On sunny afternoons, large-scale solar generation drives spot prices sharply lower, with negative prices occurring frequently. The restarts of Sendai and Genkai nuclear plants further increase the share of low-marginal-cost supply. From a BESS investment perspective, Kyushu's high curtailment rate translates into abundant low-cost or negative-cost charging opportunities, making it the area with the greatest peak-valley arbitrage potential nationally.
3. National Power Mix Trends (FY2021–FY2024)
Japan's national natural energy share reached 26.5% in FY2024, up 4.4 percentage points from 22.1% in FY2021. Nuclear's share recovered from its FY2022 trough of 5.3% to 8.8%, while oil thermal fell sharply from 11.1% to 7.3%. However, the gap to the FY2030 targets (natural energy 36–38%, nuclear 20–22%) remains substantial, particularly for nuclear, which would need to more than double from its current 8.8% — requiring accelerated restarts and potentially new construction.
4. Drivers of Inter-Area Price Differentials and Market Implications
METI's Q4 2024 market monitoring report clearly documents the "East-high, West-low" price differential. Three factors explain this pattern. First, power mix differences: western areas (especially Kansai and Kyushu) have higher nuclear shares, with nuclear's 1.9 yen/kWh variable cost structurally suppressing western prices. Second, interconnection bottlenecks: the Tokyo–Chubu FC splitting rate exceeded 90% in October 2024, producing a daily average East–West price differential of 6.5 yen/kWh. Third, geographic concentration of renewables: Tohoku's high renewable ratio creates localized low prices that cannot fully flow south due to interconnection limits, while Kyushu's high solar curtailment rate reflects local grid absorption constraints.
For trading strategy, JKM movements most directly affect eastern area prices. Inter-area arbitrage opportunities of 5–7 yen/kWh arise during FC splits, but competition for scarce FC capacity is intense. For BESS siting, Kyushu and Tohoku offer the greatest arbitrage potential; Hokkaido's interconnection constraints make intra-area balancing value particularly prominent. Looking ahead, continued nuclear restarts in western areas will sustain or widen the East–West price differential until planned interconnection expansions are completed.
