Japan's Nine-Region Power Market Deep Dive: How Power Mix, Spot Prices, Imbalance Prices, and Renewable Ratios Interact (FY2022–FY2026)

Introduction: Why Are Japan's Nine Regional Power Markets So Different?

Japan's electricity system comprises nine regional grid areas, each exhibiting significant differences in power generation mix, load characteristics, renewable energy penetration, and interconnection capacity. These structural differences not only determine the spot (JEPX day-ahead) average prices in each region but also profoundly influence the formation mechanism of imbalance prices and the frequency and scale of renewable energy curtailment.

During FY2022–FY2024, the national JEPX system average price fell from approximately ¥20/kWh to ¥10–12/kWh, a decline of over 40%. However, this macrotrend masks significant price divergence between regions: Kyushu persistently underperforms the national average due to massive solar penetration, while Hokkaido commands a premium due to interconnection capacity constraints. Understanding these differences is a core prerequisite for formulating regional electricity trading strategies and evaluating BESS investment returns.

1. Regional Divergence in Power Mix: From Nuclear-Dominated to Renewable Frontiers

In FY2024, the nine regions exhibit markedly different structural characteristics in their power generation mix (see figure below).

Kansai, Kyushu, and Shikoku have operating nuclear units, with nuclear shares reaching 28%, 22%, and 20% respectively — creating a stark contrast in marginal cost structure compared to LNG-heavy Tokyo (40%) and Chubu (35%). Hokkaido relies on coal (35%) as its base power source and has a relatively high wind share (12%), presenting a distinctive "coal + wind" combination.

Tohoku has the highest renewable energy share in the country, with solar + wind + hydro combined reaching 46%. However, constrained by interconnection capacity to Tokyo (approximately 1,200 MW), large volumes of cheap electricity cannot be transmitted southward, creating a structural "northern surplus, southern deficit" problem.

Region	Primary Base Power	Renewable Share (FY2024 est.)	Nuclear Status
Hokkaido	Coal (35%)	28%	Tomari 1–3 offline
Tohoku	LNG (18%) + Renewables	46%	Onagawa Unit 2 restarted (Nov 2024)
Tokyo	LNG (40%)	22%	Kashiwazaki-Kariwa under review
Chubu	LNG (35%) + Coal (35%)	20%	Hamaoka all units offline
Hokuriku	Coal (38%) + Hydro (28%)	40%	Shika under review
Kansai	Nuclear (28%)	25%	Ohi 3–4, Takahama 1–4 operating
Chugoku	Coal (42%)	34%	Shimane Unit 2 restarted (Dec 2024)
Shikoku	LNG (18%) + Coal (20%)	38%	Ikata Unit 3 operating
Kyushu	Nuclear (22%)	38%	Sendai 1–2, Genkai 3–4 operating

2. Spot Price Trends: Regional Divergence Within a Broad Decline

The FY2022 energy crisis pushed national spot averages to ¥18–22/kWh. As LNG spot prices retreated, nuclear restarts progressed, and renewable penetration increased, FY2023–FY2024 saw prices fall sharply to ¥9–13/kWh (see figure below).

Kyushu's FY2024 annual average spot price of approximately ¥9/kWh is the lowest among all regions, about 10% below Tokyo. This phenomenon stems from the convergence of three structural factors:

1. Nuclear low marginal cost: Continuous operation of Sendai and Genkai's four units provides large volumes of low-marginal-cost baseload power.
2. Massive solar penetration: Kyushu's solar installed capacity exceeds 14 GW, causing frequent daytime supply surpluses.
3. Interconnection capacity constraints: Limited interconnection capacity from Kyushu to Chugoku makes it difficult to export surplus power northward, creating regional low prices.

By contrast, Hokkaido commands a relative premium due to interconnection constraints (the Hokkaido-Honshu HVDC link is only 600 MW), with FY2024 average prices around ¥12/kWh — approximately 33% above Kyushu.

3. Imbalance Prices: The Hidden Risk in High-Renewable Regions

Imbalance prices are the most volatile price signal in the electricity market. In regions with high renewable shares, the intraday variability of solar generation causes frequent imbalance volumes, pushing up both the peak and average of imbalance prices.

FY2024 data shows that high-renewable regions such as Kyushu and Shikoku exhibit annual average imbalance price premiums (relative to spot average) of 1.5–2×. This means that in these regions, electricity retailers who fail to accurately forecast load or generation face significantly higher imbalance costs.

The structural imbalance price premium also creates arbitrage opportunities for BESS: charging at low prices during daytime solar peaks (even at negative prices during curtailment events), discharging at high prices during evening load peaks, while simultaneously providing imbalance adjustment services.

4. Renewable Share and Curtailment: Kyushu's Predicament as a National Microcosm

The rapid increase in renewable penetration has led to a sharp deterioration in curtailment problems. In FY2024, Kyushu's curtailment events reached 168 times, a 46% increase from 115 times in FY2022 (see figure below).

The root cause of curtailment lies in the dual constraint of "supply surplus + interconnection congestion." When solar generates heavily, if nuclear baseload cannot be reduced quickly and interconnection capacity is insufficient to transmit surplus power to higher-demand regions, curtailment becomes the only means of maintaining system frequency.

Tohoku's situation also warrants attention: despite a renewable share as high as 46%, curtailment events reached 31 times in FY2024 with an accelerating growth trend. The restart of Onagawa Unit 2 (November 2024) further compresses the system's adjustment margin, and curtailment pressure is expected to continue rising in FY2025–FY2026.

Kyushu Curtailment Monthly Distribution: A Spring-Autumn Dual-Peak Structure

The monthly distribution chart reveals a clear seasonal dual-peak structure: April–May (spring) and October–November (autumn) are the curtailment peaks, while summer (July–August) sees minimal curtailment due to high air-conditioning demand. This pattern directly reflects the mismatch between solar output and system demand — spring and autumn have abundant sunshine but lower demand, compounded by nuclear inflexibility, creating the tightest system adjustment margins of the year.

For BESS investors, the spring and autumn curtailment peaks are also the most arbitrage-dense periods: absorbing curtailed power during the day (low-price charging) and discharging during the evening peak maximizes price-spread revenue. FY2025 estimates indicate curtailment pressure will remain above FY2024 levels, with BESS arbitrage windows expected to widen further.

5. Key Metrics Heatmap: The Full Picture of Three-Year Trends

The heatmap clearly reveals three core trends:

1. Broad spot price decline: All regions have retreated from FY2022 highs, with Kyushu showing the largest decline (¥18→¥9).
2. Sustained renewable share growth: Tohoku (38%→46%), Kyushu (30%→38%), and Shikoku (32%→38%) are growing fastest.
3. Curtailment concentrated in western Japan: Kyushu far exceeds other regions, followed by Tohoku, Shikoku, Chugoku, and Hokkaido. Tokyo, Chubu, and Kansai are near zero.

6. Renewable Trend Outlook: Structural Pressure in FY2026

Based on OCCTO's FY2024 supply-demand outlook and each region's renewable new capacity plans, Tohoku, Kyushu, and Shikoku's renewable shares are projected to exceed 50%, 42%, and 42% respectively during FY2025–FY2026. This will further intensify curtailment pressure and increase imbalance price volatility in these regions.

Another key variable for FY2026 is the full launch of the day-ahead market (前日市場). From FY2026, the EPRX balancing market will shift some products to day-ahead competitive bidding, which will change the behavioral patterns of the adjustment power supply side and create new influences on the linkage between spot and imbalance prices.

7. Implications for BESS Investment Strategy

Synthesizing the above analysis, BESS arbitrage opportunities vary significantly by region. Kyushu remains the most attractive region for BESS arbitrage, but as competition intensifies and interconnection expansion plans progress (Kyushu–Chugoku capacity increase expected to complete in 2027), arbitrage margins may gradually narrow. Tohoku, with accelerating curtailment pressure following the Onagawa restart, is emerging as the next window of arbitrage opportunity worth close attention.

References

1. OCCTO. "Outlook for Electricity Supply-Demand and Cross-Regional Interconnection Lines FY2024." November 2025.
2. OCCTO. "Annual Report 2025." January 2026.
3. ISEP. "自然エネルギー電力の割合（2024年度）." 2025.
4. Asia RE Engage. "Japan's Power Market Transition." November 2025.
5. Skipping Stone. "Japan Energy Market Update 2024." October 2024.