1. Background: Balancing Market Freedom and Supply Obligation for Stable Power Sources
The fundamental design philosophy of Japan's capacity market is to ensure electricity system supply reliability while granting stable power sources substantial market freedom. The core obligation of stable power sources under capacity assurance contracts is singular: during system supply-demand tightening, provide supply capability equal to or exceeding their contracted capacity within 3 hours of a TSO instruction. Beyond this obligation, stable power sources are entirely free to bid in the day-ahead market, intraday market, and balancing market based on their own commercial judgment.
However, this "freedom" comes with a constraint. Stable power sources must maintain the ability to fulfill their supply obligation at all times. This means that day-ahead sell volumes, balancing market adjusting capacity commitments, and intraday real-time bids must all be executed under the premise of "retaining sufficient supply capability to respond during supply-demand tightening." How to optimally balance "maximizing revenue through free bidding" against "maintaining obligation fulfillment capacity" is the most critical practical challenge for stable power source operators.
From April 2026, the balancing market will fully shift from weekly to day-ahead procurement (30-minute products), shortening the adjusting capacity product unit to half-hour intervals. Stable power sources must revise their adjusting capacity provision strategies accordingly. In October 2026, the JEPX intraday market will complete its system migration to API-based trading and publish bid information for five regional zones. The cross-market bidding framework in this article is designed specifically for the practical needs of stable power sources in this new institutional environment.
2. Stable Power Sources and Dispatch Instruction Power Sources: Core Obligations and Market Position
Capacity market participants are classified into three categories based on supply stability: Stable Power Sources (安定電源), Variable Power Sources (変動電源), and Dispatch Instruction Power Sources (発動指令電源). Stable power sources are the dominant category, accounting for the vast majority of contracted capacity, while dispatch instruction power sources are supplementary resources with an introduction cap of 5% of total capacity (main auction 4% + additional auction 1%).
2.1 Definition and Core Obligations of Stable Power Sources
According to METI's "Capacity Market Bidding Guidelines" (last revised June 2025), a Stable Power Source is defined as a power source with an expected capacity of 1,000 kW or more that can provide stable supply capability. The following types are eligible:
| Power Source Type | Eligibility Conditions |
|---|
| Hydropower | Regulated, reservoir, or pumped-storage type (generation possible for 3+ hours) |
| Thermal power | — |
| Nuclear power | — |
| Renewable energy | Only those capable of stable supply (solar and wind are generally excluded) |
| Battery storage | Generation possible for 3+ hours |
The core obligation of stable power sources under capacity assurance contracts is to provide supply capability equal to or exceeding their contracted capacity within 3 hours of a TSO instruction during system supply-demand tightening, and to maintain this capability throughout the delivery year. The kW remuneration (annual fixed income) is the consideration for this obligation and is received regardless of whether the source is actually dispatched.
The market position of stable power sources far exceeds that of dispatch instruction power sources. In the FY2029 main auction, stable power sources accounted for over 95% of contracted capacity, forming the backbone of Japan's electricity supply reliability. Stable power sources are entirely free to bid in the day-ahead and intraday markets based on their own commercial judgment, with no direct restrictions from the capacity assurance contract (provided they maintain the ability to fulfill their supply obligation during supply-demand tightening).
2.2 Definition and Core Obligations of Dispatch Instruction Power Sources
Dispatch Instruction Power Sources are power sources that are difficult to operate continuously—such as on-site generation facilities, demand response (DR) resources, specific curtailment requests (consumer energy-saving requests), or combinations of generation equipment with individual expected capacities below 1,000 kW—that collectively provide 1,000 kW or more of supply capability. The fundamental distinction from stable power sources is that they can only provide supply after receiving a "dispatch instruction" from OCCTO.
According to the OCCTO 25th Capacity Market Review Committee (May 2020), dispatch instruction power sources are expected to prioritize listing their electricity on the intraday market after receiving a dispatch instruction, for retail electricity companies to procure. If the intraday market fails to settle, the TSO will use the electricity as adjusting capacity, and the kWh settlement price will be the "highest contracted price α" in the intraday market for that area.
2.3 Stable Power Sources vs. Dispatch Instruction Power Sources: Comparison
| Comparison Item | Stable Power Sources | Dispatch Instruction Power Sources |
|---|
| Supply stability | High (continuous stable supply possible) | Low (continuous operation difficult) |
| Minimum expected capacity | 1,000 kW or more | 1,000 kW or more (combinations allowed) |
| Primary eligible types | Thermal, hydro, nuclear, stable renewables, battery storage | On-site generation, DR, small-scale generation equipment |
| Dispatch mechanism | Autonomous supply during supply-demand tightening (obligation) | Supply after receiving OCCTO dispatch instruction |
| kW remuneration | Annual fixed income (regardless of dispatch) | Annual fixed income (regardless of dispatch) |
| kWh settlement | Free settlement based on market contracted price | Intraday market contracted price β, or highest contracted price α |
| Introduction cap | No limit | 5% of total (main 4% + additional 1%) |
| Day-ahead/intraday market bidding | Completely free | After dispatch instruction: prioritize intraday market sell bids |
2.4 Dual Registration System for Stable Power Sources (Applicable from FY2025 Additional Auction)
The Bidding Guidelines (footnote 5) establish an important new rule: if a stable power source has supply capability exceeding its contracted capacity, and can provide that excess as a dispatch instruction power source during supply-demand tightening, it may register as both a stable power source and a dispatch instruction power source under the same metering unit.
This system applies from the FY2025 additional auction (delivery year FY2025) and FY2026 main auction, with the following practical implications:
- Revenue maximization: The power source can simultaneously receive kW remuneration as a stable power source (fixed income) and additional kW remuneration as a dispatch instruction power source, improving capacity market revenue without additional capital investment.
- Target resources: Primarily applicable to fast-start thermal power sources (e.g., LNG peakers) and large-scale battery storage. These resources operate as stable power sources under normal conditions and can further increase output during extreme supply-demand tightening to provide additional supply as dispatch instruction power sources.
- Registration requirements: Separate registrations as both stable power source and dispatch instruction power source must be completed in the capacity market power source information registration system, and must pass OCCTO's review.
3. Optimal kW Bid Strategy for Stable Power Sources in the Capacity Market
The bid price that a stable power source submits in a capacity market auction directly determines whether it can secure a capacity assurance contract at a reasonable kW remuneration. A bid price that is too high risks failing to win the auction; too low compresses long-term investment recovery. The optimal bid price calculation framework consists of three core components: Marginal Cost (MC), Opportunity Cost (OC), and Fixed Cost Recovery Requirement (FC).
3.1 Marginal Cost (MC): Direct Cost of Capacity Assurance
Marginal cost refers to the direct costs incurred to maintain the standby state of "able to supply within 3 hours during supply-demand tightening."
| Cost Item | Description | Typical Range (Thermal) |
|---|
| Standby Fuel Cost | Fuel consumption for hot standby maintenance | ¥50–¥200/kW·year |
| Periodic Maintenance | Equipment maintenance cost allocation during capacity assurance period | ¥500–¥2,000/kW·year |
| Personnel Standby | Standby personnel costs for emergency startup | ¥100–¥500/kW·year |
| Incremental Insurance | Additional insurance premiums during capacity assurance period | ¥50–¥200/kW·year |
For battery storage and other fuel-free resources, marginal cost is primarily composed of battery capacity opportunity cost (see next section) and maintenance expenses.
3.2 Opportunity Cost (OC): Impact of Capacity Assurance on Market Revenue
Opportunity cost is the revenue foregone from other markets due to holding the capacity assurance obligation. For stable power sources, opportunity cost arises from two main dimensions.
(1) Day-Ahead Market Sales Constraint: To preserve supply capability during supply-demand tightening, stable power sources cannot sell 100% of their generation capacity in the day-ahead market. For example, a 100 MW plant with 80 MW contracted capacity must retain at least 80 MW of supply capability during high-demand periods, constraining day-ahead market sales.
| Scenario | Calculation |
|---|
| Normal conditions (no tightening) | OC ≈ 0 (free to sell full capacity) |
| Supply-demand tightening probability p | OC = p × contracted capacity × (expected day-ahead price − marginal generation cost) |
(2) Balancing Market Participation Constraint: Providing upward adjusting capacity (Tertiary Reserve ② etc.) requires retaining corresponding reserve capacity, which overlaps with the supply capability reserve required by the capacity assurance obligation. This must be considered holistically in the bid strategy.
3.3 Fixed Cost Recovery Requirement (FC): Long-Term Investment Recovery
Fixed cost recovery is the most important—and most frequently underestimated—element in a stable power source's bid strategy. Fixed costs include:
| Cost Category | Description |
|---|
| Capital Expenditure (CAPEX) | Annualized amortization of construction/acquisition costs (depreciation + cost of capital) |
| Fixed O&M | Annual maintenance and personnel costs independent of generation volume |
| Fixed Fuel Costs | Fixed capacity charges under LNG long-term contracts (Take-or-Pay) |
| Taxes | Fixed asset taxes and other charges independent of generation volume |
Fixed costs must be jointly recovered through kW remuneration (capacity market revenue) plus kWh revenue (electricity sales). The minimum bid price floor is:
Minimum Bid Price = FC_annual ÷ Contracted Capacity − Expected Net kWh Revenue ÷ Contracted Capacity
"Expected net kWh revenue" is the annual expected revenue from day-ahead, intraday, and balancing markets minus variable costs. If kWh market revenue is sufficient to cover fixed costs, the bid price can approach zero. If insufficient, the shortfall must be covered by kW remuneration.
3.4 Integrated Optimal Bid Price Calculation
Integrating the three components above, the optimal bid price calculation framework is as follows:
| Component | Calculation Basis | Impact on Bid Price |
|---|
| Marginal Cost (MC) | Standby cost + maintenance allocation | Forms the lower bound of the bid price |
| Opportunity Cost (OC) | p × capacity × (day-ahead price − VOM) | Higher tightening probability → higher OC |
| Fixed Cost Gap (FC gap) | FC_annual − expected net kWh revenue | Lower kWh market revenue → larger FC gap |
| Optimal Bid Price | (MC + OC + FC gap) ÷ Contracted Capacity | — |
In practice, since both the supply-demand tightening probability (p) and future kWh market prices are uncertain, stable power source operators typically use scenario analysis—setting pessimistic, base, and optimistic scenarios—and use the weighted average as the reference value for the final bid price.
3.5 Thermal Power vs. Battery Storage: Fundamental Differences in Bid Strategy
Although thermal power sources and battery storage are both classified as stable power sources, their capacity market obligations and bid strategies differ fundamentally. Understanding these differences is a prerequisite for developing an optimal bid strategy.
(1) Power Source Classification and Expected Capacity Calculation
According to OCCTO's "Supplementary Explanation on Expected Capacity Calculation Parameters" (August 2024), stable power sources are further divided into two sub-groups, each with a different expected capacity calculation method:
| Item | Thermal Power (excl. pumped hydro & batteries) | Battery Storage (pumped hydro & battery group) |
|---|
| Expected capacity basis | Maximum supply capacity per month (annual minimum) | Transmittable power × adjustment coefficient (monthly minimum) |
| Additional input required | Maximum supply capacity per month only | Monthly operating or discharge duration (mandatory) |
| 3-hour requirement | None (can supply continuously as long as fuel is available) | Mandatory (months with discharge duration < 3 hours result in reduced expected capacity) |
| Management capacity deduction | None | Monthly management capacity (for charge/discharge management) is deducted |
For battery storage to participate in the capacity market as a stable power source, a discharge duration of at least 3 hours is a prerequisite. Batteries with less than 3 hours of discharge duration cannot register as stable power sources and can only register as dispatch instruction power sources.
(2) Differences in Bid Price Calculation
| Cost Element | Thermal Power | Battery Storage |
|---|
| Fixed costs (CAPEX) | Annualized depreciation of power plant construction costs | Annualized depreciation of battery system construction costs (incl. battery modules) |
| Fixed O&M costs | Equipment maintenance, personnel costs | Equipment maintenance, personnel costs |
| Battery replacement costs | None | Must be included (charge/discharge cycles × degradation cost) |
| Fuel fixed costs | Fixed capacity fees under long-term LNG contracts (Take-or-Pay) | None (no fuel required) |
| Opportunity cost (OC) | Lost generation opportunity during supply-demand tightening | Lost day-ahead/intraday market sales opportunity for SOC maintenance + charging costs |
| Charging costs | None | Must be included (cost of electricity purchased for charging before obligation fulfillment) |
Battery optimal bid price = (CAPEX + Fixed O&M + Battery replacement costs − Expected net kWh revenue) ÷ Bid capacity + Opportunity cost + Charging cost
The opportunity cost for battery storage is far more complex than for thermal power. To maintain the SOC (state of charge) required for capacity market obligation fulfillment, batteries must forgo some of their day-ahead and intraday market discharge opportunities. Accurately estimating this constraint cost is the core challenge of battery storage bid strategy.
(3) Long-Term Decarbonization Auction: A Mechanism Exclusive to Battery Storage
In addition to the main auction, battery storage is eligible to participate in the Long-Term Decarbonization Power Source Auction. Thermal power sources cannot use this mechanism.
| Item | Main Auction | Long-Term Decarbonization Auction |
|---|
| Eligible power sources | All power sources (thermal, batteries, etc.) | Decarbonization sources only (batteries, renewables, etc.) |
| Output requirement | 1,000 kW or more | 10 MW or more (30 MW or more for combined projects) |
| Revenue period | 1 year (annual bidding) | In principle, 20 years from the year after commercial operation begins |
| FY2024 results | — | Over 70% of contracted projects were battery storage |
Battery storage that wins the Long-Term Decarbonization Auction secures stable kW revenue for 20 years—a significant advantage unavailable to thermal power sources. The choice between the Long-Term Decarbonization Auction and the main auction is therefore a critical strategic consideration for battery storage operators.
3.6 Pumped Hydro Power Sources: Bidding Strategy Differences
Pure pumped hydro power sources (純揚水グループ) belong to the same "Pure Pumped Hydro / Battery Storage Group" as batteries, sharing the same expected capacity calculation method (both must satisfy the 3-hour continuous supply requirement). However, their charging cost structure differs fundamentally from batteries, leading to distinct bidding strategies.
Cost Structure of Pure Pumped Hydro
| Cost Item | Pure Pumped Hydro | Battery Storage |
|---|
| Charging Cost | Nighttime pumping electricity cost (JEPX night spot price × pumping volume) | Charging electricity cost (JEPX spot price × charging volume) |
| Efficiency Loss | Pumping efficiency ~70–80%: pump 1kWh → generate 0.7–0.8kWh | Round-trip efficiency ~85–95%: charge 1kWh → discharge 0.85–0.95kWh |
| Capacity Constraint | Upper reservoir volume (MWh) determines maximum continuous generation time | Battery capacity (MWh) determines maximum discharge time |
| Degradation Cost | Near zero (hydraulic equipment lifespan 40–60 years) | Battery degradation cost (~0.1–0.3% per charge-discharge cycle) |
| Fixed Costs | Civil engineering & construction (very high CAPEX, mostly already amortized) | Battery equipment (high CAPEX, amortization period 10–15 years) |
Optimal Bid Price Calculation for Pure Pumped Hydro
The optimal bid price (P_bid) for pure pumped hydro can be calculated using the following framework:
| Cost Item | Calculation | Notes |
|---|
| Pumping Electricity Cost (MC_pump) | P_night / η_pump (¥/kWh ÷ efficiency) | P_night = JEPX average spot price during nighttime pumping hours; η_pump = pumping efficiency (0.75 typical) |
| Opportunity Cost (OC) | P_peak − P_night / η_pump | Day-ahead market peak-valley spread minus pumping cost = arbitrage opportunity |
| Fixed Cost Recovery (FC) | Annual fixed costs ÷ Annual expected capacity (kW) | Civil/electrical equipment maintenance, depreciation, etc. |
| Optimal Bid Price (P_bid) | MC_pump + FC − OC | High OC allows lower bid price; low OC requires capacity payment to cover fixed costs |
Pure Pumped Hydro vs. Battery Storage: Bidding Strategy Comparison
| Comparison Item | Pure Pumped Hydro | Battery Storage |
|---|
| Primary Revenue Source | Day-ahead peak/off-peak arbitrage (pump at night, generate during day) | Day-ahead arbitrage + balancing market + surplus capacity utilization contracts |
| Capacity Market Bid Priority | Medium (lower capacity payment need when day-ahead arbitrage revenue is high) | High (capacity payment is a foundational guarantee for multi-market revenue stacking) |
| SOC Management Complexity | Low (upper reservoir water level management is relatively intuitive) | High (requires precise SOC_min calculation and dynamic adjustment) |
| Supply Tightness Obligation | Same as batteries: 3-hour continuous supply | Same as pumped hydro: 3-hour continuous supply |
| Long-term Decarbonization Auction Eligibility | Generally not applicable (existing facilities) | Applicable (new battery storage can participate in 20-year revenue guarantee auction) |
| Maximum Bid Capacity | Upper reservoir max generatable volume (MWh) ÷ 3 hours = max kW | Battery capacity (MWh) ÷ 3 hours = max kW |
The core advantage of pure pumped hydro is near-zero degradation cost. Although pumping efficiency is lower than batteries, upper reservoir capacity typically far exceeds battery capacity, enabling longer continuous supply. During supply tightness events, pumped hydro's obligation fulfillment capability is generally more stable than batteries, making its position in the capacity market no less significant than battery storage.
4. Key Changes from the April 2026 Balancing Market Reform
The April 2026 balancing market reform is the most significant institutional change in recent years, with profound implications for dispatch instruction power source bidding plans. The core of the reform is shifting all balancing products from weekly procurement to day-ahead procurement (30-minute products).
| Item | Before Reform (Weekly) | After Reform (Day-Ahead, from April 2026) |
|---|
| Procurement frequency | Once per week | Daily (day-ahead) |
| Product unit | Weekly block | 30-minute product |
| Combined product price cap | ¥19.51/ΔkW·30min | ¥7.21/ΔkW·30min |
| Low-voltage resource participation | Not allowed | Allowed (device-level measurement required) |
| Imbalance price cap (C-value) | ¥200/kWh | ¥300/kWh |
| Imbalance price (D-value) | ¥30/kWh | ¥50/kWh |
The combined product (Tertiary Reserve II) ΔkW price cap drops sharply from ¥19.51 to ¥7.21, narrowing the kW revenue margin in the balancing market. However, the increase in imbalance prices (C-value from ¥200 to ¥300, D-value revised to ¥50) raises the penalty cost for imbalance states, strengthening incentives for accurate forecasting and bidding.
4. Cross-Market Bidding Plan Framework
The following is a bidding plan framework for dispatch instruction power sources covering a complete supply day, encompassing all four market stages.
4.1 Capacity Assurance Contract Stage (Pre-Year)
After winning the capacity market main auction, the power source signs a capacity assurance contract with OCCTO, confirming the minimum assured capacity (kW), dispatch instruction response timing, and kW consideration (annual fixed income). The core decision at this stage is verifying that the power source's technical parameters (startup time, minimum output, ramp rate) meet the "supply within 3 hours" requirement.
4.2 Balancing Market Bidding (Day-Ahead, Post-Reform)
From April 2026, the balancing market shifts to day-ahead procurement. Dispatch instruction power sources can submit ΔkW bids for Tertiary Reserve II (30-minute products) during the day-ahead procurement window (typically the previous afternoon). Key bidding strategy considerations include:
- ΔkW bid volume: Must not exceed the minimum assured capacity under the capacity assurance contract, to avoid dual-obligation conflicts.
- ΔkW bid price: Set with reference to the combined product cap of ¥7.21/ΔkW·30min, factoring in startup costs and opportunity costs.
- Coordination with day-ahead market: If balancing market bids are settled, reserve the corresponding capacity in the day-ahead market bidding plan to prevent over-selling in the day-ahead market and failing to fulfill balancing obligations.
4.3 Day-Ahead Spot Market Bidding (Before 12:00 Gate Close)
The JEPX spot market gate close is at 12:00 the previous day. Dispatch instruction power sources should consider the following at this stage:
- Available capacity confirmation: After deducting the ΔkW capacity already contracted in the balancing market, the remaining capacity can be sold in the day-ahead market.
- Dispatch instruction probability assessment: If system supply-demand forecasts indicate high emergency risk (e.g., summer peak, cold wave), retain more capacity for potential dispatch instruction and reduce day-ahead market sales.
- Bid price strategy: The day-ahead market uses Uniform Price clearing. Use marginal cost (fuel cost + amortized startup cost) as the bid floor to avoid losses from low-price settlement.
4.4 Intraday Market Bidding (Before T-1 Hour Gate Close)
The JEPX intraday market gate close is 1 hour before the supply period. This stage is the critical juncture for dispatch instruction power sources to realize kWh revenue:
- Post-dispatch-instruction operations: TSOs typically issue dispatch instructions 3 hours before actual supply. Upon receiving the instruction, the aggregator should immediately list the corresponding electricity volume on the intraday market for retail electricity companies to procure.
- Handling unsettled cases: If the intraday market fails to settle (no settlement before gate close), the TSO will use the electricity as adjusting capacity, and the kWh settlement price will be the highest contracted price α in the intraday market for that area and time period.
- Post-October 2026 transparency improvement: JEPX will publish intraday market bid information for five regional zones, enabling more accurate assessment of settlement probability and the highest contracted price α.
5. Handling Simultaneous Dispatch Instruction and Balancing Market Instruction
According to the OCCTO 39th Balancing Market Review Committee (June 2023), when a dispatch instruction power source simultaneously receives a "dispatch instruction" (based on capacity assurance contract) and a "balancing market adjustment instruction" (based on balancing market contract), it must satisfy the ΔkW requirements of both simultaneously. This is one of the most complex scenarios in the current institutional design.
The current institutional resolution direction is as follows: if the power source's actual output cannot simultaneously satisfy both the dispatch instruction ΔkW requirement and the balancing market adjustment instruction ΔkW requirement (e.g., insufficient unit capacity), the situation is treated as "intentionally failing to meet one of the requirements," with related penalty measures and substitute coverage cost allocation still under deliberation (expected to be clarified from FY2027 onwards). Power source operators are advised to maintain sufficient capacity buffers when bidding in the balancing market to avoid dual-obligation conflict scenarios.
6. kWh Settlement Price Calculation Logic
The kWh revenue of dispatch instruction power sources falls into two scenarios, with the following settlement price calculation logic:
| Scenario | Settlement Price | Description |
|---|
| Intraday market settled (normal case) | Intraday market contracted price β | Aggregator and retailer settle in intraday market at contracted price β |
| Intraday market unsettled (TSO uses as adjusting capacity) | Highest contracted price α in intraday market for that area | TSO uses as adjusting capacity; settlement at highest contracted price α for same period and area in intraday market, ensuring fair compensation for dispatch instruction power source |
The policy intent of this design is to ensure that even when the retail market cannot absorb the electricity from dispatch instruction power sources, the power source still receives compensation close to market equilibrium, avoiding kWh revenue losses due to dispatch instructions and thereby maintaining long-term investment incentives for the capacity market.
7. Practical Implications of the 2026 JEPX System Migration
JEPX will complete the day-ahead market system migration (from GUI to API) in April 2026 and the intraday market system migration in October 2026. The practical implications for dispatch instruction power source bidding plans are as follows:
- API bidding system construction: Power source operators and aggregators must complete day-ahead market API integration by April 2026 to ensure automatic bid submission before gate close.
- Intraday market automation: Building automated trigger mechanisms for intraday market listing operations after receiving dispatch instructions is recommended (target: within 30 minutes from instruction receipt to bid submission).
- Fees unchanged: JEPX confirms FY2026 transaction fees remain unchanged (day-ahead ¥30/MWh, intraday ¥100/MWh), with no impact on bidding cost calculations.
8. Practical Recommendations: Five Steps for Bidding Plan Development
Synthesizing the above analysis, the following five-step framework is recommended for dispatch instruction power sources developing cross-market bidding plans:
- Confirm capacity assurance contract parameters: Minimum assured capacity (kW), dispatch instruction response timing, kW consideration.
- Day-ahead system supply-demand risk assessment: Reference OCCTO supply-demand balance forecasts to evaluate dispatch instruction probability and determine capacity retention ratio.
- Balancing market bidding (previous afternoon): Submit ΔkW bids for Tertiary Reserve II within the retained capacity range. Set ΔkW price with reference to the ¥7.21 cap.
- Day-ahead market bidding (before 12:00 the previous day): Sell remaining capacity after deducting balancing market contracted capacity in the day-ahead market. Set bid price with marginal cost as the floor.
- Intraday market dynamic adjustment (before T-1 hour): Upon receiving dispatch instruction, immediately submit sell bids in the intraday market. If no instruction received, perform residual adjustment (buy or sell) in the intraday market based on actual output status.