Capacity Mechanisms
Energy-only markets pay generators only for energy produced (and ancillary services). But the system also needs adequate capacity — enough generation available to meet peak demand even in extreme conditions. The debate: will energy prices alone attract sufficient investment, or does the market need a separate capacity payment to ensure security of supply?
The Missing Money Problem
The theoretical argument for capacity mechanisms rests on two market failures:
- Price caps suppress scarcity rents: In an uncapped energy-only market, prices during scarcity hours would rise to the Value of Lost Load (VoLL, estimated at 10,000-20,000 €/MWh). These rare, extreme prices would signal new investment. But regulators cap prices (currently 4,000 €/MWh in SDAC) — the difference between capped and uncapped revenue is the "missing money."
- Risk aversion and investment uncertainty: Even without caps, investors may not build peakers that run only 50-200 hours/year based on the expectation of extreme price spikes. The revenue stream is too volatile and unpredictable for project finance.
The paradox: If you believe markets are efficient and price caps non-binding, there is no missing money — the energy-only market with scarcity pricing provides correct investment signals. If you believe real markets have imperfections (caps, demand inelasticity, political intervention risk), capacity payments are insurance against under-investment. This is the central policy debate in European electricity market design.
The Design Spectrum
Capacity mechanisms range from minimal intervention to full parallel markets:
1. Strategic Reserve
Minimal — last-resort capacity held outside the market
The TSO contracts generation (or demand response) to remain available as a reserve of last resort. This capacity is NOT offered into normal markets — it activates only when the market has exhausted all resources. Preserves energy market price formation.
Examples: Sweden (since 2003), Belgium (strategic reserve pre-CRM), Germany (Kapazitätsreserve, 2 GW)
Pros: Low market distortion; capacity is out-of-market. Cons: Doesn't send investment signals to the wider market; may keep old inefficient plants alive.
2. Targeted Capacity Payment
Administrative — fixed payment per MW to designated plants
The regulator determines how much capacity is needed and pays a fixed €/MW/year to existing or new capacity. The payment level is set administratively (not market-determined). Spain and Italy (until reform) used variants.
Pros: Simple to implement. Cons: No competitive price discovery; risk of over/under-payment; can distort cross-border trade (State Aid concerns).
3. Capacity Obligation (Decentralized)
Market-based — suppliers must hold capacity certificates covering their peak load
Each electricity supplier/retailer must demonstrate they hold enough capacity (certificates, contracts) to cover their contribution to system peak. Capacity providers sell certificates to suppliers. Price emerges from bilateral trading.
Examples: France (since 2017, operated by RTE)
Pros: Decentralized; market-determined price; integrates demand response (suppliers can reduce obligation by flattening their peak). Cons: Complex; certificate market may be illiquid; reference peak definition critical.
4. Centralized Capacity Market (Auction)
Full market — central auction determines capacity price years ahead
The TSO/authority determines required capacity (de-rated for availability), then holds a competitive auction 4 years ahead of delivery. Capacity providers bid their required payment (€/kW/year); the auction clears at a uniform price. All clearing providers receive this price and must be available during stress events.
Examples: UK (T-4 and T-1 auctions), Ireland (I-SEM CRM), Italy (reformed 2022), Poland, Belgium (CRM from 2025)
Pros: Competitive price discovery; technology-neutral; long-term signal (4-year lead time allows new-build). Cons: Complexity; risk of over-procurement; may suppress energy prices (capacity-paid plants can bid lower in energy market); State Aid scrutiny.
5. Reliability Options
Hybrid — capacity providers sell call options to the system operator
Providers receive an option premium (capacity payment) and in return sell a call option at a pre-defined strike price. When spot prices exceed the strike, providers pay back the difference to the system operator (or are deemed to have generated). This creates an automatic clawback of scarcity rents — aligning capacity incentive with delivery incentive.
Examples: Ireland (I-SEM uses reliability options), Italy (new design), Colombia
Pros: Strong delivery incentive (penalty for non-availability during stress); self-financing during high-price events; reduces spot price volatility for consumers. Cons: Strike price design critical; may distort bidding behavior around the strike.
The UK Capacity Market — Detailed Example
The UK's is the most developed centralized capacity auction in Europe:
| Parameter | Design |
|---|
| Auctioneer | EMR Delivery Body (National Grid ESO) |
| Demand curve | Target capacity set by DESNZ (government); sloping demand curve around target |
| Lead time | T-4 (main auction, 4 years ahead) + T-1 (top-up, 1 year ahead) |
| Auction format | Descending clock (price starts high, drops each round; bidders exit when price < their cost) |
| De-rating | Capacity credit based on technology (wind ~8-10%, solar ~2-3%, gas ~95%, interconnectors ~variable) |
| Contract length | Existing: 1 year | Refurbishing: 3 years | New-build: 15 years (bankability) |
| Obligation | Must be available during "stress events" (declared by ESO); penalties for non-delivery |
| Clearing price | Typically £15-45/kW/year (varies by auction; 2024 T-4: £65/kW for new gas) |
De-rating is the key design lever: A 100 MW wind farm with 8% de-rating contributes only 8 MW of "firm" capacity. It must hold 8 MW of obligation and is penalized only for non-delivery of 8 MW during stress events. This allows all technologies to participate but weights them by their contribution to security of supply. The de-rating factors are contested — especially for storage (what duration counts?) and interconnectors (will neighbors export during a continent-wide cold spell?).
EU Regulatory Framework
The Electricity Regulation (EU) 2019/943 sets strict conditions for capacity mechanisms:
- Adequacy assessment first: Must demonstrate a genuine adequacy concern via ERAA (European Resource Adequacy Assessment) before implementing a CRM
- Energy market reforms first: Must address market failures (price caps, market design) before resorting to capacity payments
- Technology neutrality: Must be open to all technologies including demand response, storage, and cross-border participation
- CO₂ emission limit: 550 gCO₂/kWh threshold — new fossil plants above this cannot receive capacity payments (effectively excludes new coal; allows gas)
- Temporary: Mechanisms should be phased out once the underlying market failure is resolved
- Cross-border participation: Must allow capacity from other member states to participate (at de-rated levels accounting for interconnector availability)
The Energy-Only vs. Capacity Market Debate
For Capacity Mechanisms
- Price caps politically inevitable → missing money real
- Insurance against adequacy risk at modest cost (~5% of wholesale bill)
- Long-term revenue certainty enables new investment at lower WACC
- Demand response gets a clear revenue stream → participation grows
- Most large markets have adopted one → revealed preference
For Energy-Only Markets
- Capacity payments suppress scarcity pricing → weaken the investment signal they aim to replace
- Over-procurement risk → excess capacity → lower prices → more "need" for CRM (self-fulfilling)
- Fossil lock-in: gives revenue to incumbent thermal assets that should exit
- Complexity and regulatory gaming opportunities
- Texas ERCOT manages with energy-only (albeit with $9,000/MWh cap and VoLL-based ORDC)
Optimization Implications
| For… | Capacity Mechanism Impact |
|---|
| New-build investor | 15-year capacity contract reduces revenue uncertainty → lower required return → more projects viable. Asset valuation = energy margin + capacity payment stream. |
| Existing generator | Annual capacity payment supplements energy margin. Availability obligation creates penalty risk → must maintain plant reliability. Mothballing decision: capacity payment vs. fixed maintenance cost. |
| Battery/storage | De-rating determines capacity value (1h BESS may get 50-100% de-rating depending on rules). Stacking: capacity payment + energy arbitrage + reserves. Must ensure availability during stress events doesn't conflict with other commitments. |
| Demand response | Capacity mechanisms provide first reliable revenue stream for DR beyond balancing markets. Aggregators can bid industrial loads into capacity auctions. |
| Cross-border trader | Interconnector capacity in CRMs creates locational value. A country with a CRM may import "capacity" from neighbors — this de-rated foreign capacity has a specific value = CRM clearing price × de-rating factor. |
Your tangible win: You now understand why capacity mechanisms exist (missing money from price caps + investment risk aversion), the full spectrum of designs (strategic reserve → centralized auction → reliability options), the EU regulatory constraints, and how capacity payments interact with energy market optimization — creating an additional revenue stream that must be co-optimized with energy and reserves.
Primary Source
For the theoretical foundation of the missing money problem:
Joskow, P.L. (2008). "Capacity payments in imperfect electricity markets: Need and design." Utilities Policy, 16(3), 159–170. — The canonical paper framing the debate.
For the EU regulatory framework:
Regulation (EU) 2019/943, Articles 21-26 (Generation adequacy provisions). Available at: EUR-Lex
For comparative design analysis:
ACER (2022), Methodology for the European Resource Adequacy Assessment (ERAA). Available at: acer.europa.eu
Retrieval Practice
What is the "missing money" problem in energy-only markets?
- Generators cannot recover their fuel costs because wholesale prices are below the marginal cost of production
- Price caps prevent generators from earning scarcity rents that would justify investment in peaking capacity
- Network charges absorb revenue that should flow to generators leaving insufficient profit for maintenance
- Renewable subsidies suppress wholesale prices below the level needed to cover thermal fixed costs
Retrieval Practice
How does a reliability option differ from a simple capacity payment?
- Reliability options are only available to renewable generators while capacity payments cover all technologies
- The provider must pay back revenues exceeding a strike price during scarcity, creating a delivery incentive
- Reliability options are funded by generators rather than consumers through a levy on wholesale trades
- Reliability options have no auction and are allocated administratively based on historical output data
Retrieval Practice
Why does the EU Electricity Regulation impose a 550 gCO₂/kWh threshold on capacity mechanism participation?
- To ensure only the most thermally efficient gas plants can receive payments, improving overall system efficiency
- To match the emission intensity threshold used by the EU Taxonomy for sustainable finance classification
- To prevent capacity payments from subsidizing new high-emission plants (coal) that conflict with decarbonization
- To create a technology-neutral standard that naturally favours renewables and storage over all fossil fuels
Retrieval Practice
In the UK capacity market, why is the T-4 auction held four years before delivery?
- EU regulation mandates a minimum four-year lead time for all centralized capacity mechanisms in Europe
- New-build projects need 3-4 years construction time — the lead time allows them to compete with existing plants
- Four years matches the planning horizon of electricity demand forecasts used to set the capacity target
- The descending clock auction format requires multiple rounds spread over years to reach the clearing price
💡 Want to explore the UK auction mechanics in detail, compare de-rating methodologies across technologies, analyze the interaction between CRMs and the energy transition (fossil lock-in debate), or model the revenue stacking for a new gas peaker with a 15-year capacity contract? Just ask.
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