Global electricity market design is undergoing structural realignment. The International Energy Agency (IEA) states that market signals alone are no longer sufficient to support investments with a 10 to 30-year payback period. Beyond two years, the liquidity of derivative products drops sharply, exposing producers, industrial consumers and investors to growing financial instability.
Volatility has increased ninefold since the energy crisis
Since 2019, annual wholesale price volatility has multiplied five to nine times in key markets. In Europe, the average spot price of electricity rose from €39/MWh ($42/MWh) in 2019 to more than €160/MWh ($173/MWh) in 2022, with peaks reaching €700/MWh ($758/MWh) during the winter. This surge triggered over 400 emergency measures and accelerated the reform of the European Union electricity market.
In the United States, Texas (ERCOT) recorded an average spot price above $120/MWh for several months in 2021, with extreme spikes exceeding $9,000/MWh for short periods. Australia saw a 260% rise in its national electricity market average between 2020 and 2022, peaking at AUD216/MWh ($143/MWh) during the crisis.
Short-term markets remain reliable but cannot anchor long-term investment
Short-term markets (day-ahead, intraday) continue to deliver electricity availability above 99.9%. In Europe, the day-ahead market processes more than 400,000 orders per hour across thousands of participants. Yet, these markets account for only around 20% of revenues over a 20-year project horizon, according to IEA estimates.
In Germany, negative-price hours tripled between 2019 and 2023, reaching 300 hours annually. Intraday price spreads now exceed €200/MWh ($216/MWh) at certain local nodes. These signals highlight the value of short-duration flexibility but make revenue flows unpredictable for non-contracted assets.
Lack of depth beyond 24 months
In most European and American trading hubs, less than 5% of traded volumes are tied to contracts with maturities beyond two years. However, offshore wind, nuclear and long-duration storage projects require visibility over 15 to 30 years. The mismatch between levelised cost of electricity (LCOE) and uncoupled forward prices makes these assets hard to finance without external support.
Since 2021, rising interest rates have doubled the weighted average cost of capital (WACC) for renewable projects in several OECD countries, from 3.5% to 7%, according to financial benchmarks. For a 100 MW solar plant with €100mn ($108mn) CAPEX, this adds €35mn ($38mn) in financial charges over 20 years.
Contracts designed to smooth revenues over 15 to 20 years
Contracts for difference (CfDs) now account for over 80% of capacity allocated in tenders in Spain, the Netherlands and the United Kingdom. A 15-year CfD typically secures an average fixed price of €60/MWh ($65/MWh), compared to a spot average of €120/MWh ($130/MWh) over 2022–2023. Corporate power purchase agreements (PPAs) signed in the European Union reached 16 GW in 2024, with a median duration of 12 years and average pricing around €55/MWh ($59/MWh).
Capacity remuneration mechanisms (CRMs) account for nearly €10bn ($10.8bn) in annual payouts across Europe, notably in centralised capacity markets in France, the United Kingdom and Italy. In the United States, PJM allocates around $9bn annually in capacity commitments to cover three-year-ahead needs. This safety net ensures fixed revenue for thermal power plants, batteries and demand response operators.
Crossed risks of overcompensation and opacity
The layering of CfDs, PPAs, CRMs and spot markets introduces risks of double-compensation and misaligned incentives. In some cases, a CfD-backed asset may also receive capacity payments or arbitrage between PPAs and the spot market based on contract terms. The IEA estimates that this uncoordinated overlap could misalign up to 20% of investment signals in some jurisdictions.
Regulators face growing complexity: monitoring cash flows, verifying clauses, and managing windfall risks. Visibility for foreign investors is reduced in a context of increasing regional divergence in electricity market models.
Strategic restructuring across all market participants
Electricity producers must now calibrate their portfolios between contracted and merchant revenues. An independent power producer (IPP) operating 1 GW of capacity could segment revenues as follows: 33% CfD, 33% PPA, 33% spot. Industrial consumers are internalising energy risk management skills to handle long-term contracts and payment guarantees.
Specialist infrastructure funds are demanding regulated revenue profiles to maintain 6% to 8% target returns. Traders increasingly act as risk intermediaries, transforming spot signals into structured products. Developers must now treat CfD clauses and PPA structures as strategically important as technical yields or capacity factors.
