Achieving a fully decarbonised power system by 2050, if not earlier, implies unprecedented penetration levels of variable renewable energy sources (vRES). In several mature markets, however, investment momentum is slowing as vRES projects transition from public-subsidised remuneration schemes to full merchant or quasi-merchant exposure. Current market arrangements—optimised historically for dispatchable thermal fleets—are increasingly misaligned against the operational and risk characteristics of non-dispatchable, low-marginal-cost generation.

High vRES shares are structurally altering price formation across all timeframes. Merit-order effects depress day-ahead market (DAM) prices and, increase the occurrence of zero and negative price intervals, while the stochastic nature of renewable output amplifies intraday (ID) volatility and imbalance settlement risk. Locational/zonal price spreads widen due to network congestion and spatially heterogeneous resource profiles, creating basis risk that is not fully addressed by existing financial transmission rights. The resulting erosion of captured prices (“price cannibalisation”), and the absence of firm long-term revenue stabilisers, are undermining reinvestment incentives, even for systems with growing resource adequacy and flexibility needs.

This work aims to identify where current electricity-market designs fail to support high shares of vRES and to explore solutions that can strengthen investment signals and enhance system flexibility. Therefore, the paper first provides the state of play—for energy-only and hybrid market designs to which vRES are exposed, covering selected IEA Wind Task 25 countries in Europe and overseas. The performance of DAM and balancing markets in accommodating high renewable shares is presented, with an emphasis on imbalance pricing regimes, scarcity pricing implementation, cross-zonal liquidity, and the settlement frameworks that govern vRES forecasting errors and imbalance penalties.

The second part explores mitigation measures and forward-looking design options. These include enhanced demand-side response (industrial load shifting, aggregation of distributed flexibility), co-located and system-wide storage (including long-duration storage), and reforms to negative-price rules, minimum generation constraints, and reserve procurement. We evaluate the ability of existing balancing markets to provide stable revenue streams for flexible assets that complement vRES integration. Additionally, we assess whether incremental reforms to the existing energy-only paradigm are sufficient, or whether more structural redesign—including enhanced capacity mechanisms, or alternative market-clearing constructs—may be required. We also examine the reasons behind the slow deployment of virtual power plants (VPPs) and hybrid power plants (HPPs), despite their potential to internalise flexibility, reduce imbalance exposure, and enhance market-compatible dispatch.

Finally, the paper reviews emerging hedging instruments tailored to vRES risk profiles. For example, while wind-following cap contracts adequately address inter-temporal capture-price risk, locational (zonal) basis risk remains insufficiently hedged; we, therefore, discuss the applicability of wind-following geographically fixed transmission rights (GFTRs) as a potential financial product for managing spatial price exposure.