The Market Had to Evolve With the System
A national electricity-market authority was reassessing how market rules should evolve as variable renewable generation became a larger share of the power system. The transition was changing price formation, congestion, curtailment, storage economics and the investment signals available to generation, flexibility and network capacity.
The question was not whether to continue renewable deployment. It was how to sustain a reliable, affordable and investable electricity system as the relationship between supply, demand and system flexibility changed. Market arrangements developed for a more conventional generation mix could not be assumed to create the right incentives once periods of abundant low-marginal-cost output became more frequent.
The Decision Was About Investment Signals
The client needed to determine how wholesale-market arrangements, capacity mechanisms, flexibility incentives, storage integration, network development and demand-response structures should develop together. The objective was to preserve efficient dispatch and consumer value while ensuring that the system continued to attract the resources required for adequacy, balancing, congestion management and reliable supply.
Each intervention involved a different trade-off. Longer-term revenue arrangements could improve financing certainty, but could reduce exposure to the prices that guide investment and dispatch. Capacity arrangements could support resources available during system-stress periods, but risked duplicating energy-market revenues if they were not tightly designed. Storage support could accelerate flexibility, while changing the price spreads that initially supported storage investment.
The governing question was therefore not how to maintain historic price outcomes. It was how to ensure that prices, contracts and market mechanisms continued to reward the capabilities required by the changing system.
Low Marginal Cost Changed Capacity Economics
A conventional market study could estimate average wholesale prices, renewable-project returns or the revenue stack of an individual storage asset. Those inputs were necessary, but they could not explain how the system’s composition changed the incentives within it.
Where similarly profiled renewable assets generated at the same time, rising output could lower prices during high-generation periods. The effect could be intensified where network capacity, storage or responsive demand could not absorb supply, leading to congestion, curtailment and lower technology-specific capture rates. The result was a feedback loop: additional variable output could weaken the revenues available to similarly profiled capacity, which could then affect investment in the generation, flexibility and networks required for further integration.
This did not mean that low prices were inherently undesirable. They could reveal an efficient response to abundant supply. The issue was whether the wider market could convert that signal into investment in the resources that relieved the underlying constraint: transmission, storage, flexible generation, demand response or different forms of capacity.
Storage Changed the Price Distribution
Storage was central to this adjustment because it could absorb output during low-price periods and release energy when the system placed greater value on it. In doing so, it could reduce curtailment, shift supply across time and improve the integration of variable generation.
However, storage was not a price-taking asset. Its charging and discharging behaviour changed intraday price patterns, affected renewable capture economics and could reduce the arbitrage spreads available to subsequent storage investment. Its contribution also depended on duration, grid connection, location, degradation, dispatch constraints and its availability during system-stress periods.
The relevant question was therefore not whether storage should receive support in the abstract. It was which flexibility requirements storage could credibly meet, where it created locational or temporal value, and how its market treatment should evolve alongside transmission, flexible demand and other adequacy resources.
Testing Market Designs Across System Futures
Bruqe framed the engagement around reliability requirements, consumer-cost exposure, investment needs, market-design boundaries and flexibility thresholds. The work mapped the relationships among renewable output, wholesale-price formation, capture rates, congestion, curtailment, storage behaviour, flexible generation, demand response, transmission capacity and changing electricity demand.
It then tested different system configurations: faster or slower renewable deployment, alternative storage pathways, varying transmission outcomes, electrification and AI-related load growth, demand-response participation, weather conditions and technology-cost assumptions. Under each configuration, the analysis examined how energy prices, capacity needs, flexibility value, investment incentives and consumer exposure changed together.
The work also tested alternative market structures: capacity arrangements, flexibility mechanisms, longer-term contracts, locational incentives, demand-side participation and network-development priorities. The objective was not to select a universal market design. It was to identify where intervention was necessary, which signals should remain exposed to competition, and which thresholds should trigger further market reform, flexibility procurement or network investment.
Rewarding the Resources the System Needed
The analysis separated four forms of system value that could not be treated as interchangeable: energy delivered, dependable capacity during stress periods, flexibility across time, and locational relief where networks constrained delivery. A resource that contributed to one did not necessarily provide the others.
This created a more disciplined basis for market design. Capacity arrangements could reward dependable availability during scarcity periods. Flexibility mechanisms could recognise the ability to shift generation or demand across constrained hours. Network and locational signals could direct investment toward areas where additional generation, storage or demand response would relieve the greatest system pressure. Longer-term contracts could support financing where merchant revenues alone were insufficient, while preserving incentives for operational availability and efficient dispatch.
The resulting decision architecture linked intervention to observable signposts: capture rates, curtailment, congestion, storage deployment, price-spread evolution, demand growth, adequacy assessments and consumer-cost exposure. This enabled market reform to be sequenced around conditions rather than driven by static assumptions.
Keeping the Transition Investable
The resulting approach connected renewable deployment to the market, network, flexibility and demand conditions required to sustain it. It gave the client a clearer basis for preserving efficient operation while maintaining credible investment pathways across a changing power system.
The enduring implication was clear: mitigating cannibalisation does not mean suppressing price signals. It means ensuring that the market continues to reward the energy, capacity, flexibility and network investment that high-renewables systems require.
