Great Britain’s Default Tariff Cap (DTC) sets a cap on the price suppliers may charge to domestic customers for electricity (and gas). The commodity cost component of the DTC consists of a trailing average of historical forward prices on the wholesale market for contracts purchased up to a year ahead. In order to manage their exposure to wholesale price movements, suppliers to domestic customers have an incentive to buy power ahead such that their cost of purchasing electricity broadly reflects the prices at which they can sell it to domestic customers.

Historically, thermal, dispatchable generators have been the primary providers of forward contracts in the British electricity market. As renewable generation becomes increasingly important, the availability of forward contracts from thermal generators is likely to fall. As markets for forward contracts tighten, the cost of procuring forward contracts will increase relative to the spot price of electricity (i.e., forward premia will increase). Domestic consumers paying the DTC will see their cost of energy increase because the commodity cost allowance depends on forward contract prices.

Market participants and commentators have long understood that liquidity in forward contracts may worsen and forward premia may increase, however quantitative estimates of the extent of that effect are scarce. Centrica commissioned Senior Managing Director George Anstey and Consultant Magnus Martinsen to quantify the impact of a changing generation mix on forward market liquidity and spot premia. NERA conducted innovative bottom-up modeling of the evolution in the cost of hedges. The process followed a three-stage modeling approach, with the first stage being electricity market modeling, followed by the assessment of the forward premium using a Value at Risk (VaR) framework, and ending with the identification of the forward premium across the market. To our knowledge, NERA’s study is the first empirical attempt to quantify the impact of a changing generation mix on forward premia and liquidity using a value at risk methodology.

The results of the modeling suggest the average risk premia will increase between 2023 and 2025. NERA’s findings suggest consumers may benefit from redesigning the DTC in a decarbonized electricity system, as the current DTC design can result in higher material costs to consumers. Thus, NERA proposed alternative reforms to the DTC methodology and the Contracts for Difference (CfD) framework, alongside an exploration of the impact of market designs considered in the REMA process on liquidity and the cost of hedging.