Review of Electricity Market Arrangements (REMA) – Second Consultation

What this is about

DESNZ published the second REMA consultation in March 2024, narrowing the field from the first consultation's sprawling menu of 40+ options down to a focused set of reform pathways. The first consultation (July 2022) established that current arrangements — designed around dispatchable thermal generation — are increasingly mismatched with a system dominated by weather-dependent renewables, inflexible long-duration contracts, and a transmission network that was not built for where the new generation sits. The second consultation asks which specific reforms should replace them.

The core tension is straightforward: GB's electricity market was built on the assumption that generators choose when to run and the price clears nationally. That design breaks down when most generation is zero-marginal-cost, location-constrained, and supported by administered contracts that disconnect generators from the wholesale price. REMA is the government's attempt to decide whether the fix is more planning (central dispatch, administered optimisation) or more pricing (locational signals that make generators and demand bear the costs they impose on the system). The answer will shape investment signals, cost allocation, and market structure for decades.

Options on the table

The consultation organises reform around several distinct design choices. These are not mutually exclusive packages — DESNZ presents them as components that could be combined. But the fundamental axis is clear: national pricing with administrative coordination versus locational pricing with market coordination.

#### Locational pricing (zonal or nodal)

The headline option. Instead of a single national wholesale price, the market would clear at different prices in different locations, reflecting transmission constraints. Nodal pricing (as used in US ISOs — PJM, ERCOT, CAISO) calculates a price at every node on the transmission network. Zonal pricing (as used in the Nordic countries and much of continental Europe) divides the country into a smaller number of price zones.

What it does: Forces generators and demand to face the cost of where they sit on the network. A wind farm in Scotland behind a constrained boundary would receive a lower price than one in southern England close to demand. New investment would be steered toward locations where the grid can accommodate it, rather than where the subsidy is richest.

Who wins: Generators in unconstrained areas (southern England, demand centres). Flexible demand and storage that can arbitrage locational spreads. Consumers, eventually, through lower constraint costs (currently £2-3bn/year and rising). New entrants who can site efficiently.

Who loses: Existing generators in constrained areas (Scottish wind, in particular) who invested on the basis of a national price. Network companies whose investment case changes if locational pricing reduces the urgency of transmission reinforcement. Any party holding long-term contracts referenced to a national price.

The real question: Whether the transitional costs and political resistance of repricing existing assets are worth the long-run efficiency gains. The economics are clear — locational pricing is the textbook answer. The politics are not.

#### Enhanced national pricing (status quo plus)

Retain the single national wholesale price but improve the signals around it. This means sharper balancing mechanism incentives, better forward market design, improved capacity adequacy mechanisms, and potentially a more granular Contracts for Difference design that incorporates locational or temporal signals.

What it does: Avoids the disruption of locational pricing by patching the current framework. The national price stays, but additional mechanisms layer on signals that approximate what locational pricing would provide.

Who wins: Existing asset owners whose investment cases assumed a national price. Network companies whose regulated asset base continues to grow with reinforcement. Anyone who benefits from the current complexity (consultants, compliance specialists, incumbents with regulatory expertise).

Who loses: Consumers who continue to pay constraint costs through socialised charges. New entrants who face a market where the real price signals are buried in balancing mechanism data rather than visible in the wholesale price. The system as a whole, if the patches fail to replicate what a proper price signal would achieve.

The real question: Whether layering additional administered mechanisms on top of a broken price signal can ever replicate the coordination that a functioning price system provides. History suggests it cannot — each patch creates the next distortion.

#### Central dispatch

Replace self-dispatch (where generators decide when to run based on their own commercial calculations) with central dispatch (where the system operator instructs generators when to run based on an optimisation algorithm).

What it does: NESO would run a security-constrained economic dispatch, deciding which plants run and which do not. This is how most US markets work — but in those markets, central dispatch operates alongside locational pricing. DESNZ is considering central dispatch with or without locational pricing, which creates very different dynamics.

Who wins: The system operator, which gains direct control over dispatch. Potentially consumers, if the optimisation reduces total system costs. Inflexible generators who currently struggle in the balancing mechanism.

Who loses: Flexible generators and traders whose commercial strategies depend on self-dispatch. Battery storage operators whose business model is built on arbitraging price spreads through their own dispatch decisions. Anyone who believes that decentralised decision-making produces better outcomes than centralised optimisation.

The real question: Central dispatch without locational pricing is planning without prices — it optimises the physical system but removes the commercial signals that drive efficient investment. Central dispatch with locational pricing is how PJM works, and it works reasonably well. The combination matters more than the component.

#### Capacity adequacy reform

Reforming or replacing the Capacity Market to better value flexibility, duration, and location. Options range from incremental CM reform (longer contracts, technology-specific auctions) to more fundamental alternatives (reliability options, strategic reserve, decentralised capacity obligations).

What it does: Addresses the growing mismatch between what the CM procures (nameplate capacity, four hours ahead) and what the system needs (flexible response across multiple timescales, in specific locations).

Who wins: Depends on design. Longer CM contracts favour capital-intensive plant (gas, nuclear, long-duration storage). Technology-specific auctions favour whatever technology the government picks. Decentralised obligations favour suppliers with diverse portfolios.

Who loses: The current CM design favours incumbent gas generators who clear at low prices and collect reliability payments for capacity they would have maintained anyway. Any reform that sharpens the signal will redistribute value.

#### Renewables support reform

Redesigning CfDs to incorporate locational, temporal, or market-coupling signals. Options include locational CfDs (different strike prices by zone), revenue cap-and-floor models, and moving toward merchant exposure for mature technologies.

What it does: Addresses the fundamental problem that CfDs disconnect generators from the wholesale price for 15 years, removing any incentive to respond to market signals about when or where to generate.

Who wins: Consumers, if reformed CfDs reduce the total cost of support. Developers who can manage merchant risk. The system, if generators start responding to price signals.

Who loses: Developers who have built business models around guaranteed strike prices. Lenders who price CfD-backed debt as quasi-sovereign. Any party that benefits from the current disconnect between generation and market value.

Questions being asked

The consultation poses over 40 questions across its chapters. The key themes:

#### Wholesale market design

- Whether locational pricing (nodal or zonal) should replace the current national pricing arrangement. *[This is the central question of the entire consultation. Everything else is secondary.]* - Whether the benefits of locational pricing outweigh transitional costs and risks to investor confidence. - How existing contracts and investments should be treated under a transition to locational pricing. *[Translation: who absorbs the repricing of Scottish wind?]*

#### Dispatch and scheduling

- Whether central dispatch should replace self-dispatch, and if so, whether it should be combined with locational pricing. - How central dispatch would interact with storage and flexible demand. *[Translation: would NESO dispatch batteries, or would batteries retain commercial autonomy?]*

#### Capacity adequacy

- Whether the Capacity Market should be reformed incrementally or replaced. - How capacity adequacy mechanisms should value flexibility, duration, and location. - Whether decentralised capacity obligations would better incentivise supplier-led solutions.

#### Renewable support

- Whether CfDs should incorporate locational or temporal signals. - How the transition from current CfD design to any reformed mechanism should be managed. - Whether mature technologies should move toward greater merchant exposure. *[Translation: should offshore wind take price risk?]*

#### Flexibility and demand-side response

- How market arrangements should better value flexibility across timescales. - Whether specific mechanisms are needed to support long-duration energy storage.

How to respond

The consultation closed on 7 June 2024. Responses were submitted through the GOV.UK consultation page or by email to the REMA team at DESNZ. The consultation document, supporting technical annexes, and impact assessments were published on the [GOV.UK consultation page](https://www.gov.uk/government/consultations/review-of-electricity-market-arrangements-rema-second-consultation).

DESNZ committed to publishing a government response setting out next steps, though no firm timeline was given. As of early 2025, the response had not been published — a delay that itself signals the political difficulty of the choices involved.

---

`★ Insight ─────────────────────────────────────` Why REMA matters more than any other live consultation: REMA is not a parameter tweak — it is a choice about whether GB electricity follows planning logic or pricing logic for the next 30 years. Every other reform (connections, charging, capacity) is downstream of this decision. If locational pricing is adopted, the connection queue problem partially solves itself (developers stop applying for constrained locations). If it is not, every other mechanism must do the work that prices would have done, which is why the status quo generates an ever-growing pile of administered patches.

The constraint cost number is the argument: GB constraint costs hit £2.6bn in 2023/24 and are projected to rise. That is the annual cost of not having locational pricing — paid by consumers through BSUoS charges, invisible on bills, and growing every year more wind connects in Scotland while demand sits in England. Locational pricing would not eliminate constraints, but it would make the people causing them pay for them.

The political economy is the binding constraint: The economics of locational pricing are well-established. The barrier is that it would reduce revenues for existing Scottish wind assets, which were financed on the assumption of a national price. That is a transfer from renewable generators to consumers — economically efficient, politically explosive. `─────────────────────────────────────────────────`