How best to decouple gas and electricity prices to pass through the benefits of renewables to consumers, and what is the role of marginal pricing within electricity markets?

• How best to decouple gas and electricity prices to pass through the benefits of renewables to consumers, and what is the role of marginal pricing within electricity markets?
• How can Corporate Power Purchase Agreements (CPPAs) benefit different consumers and developers of low carbon capacity, and how might this role evolve?
• How do we best incentivise electricity demand reduction from consumers, and what is the role of markets in doing this?

• How to de-risk investment in renewables while increasing operational risk exposure to deliver lowest overall system cost?

• How do we maintain security of supply in a future electricity system dominated by intermittent renewable generation?
• How do we manage a smooth transition away from unabated gas to low carbon flexible technologies?

• How do we ensure that efficient price signals are sent in the wholesale market so that whole-system costs are minimised?
• How do we improve mechanisms and markets for balancing the system?
• How do we ensure sufficient liquidity is maintained under future market arrangements?

• How the reforms will impact on existing CfDs etc

DESNZ have narrowed down the options further. They have discounted nodal pricing/Locational Market Pricing, which is where the grid is divided into hundreds of separate nodes, each with its own price for electricity. Zonal pricing is however very much still on the table (more on this in our next Insight). Splitting the market by characteristic (i.e. having a separate market for renewables, so that gas prices do not set the overall electricity price) has also been binned, as have some of the wilder CfD and capacity market options.

What we are left with is a market centred around the CfD and Capacity Market (as it is now), with some tweaks to both of these. Zonal pricing, where GB is split into geographic zones, each with a different wholesale price, is still being considered, but so are alternatives such as TNUoS (network charging) reform, reforming network access arrangements, improved constraint management and making best use of cross-border interconnectors.

The headline-grabbing point is that there is a need for more new build gas generation in the short term, to replace existing gas generation that is due to retire. This seems to go against the net zero target, although DESNZ are expecting to publish their response to the March 2023 Decarbonisation Readiness consultation shortly and legislate for changes this Spring. This would mean that new build gas plants will have to be able to convert to 100% hydrogen or retrofit carbon capture during their lifetime; something for gas generators to take into account.

So if you have a generating plant that currently has a CfD or a Capacity Market agreement or benefits from another Government support scheme, should you be worried? And what about future support schemes like the hydrogen and CCUS business models?

DESNZ are considering the impact of the REMA reforms on the CfD, Capacity Market, Renewables Obligation, Feed-in Tariffs, Net Zero Hydrogen Fund, interconnector cap-and-floor arrangements and nuclear CfD and RAB mechanisms. Unfortunately (with the exception of the CfD) they have not said much more than that at this stage, either in the consultation document itself or in the webinars they have held with industry. But we do know they will be looking at each scheme separately and how the REMA reforms will impact both how the scheme functions and the financial impacts. So it's a question of watch this space.

One of the core aspects DESNZ has looked at in detail is the impact that locational (zonal) pricing would have on the CfD. To insulate existing (and future) CfD holders from the impact of the shift to zonal pricing, DESNZ propose that the definition of the market reference price in the CfD would be amended to be based on the local zonal price where generators would sell their power. This serves to blunt the locational price signals which might otherwise result in prices during the reference period deviating from the prices used to set the reference. CfD generators in lower priced zones will have the comfort of knowing their revenue will be made up to the strike price from their local zonal price; while conversely generators in higher priced zones will be more likely to exceed their strike price from time to time, but will retain the certainty of their strike price revenue (which is critical for all existing projects, particularly those with project financing).

There is already provision in the standard CfD contract terms allowing for this adjustment to the reference price to be made, and DESNZ have confirmed that these terms will remain in place for future allocation rounds (including the current AR6) before a published government decision on REMA reforms. While such protections will be critical for existing projects and those reaching operations in the short term, they may become very expensive for bill-payers to support over the long duration of the CfDs. We therefore expect that once there is greater certainty over the zones and the local pricing within them, allocation of future CfDs will require future projects to take such zonal pricing into account when bidding for the CfDs, and that future projects' revenues will need to respond to those pricing signals.

In the next stages of REMA, DESNZ will refine the options further and look in more detail at how they will affect current assets and CfDs. DESNZ intend to publish a summary of responses to this latest consultation in summer 2024 and conclude the policy development phase in mid-2025. Reforms will be implemented after that.