Legacy Renewable Commitments

Legacy policy charges make productive electricity use more expensive and obscure the distinction between the service bought and national commitments already made. The obligations must still be paid, but they need not be paid in a way that raises the price of every additional unit of electricity used to make things, heat homes or run computers.

We will honour inherited renewable commitments and take their defined policy-support costs off the unit price of electricity. Those costs will be recovered through a fixed, banded legacy charge on each connection rather than a charge on each kilowatt-hour. Energy-intensive industry and eligible manufacturers will be exempt from the charge, with their share funded from taxation, and low-income households will receive a reduced charge. We will also reduce avoidable physical and contractual costs. Future purchases will follow the central purchaser’s system and value tests.

What problem are we trying to fix

Legacy support charges raise the price of electricity for households and businesses. They make electricity carry costs arising from national policy choices and discourage productive use, including industrial expansion. Public debate then mixes these charges with wholesale purchases, network investment and balancing costs. Consumers cannot readily see what they are paying for, which commitments can change, or whether a promised saving is simply being transferred to taxpayers.

Why abolition does not solve it

Repealing the Climate Change Act changes national policy but does not itself cancel a renewable contract or settle statutory support entitlements. Preserve inherited commitments through express saving provisions. Breach can create compensation liabilities and weaken confidence in the contracts needed for the wider programme. Renewable output remains useful while dependable supply expands. Already-awarded contracts may continue into the 2040s and 2050s; this is a long transition, not a bill that disappears within ten years. [1–2, 5]

What our policy fixes

A fixed legacy charge removes the defined policy charges from the unit price of electricity, so that using more electricity no longer carries a share of commitments that do not grow with use. Industry receives full relief funded from taxation, and every customer can see the legacy cost as a separate line on the bill. Respecting existing terms protects investment confidence. A published commitments register establishes what remains payable and when it ends. Network reinforcement, flexible demand and voluntary contractual changes can then be tested for real savings. These measures address different problems. Changing how a charge is recovered lowers the price of additional electricity, while efficiency reduces the resources Britain must spend.

The proposal covers existing renewable obligations and their settlement in Great Britain. Northern Ireland requires separate implementation consistent with its electricity market and legislation. Nuclear support, including Hinkley Point C, must be recorded separately even where the same counterparty administers it. The programme begins on taking office. This paper uses evidence available on 11 October 2026 and does not assume that today’s portfolio will remain unchanged until the targeted change in year one. Eligible biomass electricity support is included; bespoke agreements require explicit component allocation. Heat, biomethane, hydrogen and carbon-capture support retain their separate treatment.

The commitments we inherit

Three schemes dominate the legacy renewable-support portfolio. They pay for different things and should not be treated as interchangeable contracts. [3–5]

The baseline has already changed

Since April 2026, government has funded 75% of domestic Renewables Obligation costs in Great Britain through a three-year Exchequer scheme. Its published budget estimates are £2.580 billion in 2026–27, £2.100 billion in 2027–28 and £2.195 billion in 2028–29. Reported expenditure for April–June 2026 was £520.7 million, excluding administration. This is temporary household relief, not funding for the whole renewable portfolio. [6]

Our reform does not extend that scheme. It runs to its planned end in March 2029, and the domestic Renewables Obligation costs it now meets then join the fixed legacy charge. The British Industrial Competitiveness Scheme, which exempts eligible manufacturers from Renewables Obligation, Feed-in Tariff and Capacity Market costs from April 2027, and the existing relief for energy-intensive industries form part of the inherited baseline. Our industrial relief builds on them, and its additional fiscal cost must be measured against that baseline rather than claiming credit for relief already delivered.

Government also changed Renewables Obligation indexation from RPI to CPI from April 2026, with a corresponding change to Feed-in Tariffs. We inherit the resulting framework; this proposal does not restore the earlier index or introduce another retrospective reduction. The RO portfolio rolls off over 2027–2037. Other schemes have different end dates. [7–8]

Future delivery can already be committed

Allocation Round 7 included offshore wind delivery in 2030–31. Its reforms introduced 20-year terms for offshore and onshore wind and solar. A contract whose payment term begins around 2030 can therefore extend to around 2050, subject to its actual conditions. A project need not be generating today to belong in the inherited commitments register. An auction announcement, an offered contract and a signed contract must be recorded as different stages. [1–2]

The indicative AR8 timetable puts results between 27 November 2026 and 17 February 2027 across its process scenarios; signed-contract returns extend to 17 March 2027 in the longest case. Results and signing are different dates. Refresh the timetable and delivery years when recording actual awards. [17]

Track Allocation Rounds 8, 9 and 10, and any further round awarded before the cutoff in year one, including any round held in the first months in office. AR8 is in progress at this paper’s date; later rounds are prospective. Record announced, awarded or offered, signed, under-construction and operating stages separately. The volumes inherited on taking office remain unknown until awards and contracts are reconciled. [17]

Why cancellation does not solve the problem

A political decision does not erase an obligation

A renewable CfD is a private-law agreement with the Low Carbon Contracts Company. Changes to supplier funding need not change the generator’s entitlement. Unilateral cancellation, by contrast, can create disputes over breach, compensation and the financing arrangements built on that agreement. The amount and timing of any liability depend on the particular terms and action taken. There is no defensible assumption that ending payments produces a saving equal to their face value. [5]

The RO and Feed-in Tariffs are statutory schemes, so their legal position differs from a private contract. Parliament can change legislation. Our commitment to protect the inherited framework is a policy choice intended to preserve investment confidence, rather than a claim that every existing rule is legally immutable. Enforcement, correction of erroneous accreditation and action against fraud remain available under the applicable rules.

Supply still has to be replaced

Removing support would not necessarily close every operating wind or solar installation: some would continue to earn electricity revenue. It could nevertheless impair maintenance, refinancing and the completion of projects that depend on supported revenues. The risk differs by asset, debt structure and contract. Neither “all generation disappears” nor “nothing changes” is an adequate basis for policy.

Britain needs a supply expansion that serves households, industry and growing computing demand. More domestic fuel production does not itself supply a power station. New nuclear requires construction and commissioning; additional thermal generation needs usable connections, fuel and permissions. Until alternatives are available, useful renewable generation reduces the amount of electricity that must come from other sources. Decisions must follow the system plan and reliability standard, not a blanket political date for ending renewable output.

Financial support is not a command to buy every unit

A CfD settles a price difference; it is not itself a physical purchase contract. Its precise payment conditions vary by contract. System operation can still require curtailment, and the associated balancing settlement is a separate issue. Procurement, dispatch and financial support therefore need separate accounting. Ending a future support programme does not automatically remove every existing entitlement or confer a right to disregard an operating contract. [5, 9]

Credibility also has a price across the whole programme. Investors asked to finance a British-controlled generation mutual will consider whether future governments respect agreed revenues. A government that repudiates renewable commitments cannot simply assume that investors will trust its nuclear and gas commitments. The relevant comparison is the total cost of reform, including compensation and the effect on financing new supply.

The defensible distinction

We can change the rules for future procurement, enforce existing performance conditions and invite voluntary changes. Those are concrete decisions with assessable costs. A promise to “abolish subsidies” must specify which of these actions it means and who bears the remaining obligation.

What the existing commitment costs

Publish separate scheme, period, cash and valuation measures for the inherited commitment. The reported figures below establish its scale; Appendix E records their status and the reconciliation required on taking office.

These measures use different accounting bases. They should not be added and described as a precise renewable cash subsidy. Export payments include electricity purchased; certificate value is not identical to a government cash disbursement; the CfD accounts include nuclear and other contracts. The table establishes a substantial annual exposure and the need for reconciliation, rather than a headline total that conceals those differences.

Lifetime exposure requires a separate calculation

At 31 March 2026, DESNZ reported a net CfD fair value of £110.923 billion. That includes Hinkley Point C and a bespoke low-carbon dispatchable contract. The base-case valuation of the generic portfolio excluding those two was £59.1 billion. These are modelled valuations, not fixed invoices payable today, and neither figure is a complete renewable-only legacy total. Annual payments must not be added to a valuation that already includes the corresponding future cash flows. [10]

Before legislation, Treasury and DESNZ should produce a reconciled renewable-only register covering RO, FIT and CfD obligations. Publish actual outflows and receipts, the remaining support term, indexation, expected eligible output and outstanding delivery conditions. Show annual cash requirements for at least twenty-five years after the first term and a separately identified discounted valuation, with central, high and low wholesale-price cases. Forecast support for CfDs changes when their reference-price assumptions change.

Publish the incremental cost of our reform

Cost the additional Exchequer expenditure on industrial relief against the inherited policy baseline, including existing household relief and industrial exemptions. Publish the distributional effect of the fixed charge on households and businesses of different sizes, and show administration and working capital. A future expiry reduces expenditure only when the eligible obligation actually ends. Multiplying one recent year’s payments by an assumed remaining duration would conceal the varying contract dates, prices and output.

Fixed recovery and investment credibility

Why the funding route matters

Recovering inherited obligations through a charge on each kilowatt-hour increases the price of additional electricity even where consuming it does not increase those obligations. This can deter industrial production, electrification and new investment. The case for changing the method of recovery is to remove that distortion, rather than to claim that moving the payment creates a saving. The Institute for Fiscal Studies distinguishes the funding of fixed commitments from the incremental cost of electricity supplied. [14]

Two routes remove the distortion: general taxation and a fixed charge. Moving the whole cost to taxation would add around £10 billion to £15 billion a year to public spending and require higher taxes elsewhere, which change behaviour in their own ways. A fixed charge removes the distortion at no cost to the Exchequer, because a customer's charge does not change with the electricity they use. We therefore adopt the fixed charge for most customers and use taxation only where it matters most, for energy-intensive industry and manufacturers whose competitiveness depends on their total electricity cost as well as its marginal price. Any resulting productivity benefit is a separate, uncertain economic outcome and should not be booked as money available to pay the contracts.

One fiscal plan for the whole programme

Complete the fixed charge, industrial relief, credits, administration and liquidity entries in UK Energy Reform Programme Annex Appendix E before commencement. Keep commercial electricity purchases separate and apply its shared release test to material public exposure.

Identify the Exchequer funding for industrial relief before commencement. Keep speculative renegotiation savings and any unlegislated future tax outside the funding baseline; maintain generator payments during migration.

Honour the substance of the commitment

Respect inherited contractual and statutory rights in substance. Do not use targeted tax, planning or environmental measures primarily to defeat committed revenues. Objective regulation and ordinary taxation remain available. New contracts must define breach, public termination and specifically allocated change-in-law risks; general policy changes remain investor risks unless a priced, bounded clause says otherwise. Settlement accounts for mitigation, avoided costs and duplicate recovery. The stability commitment supplies no blanket indemnity against future taxation or regulation.

A bounded option for future taxation

Additional taxation of exceptional renewable profits may be appropriate in future, particularly on merchant earnings after legacy support expires. Expiry alone does not establish a windfall. Any proposal must be prospective, independently justified after allowing for capital recovery, genuine costs and a return commensurate with risk, and assessed for its effects on maintenance, refinancing, new investment and reliable supply. Comparable exceptional returns should face comparable rules, rather than a penalty based simply on technology.

The charge must avoid double recovery of value already returned through CfD repayments, sharing provisions or other taxes. Specify a review and sunset, demonstrate net public value after financing and supply effects, and preserve committed support revenues. It is an exceptional option, not a promised way to claw back past subsidies. The existing Electricity Generator Levy already taxes exceptional receipts and excludes CfD-covered generation; any future measure must account for the regime inherited on taking office. [15–16]

Taking legacy costs off the unit price

Define the boundary before promising the reduction

Target commencement from 1 April in year one under the Energy Objectives Repeal and Replacement Bill or accelerated legacy settlement legislation, subject to Programme Annex Appendix F’s operational conditions. From commencement, the eligible legacy renewable policy-support requirement will be recovered through the fixed legacy charge rather than unit rates. Wholesale electricity, networks and ordinary commercial operating costs remain charges for the service supplied. The change is not a promise to remove every cost associated with a renewable generator from the bill. It is a defined change in how inherited national policy commitments are recovered. Include eligible inherited biomass electricity support and allocate bespoke contract components explicitly, without charging commercial electricity purchases twice. The existing domestic Renewables Obligation Exchequer scheme runs to its planned end, and Appendix F sets out the transition.

The public settlement account should have separate RO, FIT and renewable CfD ledgers. Keep LCCC and existing scheme administrators responsible for their established settlement tasks. Suppliers collect the fixed charge and pass it to the settlement account, Treasury funds the industrial relief and provides a liquidity facility for timing differences, and the account publishes its receipts, payments and reserves.

For FIT exports, preserve the accredited generator’s payment but distinguish the reasonable value of the electricity purchased from any supported premium. The purchasing side pays for the electricity and the fixed charge funds the policy component. Market-based export purchases outside legacy support do not become a new obligation on the charge. The detailed allocation needs published valuation rules and reconciliation, rather than discretionary cuts to existing entitlements.

A banded fixed charge

Set the legacy charge each year as a fixed annual amount for each connection, collected by suppliers in equal instalments and shown as a separate line on the bill. Charges will be banded so that larger users carry a larger share. Households will be banded by property, using council tax bands in England, Scotland and Wales and the equivalent valuation in Northern Ireland where the scheme applies. Businesses will be banded by the capacity of their connection. Ofgem will set the bands and publish the charge for each, so that the total collected matches the forecast requirement after industrial relief, with any difference corrected in the following year.

A fixed charge does not change a customer's bill with the electricity they use, so the unit price falls for everyone by the full amount of the legacy levy. Customers who use more electricity, including those who move to electric heating or vehicles, gain most from the lower unit price. Total bills for an average customer stay broadly the same, because the cost is recovered in a different form rather than removed.

Relief for industry funded from taxation

Exempt energy-intensive industries and manufacturers eligible for the British Industrial Competitiveness Scheme from the legacy charge in full, and extend their relief to renewable Contract for Difference costs where it does not already apply. Their share of the legacy cost will be funded from taxation rather than passed to other customers. This gives industry a lower total electricity bill, not only a lower marginal price, which matters for firms that compete on the cost of every tonne they produce. The relief builds on schemes already in place, so its additional fiscal cost is the extension of relief and the move of its funding from other bill payers to the Exchequer, estimated at around £1 billion to £2 billion a year before reconciliation.

Protection for low-income households

Low-income households will pay a reduced legacy charge, delivered automatically through the data-matching that already identifies households for the Warm Home Discount. The reduction will be funded within the charge, so that it does not create a new call on the Exchequer, and its cost to other households will be published.

Protect the benefit of CfD repayments

CfDs can require generators to repay when the reference price exceeds the strike price. Under the present funding model, the supplier settlement can return money to suppliers. Under the fixed charge, the destination of those receipts must be explicit. We propose to retain them in the same public settlement account, where they reduce the following year's charge, and to return any net portfolio surplus to electricity customers after reconciliation and necessary reserves. [5, 9]

If a period has £600 million of eligible top-ups and £100 million of repayments, the charge recovers the £500 million net requirement. If receipts are £250 million and top-ups £150 million, the £100 million net surplus is available for consumer credits. This preserves a benefit for customers during high-price periods. These examples illustrate the rule, not a forecast.

Credits must reach customers served by the central purchaser and those buying through other licensed routes on an equivalent basis. Do not credit a repayment twice if it already reduces the customer’s purchasing price. Report generator outflows minus receipts, consumer credits and administration separately so the same money is not counted twice.

Require full pass through

Ofgem should remove the legacy cost allowances from unit rates and audit the replacement fixed charge, certificate costs and tariff adjustments. Cover fixed tariffs as well as default tariffs, with clear rules for commercial contracts and hedged arrangements. The change must not become an extra supplier margin, and the reduction in unit rates must match the legacy cost removed from them. Ofgem will publish the effect on households and businesses in each band.

Where genuine savings can be made

Reduce the cost of moving and using electricity

Priority should go to network bottlenecks where reinforcement or changes in operations produce credible net savings. Value additional generation by its location and usable connection date. Competitive flexible-demand and storage procurement can help use output that would otherwise be constrained, but its enabling costs and effects on reliability must be counted. UK Electricity Market Reform provides the planning and purchasing framework for this work.

Measure constraints as a complete operational transaction, including any replacement generation and the cost of the solution. Do not count the same foregone subsidy, curtailment payment and replacement electricity twice. A payment to consume surplus electricity is justified by a cheaper reliable system, not by assuming every new flexible load deserves a guaranteed revenue floor.

Invite contractual changes that save money overall

Offer voluntary conversions or buyouts where an independently tested transaction improves the public position. Evaluate the full remaining cash-flow stack: electricity revenue, renewable support, indexation, repayment rights, hedges and transaction costs. Compare the proposal with continuing the current arrangement under the same market assumptions. A lower payment this year financed by a longer support term is not necessarily a lifetime saving.

Government already announced voluntary Wholesale Contracts for Difference in April 2026, with an intended allocation process in 2027. A July parliamentary answer clarified that this proposal changes wholesale revenues while RO support continues. It must therefore be assessed as a price-risk transaction, not described as the abolition of RO subsidy. Our central purchaser should evaluate the position inherited on taking office before creating an overlapping offer. [11–12]

For any new voluntary offer, publish eligibility, the valuation method and the public risk accepted. Use competition where assets are comparable; otherwise require an independent benchmark and an explanation of value for money. Changes require consent from the relevant counterparties and lenders. Refusal should leave existing contractual and statutory rights intact. No savings should be booked before an agreement is executable. Map procurement, subsidy-control and contract-modification requirements under the market paper before the offer becomes binding.

Enforce the obligations already agreed

Check eligible output, metering, accreditation and compliance with delivery conditions. Recover overpayments under the applicable rules. Apply contractual deadlines and remedies consistently. Negative-price provisions vary across contract generations, so administer the actual terms rather than claiming that one new rule automatically applies to every existing plant. Enforcement protects public value; it should not be used as a pretext to rewrite valid entitlements.

Keep transfers separate from savings

Changing how a payment is recovered changes who pays and how. Replacing fuel expenditure with cheaper useful generation, avoiding an unnecessary network cost or agreeing a genuinely cheaper contract changes the cost itself. Publish those categories separately. Independent research on electricity costs reinforces the need to examine the complete cost stack and the design of charges; it does not establish that this particular change in recovery pays for itself. [13–14]

The rules for future procurement

Buy the system we need

Future generation purchases should follow a funded system plan and an explicit reliability standard. Compare energy, dependable contribution at times of scarcity, flexibility, location, connection requirements and the public downside. Distinguish services that need separate purchases rather than pretending one electricity price captures them all. Use consistent assumptions for fuel, capital, networks, emissions policy and financing across technologies.

From year one, new wind and solar may compete for long-term, price-stabilising energy purchases under UK Electricity Market Reform. Award for useful supply at attractive whole-system value, with no automatic technology-specific subsidy entitlement. Use Electricity Supply through the Transition to assess the effect of each credible supply addition.

Choose the contract after identifying the need

A CfD is a settlement instrument, not a technology. Its name does not establish whether a particular purchase is good value. The central purchaser may use fixed prices, two-way price settlement, availability payments or combinations appropriate to the service. The terms must state the volume, duration, performance conditions, risk allocation and maximum public exposure. Eliminating the label while reproducing the same guarantee would achieve little.

Avoid promising both unlimited market upside and a taxpayer-funded downside. Where public commitments stabilise revenue, competitive procurement and repayment or sharing provisions should secure value for that protection. Assess indexation and contract length together: a longer term can reduce an annual price while increasing the period of commitment. Investors need a credible offer, and the public needs a transparent explanation of its cost.

Set the boundary between legacy and new business

The legacy register should include all valid commitments in force at commencement, including signed contracts for projects still under construction. Record unresolved awards, offers and legal claims separately; do not assume they can be cancelled without consequence. Announce the new procurement framework early enough for applicants to understand which rules govern them. The next government cannot responsibly freeze the present portfolio retrospectively at October 2026.

Existing plants may continue selling electricity after support expires. Repowering or major extensions should be assessed as new investment, subject to the applicable rights and the future purchasing rules. Expiry of support need not mean closure, but continued operation should not automatically earn an extension of the old subsidy.

Keep physical and financial responsibilities clear

The central purchaser manages its contracts and portfolio risks; NESO operates the system; Ofgem regulates delivery and pass-through; Treasury funds the defined public obligations. Generation operators remain accountable for their assets. Existing support does not confer an unrestricted right to dispatch, and a new purchasing contract must not bypass operational safety or system security. Publication and independent challenge of procurement decisions are necessary protections against political allocation.

Delivery and the test of success

Prepare before the targeted commencement in year one

Commission the reconciled obligations register, independent valuations and distributional assessment before setting the charge bands. Treasury must identify the Budget funding and annual cash provision for industrial relief, alongside the state’s first nuclear builds and other spending commitments.

The repeal and market legislation must preserve existing contracts, accrued rights and the statutory machinery needed to administer continuing support. Establish the fixed charge, the industrial relief and its Treasury funding duty, settlement reserves, the receipts rule and audit requirements. Map each change to primary legislation, regulations, contractual consent or supplier arrangements. The charge can operate through existing licensed suppliers while retail concessions are introduced, and payments must continue without a funding gap.

For Northern Ireland, work through its separate market arrangements and the relevant authorities. Its RO scheme must be mapped rather than assumed to follow a Great Britain supplier rule. Publish the territorial scope of each change to charges and public commitments. Customers should be able to see whether a promised change applies to them. [7]

Implement with a visible reconciliation

At commencement, remove eligible legacy charges from unit rates, introduce the fixed charge and fund the administrators directly or through an audited reimbursement route. Reconcile supplier claims against obligations actually incurred, taking account of existing exemptions and support. Require corrections where customers received too little or claims were excessive. Set common rules for consumer credits, including customers who change supplier or purchasing route during a settlement period.

Continue payments on time while the funding route changes. Avoid a cash gap between the end of unit-rate collection and the first receipts from the fixed charge. Publish opening reserves, working-capital needs and the treatment of disputes. A transition that interrupts settlement would damage the credibility the policy is intended to preserve.

Report outcomes that distinguish the objectives

Judge delivery separately on the audited fall in unit prices, the cost of industrial relief, real system savings and settlement continuity.

Repeal and continuity of inherited commitments

Change future policy without defeating existing rights

Apply UK Energy Reform Programme Annex Appendix C’s repeal and saving provisions to each scheme’s actual legal form. Preserve payment administration, counterparty powers and valid future-delivery rights while the fixed charge replaces the unit levy.

The fixed charge and the tax-funded industrial relief replace the defined unit-rate policy charges under the rules in this paper. Preserve counterparty authority, collection or reimbursement during migration, reserves, repayments, indexation and dispute handling. Ending future eligibility is a prospective decision. It must not create a payment gap, extinguish a valid future-delivery contract or return the legacy cost to unit rates through the purchaser settlement account.

Use the replacement objectives for new procurement

Apply the future-purchase rule in UK Electricity Market Reform and UK Energy Reform Programme Annex Appendix B. Voluntary buyouts and any exceptional-returns tax retain the tests in this paper.

Keep carbon pricing separate from support payments

Apply Programme Annex Appendix C’s carbon tax settlement, replacing the UK ETS with a £10 per tonne CO2e carbon tax and abolishing UK CBAM from the start of year two while honouring inherited support contracts. Preserve pre-closure liabilities and final settlement.

Rebase the legacy funding requirement for the £10 carbon tax wholesale-price case and a delayed-closure sensitivity. Lower reference prices can increase CfD top-ups or reduce repayments, raising the fixed charge and the cost of industrial relief. Reconcile this with lost ETS and CBAM receipts, net of carbon tax receipts in Appendix E, and do not book lower wholesale prices as a net programme saving. Keep nuclear and thermal commitments visible in the same assessment. [5, 10]

What this paper does not claim

A fixed charge changes how inherited obligations are paid. It does not erase them or prove net savings. Historical scheme amounts are not a reconciled budget for the first year or lifetime commitment.

Sources and evidence

Primary sources establish the scheme rules and reported amounts. Independent research informs the discussion of cost allocation. Policy recommendations, illustrative settlements and proposed implementation rules are our own. All sources accessed 11 October 2026.

[1] DESNZ Contracts for Difference Allocation Round 7 results. Results updated 10 February 2026. Delivery years and strike prices are award information, not evidence that every announced offer has been signed.

https://www.gov.uk/government/publications/contracts-for-difference-cfd-allocation-round-7-results/contracts-for-difference-allocation-round-7-results-accessible-webpage

[2] DESNZ Further reforms to the CfD scheme for AR7. July 2025 government response. Introduces 20-year contracts for specified wind and solar technologies.

https://www.gov.uk/government/consultations/further-reforms-to-the-contracts-for-difference-scheme-for-allocation-round-7/outcome/further-reforms-to-the-cfd-scheme-for-ar7-government-response-to-policy-proposals-published-july-2025-accessible-webpage

[3] Ofgem Renewables Obligation Annual Report Scheme Year 23. Report for April 2024 to March 2025, published March 2026. Scheme value calculation at printed page 67.

https://www.ofgem.gov.uk/sites/default/files/2026-03/RO_24-25_SY23_Annual_Report-20260327121336.pdf

[4] Ofgem Feed in Tariffs Annual Report Scheme Year 15. Report for April 2024 to March 2025, published 11 December 2025. Scheme value differs from total payments.

https://www.ofgem.gov.uk/transparency-document/feed-tariffs-annual-report-scheme-year-15-april-2024-march-2025

[5] Government Electricity Market Reform Contracts for Difference. Official account of private-law contracts, market sales and two-way price settlement. This collection contains legacy documents; contract-specific terms govern individual projects.

https://www.gov.uk/government/collections/electricity-market-reform-contracts-for-difference

[6] DESNZ Renewables Obligation to Exchequer scheme expenditure. Published 10 September 2026. April–June actual expenditure, three-year duration and annual Budget estimates.

https://www.gov.uk/government/publications/renewables-obligation-to-exchequer-scheme-expenditure-1-april-to-30-june-2026/the-renewables-obligation-to-exchequer-scheme-expenditure-1-april-to-30-june-2026

[7] DESNZ Renewables Obligation scheme indexation government response. 2026 response covering the change to CPI, the separate territorial schemes and the portfolio run-off.

https://www.gov.uk/government/consultations/renewables-obligation-ro-scheme-indexation-changes/outcome/renewables-obligation-ro-scheme-indexation-changes-government-response-html

Sources continued

[8] Ofgem Feed in Tariffs Guidance for Suppliers. Version 18, incorporating the 2026 change to CPI indexation.

https://www.ofgem.gov.uk/guidance/feed-tariffs-guidance-suppliers

[9] Government Electricity Market Reform CfD Supplier Obligation. Official supplier funding and settlement framework.

https://www.gov.uk/government/collections/electricity-market-reform-cfd-supplier-obligation

[10] DESNZ Annual Report and Accounts 2025 to 2026 Financial Statements. CfD payments and valuations at 31 March 2026. Figures cover a wider portfolio than renewable electricity and must retain that scope.

https://www.gov.uk/government/publications/desnz-annual-report-and-accounts-2025-to-2026/financial-statements

[11] Government Decisive action to break influence of gas on electricity prices. Announcement on 21 April 2026 of proposed voluntary Wholesale Contracts for Difference.

https://www.gov.uk/government/news/decisive-action-to-break-influence-of-gas-on-electricity-prices

[12] House of Lords written question 14078. Answer on 7 July 2026. Clarifies that proposed wholesale conversion retains RO support.

https://questions-statements.parliament.uk/written-questions/detail/2026-06-29/14078

[13] UK Energy Research Centre The cost of electricity in the UK. July 2026 review of drivers, challenges and opportunities for reform.

https://ukerc.ac.uk/publications/the-cost-of-electricity-in-the-uk-drivers-challenges-and-opportunities-for-reform/download

[14] Institute for Fiscal Studies Electricity prices. 2026 analysis of electricity costs and the effects of charging and taxation. Its wider recommendations are not adopted wholesale in this paper.

https://ifs.org.uk/publications/electricity-prices

[15] HMRC Electricity Generator Levy Manual Introduction. Current explanation of the levy on exceptional receipts, including the rate change from July 2026.

https://www.gov.uk/hmrc-internal-manuals/electricity-generator-levy-manual/egl01100

[16] HMRC Electricity Generator Levy Introduction. Scheme scope and the exclusion of generation covered by a CfD. Later amendments must be read alongside this original policy paper.

https://www.gov.uk/government/publications/electricity-generator-levy-introduction/electricity-generator-levy

[17] DESNZ and the CfD Delivery Body. Indicative Allocation Round 8 timetable. Process scenarios distinguish results, contract offers and signing. Checked 12 October 2026.

https://assets.www.cfdallocationround.uk/documents/Indicative_CfD_AR8_Timetable.pdf

Shared legislative sources appear in UK Energy Reform Programme Annex.