Forty-five years of network payments. A grid struggling to keep pace. Who is accountable for Britain’s complete energy bill?
HOPE consolidated energy-cost investigation · Evidence checked 17 October 2026
Decisions being taken today can leave our children paying through their energy bills for decades. Before those commitments grow, the public deserves to see the complete cost — and who is responsible for it.
“conceptually the same as repaying a 45-year loan to the network companies with associated interest payments”
Ofgem, December 2025 funding decision, paragraph 2.14. Its explanation includes debt interest and shareholder returns recovered from consumers. [28]
That is a financial commitment reaching across generations. The statement concerns regulated network funding; it is not a claim that every household has signed a personal loan or that every renewable project has a 45-year contract.
Long-lived infrastructure can justify long repayment periods. It must still demonstrate lasting public value. Where generation, grid connections and demand arrive on different timetables, households can fund the infrastructure while also paying for the operating consequences of the mismatch.
We pay for the power. We finance the network. We fund the interventions when the system cannot deliver electricity where it is needed.
The National Audit Office has already challenged the programme’s foundations: without an integrated plan or whole-system appraisal, Government had not demonstrated that its selected grid upgrades were the best way to achieve its objectives. [8]
That is the central public-interest question: who takes responsibility for the complete system, its complete cost and the risks passed to the people paying?
This report consolidates the infrastructure briefing, the Highlands and Islands investigation, the finance research and the affordability articles. It follows costs into bills and taxation, with a separate ledger for the evidence and unresolved figures.
The applause was public. The costs must be public too.
Screenshot supplied by HOPE. Original photograph: Leon Neal / Getty Images.
View the same meeting in an archive photograph
Political enthusiasm creates an obligation to explain the consequences. The public should be able to follow each subsequent target into the projects, contracts, financing and costs needed to deliver it.
The Climate Change Act dates from 2008, before this meeting. Responsibility for policy and its implementation rests with ministers, Parliament and the bodies making the decisions.
Your bills. Your employment. Your security. Your children’s future.
The household must be able to afford the system
A household pays for electricity and for the infrastructure and services needed to deliver it. Public scrutiny should follow the whole charge: construction, financing, support contracts, networks, reserve capacity and operating interventions. Putting a charge into taxation changes how it is collected; the national cost still needs explaining.
Industry needs power it can compete with
Our economic test is whether businesses can obtain dependable electricity at competitive prices, and whether investment delivers lasting value. The assessment should identify the effects on production, employment, supply chains and the cost of goods. A construction-investment headline cannot establish those outcomes on its own.
Security depends on power reaching the place that needs it
Installed capacity is only part of the engineering question. Britain also needs sufficient available generation, fuel and storage endurance, usable network capacity and dependable system control. The report examines what NESO actually did during tight conditions and which costs can be evidenced.
Future billpayers deserve an account before commitments are made
A long repayment horizon means today’s decisions reach beyond today’s voters and ministers. Our case is for a published lifetime account, tested alternatives and clear responsibility for delivery, so future consumers inherit infrastructure whose value has been demonstrated.
Electricity has become much dearer over the long run
ONS’s electricity price index rose from 287.2 in 2013 to 582.5 in 2025: approximately 103% in cash terms. The corresponding gas indices imply a rise of approximately 50%. These are annual price comparisons, rather than a comparison between households using different amounts of energy. [2] [3]
Prices have moved down as well as up. The 2022–23 crisis produced an exceptional peak. General inflation accounts for part of the longer-term increase. The difference between electricity and gas deserves investigation, but does not itself identify how much each policy contributed.
A smaller “typical” customer can obscure the comparison
For October–December 2026, Ofgem quotes an annualised dual-fuel cap of £1,723 on its revised typical-use benchmark.
Ofgem also publishes the equivalent on the previous benchmark: £1,935. These are two consumption assumptions applied to the same quarter, not two tariffs available to a household. The cap limits rates; an individual household’s bill still depends on consumption. [4]
Our consolidated account should therefore track unit rates, standing charges and bills at fixed consumption. A reduction in assumed usage must never be presented as though the underlying electricity had become cheaper.
The targets are binding. The technology choices require scrutiny.
The Climate Change Act established the legal framework. The 2050 target was tightened to Net Zero in 2019. Carbon budgets cap emissions over five-year periods. The CCC advises; ministers propose; Parliament approves the budget Orders. Those emissions limits do not, by themselves, prescribe an individual wind farm or solar development. [5]
| Budget | Period | Emissions ceiling |
|---|---|---|
| Fourth | 2023–2027 | 1,950 MtCO₂e |
| Fifth | 2028–2032 | 1,725 MtCO₂e |
| Sixth | 2033–2037 | 965 MtCO₂e |
| Seventh | 2038–2042 | 535 MtCO₂e |
The seventh budget is now set, rather than merely recommended. Accounting scope changes, including international aviation and shipping, make simplistic percentage comparisons between budgets unreliable. [5]
Clean Power 2030 adds a demanding construction timetable
The Government’s action plan sets out the following capacity ranges. They are installed-capacity ambitions, not a promise that all that capacity will produce electricity simultaneously. [6]
| Technology | 2030 plan |
|---|---|
| Offshore wind | 43–50 GW |
| Onshore wind | 27–29 GW |
| Solar | 45–47 GW |
| Batteries | 23–27 GW |
| Long-duration storage | 4–6 GW |
| Retained unabated gas reserve | 35 GW expected |
The plan’s clean-power definition concerns annual production and a typical weather year, including at least 95% clean domestic generation. It retains gas for security. Battery power in GW also needs an energy capacity in GWh before we know how long it can sustain that output. [6]
Our test is practical: can the generation, network, storage, firm capacity and workforce arrive together, and what does the complete timetable cost?
The heat-pump bill reaches right into the home
A household’s direct installation bill belongs in the national account alongside the power stations and grid. Grants, private payments and borrowing must be traced to the people funding them.
The £258 billion illustration — what it measures
The Boiler Upgrade Scheme workbook records a £12,908 median reported air-to-water installation cost for April–June 2026 redemptions in England and Wales. It covers equipment, labour and VAT; installers should include the grant. The data are self-reported and filtered for outliers. [30]
20 million installations × £12,908 = £258.16 billion.
A scale illustration at an unchanged benchmark. Twenty million is our scenario, not a verified government installation target. This is gross installation expenditure, not the additional cost compared with continuing to replace boilers.
This calculation does not allow for financing, later replacement cycles or separately required building and network works. It deducts neither avoided boiler replacement costs nor future running-cost savings. Future prices and property requirements will vary. Do not add it to the economy-wide Carbon Budget model, which already contains heating investment.
A grant changes who pays
With the standard £7,500 air-source grant, that benchmark leaves an illustrative £5,408 for the household. The grant is part of the installation price; adding it again would count the same cost twice. Eligibility matters, and some off-gas oil or LPG homes can receive an extra £1,500 until March 2027. Taxpayer support reduces the recipient’s bill while transferring part of the funding to the public purse. [34]
The local electricity supply also has to be ready
DESNZ research estimates 3.1–4.7 million GB homes may have shared, or “looped”, supply connections. Some need new service cables before additional electrical demand can be connected. One network operator reported £2,500–£6,000 per unlooping job; standard works are generally funded through network charges. [32]
Homes and engineering jobs are different units. These figures do not establish that every affected home needs work for a heat pump, or justify multiplying all affected homes by one operator’s job cost. Identify the necessary work and existing network funding before estimating any additional national cost.
The delivery rate and the saving both need explaining
The CCC says retrofit installations need to reach around 1.4 million a year in 2035 in its pathway. Workforce, connection readiness and household affordability have to support that pace. [31]
Its 2026 assessment says many households would not currently save by switching to a heat pump alone. It also finds that suitable homes can save with solar panels, a time-of-use tariff and available support. Those options are not accessible to every household; performance and tariff choice matter. [31]
Our test: publish the installation bill, any enabling works, the funding split and the expected lifetime saving for the home that actually has to make the change.
Your electricity bill funds several different things
The Commons Library provides a useful worked breakdown for April–June 2026. It uses a direct-debit customer consuming 2,700 kWh annually. This is a historical explanatory snapshot, not the current quarter’s bill. [7]
| Component | Annual allowance |
|---|---|
| Wholesale, including CfD and Capacity Market allowances | £333 |
| Network infrastructure | £214 |
| System balancing | £42 |
| Direct policy costs | £78 |
| Supplier operating, debt and industry costs | £141 |
| Remaining VAT, profit and other allowances* | £67 |
| Total | £875 |
*£67 is our subtraction from the rounded published figures. Components are already inside the £875 bill.
Gas and carbon costs influence wholesale electricity prices because gas generation frequently sets the marginal price. Network charges fund maintenance and expansion. Balancing pays for operational interventions. Direct policy charges include renewable support and social or efficiency schemes. [7]
These costs can move in different directions. Lower wholesale electricity prices can be partly offset by other charges. Equally, a rise driven by international gas markets should be identified as such. The reader deserves the contribution of each component, rather than a single explanation selected to suit the argument.
We pay when generation gets ahead of the network
The NAO reports £1.9 billion of constraint costs in 2025–26. These fund redispatch around grid bottlenecks, including replacement generation, rather than solely wind turn-down payments. [8]
Its delayed critical-upgrade scenario reaches £7.8 billion annually by 2030. This is a forecast, not an outturn.
Ofgem estimates around £70 billion of transmission investment between 2025 and 2031. It projects a £30 net annual household saving against slower delivery, after higher network charges and avoided constraints. [8]
Our conclusion: generation location, commissioning dates and usable grid capacity must be costed together. Delay has a price, and so does building the wrong sequence.
Margin notices: follow the actions and the money
An Electricity Margin Notice asks the market to make more capacity available when NESO wants a larger operating cushion. A Capacity Market Notice is a separate, automatic signal with different thresholds and timing. Emergency Assistance is another operational tool. These should not be treated as interchangeable events. [9]
The original explanations matter
NESO’s June account describes high temperatures and lower-than-expected wind and gas availability. It used demand flexibility, generator engagement and coordination with neighbouring system operators; the margin notice was withdrawn after conditions improved. [10]
Its 14 October account confirms two recent requests for Emergency Assistance. On the Friday, transmission constraints limited access to northern generation while wind output fell. On the Monday, unavailable South East transmission infrastructure restricted transfers; assistance eventually reached 1,200 MW. NESO says supplies remained secure. [11]
The original July monthly report supplies a costed example: £5.1 million in total balancing costs on 9 July, the day covered by a margin notice issued on 8 July. That is the day’s total, not the notice’s incremental cost. [27]
Those explanations strengthen the cost investigation: available national generation is of limited use if the network cannot deliver it to the place that needs it.
However, a notice does not have a standard fee. Issuing or cancelling one cannot prove that it added a particular number of millions to bills. The costs arise from the associated trades, accepted balancing bids and offers, reserve activation, demand-response payments and assistance arrangements.
For each incident, the account needs the warning and withdrawal times, affected periods, instructed volumes, accepted prices and subsequent settlement. The incremental cost also needs a defensible comparison with what normal operation would have cost. A day’s entire balancing bill cannot automatically be attributed to its notice.
The monthly account already shows material expenditure
NESO’s September 2026 balancing outturn, against a £306 million month-ahead forecast. This is a system-wide operating figure, not a price attached to individual margin notices. [1]
| Month | Balancing cost |
|---|---|
| April 2026 | £309.0m |
| May 2026 | £235.7m |
| June 2026 | £302.3m |
| July 2026 | £298.1m |
| August 2026 | £247.2m |
| September 2026 | £541.1m |
Our sum of the publication’s twelve monthly balancing figures is approximately £3.639 billion for October 2025–September 2026. It excludes the separately listed internal BSUoS costs. It is a rolling-year total, not a financial-year total. [1]
BSUoS charges recover operating and balancing costs. Recovery uses tariffs set in advance, so an expensive operating day does not translate directly into an identically timed household-bill increase. [12]
The contracts continue long after construction
We also pay for capacity to be ready
The Capacity Market pays providers to remain available for system stress. It supports gas, nuclear, storage, interconnectors and demand response; the electricity they supply is a separate transaction. In March 2025, the T-4 auction secured 43.1 GW for 2028–29 at £60/kW a year. Multiplying those rounded figures gives an indicative £2.59 billion annual availability commitment, before contract adjustments and indexation. This is one auction’s future delivery-year commitment, not current annual spending or an extra charge to add to the bill table. [16]
Keeping voltage, frequency and stability within limits also requires paid services. NESO identifies wholesale prices, ancillary-service procurement and rising variability among balancing-cost drivers. Those service costs must be reconciled within the operating account before separate contract totals are added. [26]
One checked example is £40.8 million for voltage control in July 2026. NESO links the increased requirement for synchronous generation to very high solar output and system-operability needs. This cost is within its July monthly account, not an extra amount to add to the month’s total. [27]
Legacy support and newer revenue contracts
Legacy renewable support remains material. Ofgem values the Renewables Obligation at approximately £7.7 billion for 2024–25. That is its scheme-value measure, not an audited cheque paid by the Treasury to developers. [13]
For the same period, the Feed-in Tariffs report distinguishes roughly £1.83 billion paid to generators from approximately £1.73 billion in total scheme cost after the relevant export-value and administration treatment. These are alternative measures, not amounts to add. [14]
DESNZ’s accounts show CfD cash payments to generators of £2.198 billion in 2024–25, rising to £2.924 billion in 2025–26. The later accounts put the net CfD derivative liability at £110.923 billion at 31 March 2026. That is a valuation of expected future contract exposure, not another cash payment that year. [15]
A CfD stabilises revenue around an agreed strike price. Payments can reverse when the market reference price exceeds that strike price. For several renewable technologies, Allocation Round 7 moved to 20-year contracts; the new contracts are CPI-indexed. A complete account must show receipts back from generators and wholesale-price effects as well as support paid out. [16] [17]
Moving a charge into taxation changes who pays
From April 2026, 75% of domestic Renewables Obligation costs were transferred to Exchequer funding for three years. Government reports £520.71 million of spending in April–June 2026. [18]
The change can help households with their electricity bills. But the underlying support obligation still exists. The national account must show the reduction on bills alongside the cost to taxation, without counting the transfer as a second subsidy.
Carbon charges need their own line
UK ETS and Carbon Price Support costs should be identified within the wholesale account. They are separate from developers’ borrowing costs. CPS remains equivalent to £18 per tonne of CO₂ for 2026–27; Government has announced removal from April 2028, with legislation to follow. Long-term projections must reflect that announced change rather than assuming CPS continues indefinitely. [19] [20]
The 45-year commitment: capital, interest and investor returns
The phrase “private investment” tells us who provides money initially. It does not settle how the investment is ultimately recovered.
For regulated transmission, network charges fund allowed expenditure and capital recovery, including an allowance for debt and equity returns. For supported generation, market receipts and contract settlements support the project’s revenue. Banks receive interest; shareholders receive returns. Neither should be labelled as the other’s payment.
Ofgem’s RIIO-3 finance settlement sets an electricity-transmission real equity allowance of 5.70%. Its nominal weighted-average cost-of-capital allowances range from 6.65% to 6.86% across the three transmission owners. These are regulatory benchmarks on specified capital bases, not guaranteed dividends or a percentage to apply indiscriminately to every project announcement. [21]
The same settlement retains a 45-year regulatory asset life for electricity transmission. The consumer obligation therefore extends well beyond the construction period. The question for scrutiny is the total allowed revenue and the value delivered over that life. [21]
A simple example shows why the finance matters
Take an illustrative £1 billion loan, repaid through equal annual payments over 45 years. This is our calculation, not a named project’s financing arrangement or a model of Ofgem’s regulatory charging formula.
| Fixed annual interest rate | Annual repayment | Total interest |
|---|---|---|
| 4% | £48.3m | £1,171.8m |
| 6% | £64.7m | £1,911.5m |
| 8% | £82.6m | £2,716.4m |
Nominal, undiscounted payments; constant rates; annual repayments in arrears; no fees, tax, inflation indexation, construction drawdown or refinancing. Principal is repaid within the annual payments.
Real projects have mixed financing, construction schedules and different asset lives. The example demonstrates sensitivity, rather than estimating Britain’s finance bill. Higher rates, delays and longer construction can materially change the revenue needed to recover a project.
Revenue certainty can reduce financing costs. Consumers should see what they receive in exchange for bearing price or delivery risk: lower allowed returns, stronger delivery obligations, refinancing gains where contracts provide for sharing, or enforceable cost controls.
Apply the same scrutiny across technologies. Sizewell C uses a regulated-asset-base funding model, so nuclear belongs in the financing account too. A preferred technology should face the same questions about construction, funding, operating cost and risk. [22]
Hundreds of billions are in the plans. They are not all additional to one another.
NISTA’s March 2026 pipeline identified £365 billion of planned energy investment over ten years. It is a pipeline measure, not a complete lifetime consumer bill or expenditure already incurred. [23]
SSE separately describes more than £29 billion for transmission in the north of Scotland. This sits within the wider transmission programme. It cannot simply be added to the national grid envelope as if it were entirely separate. The Highlands and Islands work is valuable because it exposes the physical projects and supporting works inside these larger figures. [24]
Each cable contract, substation, access road and converter station needs a project identifier and a parent budget. We should identify the cost of battery-cell replacement, repowering and restoration as well, using evidenced asset lives rather than one assumed replacement date for the whole system.
The broad Net Zero model answers a different question
Table 6 of the Seventh Carbon Budget impact assessment estimates £880 billion of additional capital and finance costs over 2025–2050, against its “no Net Zero” baseline. It also models operating savings and wider benefits. The figure is discounted, uses 2025 prices and spans the economy; it is not an electricity-only cash bill. [25]
Its forecast benefits include values assigned to avoided emissions, air quality and nature. These are appraisal benefits, rather than money arriving in a family’s bank account. They deserve assessment on their own terms. Separately, Annex A3 says detailed quantified distributional analysis was not possible at that stage because a specific policy package had not been assessed.
A favourable national model still leaves a household question: who must find the money, in which year, and with what protection if costs or delivery differ from the forecast?
We should test fuel savings, reduced exposure to imported gas and other benefits alongside the full costs. Credible alternatives need the same demand, weather, reliability, fuel-price and finance assumptions. A generation-only comparison cannot settle the cost of a functioning national system.
Scotland shows what the grid numbers mean on the ground
The grid programme includes access roads, foundations, substations, cables and construction logistics. The same December update reported more than 350,000 cubic metres of earth moved within the Creag Dhubh substation site. These are substantial physical works, with financial and local consequences. [33]
SSE’s £29 billion-plus north Scotland transmission programme is a wider company investment envelope. It is not the cost of the pictured sites, and those photographs cannot establish its entire environmental or economic impact. [24]
For each project, the public needs the budget, financing, connection timetable, land and habitat requirements, reinstatement obligations and the cost of delay. Claimed jobs, resilience and avoided constraint costs should be tested alongside the construction and operating costs.
A national target must be accountable for the complete works required to deliver it, including the communities and landscapes hosting them.
Who is accountable for the complete system?
The bill has several sources of pressure: fuel-market shocks; continuing support contracts; network expansion and replacement; financing; and the operational cost of keeping a changing system within its limits.
Generation and network delivery are poorly aligned in important places. Current operating records show substantial balancing expenditure, while the contract accounts disclose recurring payments and long-term exposure.
Those are strong findings. The precise share of the historical price increase caused by each policy remains unestablished. Some network and security expenditure would be required under any plausible system, and the benefits of alternative pathways must be tested rather than assumed.
Responsibility sits across institutions with different functions. The public should be able to identify the decision, the responsible body and the consequences for the bill.
| Body | What it is responsible for | What the public should require |
|---|---|---|
| Government / DESNZ | Policy choices and proposed targets; Parliament approves budget Orders. | A costed delivery plan and named ministerial accountability. |
| Climate Change Committee | Independent advice on carbon budgets and scrutiny of emissions progress. | Transparent assumptions and challengeable cost and delivery evidence. |
| NESO | System planning, operation and balancing. | Compatible generation and grid timetables, operability evidence and costs. |
| Ofgem | Network price controls and allowed revenues. | Evidence of need, efficient costs, appropriate returns and delivery protections. |
| Network companies | Ownership, construction and management of network assets. | Visible project budgets, progress, performance and consequences of delay. |
Roles are described in the carbon-budget guidance, NESO’s operational account, Ofgem’s finance determination and the NAO’s grid investigation. [5] [11] [21] [8]
Our criticism is that the complete consumer commitment must be demonstrated across those decisions. A target, an investment announcement and a regulatory approval do not individually answer whether the whole programme is affordable, secure and deliverable.
The public deserves one account: what it costs, what is included, what is missing, and who pays.
Parliament should require a year-by-year consumer and taxpayer account that connects the targets to physical assets, grid readiness, contracts and financing. It should compare feasible alternatives and publish the distribution of costs across households and industry.
For margin notices and assistance events, it should require an incident ledger reconciling the operational response with settled costs. No unexplained “millions per notice”. No dismissal of material expenditure simply because the lights stayed on.
MAKE THEM SHOW THE EVIDENCE
Our petition calls for Climate Change Act targets to be suspended while a full national impact assessment examines costs, delivery, bills, industry, food security, energy security and the countryside.
Read, sign and share the petition
Official UK Parliament petition: https://petition.parliament.uk/petitions/780321
The consolidated cost ledger
These entries answer different questions and are deliberately not summed. “Published” means the source publishes the figure; it does not make a forecast an outturn. GB and UK coverage must be harmonised before an aggregate is calculated.
| Item | Figure / period | What it measures | Treatment |
|---|---|---|---|
| ONS electricity prices | 287.2 → 582.5; 2013 → 2025 | Annual nominal RPI indices | About +103%; no causal attribution. [2] |
| Current cap comparison | £1,723 / £1,935; Q4 2026 | Annualised dual-fuel bill on new / previous usage assumptions | Two benchmarks, one quarter. [4] |
| Transmission programme | Around £70bn; 2025–2031 | Estimated investment requirement | Capital envelope; overlaps company programmes. [8] |
| Constraint outturn | £1.9bn; 2025–26 | Annual constraint costs reported by NAO | Subset of wider balancing; never add twice. [8] |
| Constraint risk | Up to £7.8bn; 2030 | Conditional annual forecast | Separate from actuals; scenario-dependent. [8] |
| September balancing | £541.10m; Sep 2026 | External balancing-cost row | Excludes separate internal BSUoS row. [1] |
| Renewables Obligation | About £7.7bn; 2024–25 | UK scheme value | Not the same as Exchequer spending. [13] |
| Feed-in Tariffs | About £1.73bn; 2024–25 | GB total scheme cost, after specified adjustments | Do not add gross generator payments again. [14] |
| CfD annual payments | £2.198bn → £2.924bn; FY2024–25 → FY2025–26 | Cash payments to generators | Not construction cost or a net whole-market impact. [15] |
| Capacity Market 2025 T-4 auction | Indicative £2.59bn for delivery year 2028–29 | 43.1 GW × £60/kW/year | Rounded auction arithmetic; adjustments and indexation excluded. [16] |
| CfD closing liability | £110.923bn; 31 March 2026 | Net derivative liability valuation | Not an annual payment; not additive to annual cash flows. [15] |
| RO Exchequer transfer | £520.71m; Apr–Jun 2026 | Reported GB expenditure | Funding transfer for existing support; excludes running costs. [18] |
| Transmission finance | 5.70% real equity; 6.65–6.86% nominal WACC | RIIO-3 regulated benchmarks | Use correct capital base, gearing and price basis. [21] |
| Long-term network recovery | 45-year recovery explanation; December 2025 | Ofgem’s description of regulated network funding | Includes debt interest and shareholder returns; not a universal generation-contract term. [28] |
| North Scotland transmission | £29bn+; RIIO-T3 programme | Company investment programme | 100% programme value; overlaps national transmission envelope. [24] |
| NISTA energy pipeline | £365bn; March 2026 ten-year outlook | Planned investment | Portfolio control; not a full lifetime bill. [23] |
| Heat-pump installation illustration | £258.16bn for 20 million installations | Own scenario using £12,908 median BUS benchmark | Gross installation scale; not a forecast, net cost or addition to CB7. [30] |
| CB7 capital and finance | £880bn; 2025–2050 | Additional discounted model cost, 2025 prices | Economy-wide; includes finance; specified no-Net-Zero baseline. [25] |
Corrections and figures held for reconciliation
Consolidation should preserve the useful earlier work while correcting labels and preventing old assumptions becoming new facts.
| Earlier material | Decision for this account |
|---|---|
| July £302m / £298.10m | The original July Monthly Balancing Cost Report says £302m, including £40.8m voltage control. The September BSUoS sheet lists July at £298.10m and June at £302.30m. Preserve both publications: the difference needs definition and reconciliation checks, rather than a date correction. The earlier £167.8m thermal comparison still needs its original chart. [27] |
| “September £505m” / “nearly £50m in a day” | Use £541.10m for the verified September balancing row. The other figures need their original datasets, precise scope and settlement dates; neither is assigned to a margin notice here. |
| £15.6bn and £17.8bn annual support totals | Rebuild by scheme, period, territory and cash/accrual basis. The baskets differ and can include heat, efficiency or system costs. Neither is adopted as a verified electricity-only annual total. |
| £2.2165bn CfD figure in the infrastructure briefing | The financial statements provide £2.198bn FY2024–25 cash payments. Reconcile timing and accounting basis before substituting or aggregating the earlier figure. |
| £20bn Highlands and Islands / £29bn+ wider north Scotland | Different geographies, dates and overlapping programmes. Keep the regional audit as a project map; establish unique asset identifiers before a regional sum. |
| £660–£765bn across Carbon Budgets 4–6 | Historical 2021 model estimates, not cumulative observed spending. Recheck source tables and overlap before use. Do not add to newer CB7 models. |
| CCC-derived £1.03tn excluding direct road transport | Retain the existing spreadsheet’s separate scope and model basis. It still includes shared infrastructure reflecting transport demand; it is not an EV-free electricity bill. |
| £957bn / £478.42bn spreadsheet discussion | The corrected sector subtotal must be traced to the original workbook and price basis. Do not add an existing total row to its component rows. The discredited double-counted headline is excluded. |
| National battery replacement, voltage-control and reserve totals | Build asset and contract registers. Contract award values, annual utilisation costs and equipment capital can overlap. No evidenced national lifetime total is established here. |
| Heat-pump national extrapolation | The 20-million scenario uses a single current benchmark without a future price path. It excludes separate enabling works and finance, but also omits avoided boiler purchases and operating savings. No per-home unlooping charge is extrapolated nationally; homes are not job counts. |
| January 2027 bill forecasts | Keep separate from confirmed Q4 2026 rates. Update from a dated forecaster and retain the same consumption benchmark; do not present an older forecast as an Ofgem decision. |
How to finish the national account
- Assets: Give every project a unique ID, parent budget, owner, location, grid dependency, commissioning date, construction cost, price basis and expenditure profile. Map regional projects into national controls.
- Revenue: Record energy sales, support, regulated charges, capacity payments and other contracted services. Separate actual payments, accrued costs, forecasts and accounting liabilities.
- Finance: Identify debt, equity, fees, construction interest, indexation, refinancing and risk-sharing. Count each financing cost once, including costs already inside a model or allowed revenue.
- Operations: Reconcile constraints with total balancing, and security/stability contracts with utilisation and internal operator costs. Keep settlements and refunds visible.
- Incidents: Match each EMN, CMN and assistance request to original notices and instructed actions. Event-specific incremental cost remains open until that reconciliation is done.
- Alternatives: Compare demand-led pathways on common hourly reliability, fuel, finance and weather assumptions, including nuclear, dispatchable gas, renewable options, efficiency, storage and their infrastructure needs.
- Payers: Allocate costs to household electricity, gas, businesses, taxation and direct household purchases. Show income and regional impacts and test projected benefits with the same rigour as projected costs.
Calculation notes: Loan repayment A = P × r ÷ [1 − (1 + r)−n]; interest = nA − P. Rolling balancing total uses the 12 figures in source 1 without internal BSUoS costs. Historical price changes use annual indices, not a comparison with one selected month. No household “share” is calculated by simply dividing national costs by the number of homes.
Primary sources
Links identify the publications supporting this report. Earlier HOPE drafts were used to locate evidence; they are not treated as independent verification of their own claims.
- NESO — BSUoS Outturn for September 2026, published 15 October 2026. Page 1 monthly rows; September outturn and forecast commentary. Latest verified monthly operational account used here.
- ONS — Electricity RPI, DOBX. Annual averages 2013 and 2025; cash-price comparison.
- ONS — Gas RPI, DOBY. Annual averages 2013 and 2025; separate gas-price comparison.
- Ofgem — Energy price cap will rise by 4% from October 2026, 26 August 2026. See notes on revised typical consumption and old-benchmark equivalent. Published rates and temporary electricity-VAT treatment.
- DESNZ — Carbon budgets, current guidance. Statutory levels, periods and seventh-budget status. Carbon Budget Order 2026.
- DESNZ — Clean Power 2030 Action Plan, main report. Summary: annual clean-power definition, technology ranges and retained gas reserve.
- House of Commons Library — What costs make up an electricity bill?, 13 May 2026. Q2 2026 component allowances; wholesale price formation and classification of CfD/Capacity Market costs.
- NAO — Delays to electricity grid upgrades risk higher bills, 11 September 2026. Full report. Constraint outturn, conditional 2030 forecast, investment envelope and appraisal shortcomings.
- NESO — What are system notices? Distinguishes operational margin notices and automatic Capacity Market notices.
- NESO — Electricity Margin Notice explanation, 24 June 2026. Original operator account of conditions and actions.
- NESO — Emergency Assistance: what it is, and why we used it over the last week, 14 October 2026. Original operator account of the two October incidents; no incident cost is supplied.
- NESO — BSUoS charges. Cost recovery and tariff information. Fixed-tariff methodology explanation.
- Ofgem — Renewables Obligation Annual Report, Scheme Year 23. Scheme value in 2024–25; see summary and scheme-value methodology.
- Ofgem — Feed-in Tariffs Annual Report, Scheme Year 15. Distinguishes payments, scheme value, levelisation and total scheme cost.
- DESNZ — Annual report and accounts 2025–26, financial statements. Cash-flow statement and note 9.1 derivative table; comparative FY2024–25 cash payments and 31 March 2026 net liability.
- DESNZ — CfD and Capacity Market scheme update 2025. AR7 CPI-indexed 20-year terms and scheme mechanisms.
- DESNZ — AR7 subsidy-control estimates, 14 April 2026. Contract terms, uncertainty and why subsidy estimates are not the net impact on bills.
- DESNZ — RO to Exchequer expenditure, April–June 2026, 10 September 2026. 75% domestic-cost transfer and £520,709,288.19 reported spending.
- HM Treasury — Autumn Budget 2024 tax measures, section 2.27. CPS equivalent £18/tCO₂ in 2026–27.
- Treasury — Carbon Price Support written statement, 16 April 2026. Announced removal from April 2028 and intended legislation.
- Ofgem — RIIO-3 Final Determinations, Finance Annex, December 2025. Table 16, printed page 77: equity, gearing, debt and nominal/real WACC. Allowances are not project-specific realised profits.
- DESNZ — Sizewell C: Regulated Asset Base. Financing-model documentation; nuclear retained within the scrutiny framework.
- NISTA — Infrastructure pipeline update, 9 March 2026. £365bn energy investment in the ten-year pipeline.
- SSE — North Scotland transmission investment programme, 2 April 2026. £29bn+ programme; full programme value, rather than SSE’s ownership share.
- DESNZ — Seventh Carbon Budget impact assessment, 2026. Table 6, printed page 43: discounted 2025–2050 costs and benefits against the no-Net-Zero baseline. Annex A3, printed page 119: limits of quantified distributional assessment.
- NESO — Balancing costs. Physical system actions, ancillary services and the operator’s explanation of rising-cost drivers.
- NESO — July 2026 Monthly Balancing Cost Report. Executive summary: monthly total, voltage control and the 9 July margin-notice day.
- Ofgem — RIIO-2 Re-opener Applications 2025 Final Determinations, Overview Document, 12 December 2025. Paragraph 2.14, printed pages 16–17: 45-year recovery, debt interest and shareholder returns. Quotation: © Crown copyright 2025, Open Government Licence v3.0.
- Getty Images — Greta Thunberg receives applause, 23 April 2019. Leon Neal, editorial photograph 1144590725. Displayed screenshot supplied by HOPE. Names cross-checked against the BBC’s photograph caption. Same-meeting archive image: Defra Press Office, 24 April 2019, Crown copyright / OGL v3.0. Neither image establishes the cost or causation of later policies.
- DESNZ — Boiler Upgrade Scheme statistics, August 2026, published 24 September 2026. Workbook Q1.1A, cell S10: April–June 2026 median; note 4: self-reported cost scope, grant inclusion and filtering. £258.16bn is our scenario calculation.
- CCC — Progress in reducing emissions, 2026 report to Parliament. Box 4.1: retrofit installation rate in 2035; section 5.2.4 and executive summary: household heating costs, solar, tariffs and access limitations.
- DESNZ — Unlooping Electricity Network Connections Research, summary report. Printed pages 4 and 16–18: uncertain property estimates; page 27: operator-specific job costs and socialised funding of standard works.
- SSEN Transmission — First tower completed on Creag Dhubh–Dalmally overhead line project, December 2025. Construction photograph, route, tower count, access tracks and substation earthworks. Archive update, not a current site inspection.
- GOV.UK — Boiler Upgrade Scheme: what you can get. Grant amounts and temporary oil/LPG supplement, checked 17 October 2026.
- SSEN Transmission — Creag Dhubh–Inveraray construction update, 10 March 2026. Source and publication date of the Creag Dhubh substation aerial photograph; © SSEN Transmission.
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