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An SMR business case must model the entire asset life, not just the reactor’s overnight price. Include development, licensing, first-of-a-kind (FOAK) design work, site and grid infrastructure, construction financing, operations, fuel, waste, decommissioning and dismantling. On the revenue side, build a net-electricity cash-flow case from contracted or forecast market prices, then add heat, hydrogen, synthetic-fuel or data-centre sales only when a named customer, compatible output, delivery infrastructure and contract terms exist.
Keep three ledgers separate: project cash flow, policy support and wider public value. Energy security, jobs and regional growth may justify public participation, but they are not plant revenue unless the project has a mechanism to capture them.
Start with a defined project boundary
“SMR” can describe very different reactors, factory strategies and commercial structures. Before entering a number, record the country and market, reactor design and maturity, net electrical output, number of units, site, construction sequence, ownership structure, price year, currency and whether values are real or nominal. State whether each figure is an estimate, a bid, a regulated allowance or a scenario assumption.
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Do not combine a generic six-unit estimate, a FOAK technology assessment and a current programme budget as though they were comparable quotes. Align plant size, design maturity, included scope, unit count, financing basis, price year and currency before comparing costs per kilowatt or levelised cost.
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Use a scope register
- Define the boundary around the nuclear island, turbine or conversion equipment, balance of plant, site works, grid connection and any heat or hydrogen facilities.
- Specify whether values are overnight costs or include interest during construction (IDC), owner’s costs, contingency, taxes, insurance and escalation.
- Identify which costs are shared across a fleet and which are charged to the first unit.
- Separate cash costs from external benefits such as avoided emissions or local employment.
Cost assumptions to include
Development and pre-construction
Budget site screening, geological and hydrological studies, environmental surveys, cooling and water assessments, transport studies, grid studies and land control. Include design completion, engineering, safety and environmental cases, licensing and regulatory review, permitting, legal work, insurance during development, procurement support and the owner’s project-management team. Development spending often occurs years before revenue and should be shown by year in the cash-flow model.
FOAK design and supply-chain costs
A new design carries obligations that are easy to omit from a plant-only estimate: final design engineering, licensing and certification, qualification of suppliers, factory tooling, manufacturing-facility setup, prototype or test work, first-unit commissioning and the cost of resolving early defects. Decide how much of these shared costs the first project bears and how much is recovered from later units. The U.S. Energy Information Administration (EIA) generic estimate explicitly excludes the full design, licensing and manufacturing-facility burden of bringing a new SMR design to market; it is therefore not a complete developer budget.
Plant, site and enabling capital
Include the nuclear island, conventional island, turbines and generators, balance of plant, construction management and EPC scope. Add land, site preparation, roads, rail or port access, water intake and treatment, cooling systems, warehouses, security, construction camps, temporary utilities and waste-handling facilities. Grid scope should cover the substation, electrical interconnection, transmission upgrades and the owner’s utility works. If heat or hydrogen is part of the plan, add reactors or heat exchangers, pipelines, storage, electrolysers, compression, customer interconnection and metering rather than treating those facilities as free options.
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Owner’s costs can include project development, permitting, legal services, project management, engineering, start-up, land and utility interconnection. Make contingency visible by risk category: design maturity, supply chain, civil works, regulatory changes, weather, commissioning and schedule. A single percentage can conceal that FOAK uncertainty and conventional construction uncertainty are different risks.
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Financing and delivery schedule
Model the debt/equity mix, drawdown profile, interest during construction, fees, reserve accounts, refinancing and any guarantee or cost-sharing arrangement. Construction duration is a value driver because a delayed project accumulates IDC, owner overhead and replacement-power costs while postponing revenue. Run explicit delay cases rather than burying schedule risk in a generic contingency.
The 2017 UK SMR Techno-Economic Assessment used an 8.9% cost of capital for its generic FOAK case and warned that development-cost accumulation or higher early financing costs could push costs higher. That rate is a dated scenario input, not a universal financing quote.
Operations, fuel and end of life
Operating expenditure should cover staffing, training, maintenance, security, contracted services, administration, insurance, property taxes, regulatory fees, fuel procurement and fabrication, consumables, water and discharge treatment, waste conditioning and disposal, outage and refuelling work, and working capital. Include a realistic outage schedule and the effect of planned and unplanned outages on saleable generation.
Set aside decommissioning and site-restoration provisions from the start. Model the timing of contributions, investment returns on the fund, dismantling work, spent-fuel and radioactive-waste obligations, final site condition and any residual value. Do not assume that a future operator or government will absorb these liabilities without a documented contractual basis.
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Benchmarks: what published figures do—and do not—mean
| Published figure | What it represents | Important qualification |
|---|---|---|
| £86–£124/MWh; central £101/MWh | 2017 UK SMR Techno-Economic Assessment estimate for a generic IPWR FOAK levelised cost of electricity | Excludes GDA costs, applies a 54% optimism-bias uplift and assumes an 8.9% cost of capital; it is not a current vendor price |
| $4.289 billion total capital; $8,936/kW | EIA and Z Federal 2025 publication, six 80 MW units (480 MW), in 2023 dollars | Includes EPC and owner costs but excludes the full burden of new-design development, licensing and manufacturing-facility deployment; generic model, not a bid |
| $121.99/kW-year fixed non-fuel O&M | EIA and Z Federal modeled SMR case, in 2023 dollars | Includes labour, materials, contracted services and G&A; fuel, property taxes and insurance are excluded |
| $3.19/MWh variable non-fuel O&M | EIA and Z Federal modeled SMR case, in 2023 dollars | Covers water, discharge treatment, chemicals and consumables; fuel, property taxes and insurance are excluded |
| 6.5–8% central learning-rate range | 2017 UK assessment of modeled SMR cost reduction for a single design | Depends on deployment pace, exports and market access; not a guaranteed learning curve for one project |
| 5–8 GWe deployment | UK assessment’s modeled point at which a single-design SMR could become cost-competitive with large nuclear | Scenario-dependent fleet result, not an entitlement for an individual first unit |
Do not treat LCOE as the electricity sale price
“A ‘levelised cost’ is the average cost of the lifetime of the plant per MWh (megawatt hour) of electricity generated.” — DESNZ, Electricity generation costs 2025
Levelised cost combines lifetime capital, operating and decommissioning costs for a generic plant and divides them by lifetime generation. It is useful for comparing technologies on a common basis, but it does not state what a project will receive for each megawatt-hour. A project can have an LCOE below a market price and still fail if construction overruns, debt service, curtailment or transmission charges consume the margin. Conversely, a project with a higher LCOE may be financeable under a long-term contract that values firm, low-carbon output.
Build the electricity revenue case from saleable output
Model generation before price
Start with gross capacity and convert it to net saleable generation. Apply thermal and electrical losses, planned refuelling outages, maintenance outages, forced-outage assumptions, derating, degradation where relevant, curtailment and transmission availability. Use an hourly or sub-hourly dispatch profile when the market has negative prices, congestion or ancillary-service opportunities; an annual capacity-factor shortcut can hide those effects.
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Separate contracted and merchant exposure
For contracted output, specify the strike or tariff, indexation, tenor, volume obligations, availability guarantees, balancing responsibility, change-in-law treatment, credit support, termination rights and inflation basis. For merchant output, document the market, price forecast, capture-price discount, congestion, imbalance costs, transmission charges and ancillary-service revenue. Show the percentage of net generation exposed to each case rather than blending all MWh into one average price.
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Account for support mechanisms explicitly
Record capacity payments, reliability payments, grants, tax credits, regulated-asset allowances, contracts for difference or other support in separate lines. State eligibility, application date, duration, indexation, clawbacks and expiration. The 2026 UK programme business case describes an initial project capacity of up to 1.5 GW and more than £2.5 billion of capital funding; those are UK programme-specific figures, not general assumptions for every SMR.
When heat, hydrogen and other products belong in the model
The 2017 UK assessment identified district heating as a possible additional revenue stream. The current Advanced Nuclear Framework also names industrial process heat, hydrogen, synthetic fuels and firm power for data centres. These categories become bankable only when the project demonstrates a compatible output, a nearby customer and an executable delivery arrangement.
District or industrial heat
Specify the customer’s temperature and pressure requirement, seasonal load shape, minimum take-or-pay volume, heat-exchanger and pipeline costs, backup boilers, metering, losses and the distance between plant and customer. Model the heat price and contract separately from electricity because heat demand may be seasonal while the reactor operates continuously.
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Hydrogen and synthetic fuels
Include the conversion plant, electricity or process-heat allocation, water, compression, storage, transport, certification, carbon or renewable-power requirements and offtake contract. Test whether the reactor can supply the required temperature and whether diverting energy reduces higher-value electricity sales.
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Data-centre supply
A data centre may value firm, low-carbon power, but the case still needs a named load, connection schedule, redundancy requirements, power-quality obligations, security arrangements, backup generation and a creditworthy contract. Do not book a premium simply because data-centre demand is growing.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Keep public and system value outside plant revenue
Energy security, resilience, avoided emissions, supply-chain capability, skilled employment and regional growth belong in a separate economic-impact or public-value account. The 2026 UK programme case reports positive marginal system value in initial modeling while noting early-stage uncertainty. Such benefits can inform government support or investment decisions, but they should not be added to the project’s sales ledger unless a payment mechanism captures them.
Run scenarios that expose the real risks
| Scenario family | Variables to change | Decision it informs |
|---|---|---|
| FOAK versus repeat units | Design maturity, shared development cost, unit count, learning rate, factory throughput and export volume | Whether the first project can carry costs that later fleet units may avoid |
| Capital and schedule | Overnight cost, contingency, construction duration, delay, inflation, drawdown timing and financing rate | Debt capacity, required support and break-even price |
| Operations and fuel | Availability, outage timing, staffing, fixed and variable O&M, fuel, waste and insurance | Reliability of annual cash generation and downside exposure |
| Electricity revenue | Low and high power prices, contracted share, merchant share, capture price, curtailment and imbalance costs | Dependence on a forecast rather than a committed buyer |
| Non-electric products | Customer take-up, heat or hydrogen volume, conversion cost, delivery distance and contract tenor | Whether optional products are genuine revenue or an unpriced opportunity |
| Policy and market access | Committed support, prospective support, expiration, eligibility and absence of support | Resilience if a proposed mechanism is delayed or unavailable |
| Counterfactual system case | Common price year and scope for alternatives, dispatchability, location and grid effects | Whether the SMR creates system value that a plant-only metric misses |
The UK assessment found that the net-present-value result for an initial 2 GWe programme moved substantially with FOAK capital cost, learning rate and export-market assumptions, and was also sensitive to the cost of capital. Present ranges and tornado charts, not a single “most likely” number.
A practical build sequence for the spreadsheet
- Write the basis of estimate. Record design, net output, unit sequence, site, jurisdiction, price year, currency, real or nominal basis and scope exclusions.
- Create a time-phased cost ledger. Place development, licensing, construction, IDC, commissioning, operating, fuel, waste and decommissioning cash flows in the year they occur.
- Calculate net saleable output. Apply outages, derating, curtailment, transmission losses and any allocation to heat or hydrogen.
- Layer revenue contracts. Add electricity by contract and market segment, then add only supported heat or product offtake. Show support payments on separate lines.
- Calculate financing metrics. Produce project NPV, IRR, debt-service coverage, minimum cash balance, break-even electricity price and required support under each scenario.
- Stress the assumptions. Run FOAK, repeat-unit, delay, high-rate, low-availability, low-price and no-support cases. Show which variables drive the result.
- Reconcile with external benchmarks. Explain scope and price-year differences before comparing your result with the 2017 UK or 2025 EIA figures.
Common modeling failures and corrections
- Using LCOE as a tariff: replace it with a contract or market-price forecast tied to net MWh.
- Omitting owner and balance-of-plant costs: include site, grid, water, construction facilities, project management and interconnection.
- Calling a generic estimate a quote: label EIA and UK figures as dated scenario evidence with their exclusions.
- Assuming fleet learning on unit one: allocate FOAK costs explicitly and disclose the deployment needed for learning.
- Counting optional products as sales: require customer demand, infrastructure, product compatibility and contract terms.
- Hiding financing risk: show IDC, drawdowns, construction duration and cost-of-capital sensitivities.
- Mixing currencies and bases: convert to a common price year and state whether figures are nominal or real.
- Adding public benefits to cash flow: keep system and regional value in a separate account unless monetised by an approved mechanism.
What the evidence cannot determine without project data
No universal SMR electricity sale price, capacity factor, construction duration, tax treatment, fuel contract, heat-network cost, hydrogen conversion cost, waste obligation or financing package applies across designs and countries. Those inputs require a defined site, reactor, customer, market rules and legal structure. The 2017 UK assessment is useful for explaining FOAK and learning sensitivities; the EIA case is a standardized 2023-dollar model; and the 2026 UK programme case is a public-programme summary rather than a full financial model for an individual project.
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