An SMR business case must model the full life of the project—from design and licensing through construction, operation, waste management and decommissioning—then layer on financing, schedule and policy risk. Electricity sales are the base revenue case. Heat, hydrogen, synthetic fuels and data-centre supply count only when a specific customer, delivery system and contract make them bankable. Public benefits such as energy security and regional jobs should be reported separately from cash revenue unless the project has a way to capture them.
What the business case must prove
A small modular reactor (SMR) proposal is investable only if its cash flows remain credible after realistic construction, financing, operating and market assumptions. The model should answer four questions:
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- What does the project cost from early development to final decommissioning?
- How much capital is exposed to delay, inflation, interest during construction and first-of-a-kind (FOAK) risk?
- What net products can the plant sell, at what price, under which contracts and with what delivery costs?
- Which benefits are public or system-wide rather than revenue received by the project company?
Start with a project-specific financial model, not a headline cost per megawatt-hour. The site, reactor design, unit count, jurisdiction, ownership structure, market and customer determine the result. A generic estimate can frame scenarios, but it is not a vendor quotation or a guaranteed tariff.
Set a consistent model boundary before entering numbers
Every cost and revenue line needs the same scope and economic basis. State these choices on the model’s front page:
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| Model dimension | What to specify |
|---|---|
| Plant definition | Reactor design, thermal and net electrical output, number of modules, dispatch profile and design maturity. |
| Cost basis | Currency, price year, real or nominal terms, exchange-rate treatment and whether figures are overnight cost or total financed cost. |
| Schedule | Development start, licensing milestones, construction period, commissioning date, outage pattern and delay cases. |
| Ownership and finance | Debt and equity shares, drawdown profile, interest during construction, refinancing, guarantees and public risk sharing. |
| Revenue boundary | Net saleable electricity and any heat, hydrogen, fuel or synthetic-product output after the plant’s own consumption and conversion losses. |
| Accounting boundary | Taxes, insurance, property charges, working capital, waste obligations, decommissioning provisions and terminal value. |
Do not compare estimates until these boundaries match. A six-unit generic estimate in 2023 dollars, a 2017 UK FOAK techno-economic assessment and a current project budget describe different things even when all are expressed as a cost per kilowatt or megawatt-hour.
Cost assumptions to include
Development and pre-construction
Include site screening and surveys, geotechnical and environmental work, design completion, safety and environmental cases, licensing and regulatory review, permits, legal advice, insurance during development, owner’s project management and procurement preparation. If a new design is being commercialised, add design verification, qualification testing, certification and supply-chain development. Development spending occurs before revenue and must be funded in the downside schedule even if the project is later cancelled.
Plant, site and balance-of-plant capital
Separate the nuclear island from the conventional island and the rest of the site so omissions are visible. The ledger should cover engineering, procurement and construction; construction management; owner’s engineering and services; buildings and security; turbine or power-conversion equipment; cooling and water systems; electrical systems; waste handling; land; site preparation; roads, cranes and construction facilities; water and transport access; grid interconnection; transmission upgrades; and enabling works.
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Owner’s costs are not a rounding error. The U.S. Energy Information Administration (EIA) and Z Federal modeled a 480 MW plant made up of six 80 MW units at a total capital cost of $4.289 billion, or $8,936 per kilowatt, in 2023 dollars. That estimate includes engineering, procurement and construction and owner costs within its stated boundary, but it does not carry the full burden of design, licensing and manufacturing-facility development required to bring a new SMR design to market.
FOAK exposure and allocation of shared costs
A first unit may carry costs that later units do not. Identify design completion, licensing and certification, supplier qualification, factory tooling or setup, first-unit commissioning, training and initial spares. Decide explicitly how shared development and factory costs are allocated between the first project and a future fleet. A business case that assigns all of those costs to a fleet without showing who funds the first unit is overstating repeat-unit economics.
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The 2017 UK SMR Techno-Economic Assessment is useful as scenario evidence, not as a present-day quote. Its generic integral pressurised-water-reactor FOAK case produced a levelised-cost range of £86–£124 per MWh, with a £101 per MWh central estimate, excluding Generic Design Assessment costs. The assessment applied a 54% optimism-bias uplift and an 8.9% cost of capital, and warned that accumulated development spending or higher early financing costs could push the result higher.
Financing, schedule and delivery
Model the debt/equity mix, interest rate or weighted cost of capital, commitment fees, drawdown timing, interest during construction, inflation, contingency, refinancing and any guarantee fees. Link financing to a monthly or quarterly construction schedule rather than applying interest to a single overnight-cost number.
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Operating, fuel and end-of-life costs
Operating expenditure should include staffing, training, maintenance, security, regulatory compliance, insurance, taxes, fuel procurement and fabrication, consumables, water, waste treatment, spent-fuel and radioactive-waste management, outage and refuelling work, decommissioning contributions and working capital. State whether costs are fixed, variable or outage-related.
For reference, the EIA/Z Federal modeled case reports fixed non-fuel operation and maintenance of $121.99 per kilowatt-year and variable non-fuel operation and maintenance of $3.19 per megawatt-hour, both in 2023 dollars. Those benchmarks exclude fuel, property taxes and insurance. They are therefore not a complete operating-cost allowance and should not be pasted directly into a project model without adding the omitted items.
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Site-specific infrastructure
Site costs can dominate the difference between two apparently similar projects. Price the grid connection and any transmission reinforcement, water intake and discharge, roads and heavy-haul logistics, construction compounds, emergency-planning requirements, heat networks, hydrogen equipment, customer interconnection and shared infrastructure. The EIA modeled case includes land and an electrical transmission line; its owner-cost category also covers development, permitting, legal work, project management, engineering, start-up, land and utility interconnection. Confirm which of these are already in a supplier estimate before adding them again.
Revenue assumptions that can be defended
Electricity is the base case
Build annual electricity revenue from net saleable generation, not nameplate capacity. A transparent calculation is:
net MWh sold × contracted or market price − transmission charges − imbalance and market fees − curtailment cost
Derive net MWh from availability, planned outages, refuelling outages, derating, degradation where relevant and forced outages. Show contracted and merchant volumes separately. Contract cases should specify term, indexation, floor or ceiling prices, volume obligations, credit support, balancing responsibility and termination rights. Merchant cases need a defined market and price forecast, not an unexplained “SMR power price.” The available evidence does not establish a universally valid sale price, capacity factor or construction duration for every SMR; those are project and jurisdiction inputs.
Heat, hydrogen and synthetic products
District heat and industrial process heat can add value when a compatible customer is close enough to limit pipeline losses and capital. The model must include heat extraction equipment, a network or private connection, backup supply, seasonal demand, conversion losses, customer connection costs, tariff structure and a credible take-or-pay or availability commitment.
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Hydrogen and synthetic fuels require electrolyser or synthesis equipment, electricity or heat allocation, water, storage, transport, certification and an offtake contract. The UK Advanced Nuclear Framework identifies industrial heat, hydrogen, synthetic fuels and data-centre power as possible applications, but naming an application does not establish demand or bankability. Include these products only when the reactor can deliver the required temperature, pressure, timing and reliability and a named customer has acceptable credit terms.
Firm power for data centres and other customers
A data-centre or industrial customer may value firm, low-carbon supply, but the business case still needs an interconnection design, backup arrangements, delivery schedule, redundancy requirements, power-quality terms, curtailment rights and a contract price. Treat the customer’s avoided grid cost as a negotiation input, not automatic project revenue.
Keep policy support and public value outside ordinary sales
Record grants, tax credits, capacity or reliability payments, contracts for difference, regulated-asset treatment, revenue floors and public guarantees as separate cases. State eligibility, approval status, payment timing, duration, indexation and clawback provisions. The 2026 UK programme business case describes an initial programme of up to 1.5 GW and more than £2.5 billion of capital funding; those are UK programme figures, not generic assumptions for an individual SMR.
The same discipline applies to wider benefits. Energy security, resilience, emissions reduction, supply-chain capability, employment and regional growth belong in an economic or public-value account. The 2026 UK programme case reports positive marginal system value in initial modelling while noting early-stage uncertainty. Do not add that system value to the plant’s electricity revenue unless a market mechanism actually pays the project for it.
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Do not mistake LCOE for a sale price
The Department for Energy Security and Net Zero defines levelised cost as “the average cost of the lifetime of the plant per MWh (megawatt hour) of electricity generated.” LCOE combines construction, operating and decommissioning costs for a modeled plant. It is useful for comparing technologies on a common basis, but it is not the price a project will realise in a contract or wholesale market.
A project can have an attractive LCOE and still fail if it cannot obtain a bankable offtake agreement, finance a long construction period or pay for a site-specific grid and heat connection. Conversely, a project with a higher LCOE may earn adequate returns under a firm contract or policy mechanism. Show LCOE, project-level cash flow, equity returns and debt-service coverage as different outputs.
Scenarios and sensitivities every model should show
| Risk area | Minimum cases | Decision question |
|---|---|---|
| Deployment maturity | FOAK, early repeat units and mature fleet; disclose unit count and learning assumptions. | Who pays for first-of-a-kind work, and when do savings arrive? |
| Capital and schedule | Overnight-cost range, contingency, construction duration, delay and higher financing rate. | How much value is lost for each year of delay or cost overrun? |
| Operations and fuel | Availability, outage timing, fixed and variable O&M, fuel, waste and staffing ranges. | Can debt service be met during a poor operating year? |
| Electricity revenue | Low and high power prices, contracted versus merchant share, curtailment and imbalance costs. | Is the project dependent on an optimistic market forecast? |
| Non-electric products | No heat or hydrogen sales, delayed customer, partial take-up and full contracted case. | Does the reactor remain viable if the anchor customer withdraws? |
| Policy and market access | Committed support, prospective support and no support or support expiry. | What happens when an unapproved mechanism is unavailable? |
| Counterfactual system value | Alternatives with common price year, scope and dispatch assumptions. | What value comes from location, firmness or grid effects rather than energy alone? |
The UK TEA’s central 2 GWe programme analysis found that net present value changed materially with FOAK capital cost, learning rate, export-market assumptions and cost of capital. Its 6.5–8% central learning-rate range and modeled cost competitiveness with large nuclear after 5–8 GWe of global deployment applied to a single-design fleet and depended on deployment pace, exports and market access. They are not guaranteed learning rates for one project.
A practical sequence for building the model
- Define the asset. Record design, net output, modules, site, customer, jurisdiction, dispatch profile and FOAK or repeat-unit status.
- Freeze the accounting basis. Choose currency, price year, real or nominal treatment, tax basis and the boundary between project, customer and public infrastructure.
- Build the schedule. Map development, licensing, procurement, construction, commissioning, outages and decommissioning by month or quarter.
- Load the cost ledger. Enter development, nuclear and conventional plant, owner’s costs, site works, grid, first-unit exposure, financing, operations, fuel, waste, taxes, insurance and end-of-life provisions.
- Model physical output. Convert gross capacity into net saleable electricity and any heat or product volumes after internal use, outages, derating and conversion losses.
- Attach contracts and markets. Apply offtake prices, indexation, volume obligations, credit terms, market forecasts, transmission charges, balancing costs and curtailment.
- Separate support and public value. Add only confirmed grants, credits or payments to the base case; place prospective support and wider system benefits in clearly labelled alternatives.
- Run sensitivities and downside cases. Stress capital, schedule, financing, availability, fuel, customer demand, prices and policy withdrawal independently and in combinations.
- Report decision metrics. Show total funded cost, LCOE, project NPV, internal rate of return, debt-service coverage, break-even power price and the assumptions that drive each result.
Benchmarks worth quoting, with their limits
| Published figure | What it represents | Qualification |
|---|---|---|
| £86–£124/MWh; £101/MWh central | 2017 UK SMR Techno-Economic Assessment generic IPWR FOAK LCOE. | Excludes Generic Design Assessment costs; includes a 54% optimism-bias uplift and 8.9% cost of capital; not a current vendor bid. |
| $4.289 billion total; $8,936/kW | EIA/Z Federal modeled six-unit, 480 MW SMR capital cost. | 2023 dollars; stated scope excludes the full design, licensing and manufacturing-facility burden of commercialising a new design. |
| $121.99/kW-year fixed non-fuel O&M; $3.19/MWh variable non-fuel O&M | EIA/Z Federal modeled operating costs. | 2023 dollars; fuel, property taxes and insurance are excluded. |
| 6.5–8% learning rate; 5–8 GWe deployment | 2017 UK TEA central fleet-learning and modeled cost-competitiveness assumptions. | Scenario-dependent for one design; depends on deployment pace, exports and market access. |
| Up to 1.5 GW and over £2.5 billion | 2026 UK programme business-case scale and capital funding. | UK programme-specific, not a generic project budget or sale-price assumption. |
How to compare two SMR proposals fairly
Normalize both proposals to the same currency and price year, net rather than gross output, financing basis and plant boundary. Then compare:
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- Total project scope and cost per net kilowatt, including owner, grid and site costs.
- Construction duration, contingency, cost of capital and who bears delay risk.
- Net output, availability, outage schedule, flexibility and degradation assumptions.
- Contracted, merchant and ancillary-service revenue shares.
- Heat or other offtake customers, connection distance, conversion equipment and contract strength.
- Committed policy support, prospective mechanisms and allocation of public risk.
If a value is missing, label it as not stated and request the underlying scope rather than filling the gap with a benchmark from another design or country.
What remains project-specific
No generic source can settle an individual project’s electricity sale price, capacity factor, construction duration, tax treatment, fuel contract, heat-network cost, hydrogen conversion cost, waste obligation or financing package. Those inputs require a defined country, reactor, site, unit count, customer and commercial structure, supported by jurisdiction-specific engineering, legal and financial advice. A robust business case makes those unknowns visible and prices them through scenarios instead of hiding them inside one optimistic point estimate.
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