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There is no fair universal cost ranking of small modular reactors (SMRs), renewables and batteries. Compare them on the same electricity service, location, demand profile, delivery date, financing basis and system boundary. A generator’s levelized cost of electricity (LCOE) is useful, but it does not by itself price reliable power delivered at the hours a buyer needs.
Start by defining what the project must deliver
Before comparing costs, state what the buyer is purchasing. A project might sell energy over a year, provide dependable capacity at peak times, follow a fixed output schedule, or supply a combination of grid services. Those products are not interchangeable, so comparing their prices without defining the service can produce a misleading winner.
Write down the demand profile the project must serve, including when demand occurs and whether the obligation is seasonal, hourly or continuous. Specify the reliability standard and delivery date, too. If the requirement is around-the-clock supply, compare complete supply portfolios capable of meeting it—not an isolated renewable generator against an isolated nuclear plant.
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- Energy: How many megawatt-hours must be produced, and in which hours?
- Capacity: How much power must be available during a specified peak or other critical event?
- Duration: For how long must that power be sustained?
- Reliability: What happens if output is unavailable, the resource is low, or a component is down?
- Timing: When must the first electricity be delivered, and when must the full service be available?
These requirements determine what belongs in the comparison. A wind or solar plant, a battery, an SMR, and a portfolio combining generation, storage, transmission and demand response may each meet different parts of the need. The relevant question is what it costs to meet the same obligation in the same place and timeframe.
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Know what LCOE does—and does not—measure
LCOE expresses a generator’s costs over its economic life as a unit cost of electricity, commonly dollars per megawatt-hour. It incorporates capital recovery and ongoing costs such as fuel, operations and maintenance under the model’s assumptions. As CSIRO Chief Energy Economist Paul Graham explains, the metric calculates a cost per MWh over an asset’s economic life, incorporating initial capital expenses and ongoing fuel, operation and maintenance costs.
That makes LCOE a useful orientation metric when the projects being compared use compatible assumptions and deliver comparable energy. It is not, by itself, a price for electricity at every hour or a measure of whether a project can meet a particular reliability obligation. A low standalone generation LCOE does not automatically mean low cost for firm, dispatchable supply.
System LCOE, sometimes described as SLCOE, adds integration costs such as storage and transmission. Graham describes it as the average cost of electricity including those integration costs. Other approaches address aspects of system value: IRENA discusses Levelized Avoided Cost of Electricity (LACE), while the IEA uses Value-Adjusted LCOE (VALCOE). These measures are not interchangeable; each has a boundary and assumptions that should be stated.
For every comparison, label the metric and its boundary. Say whether the result includes grid connection, transmission, balancing, storage, curtailment, capacity value, backup, financing, and end-of-life costs. If a cost or benefit is outside the boundary, name it rather than letting a headline figure imply that it has been counted.
What the published cost benchmarks can tell you
Global benchmarks show the broad cost position of technologies in their stated sample and year. They do not substitute for a project-specific model of a particular grid, site or service.
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| Benchmark | Reported value | How to interpret it |
|---|---|---|
| Onshore wind | USD 0.034/kWh (USD 34/MWh) | IEA’s 2025 report gives the global weighted-average LCOE for projects in 2024. |
| Solar PV | USD 0.043/kWh (USD 43/MWh) | IEA’s 2025 report gives the global weighted-average LCOE for projects in 2024. |
| Hydropower | USD 0.057/kWh (USD 57/MWh) | IEA’s 2025 report gives the global weighted-average LCOE for projects in 2024. |
| UAMPS Carbon Free Power Project (CFPP) | A$28,580/kW in 2023 Australian dollars | CSIRO’s 2023–24 GenCost report cites this as the project’s updated SMR capital-cost estimate. The project was cancelled in November 2023; this is not a completed plant’s observed final cost. |
The IEA figures are global weighted averages, not prices guaranteed to be available to a buyer. Resource quality, site conditions, financing, grid access, curtailment and other project-specific costs can change the result. Nor do those generation LCOEs establish the cost of making output firm in a particular set of hours.
IRENA’s report on projects in 2024 says renewables remained the most cost-competitive new electricity generation globally on an LCOE basis. Its 2025 publication also reports that some global technology averages moved up compared with the prior year: solar PV LCOE by 0.6%, onshore wind by 3%, offshore wind by 4% and bioenergy by 13%. Changes in capacity factors, market share and financing costs affected some averages. These are global statistics, not a universal ranking of delivered firm power.
In July 2026, Lazard’s annual LCOE+ benchmark said renewables remained the lowest-cost unsubsidized new-build generation in its analysis. It also highlighted rising costs across technologies, reliability concerns, and permitting and infrastructure constraints. That conclusion is useful context, but it does not prove that every renewable project costs less than every SMR, or that the ranking holds for every grid and firm-output obligation.
Australian analysis provides another useful but geographically bounded reference. CSIRO and AEMO’s GenCost work compares generation and storage assumptions in the Australian context. CSIRO’s 2024 release says updated modelling found renewables remained the lowest-cost new-build technology even after additional storage and transmission costs were included. Australian resource, construction and system assumptions matter; the result should not be presented as a worldwide answer.
Build a like-for-like renewable and battery case
“Renewables plus batteries” is not a single design. A useful case identifies the generation technology and resource quality, then specifies the storage system and operating rules. The battery’s power rating, measured in MW, describes how quickly it can deliver energy; its energy capacity, measured in MWh, and duration indicate how long it can sustain that output. Neither figure alone establishes how much energy will be available during a critical event.
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At a minimum, specify these inputs for the renewable-plus-storage option:
- Generation: technology, site resource quality, capacity factor, expected output profile and expected curtailment.
- Storage: MW power, MWh energy, duration, efficiency, degradation, replacement assumptions and charging source.
- Dispatch: when the battery charges and discharges, what reserve is maintained, and whether capacity is committed to ancillary services.
- Grid access: interconnection scope, transmission needed to reach load, and any balancing or integration costs included.
- Service obligation: the hours, peak events and reliability standard the combined system is expected to meet.
Do not equate battery nameplate MW with guaranteed peak delivery. The IEA notes that discharge during a peak event can be lower because of temperature derating, incomplete charge, insufficient duration or capacity already committed to ancillary services. A model should represent the battery’s state of charge and competing obligations at the time reliability is needed—not assume full output is available whenever called.
When comparing the battery configuration with an SMR, use the same hourly demand and reliability test. Count the renewable plant, battery, transmission and other resources required by the portfolio, but avoid counting the same service twice. If the model depends on demand response or other firm capacity, state its role and cost. A battery may be valuable for one duration and operating pattern without replacing every form of firm capacity.
Make financing and construction assumptions visible
Capital-intensive generation technologies are especially sensitive to financing because costs are incurred before—and recovered over—the period of electricity production. A comparison that uses different discount rates, construction-finance treatment or economic lives can make projects look more comparable than they are.
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For each case, disclose the price year and currency, discount rate or weighted cost of capital, debt and equity shares, debt and equity costs, construction financing, tax support, fuel costs, economic life, capacity factor and expected schedule. State whether an incentive is included and whether a financing assumption is a benchmark convention or a project-specific offer.
Lazard’s 2025 benchmark uses a base financing structure of 60% debt and 40% equity, with an 8% debt cost and a 12% equity cost, and includes cost-of-capital sensitivities. Those are assumptions for that analysis, not a financing quote for a specific project. The benchmark’s nuclear LCOE also relies on older Vogtle cost estimates adjusted for inflation because public data for new-build nuclear are limited. Readers should not treat that nuclear estimate as a direct observation of an SMR’s commercial cost.
Run sensitivity cases rather than presenting one result as precise. Change the financing cost, construction schedule, capital cost, capacity factor and fuel or operating assumptions within defensible ranges. Report which assumptions move the ranking and by how much. Where the evidence does not support a credible range, describe the uncertainty rather than inventing one.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Treat SMR cost and delivery claims according to their evidence
SMR economics carry a particular evidence limitation: commercial operating experience remains limited. CSIRO’s December 2024 explainer said no completed commercial SMR project worldwide then provided a basis for reliable cost estimates. It identified Canada’s Darlington SMR project as strengthening the evidence base, with a schedule then reported as completion by the end of 2029 and expected operation in 2030. Those were reported expectations at that time, not a guarantee of current schedule or cost.
Separate first-of-a-kind (FOAK) estimates from nth-of-a-kind (NOAK) projections. A projected factory-learning or series-build saving is not an achieved saving until supported by relevant completed projects. CSIRO’s Australian explainer describes a FOAK nuclear cost premium of up to 120% in its assumptions. This is a modelling assumption for that context, not a universal premium applicable to every design, country or contract.
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CSIRO’s cited UAMPS estimate of A$28,580/kW is a reference point from an updated estimate for a cancelled project, expressed in 2023 Australian dollars. It is neither the cost of a completed SMR nor a stand-alone estimate for another project. The cancellation in November 2023 is important context: the figure can inform the discussion of project assumptions, but it should not be presented as observed plant performance.
Imported cost data also need adjustment. CSIRO notes that overseas cost data may differ from Australian projects because of labour costs, workforce expertise, governance and standards. More generally, a proposed plant’s location, licensing route, supply chain and contracting arrangements affect how relevant another country’s estimate is. Label the geography and date of every reference rather than transferring a figure directly across jurisdictions.
Include project risks and costs beyond the headline generation number
A decision-grade comparison follows costs and risks across the project boundary. Some items may be small or irrelevant in one location and decisive in another. The model should say whether and how it treats:
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- Approvals and schedule: permitting, licensing, construction duration, commissioning and the date the project can first supply energy.
- Operations: maintenance, fuel and supply-chain exposure, battery degradation and replacement, and availability assumptions.
- End of life: decommissioning and other costs included in the economic-life calculation.
- System support: storage, balancing, transmission, demand response and firm capacity needed to meet the required service.
Delivery risk has economic consequences even when a model reports only a cost per MWh. A project that reaches operation later may fail to meet the buyer’s required date or require an interim supply arrangement. That makes schedule assumptions part of the comparison, not a footnote. Likewise, a low-cost site that cannot connect economically to the load is not equivalent to an accessible site with a different generation cost.
For a portfolio decision, assess the marginal value of each component in the grid where it will operate. The contribution of storage, transmission or firm capacity depends on the existing system and the demand being served. A whole-system result for one country or grid should not be transferred to another without checking those conditions.
A practical comparison workflow
- Write the service specification. Define hourly or seasonal demand, required energy and capacity, duration, reliability standard, location and first-power date.
- Set a common boundary. Decide whether the comparison is generator LCOE, system LCOE, LACE, VALCOE or another measure. List included and excluded costs and services.
- Define each project, not just each technology. Specify the SMR design and project assumptions; renewable type and site; and battery power, energy, duration, charging and dispatch rules.
- Use one financing basis. Align currency, price year, economic life, discounting, construction-finance treatment, taxes and other support. Show sensitivities where financing differs or is uncertain.
- Model output against the same demand. Use the same time profile and reliability test for each option. Account for curtailment, storage state of charge, availability and any other resources needed to meet the obligation.
- Include delivery and integration. Add relevant interconnection, transmission, balancing, replacement, fuel, maintenance and end-of-life costs, and state the expected schedule.
- Separate observed data from assumptions. Identify measured project outcomes, estimates, benchmark conventions and projected FOAK or NOAK costs. Attach geography, date and qualification to each number.
- Show what drives the result. Report the cases or assumptions that change the ranking, as well as costs or risks that remain outside the model. Do not turn a narrow benchmark result into a universal claim.
How to read the result
A defensible comparison will often have more than one answer because the options provide different services and their costs depend on location, schedule, financing and system needs. Report standalone generation costs separately from the costs of delivering the required service. If the question is firm supply, show the portfolio that meets that requirement and the assumptions that make it reliable.
On the evidence available in the cited benchmarks, renewables have a strong position in global and Australian new-build LCOE comparisons, while SMR project economics remain less certain because completed commercial cost observations are scarce. That is not a universal verdict on every project: it is a reason to keep benchmark conclusions within their stated geography, date, metric and system boundary, and to avoid false precision where an SMR estimate is still a projection.
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