There is no fair universal cost ranking between small modular reactors (SMRs), renewables and batteries. Compare projects that provide the same service, in the same location, on the same delivery schedule and financing basis. A generator’s levelized cost of electricity (LCOE) is a useful starting point, but it does not by itself tell you what it costs to deliver reliable power in the hours a buyer needs it. For that, account for the whole system: storage, transmission, balancing, firm capacity, project risk and timing.
What the headline cost figures do—and do not—tell you
LCOE expresses a generator’s costs over its economic life as a cost per unit of electricity generated. It can support a useful comparison when the projects being compared use compatible assumptions about financing, operating life, output and costs. It is not automatically the price of dependable electricity delivered at a specific time, location or reliability level.
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Global figures illustrate both the value and the limits of the metric. The International Energy Agency’s 2025 report gives 2024 global weighted-average LCOEs of USD 34/MWh for onshore wind, USD 43/MWh for solar PV and USD 57/MWh for hydropower. These are technology averages, not quotes for projects at a particular site. They do not establish that every wind or solar project is cheaper than every SMR, nor do they include every location-specific expense or make the projects equivalent in output profile.
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The International Renewable Energy Agency’s analysis of projects in 2024 likewise finds that renewables remained the most cost-competitive new electricity generation globally on an LCOE basis. Its 2025 publication reports that global average LCOE rose year over year for some technologies: solar PV by 0.6%, onshore wind by 3%, offshore wind by 4% and bioenergy by 13%. Capacity factors, market share and financing costs affected some averages. These figures describe global trends, not an individual project’s costs.
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Lazard’s July 2026 LCOE+ release says renewables remain the lowest-cost unsubsidized new-build generation in its annual benchmark. It also highlights rising costs across technologies, reliability concerns, and permitting and infrastructure constraints. That conclusion is specific to the benchmark’s assumptions; it is not proof that every renewable project beats every SMR or that the same ordering holds when comparing firm output in every grid.
Start by defining the service being purchased
Before comparing technologies, state what the project must deliver. A buyer may be seeking annual energy, a block of dependable capacity, a fixed output profile, electricity during a defined peak, or another grid service. Those products are not interchangeable. A megawatt of nameplate capacity is not necessarily a megawatt-hour available at the hour of peak demand.
Set the same demand profile and reliability standard for each option. If the requirement is around-the-clock supply, model the full portfolio needed to meet it: generation, storage, transmission, balancing resources, demand response and firm capacity where applicable. Do not compare a renewable plant’s standalone LCOE with an SMR’s generation cost and describe the result as a firm-power comparison.
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- Capacity and duration: What output must be available during a peak, and for how long?
- Reliability: What standard must the portfolio meet, and which resources cover low-output periods or outages?
- Location: Where is the demand, where can the project connect, and what resource or grid constraints apply?
- Delivery: When must the first power be available, and what happens economically if the schedule slips?
Choose the right cost and value metric
Generation LCOE
Generation LCOE is the average cost of producing electricity over an asset’s economic life, expressed per unit of energy. As CSIRO Chief Energy Economist and GenCost lead author Paul Graham describes it, the method calculates a dollar cost per megawatt-hour over the asset’s life, incorporating initial capital expenses and ongoing fuel, operation and maintenance costs. The result depends on its assumptions: financing, economic life, capacity factor, construction cost, operating cost and, for fuel-using plants, fuel costs.
Use LCOE to orient a comparison of generators, but show its boundary. A standalone figure generally does not answer what extra infrastructure or balancing is needed to make the power available when required.
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System LCOE and value-adjusted measures
System LCOE adds integration costs, such as storage and transmission, to the average cost of electricity. Graham describes CSIRO’s system-level measure as including integration costs such as storage and transmission. It can therefore address a broader question than generator-only LCOE, although the result still depends on the modeled system boundary and assumptions.
IRENA also discusses Levelized Avoided Cost of Electricity (LACE), and the IEA uses Value-Adjusted LCOE (VALCOE), as approaches that incorporate aspects of system value. These measures can help account for the fact that electricity’s value varies with when and where it is generated. They do not eliminate the need to disclose what costs, services and grid conditions the analysis includes.
Model renewables and batteries as a specific design
“Renewables plus batteries” is not a single project configuration. The comparison needs to identify the renewable resource and its quality, the storage system’s power and energy capacity, how it charges and dispatches, and what grid connection it uses. Different configurations can provide different services even when their headline megawatt capacity looks similar.
The IEA’s 2023 regional comparison defines one solar-plus-storage case as four-hour storage scaled to 20% of solar output capacity. Those details describe that modeled configuration, not a universal battery design or a requirement that all solar projects use the same storage ratio.
For a renewable-plus-storage model, make these assumptions explicit:
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- Generation: technology, site resource quality, expected output profile, capacity factor and curtailment.
- Storage size: power capacity in MW, energy capacity in MWh and duration at the assumed discharge rate.
- Operation: charging source, charging and discharging rules, efficiency, dispatch priorities and any capacity reserved for other services.
- Lifetime costs: degradation, maintenance, replacement timing and costs, and the assumed operating life.
- Connection and integration: interconnection, transmission, balancing and other system costs included in the model.
A battery’s nameplate MW rating does not guarantee that full output will be available throughout a peak event. The IEA notes that peak-event discharge can be lower because of temperature derating, an incomplete charge, insufficient duration or capacity committed to ancillary services. A capacity comparison should therefore state the expected energy available during the event, not just the battery’s power rating.
Understand what is known about SMR costs
SMR project economics are especially sensitive to the difference between modeled expectations and demonstrated commercial performance. CSIRO’s December 2024 explainer said that 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, and reported a schedule at that time of completion by the end of 2029 with operation expected in 2030. That was a reported schedule, not confirmation of current project status; schedules and disclosures can change.
CSIRO’s 2023–24 GenCost report cites an updated capital-cost estimate of A$28,580/kW for the UAMPS Carbon Free Power Project (CFPP), in 2023 Australian dollars. CSIRO aligned its current SMR capital assumptions with that estimate. The CFPP was cancelled in November 2023, so the figure is a cost estimate for a cancelled project—not the observed final cost of a completed SMR facility.
That distinction matters when an analysis assumes future factory learning or lower costs from repeated construction. Label first-of-a-kind (FOAK) estimates separately from nth-of-a-kind (NOAK) projections. Projected reductions are assumptions until repeat projects demonstrate them. CSIRO’s Australian explainer describes a FOAK nuclear cost premium of up to 120% in its assumptions. It also cautions that overseas cost data need adjustment for differences in labour costs, workforce expertise, governance and standards. The premium is an assumption in that Australian context, not a universal surcharge to apply to every SMR project.
For an SMR estimate, identify the design and project stage, what the capital number includes, whether it is an estimate or observed result, and which schedule, financing, construction and operating assumptions underpin it. Where no completed commercial project establishes a reliable cost basis, report that uncertainty instead of presenting a target cost as a proven outcome.
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Put financing and project timing on the same basis
Capital-intensive projects can have materially different economics when their cost of capital, financing structure or construction schedule differs. For each option, disclose the price year and currency, discount rate or weighted average cost of capital, debt and equity mix, construction financing, tax support, fuel costs where relevant, capacity factor, economic life and expected schedule.
Lazard’s 2025 LCOE benchmark uses a base financing structure of 60% debt and 40% equity, with an 8% cost of debt and a 12% cost of equity, and provides cost-of-capital sensitivities. These are benchmark assumptions, not a financing offer or a universal project cost of capital. The same benchmark’s nuclear LCOE uses older Vogtle cost estimates adjusted for inflation because public data for new-build nuclear are limited. Treat that figure as an illustrative benchmark with a disclosed data limitation, not a current quote for a new SMR.
Compare projects at the same currency and price year, and make clear whether values are real or nominal if the analysis distinguishes them. State which construction-period costs and financing effects are included. A project that begins producing power later can have different value and exposure from one available earlier, even if their eventual generation costs appear similar. Include the expected first-power date and a consistent treatment of schedule risk rather than hiding delivery timing behind a lifetime average.
Include the costs and risks outside the plant fence
A complete project comparison may need more than plant construction and operation. Depending on the site and system boundary, include land and siting constraints, grid connection, transmission, permitting and licensing, maintenance, fuel and supply-chain exposure, storage replacement, decommissioning and timing of first power. These items may differ significantly by technology and location; do not assume they are negligible or identical.
CSIRO and AEMO’s GenCost work is tailored to Australian generation and storage assumptions. CSIRO’s 2024 release says its updated modelling found renewables remained the lowest-cost new-build technology even after including additional storage and transmission costs. This is a result for its Australian analysis, not a worldwide ranking. The underlying assumptions about construction, resources and the electricity system are part of the result.
Project risk also belongs in the comparison. Permitting and infrastructure constraints can affect delivery; first-of-a-kind construction exposes a project to risks that a mature, repeatedly built design may not share. Fuel and supply-chain exposure, interconnection timing, replacement needs and the availability of skilled workers can change both cost and schedule. State which risks are priced into the model and which remain outside it.
A practical comparison checklist
Use a common model boundary and complete this checklist for each option before drawing a conclusion:
- Specify the product. Define the hourly or seasonal demand profile, required reliability, peak capacity, duration and any other grid service.
- Define each project. Identify the SMR project and stage, renewable technology and site, and battery power, energy, duration and operating rules.
- Choose the metric. State whether the comparison is generator LCOE, system LCOE or a value-adjusted measure, and list what it includes.
- Align financing. Use consistent currency, price year, discount rate, debt/equity assumptions, tax treatment, operating life and construction financing—or show sensitivities when alignment is not possible.
- Model delivery and output. Show expected first-power date, annual and hourly production, curtailment, peak availability and the duration for which firm output can be sustained.
- Add system costs. Include relevant storage, transmission, interconnection, balancing, fuel, replacement, maintenance and decommissioning costs.
- Separate evidence from projection. Label observed costs, project estimates and FOAK or NOAK assumptions distinctly; give an uncertainty range when the underlying evidence supports one.
- Test the result. Show how the ranking changes with plausible changes in financing, construction schedule, resource quality, capacity factor and integration needs.
The output should be a comparison of defined projects and services, not technologies in the abstract. A single cost per MWh can obscure whether the figure prices only generation or also the infrastructure and dependable supply the buyer needs.
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How to read a claimed winner
When a study or headline says one option is “cheapest,” check the scope before applying that result to a project decision. A global renewable LCOE average, an Australian system-cost model, an investment-bank benchmark and a cancelled-project SMR estimate answer different questions. They have different geographies, boundaries, dates and evidence bases.
- If one number is generator-only and another includes storage or transmission, they are not directly comparable.
- If a battery comparison omits duration, charging and peak-event availability, its firm-capacity conclusion is incomplete.
- If an SMR figure is a target, FOAK assumption or NOAK projection rather than a completed-project cost, it should not be presented as an observed commercial outcome.
- If the cost year, currency, financing or delivery date differs, the apparent ranking may reflect those assumptions as much as the technology.
For portfolio decisions, compare the marginal contribution of each resource within the actual grid. Generation, storage, transmission, demand response and firm capacity can complement one another, and their value depends on the demand profile and system constraints. The useful question is not simply which technology has the lowest headline LCOE, but which defined portfolio meets the required service at the best evidenced cost and risk.
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