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Levelized cost of electricity
Levelized cost of electricity
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A line graph tracking the levelized cost of major electricity sources between 2009 and 2023 in dollars, according to data from Lazard. With time, the cost of renewable energies goes down significantly, most notably solar, for which the price goes from 359 dollars per megawatt-hour in 2009 to 60 dollars in 2023
Average unsubsidized levelized cost of electricity in the United States. With increasingly widespread implementation of sustainable energy sources, costs for sustainable have declined, most notably for energy generated by solar panels. Data source is Lazard,[1] it is assuming a discount factor of 7.7%.

The levelized cost of electricity (LCOE) is a measure of the average net present cost of electricity generation for a generator over its lifetime. It is used for investment planning and to compare different methods of electricity generation on a consistent basis.

The more general term levelized cost of energy may include the costs of either electricity or heat. The latter is also referred to as levelized cost of heat[2] or levelized cost of heating (LCOH), or levelized cost of thermal energy.

Definition

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The cost of electricity production depends on costs during the expected lifetime of the generator and the amount of electricity the generator is expected to produce over its lifetime. The levelized cost of electricity (LCOE) is the average cost in currency per energy unit, for example, EUR per kilowatt-hour or AUD per megawatt-hour.[3]

LCOE is defined by the formula:[4][5][6]

Input values are:
It : investment expenditures in the time interval t
Mt : operations and maintenance expenditures in the time interval t
Ft : fuel expenditures in the time interval t
Et : electrical energy generated in the time interval t
r : discount rate
n : expected lifetime of system or power station in number of time intervals of t
: interval in which energy production begins

Applicability

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LCOE is an estimation of the cost of production of electricity and not the price of electricity. The price of electricity may be influenced by additional factors including markup and price controls.

LCOE is commonly used for:

Significant caution needs to be applied to use of LCOE as outputs are highly sensitive to the selection of input values.[9] The ability to interpret and compare LCOE model outputs is dependent upon the level of detailed justification provided for input values and the results of sensitivity analysis against the selection of input values.[9] For any given electricity generation technology, LCOE can vary significantly from region to region depending on factors such as the cost of fuel or availability of renewable energy resources. For LCOE to be usable for rank-ordering energy-generation alternatives, caution must be taken to calculate it in "real" terms, i.e. including adjustment for expected inflation.[10][11]

An energy efficiency gap phenomenon exists due to observed lack of consideration of and implementation of demand-side energy conservation.[12] LCOE is typically used in support of supply-side generation capacity replacement and expansion decision making. The energy efficiency gap phenomenon suggests demand-side energy conservation should also be considered in investment strategies and energy policy.[12]

Limitations

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LCOE is often cited as a convenient summary measure of the overall competitiveness of different generating technologies, however, it has potential limitations. One of the most important potential limitations of LCOE is that it may not control for time effects associated with matching electricity production to demand. This can happen at two levels:

  • Dispatchability, the ability of a generating system to come online, go offline, or ramp up or down, quickly as demand swings.
  • The extent to which the availability profile matches or conflicts with the market demand profile.[13]

In particular, if the costs of matching grid energy storage are not included in projects for variable renewable energy sources such as solar and wind, they may produce electricity when it is not needed in the grid without storage. The value of this electricity may be lower than if it was produced at another time, or even negative. At the same time, variable sources can be competitive if they are available to produce when demand and prices are highest, such as solar during summertime mid-day peaks seen in hot countries where air conditioning is a major consumer.[9]

To ensure enough electricity is always available to meet demand, storage or backup generation may be required, which adds costs that are not included in some instances of LCOE.[14] Excess generation when not needed may force curtailments, thus reducing the revenue of an energy provider. Decisions about investments in energy generation technologies may be guided by other measures such as the levelized cost of storage (LCOS) and the levelized avoided cost of energy (LACE), in addition to the LCOE.[13]

Another potential limitation of LCOE is that some analyses may not adequately consider the indirect costs of generation.[15] These can include the social cost of greenhouse gas emissions, other environmental externalities such as air pollution, or grid upgrade requirements. On the other hand, the LCOE often ignores other potential co-benefits of a power source.[16] For example, solar photovoltaic systems provide electricity but systems for agrivoltaics can produce more food[17][18], floating solar (floatovoltaics) reduces water evaporation[19][20], building integrated photovoltaics (BIPV)[21] and solar canopies[22] produce shade to cool buildings/cars, all of which have an economic value. While LCOE remains the dominant tool for assessing solar photovoltaics and other energy source economics due to its simplicity, it fails to account for these non-electricity-related co-benefits, leading to an undervaluation of emerging solar technologies.[23]

The LCOE for a given generator tends to be inversely proportional to its capacity. For instance, larger power plants have a lower LCOE than smaller power plants. Therefore, making investment decisions based on insufficiently comprehensive LCOE can lead to a bias towards larger installations while overlooking opportunities for energy efficiency and conservation[24] unless their costs and effects are calculated, and included alongside LCOE numbers for other options such as generation infrastructure for comparison.[25] If this is omitted or incomplete, LCOE may not give a comprehensive picture of potential options available for meeting energy needs.

Selection of input values

[edit]

Electrical energy generated

[edit]

The amount of electrical energy generated or estimated to be generated is dependent upon a large number of factors including:

  • Electricity market effects of grid balancing may require a load-following power plant to curtail generation of energy if the grid does not demand energy (negative spot prices) or allow a generator with high variable costs to be brought online to dispatch into a grid with significant unmet demand and high spot prices. Battery, run-of-the-river hydroelectricity with pondage, variable renewable energy and natural gas turbine generators are examples of dispatchable generators. Seasonal diurnal cycles and climatology, as well as short term meteorological events have significant impacts to grid balancing from both supply and demand perspectives. The geographical region within which LCOE is being assessed, the mix of generators in a grid, the proportion of demand flexibility (or conversely firm power demand) within a grid and transmission capacity limits within a grid also significantly influence required generation curtailment.

For a proposed generator with only the proposed nameplate capacity known, observed capacity factor data available for similar existing generators can be used to estimate the electrical energy generated for the proposed new generator.

Expenditures

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Investment expenditures , operations and maintenance expenditures and fuel expenditures are influenced by a variety of taxes commonly imposed by governments including tariffs impacting the cost of importing generation equipment and fuels, excises impacting the cost of production of fuels, carbon taxes for offsetting the social cost of carbon and other taxes for recouping shared industry costs of electric power transmission and research and development of energy technologies. Expenditures can also be influenced by a variety of energy subsidies.

Assumptions are required to be made due to the subjective nature of prediction of future levels of taxation and subsidies and influence of the politics of climate change.

Discount rate

[edit]

Cost of capital expressed as the discount rate is one of the most controversial inputs into the LCOE equation, as it significantly impacts the outcome and a number of comparisons assume arbitrary discount rate values with little transparency of why a specific value was selected. Comparisons that assume public funding, subsidies, and social cost of capital tend to choose low discount rates (3%), while comparisons prepared by private investment banks tend to assume high discount rates (7–15%) associated with commercial for-profit funding.[citation needed] Assuming a low discount rate favours nuclear and sustainable energy projects, which require a high initial investment but then have low operational costs.

In a 2020 analysis by Lazard,[26] sensitivity to discount factor changes in the range of 6–16% results in different LCOE values but the identical ordering of different types of power plants if the discount rates are the same for all technologies.

See also

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References

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Revisions and contributorsEdit on WikipediaRead on Wikipedia

Levelized cost of electricity

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from Grokipedia
The levelized cost of electricity (LCOE) is a financial metric that estimates the average net present cost of electricity generation for a power plant over its assumed economic lifetime, divided by the total electricity output, expressed in dollars per megawatt-hour. It incorporates upfront capital expenditures, fixed and variable operations and maintenance costs, fuel expenses (where applicable), and a discount rate to reflect the time value of money, enabling comparisons across diverse technologies like coal, natural gas, nuclear, solar, and wind. Developed as a tool for investment appraisal and policy analysis, LCOE assumes a constant output profile and does not inherently capture dispatchability or grid integration challenges, leading to criticisms that it understates the true system costs of variable renewable sources which require supplementary firm capacity, storage, or curtailment management. Empirical data from sources such as Lazard's annual analyses reveal dramatic LCOE reductions for unsubsidized utility-scale solar photovoltaic systems, dropping from approximately $359/MWh in 2009 to $24-96/MWh by 2023, driven by plummeting panel prices and efficiency gains, though wide ranges reflect site-specific factors and optimistic capacity factors. Despite its utility in highlighting capital-intensive technology trends, LCOE's limitations—such as ignoring revenue streams from ancillary services, capacity markets, or externalities like emissions—have prompted extensions like LCOE+ to better approximate real-world deployment economics.

Definition and Formulation

Core Concept

The levelized cost of electricity (LCOE) is a metric that calculates the average net present value of the total costs associated with building, operating, and maintaining an electricity generating asset over its expected lifetime, divided by the total discounted electricity output during that period, typically expressed in dollars per megawatt-hour ($/MWh). This approach uses discounted cash flow analysis to account for the time value of money, enabling standardized comparisons across diverse generation technologies such as coal, natural gas, nuclear, solar, and wind. By aggregating upfront capital costs, ongoing operations and maintenance expenses, and fuel inputs (where applicable) into a single per-unit measure, LCOE facilitates evaluations of economic competitiveness under specified assumptions like plant capacity factor, discount rate, and operational lifespan. In the formula, ItI_t, MtM_t, and FtF_t denote the investment, operations and maintenance, and fuel costs incurred in year tt; EtE_t represents the electricity generated in year tt; rr is the real discount rate; nn is the economic lifetime in years; and α\alpha marks the initial period before full capacity is reached. LCOE assumes a constant annual energy profile adjusted for capacity factor—the ratio of actual output to maximum possible output—and does not inherently incorporate grid-level integration costs, such as additional transmission infrastructure or backup capacity for intermittent renewables, which can significantly alter effective system costs. Empirical analyses, such as those from the U.S. Energy Information Administration, apply LCOE to projected builds, using inputs like a 3% real discount rate and 30-year lifetimes for fossil and nuclear plants, though variable renewables often feature shorter horizons (e.g., 20-25 years) and lower capacity factors (20-40% for solar and wind versus 80-90% for baseload nuclear). While LCOE originated as a tool for assessing baseload technologies with predictable dispatch, its application to renewables has drawn scrutiny for potentially overstating affordability by isolating plant-level from broader grid reliability requirements; for instance, high penetration of solar and necessitates overbuilding capacity and firming resources, costs not captured in standalone LCOE figures. Nonetheless, it remains a foundational input for investment decisions, regulatory planning, and policy assessments, with organizations like the updating estimates biennially to reflect technological advancements and market conditions as of 2020.

Mathematical Expression

The levelized cost of electricity (LCOE) is calculated as the of the total lifetime costs of a generating facility divided by the of the total lifetime electricity output, expressed in real units per unit of (typically dollars per megawatt-hour). This approach accounts for the by applying a discount rate to future costs and production. In the formula, the numerator sums the discounted costs including capital investments ItI_t, operations and maintenance MtM_t, and fuel expenditures FtF_t over periods t=1t = 1 to nn, where nn is the economic lifetime in periods (often years). The denominator sums the discounted EtE_t from period α\alpha (the onset of production, potentially after construction) to nn. The discount rate rr reflects the or , typically 5-10% depending on financing and . This structure ensures comparability across technologies by annualizing costs on a per-unit basis, though assumptions about constant capacity factors and discount rates can introduce sensitivities.

Historical Development

Origins for Baseload Technologies

The levelized cost of electricity (LCOE) concept originated as a tool in regulated markets, where state-sanctioned monopolies evaluated competing baseload technologies to meet constant grid demand and justify capital investments through cost-recovery tariffs. In these vertically integrated systems, prevalent in the United States and from the post-World War II era through the late , utilities faced high fixed costs for constructing large-scale -fired steam plants and, later, nuclear reactors, offset by predictable fuel expenditures and near-continuous operation at capacity factors exceeding 70%. LCOE aggregated these elements—capital outlays, fixed and variable operations and maintenance, fuel, and decommissioning—into a single metric representing the constant revenue stream needed per unit of output over the asset's lifetime, discounted at the utility's , typically 7-10%. This facilitated apples-to-apples comparisons, such as plants with annualized capital costs of $30-50 per kilowatt-year and fuel at $20-30 per megawatt-hour in the versus nuclear's higher initial 1,000−2,000perkilowattbutsub−1,000-2,000 per kilowatt but sub-10 per megawatt-hour fuel equivalent. The metric's formulation drew from established financial practices like analysis, adapted to power sector realities where baseload amortized costs over 30-60 years of output, assuming 80-90% capacity factors to minimize per-unit expenses. Regulatory bodies, such as the U.S. Federal Power Commission (predecessor to the ), implicitly endorsed LCOE-like evaluations in rate cases to verify "prudent" investments, ensuring consumers paid for reliable supply without undue burden. For , dominant in U.S. baseload until the (comprising over 50% of generation), LCOE highlighted from supercritical units exceeding 500 megawatts, with total costs stabilizing at $40-60 per megawatt-hour in constant dollars by the . Nuclear applications emphasized low marginal costs post-construction, though overruns—like those at such as Shoreham (completed at $6 billion, triple initial estimates)—exposed sensitivities to construction delays and interest during construction, often 20-30% of total expense. Early LCOE calculations prioritized dispatchable, firm capacity suited to regulated planning horizons, excluding or costs irrelevant to baseload dominance. Government reports, including those from the U.S. Commission in the 1950s-1960s, employed precursor methods to project nuclear breakeven against at LCOE parity around $0.02-0.03 per (1960 dollars), influencing the buildout of over 100 reactors by 1990. This framework assumed stable fuel markets and no carbon pricing, reflecting causal links between upfront , utilization rates, and revenue adequacy in monopoly settings.

Evolution with Renewables and Deregulation

The application of levelized cost of electricity (LCOE) expanded significantly in the late 1990s and as renewable technologies, particularly and solar photovoltaic (PV), gained policy support through renewable portfolio standards and feed-in tariffs. Originally designed for dispatchable baseload plants, LCOE methodologies were adapted to account for the lower and more variable capacity factors of intermittent renewables, typically ranging from 20-40% for solar PV and 30-50% for onshore , compared to over 80% for nuclear or . This reflected empirical cost declines driven by technological learning curves and manufacturing scale, with global weighted-average LCOE for utility-scale solar PV falling 89% between 2010 and 2023, from approximately $0.36/kWh to $0.049/kWh, and onshore decreasing 69% to $0.033/kWh. Annual LCOE analyses, such as Lazard's reports initiated in , highlighted unsubsidized renewables achieving cost parity with fuels in optimal conditions by the mid-2010s, with utility-scale solar reaching $30-60/MWh and onshore $25-50/MWh by 2023. However, these metrics faced growing scrutiny for underrepresenting system-level integration costs, including backup generation, transmission upgrades, and balancing services required for , which can add 50-100% to effective costs in high-renewable grids. Peer-reviewed critiques emphasized that standard LCOE assumes steady output and neglects dispatchability, rendering it less suitable for comparing intermittent sources to firm capacity without adjustments for storage or firming. Electricity market deregulation, accelerating in the with reforms like the UK's 1990 Electricity Act and U.S. FERC Order 888 in 1996 promoting wholesale competition, shifted utility planning from regulated cost recovery to market-based pricing. In these environments, LCOE informed bids and investment decisions but proved inadequate for capturing value in merit-order dispatch systems, where zero-marginal-cost renewables depress wholesale prices during high output, eroding revenues for all generators including themselves. This dynamic, observed in deregulated markets like and , amplified LCOE's limitations by prioritizing short-run marginal costs over long-run averages, leading to events exceeding 10% of hours in some regions by 2020. Evolving responses included hybrid metrics like LCOE+ incorporating storage and costs, as in Lazard's post-2018 iterations, to better reflect deregulated market realities. Despite these advancements, analyses from organizations like the Clean Air Task Force argue LCOE remains over-relied upon for policy, often ignoring reliability premiums in competitive frameworks.

Calculation Components

Capital and Investment Costs

Capital and investment costs in levelized cost of electricity (LCOE) calculations represent the upfront expenditures to engineer, procure, construct, and commission a generation facility, corresponding to the ItI_t term in the LCOE formula. These costs exclude ongoing operations but include direct expenses such as equipment, materials, and labor for turbines, generators, civil works, and electrical systems, as well as indirect costs like engineering, project management, permitting, land acquisition, interconnection, and contingency allowances. They are typically quantified as overnight capital costs (OCC), which assume instantaneous construction in constant dollars without financing charges, with interest during construction (IDC) added separately to derive total investment requirements. Financing costs during development, often 5-10% of total capital depending on project scale and debt-equity structure, amplify effective investment for long-lead technologies like nuclear plants, where construction periods exceed five years. Overnight vary widely by technology due to differences in material intensity, scale, site-specific factors, and regulatory hurdles; plants emphasize durable for high-temperature operations, while renewables prioritize modular components amenable to . The U.S. Energy Information Administration's 2024 assessment for Annual Energy Outlook 2025, based on bids in 2023 dollars, provides representative U.S. averages excluding IDC and escalation.
TechnologyAverage Overnight Capital Cost ($/kW, 2023 USD)
Advanced Nuclear7,861
(Ultra-Supercritical, no CCS)4,103
Offshore Wind3,689
Natural Gas Combined Cycle (H-Class)868
Onshore Wind1,489
Utility-Scale Photovoltaic (Single-Axis)1,502
Battery Storage (4-Hour)1,744
These figures reflect generic U.S. sites with standard ambient conditions (59°F, 60% ) and exclude tax credits or regional adjustments for labor and resources. for solar photovoltaic and onshore have declined over 80% since 2010 due to efficiencies and effects, reaching parity with or below some gas plants, whereas nuclear costs remain elevated from complex safety systems and fragmentation. In LCOE, these costs are levelized by dividing the of total capital outlay—amortized via the incorporating discount rates (typically 3-10%)—by lifetime energy output, making high a primary driver for dispatchable baseload versus intermittent sources. Owner's costs, comprising 10-20% of OCC for development and , further differentiate projects, with renewables benefiting from shorter timelines reducing IDC exposure.

Operating, Maintenance, and Fuel Costs

Operating, maintenance, and fuel costs in the levelized cost of electricity (LCOE) formulation capture the ongoing expenses required to sustain power generation after initial capital outlays, including fixed operation and maintenance (O&M) costs for labor, administrative overhead, and facility upkeep; variable O&M costs tied to output, such as repairs and consumables; and fuel procurement for combustion-based systems. These components, represented as MtM_t (O&M) and FtF_t (fuel) in the discounted numerator of the LCOE equation, vary significantly by technology due to differences in mechanical complexity, regulatory demands, and resource dependence. Empirical data from U.S. government analyses indicate that these costs typically comprise 10-30% of total LCOE for renewables but can exceed 60% for gas-fired plants under volatile fuel markets. Renewable technologies exhibit no fuel costs, as they harness free , or geothermal resources, with O&M dominated by fixed elements for monitoring, cleaning, and occasional component replacement. Utility-scale solar PV incurs fixed O&M of approximately $13-17 per kilowatt-year (kW-yr), reflecting inverter replacements every 10-15 years and panel cleaning, with variable O&M near zero. Onshore wind fixed O&M averages $30-40 per kW-yr, driven by servicing including inspections and gearbox overhauls, while offshore wind escalates to $85-124 per kW-yr owing to marine access challenges and mitigation; variable O&M remains minimal across these. Geothermal plants face higher fixed O&M around $150 per kW-yr due to reservoir management and well maintenance. These estimates derive from bottom-up assessments incorporating historical fleet data, though actual costs may rise post-warranty as third-party contracts replace manufacturer support. Fossil fuel and nuclear plants, by contrast, incur substantial fuel costs that introduce economic sensitivity to prices and supply chains. combined-cycle (CC) units feature low fixed O&M of $10-15 per kW-yr and variable O&M of $2-3 per megawatt-hour (MWh), but fuel—calculated via heat rate (typically 6,400 Btu/kWh) multiplied by gas price—can reach $15-20 per MWh at $3-4 per million Btu, often accounting for over half of lifetime costs. plants demand higher fixed O&M (~$45 per kW-yr) for emissions controls and ash handling, with variable O&M $5 per MWh excluding fuel; fuel costs, at heat rates of 8,600-9,000 Btu/kWh and prices around $2-3 per million Btu, yield $15-25 per MWh, though declining fleets limit recent data granularity. Nuclear generation emphasizes fixed O&M ($90-140 per kW-yr) for protocols, monitoring, and specialized staffing, with low variable O&M ($2-3 per MWh) and fuel ($7-8 per MWh from enrichment and fabrication), reflecting efficient fuel utilization but regulatory overhead that exceeds peers. Fuel costs for all plants are modeled using projected prices, heat rates, and efficiency, underscoring LCOE's reliance on long-term forecasts prone to geopolitical disruptions.
TechnologyFixed O&M ($/kW-yr, 2022 basis)Variable O&M ($/MWh)Fuel Cost ($/MWh, reference case)
Utility PV13-1700
Onshore Wind30-4000
Gas CC10-152-315-20
45515-25
Nuclear90-1402-37-8
These values, drawn from 2023-2024 analyses, assume constant dollars and exclude externalities like emissions; estimates incorporate baseline prices and may vary 20-50% with market shifts. In practice, O&M optimization through and modular designs can reduce these by 5-15% over plant lifetimes, though aging infrastructure often elevates costs beyond projections.

Discount Rate, Lifetime, and Capacity Factor

The discount rate rr, representing the weighted average cost of capital (WACC), discounts future costs and energy production to present value in the LCOE formula, capturing the time value of money and project-specific risks such as financing costs and uncertainty. Lazard's LCOE analyses apply an after-tax WACC of approximately 9.6%, derived from 60% debt financing at 8% interest and 40% equity at 12% return. In contrast, the International Energy Agency (IEA) uses a 7% real discount rate in base-case projections for baseload technologies like nuclear, coal, and combined-cycle gas turbines (CCGT), reflecting lower perceived risks for established dispatchable sources. Higher discount rates amplify the relative LCOE of capital-intensive, long-lived assets like nuclear plants—where upfront costs dominate—compared to technologies with deferred or lower capital outlays, such as natural gas or renewables; this sensitivity underscores methodological choices that can favor intermittent sources when rates exceed 8-10%. The lifetime nn denotes the projected operational years of the electricity-generating asset, determining the summation periods for costs and output in the LCOE calculation and thus spreading fixed capital expenditures over total produced. Assumptions differ markedly by technology: nuclear facilities are typically modeled at 60 years to account for extensions and refurbishments, while utility-scale solar photovoltaic (PV) systems use 30 years and onshore turbines 25-30 years, based on warranty periods, degradation rates, and historical decommissioning data. Shorter lifetimes for renewables reflect faster technological obsolescence and module replacement needs, but optimistic extensions can understate LCOE by assuming minimal degradation; from operational fleets shows solar output declining 0.5-1% annually, potentially shortening effective lifetimes below modeled values. Capacity factor, the ratio of actual annual energy output to maximum possible output at rated capacity (i.e., Et=P×8760×CFE_t = P \times 8760 \times CF, where PP is and 8760 approximates hours in a year), directly scales the denominator of the LCOE , with lower values elevating costs per unit energy due to underutilized fixed investments. U.S. (EIA) data for 2023-2024 report average capacity factors of 92% for nuclear, 50-60% for , 56% for CCGT, 34% for onshore , and 23% for utility-scale solar, reflecting constraints absent in dispatchable sources. For solar power plants, capacity factors vary significantly by region, with higher irradiance locations like the U.S. Southwest yielding greater output and lower LCOE; technology choices such as fixed-tilt versus tracking panels affect capacity factors and capital costs, while pairing with storage increases overall LCOE to provide dispatchability. The IEA assumes 85% for baseload plants in LCOE projections to represent high-availability operations, but real-world renewable factors often fall short of optimistic models (e.g., early solar assumptions exceeded 30%), inflating perceived affordability when not adjusted for grid integration losses or curtailment. Variations in these inputs—such as using site-specific rather than national averages—can alter LCOE rankings, with critics noting that uniform high capacity factors for renewables overlook systemic reliability costs borne by backup capacity.

Applications and Comparisons

Cross-Technology Cost Evaluations

Levelized cost of (LCOE) evaluations across technologies standardize comparisons by discounting total lifecycle s against expected production, enabling assessment of economic viability for dispatchable and intermittent sources alike. Financial analyses, such as 's Levelized of + Version 18.0 released in June 2025, calculate unsubsidized LCOE ranges using a with 60% at 8% and 40% equity at 12%, alongside technology-specific capacity factors and lifetimes. These estimates highlight utility-scale solar photovoltaic (PV) and onshore as having the lowest ranges among major options, driven by sharp declines in capital s since the . The following table summarizes key unsubsidized LCOE ranges from Lazard's 2025 report for new-build technologies:
TechnologyUnsubsidized LCOE ($/MWh)Capacity Factor (%)
Utility-Scale Solar PV38–78Varies by location
Onshore 37–8630–55
Offshore 70–15745–55
Gas Combined Cycle48–10930–90
71–17365–85
Nuclear141–22089–92
Gas Peaking149–25110–15
In contrast, the U.S. Energy Information Administration's (EIA) Annual Energy Outlook 2025 projects levelized costs for resources entering service in 2030, using a 30-year cost recovery period and after-tax of 6.65%, yielding simple average values such as $29.58/MWh for utility-scale solar PV and $64.55/MWh for combined cycle, though onshore wind appears higher at $133.88/MWh in simple averages due to regional variations. Discrepancies arise from differing assumptions on prices, escalation rates, and regional build locations, with EIA incorporating 25 U.S. supply regions for capacity-weighted averages that better reflect modeled deployments. Such evaluations inform investment decisions by indicating that, on a standalone basis, variable renewables like solar and often undercut alternatives in low-penetration scenarios, as evidenced by 's data showing solar and onshore wind below gas combined cycle medians. However, nuclear's elevated costs stem primarily from high upfront capital expenditures and extended timelines, while gas benefits from lower and fuel flexibility. Government projections like EIA's further emphasize hybrid systems, with PV-battery at $31.86/MWh simple average, underscoring evolving evaluations that pair renewables with storage to enhance firm capacity. These metrics, while empirical, vary by ; for instance, European analyses report similar renewable advantages but higher offshore wind costs due to factors.

Influence on Policy and Investment

The levelized cost of electricity (LCOE) has significantly shaped by providing a standardized metric for comparing generation technologies, often prioritizing those with the lowest projected LCOE, such as solar photovoltaic and onshore , which fell to $24–$96 per megawatt-hour and $24–$75 per megawatt-hour respectively in unsubsidized estimates for 2023. Policymakers , for example, reference EIA's annual LCOE analyses in Energy Outlook to justify incentives like the production tax credit and investment tax credit, extended and expanded under the of 2022, which commits over $369 billion to clean energy deployments based on renewables' apparent cost advantages over fossil fuels and nuclear. Similarly, the incorporates LCOE in its Projected Costs of Generating Electricity reports to recommend policy pathways, influencing commitments under the to scale renewables despite their intermittency. In subsidy design, LCOE calculations determine required support levels; China's feed-in tariff policies for renewables, implemented since 2009, were calibrated using LCOE estimates to bridge the gap between renewable and generation costs, resulting in subsidies exceeding 1 trillion yuan annually by the mid-2010s and accelerating solar capacity additions to over 500 gigawatts by 2023. strategies, including the plan of 2022, cite falling LCOE for and solar—down 60–80% since 2010—to advocate phasing out fuels, directing €300 billion in investments toward grid modernization and storage to accommodate variable output. However, such policies often exclude system-level externalities, leading critics to argue that LCOE-driven mandates undervalue dispatchable sources like combined-cycle plants, whose LCOE remains competitive at $40–$80 per megawatt-hour when factoring reliability. For investment decisions, LCOE underpins by banks and developers, signaling profitability thresholds that have channeled over $1.1 trillion into renewable projects globally from 2010 to 2023, with and favoring low-LCOE assets amid declining for panels and turbines. Lazard's annual LCOE reports, showing unsubsidized solar and below and gas in optimal conditions, have bolstered confidence, contributing to a 23% drop in Latin American renewable LCOE from 2020 to 2024 and record bids under $20 per megawatt-hour in regions like . Yet, empirical analyses indicate that reliance on LCOE alone distorts allocations, as it omits capacity and curtailment costs, potentially inflating total expenses by 50–100% in high-renewable grids per modeling from the National Renewable Energy Laboratory. This has prompted calls for augmented metrics in investment prospectuses, though standard practice persists, correlating with utility-scale solar comprising 40% of new U.S. capacity additions in 2023.

Limitations

Inadequate Handling of Intermittency

The levelized cost of electricity (LCOE) incorporates primarily through the , which reflects the average output of a generator relative to its maximum potential, typically lower for variable renewables like (around 35-45%) and solar (20-30%) compared to dispatchable sources like combined cycle (50-60%). However, this adjustment fails to capture the full implications of , as it assumes the generated is reliably usable without additional system-level accommodations, thereby understating the need for backup capacity, , or overbuilding to ensure grid stability. For instance, and solar output correlates poorly with demand patterns, leading to periods of overgeneration (requiring curtailment) or shortfall (necessitating rapid ramping from reserves), costs which standard LCOE externalizes to the broader system. Empirical analyses demonstrate that integration costs escalate with higher penetrations of intermittent sources. A study on levelized full system costs (LFSCOE) defines these as the sum of generation LCOE plus marginal integration costs, revealing that for onshore wind in Germany, the effective cost rises from approximately 60 EUR/MWh at low penetration to nearly 100 EUR/MWh at 40% share due to increased balancing and backup requirements. Similarly, system LCOE frameworks account for variability-induced expenses such as additional transmission and flexibility services, which can add 20-50% or more to the standalone LCOE of renewables depending on grid penetration levels and location. These externalities arise because intermittency imposes opportunity costs on dispatchable plants (e.g., frequent starts and stops reducing efficiency) and demands redundant capacity that remains idle much of the time, yet standard LCOE comparisons treat intermittent and firm generation as directly substitutable. Critics argue that this omission biases toward renewables by presenting artificially low costs, ignoring causal realities like the physical limits of weather-dependent . For example, even advanced reduces but does not eliminate , with residual balancing costs for and solar estimated at 4-10 EUR/MWh in European systems at moderate penetrations, scaling nonlinearly as shares exceed 30%. While some analyses, such as Lazard's LCOE+ variant introduced in 2020, attempt to quantify "firming" costs for (e.g., adding storage or hybrids to achieve dispatchability), these remain optional extensions rather than core to traditional LCOE methodology, perpetuating incomplete evaluations. In high-renewable scenarios, such as California's grid where solar has led to duck-curve challenges, the unaccounted system costs have manifested in elevated wholesale prices and reliability risks during non-solar hours.

Neglect of Dispatchability and Reliability

Standard LCOE calculations assess the average cost per unit of generated over a plant's lifetime but fail to incorporate dispatchability, the capacity of a generation technology to produce power on demand in response to grid operator instructions. This attribute is inherent in baseload sources like nuclear and plants, which can adjust output to match fluctuating demand, whereas variable renewables such as and solar generate intermittently based on meteorological conditions, limiting their . By treating all kilowatt-hours as equivalent regardless of timing or predictability, LCOE undervalues the premium associated with dispatchable power, which ensures grid stability during peak loads or unexpected shortfalls. Reliability, the sustained ability of the electricity system to meet without interruptions, is likewise excluded from LCOE frameworks, which focus solely on generator-level without for the need for or firming capacity to compensate for renewable variability. Intermittent sources require supplementary dispatchable reserves—often gas-fired peaker plants or emerging storage—to maintain adequacy, costs that standard LCOE attributes to individual projects rather than the integrated grid. For example, analyses demonstrate that levelized cost comparisons misrepresent intermittents' viability because they ignore capacity value, the contribution to peak reliability, which can be near zero for non-dispatchable output during high- periods. This neglect contributes to policy distortions, as LCOE-driven assessments have historically favored renewables in isolation, overlooking the elevated system integration expenses that escalate with penetration levels above 20-30%. Empirical grid studies, such as those in regions with high renewable shares like and , reveal increased curtailment, overbuild requirements, and reliance on fossil backups during lulls, underscoring how dispatchable technologies provide inherent reliability value absent in LCOE. Critics argue that without adjustments for these factors, LCOE promotes inefficient , prioritizing low marginal costs over the causal role of dispatchability in averting blackouts and supporting economic .

Criticisms and Debates

Methodological Biases Favoring Renewables

The levelized cost of electricity (LCOE) methodology often understates the effective costs of intermittent renewables like solar and wind by treating their output as equivalent to dispatchable sources, ignoring the need for backup capacity, storage, and grid reinforcements to ensure reliability. This bias arises because standard LCOE calculations assess individual generator costs in isolation, assuming full utilization of generated energy without accounting for variability in supply that requires overbuilding or complementary firm power. For instance, a 2011 analysis by economist Paul Joskow highlighted that LCOE fails to incorporate intermittency costs, such as the additional expenses for balancing variable renewables, which can double or triple their system-level expenses compared to baseload alternatives. Another methodological flaw favoring renewables lies in the assumption that all megawatt-hours (MWh) provide equal value, disregarding the temporal mismatch between renewable generation peaks and demand patterns. , for example, typically generates most during midday when prices are low, while evening peaks require expensive peaker plants or storage not reflected in standalone LCOE figures. This oversight implicitly subsidizes renewables by equating their to high-value dispatchable output from nuclear or gas plants, which can respond to grid needs. A 2019 assessment noted that LCOE's focus on costs alone, without revenue or system value adjustments, misleads comparisons by undervaluing reliability attributes of non-intermittent sources. Capacity factor assumptions in LCOE models further bias results toward renewables by relying on optimistic projections from prime locations, such as offshore sites with 50-60% factors, rather than grid-averaged realities closer to 25-35%. These inputs, drawn from manufacturer data or pilot projects, do not scale to national deployments where land constraints and weather variability reduce performance. Peer-reviewed critiques, including a 2023 study, argue that such assumptions mask the overcapacity required—often 2-3 times for —to match firm capacity, inflating apparent cost competitiveness. Discount rate selections exacerbate the favoritism, as low rates (e.g., 3-5%) disproportionately benefit capital-intensive renewables with upfront-heavy investments, discounting future backup and decommissioning costs more heavily than for fuel-dependent dispatchables. Higher real-world rates reflecting policy and technology risks—up to 7-10% for unsubsidized renewables—would widen the gap, yet models from firms like often apply uniform or subdued rates. This sensitivity, documented in sensitivity analyses, stems from LCOE's origins in regulated utility planning, ill-suited for competitive markets with volatile renewables.

Distortions from Subsidies and Assumptions

Subsidies significantly distort levelized cost of electricity (LCOE) estimates by reducing the effective costs attributed to intermittent renewable sources like and solar, while comparable supports for dispatchable technologies such as or nuclear are often excluded or minimal in comparisons. In the United States, the production tax credit (PTC) for , providing up to 2.6 cents per , and the investment tax credit (ITC) for solar, offering 30% of qualifying capital expenditures, are routinely factored into LCOE models for these technologies, lowering their reported figures by 20-50% depending on project specifics. This inclusion creates an uneven playing field, as and nuclear LCOE calculations seldom incorporate production or investment incentives on a similar scale, leading to artificially favorable portrayals of renewable competitiveness. Even unsubsidized LCOE analyses, such as those from Lazard's 2025 report, reveal ongoing distortions when subsidies indirectly influence market dynamics, including depressed wholesale prices during high renewable output periods that undermine revenue for reliable baseload sources. For instance, unsubsidized utility-scale solar LCOE ranges from $38 to $78 per megawatt-hour, yet historical subsidy flows—totaling hundreds of billions in federal support—have accelerated deployment and declines that may not persist without continued intervention, masking true long-term viability. Critics argue this dependence distorts signals, favoring intermittent over technologies capable of firm , as evidenced by persistent market interventions like capacity payments for backups not reflected in standard LCOE. Assumptions embedded in LCOE methodologies further exacerbate distortions, particularly through optimistic projections for renewable performance metrics that overlook real-world constraints. Capacity factors for wind and solar are frequently modeled at 35-50% for onshore wind and 25-30% for solar, yet actual grid-integrated values often fall lower due to curtailment and variability, inflating energy output denominators and understating costs. Discount rates, typically set at 5-7% for private projects, can bias toward capital-intensive renewables when lower social rates (3-5%) are applied selectively, amplifying present value reductions for upfront-heavy technologies while devaluing future fuel savings in dispatchable plants. Lifetime assumptions of 25-30 years for solar panels and turbines ignore degradation rates—often 0.5-1% annually—leading to overestimated production over time, a factor compounded by subsidies that extend financial incentives beyond unsubsidized benchmarks. These parametric choices, when combined with subsidy inclusions, systematically undervalue the reliability premiums required for system stability, rendering cross-technology LCOE comparisons misleading for policy decisions.

Empirical Evidence of Misleading Comparisons

In real-world deployments with high shares of intermittent renewables, total electricity system costs have frequently surpassed projections derived from standalone LCOE analyses, which exclude expenses for backup capacity, grid reinforcements, and balancing services. A seminal critique by economist Paul Joskow highlights that LCOE comparisons overvalue intermittent sources like wind and solar relative to dispatchable technologies by ignoring generation profile mismatches and the need for firm capacity to ensure reliability. This discrepancy manifests empirically when renewables exceed 40-50% penetration, as variability amplifies system-wide integration costs estimated at 50-100% of standalone renewable LCOE in various studies. Germany's exemplifies this, with renewables supplying 62.7% of net public electricity in 2024, yet household prices averaged €0.402 per kWh in late 2023—among Europe's highest—incorporating surcharges for subsidies and network upgrades. The program's total expenditures reached €696 billion by end-2022, far exceeding benefits from low marginal wholesale prices during high renewable output, due to persistent reliance on gas and for dispatchability and hidden costs like EEG levies funding feed-in tariffs. These outcomes contradict LCOE narratives portraying unsubsidized renewables as inherently cheaper, as system-level demands for overbuild and storage elevate effective costs. South Australia's grid, achieving near-70% renewable penetration by 2023, similarly demonstrates elevated expenses, with prices driven higher by necessitating gas-fired peakers and batteries during shortfalls, despite favorable LCOE for local and solar. Volatility has led to repeated price spikes and blackouts, such as in , underscoring how LCOE neglects the premium for reliability in isolated, high-renewable networks. The 2021 Texas freeze further illustrates reliability shortfalls, where and solar output plummeted to near-zero during —despite comprising ~25% of ERCOT capacity—while dispatchable gas and nuclear provided critical baseload, averting total collapse amid 20 GW of rolling blackouts affecting millions. This event, costing over $195 billion in damages, revealed how LCOE undervalues the insurance value of dispatchable sources against intermittency risks not captured in averaged lifetime metrics. Analyses incorporating such system costs, like levelized full system LCOE, consistently show renewables' advantages eroding when externalities are quantified.

Extensions and Alternatives

Incorporation of System Costs

Standard levelized cost of electricity (LCOE) calculations focus on the costs attributable to a single generating unit, excluding broader system-level expenses required for reliable grid operation, such as backup capacity, , transmission reinforcements, and balancing services necessitated by the and variability of sources like and solar photovoltaic (PV). These system costs arise because (VRE) outputs fluctuate unpredictably, requiring dispatchable reserves to maintain supply-demand balance, which can add 20-50% or more to the effective cost of delivered electricity depending on penetration levels. For instance, at high VRE shares exceeding 30-40% of mix, and curtailment become significant, further elevating integration expenses through excess generation that must be managed or wasted. To address these omissions, researchers have developed extended metrics like System LCOE (SLCOE), which augments the generator-specific LCOE with marginal integration costs, including the value of lost load avoided and additional for variability smoothing. Similarly, Levelized Full System Costs of Electricity (LFSCOE) evaluates the total costs of serving the entire demand across a modeled grid, incorporating interactions between technologies rather than isolating them; this reveals that dispatchable sources like nuclear or impose lower system burdens due to their capacity factors and predictability. Lazard's LCOE+ framework, updated in 2025, quantifies "firming" costs for —such as pairing renewables with storage or peaker —estimating that these can raise the unsubsidized cost of wind-plus-storage to $100-150 per MWh and solar-plus-storage to $120-200 per MWh in scenarios requiring 90% capacity credit. Empirical analyses incorporating system costs consistently show that VRE technologies become less competitive at scale compared to baseload alternatives. A study on European and U.S. grids found SLCOE for onshore rising from approximately €50/MWh (standalone LCOE) to €70-90/MWh with integration, while offshore and solar PV incurred even higher penalties due to greater variability, versus near-zero added costs for nuclear. In and , full-system evaluations indicate that and solar's true societal costs, including backup and grid upgrades, exceed those of combined-cycle gas by factors of 2-3 times when accounting for -driven overcapacity needs. These adjustments underscore causal linkages between source attributes— demanding —and total system economics, challenging standalone LCOE rankings that favor renewables without such holistic accounting.

Alternative Metrics like LFSCOE and Value-Adjusted Approaches

The Levelized Full System Cost of Electricity (LFSCOE) addresses LCOE's omission of integration costs by calculating the total expenses required to supply an entire using a single generation technology, including overcapacity, storage, generation, and grid reinforcements needed to achieve near-100% reliability. Introduced by Robert Idel in a 2022 peer-reviewed , LFSCOE assumes the technology must meet annual demand profiles without imports, forcing intermittent sources like solar and to incorporate firming measures such as excess capacity factors exceeding 300-500% or equivalent battery storage to compensate for low availability (typically 10-30% capacity factors). For dispatchable technologies like nuclear or combined-cycle gas turbines, which operate at 80-90% capacity factors with minimal backups, LFSCOE values closely align with LCOE, often ranging from $60-100/MWh depending on fuel and site specifics as of 2022 data. In contrast, LFSCOE for onshore can exceed $150/MWh and solar up to $200/MWh or more in analyses for European markets, reflecting the capital-intensive requirements for to match baseload supply. This metric thus reveals how LCOE understates the true economic burden of by isolating generator costs from systemic necessities. Value-adjusted LCOE (VALCOE) extends LCOE by incorporating the economic value of generated electricity to the grid, computed as LCOE multiplied by a system value factor that accounts for generation timing relative to peak demand, curtailment risks, and market pricing signals. Developed by the International Energy Agency (IEA) and Nuclear Energy Agency (NEA) in their 2020 joint report, VALCOE penalizes technologies producing low-marginal-value output—such as midday solar in high-penetration scenarios where wholesale prices drop to near-zero due to oversupply—via factors often below 0.7 for unsubsidized renewables in mature markets like Germany or California as of 2020-2023 projections. For instance, IEA modeling for 2022-2030 in regions like the European Union shows VALCOE for solar PV plus battery storage rising to $80-120/MWh, surpassing coal or gas in some stated policies scenarios, while dispatchable sources maintain higher value factors near 1.0 due to their alignment with evening peaks. Complementary metrics like the National Renewable Energy Laboratory's (NREL) Levelized Value of Electricity (LVOE) further disaggregate this by estimating revenue streams from capacity, energy, and ancillary services, demonstrating that wind and solar capture rates can fall below 50% of average wholesale prices in high-renewables grids, eroding their apparent LCOE competitiveness. These alternatives emphasize causal linkages between technology attributes—such as variable output and predictability—and broader system performance, enabling more accurate comparisons for and . Empirical applications, including sensitivity analyses in Idel's LFSCOE framework under 95% supply assumptions (LFSCOE-95), confirm that intermittency-driven costs dominate in diversified grids, with nuclear emerging cost-competitive at scales where renewables require 3-5 times the for equivalent firm output. IEA projections indicate VALCOE spreads for renewables widen post-2030 as penetration exceeds 40%, underscoring the need for hybrid metrics over standalone LCOE in scenarios with storage costs projected at $150-300/kWh for 4-hour duration as of 2023. While computationally intensive, requiring hourly load-matching models, such approaches mitigate LCOE's bias toward capital-light but unreliable generation by integrating real-world dispatch dynamics and avoided cost benchmarks.

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