Modern generation planning — understanding the Levelised Cost of Energy

The Levelised Cost of Energy (LCOE) represents the average cost to build and operate a power-generating facility over its lifetime, divided by the total energy it produces. Expressed in $/MWh or ZAR/MWh, it offers a standardised basis for comparing solar farms, wind turbines, battery storage facilities, gas-to-power plants and nuclear reactors.

LCOE includes capital costs, financing, operations and maintenance, fuel (where applicable), and end-of-life costs. Crucially, it excludes market price fluctuations and environmental externalities.

LCOE = Total Lifetime Costs ÷ Total Lifetime Energy Production

Taking into account the time value of money through a discounted cash flow analysis, this can be expressed more correctly as:

Where:

• I_t = Investment expenditures in year t (typically upfront capital cost in year 0, and reinvestments over time)
• O_t = Operation and maintenance costs in year t
• F_t = Fuel costs in year t (zero for renewables like solar and wind)
• E_t = Electricity generated in year t (usually in MWh)
• r = Discount rate (reflecting the cost of capital)
• N = System lifetime (typically 20 to 40 years, depending on technology)

This formula allows stakeholders to compare technologies on an equal footing – whether they rely on coal, sunlight, wind, coal, gas or steam.

Why LCOE matters

LCOE is central to energy investment, planning and procurement. Project developers use it to assess economic viability. Utilities and regulators use it to shape long-term power system plans. Governments refer to it when crafting renewable energy auctions and climate policy. And investors rely on it to evaluate return-on-investment potential.

In an age of surging energy demand, carbon targets and technology disruption, LCOE plays a defining role in shaping what gets built, where and why.

Insights from Lazard’s 2025 LCOE+ report

The June 2025 LCOE+ report by Lazard – now in its 18th edition – confirms that renewables remain the lowest-cost sources of new electricity in the United States and elsewhere, even without subsidies.

In the US, unsubsidised costs for utility-scale solar PV range from $37 to $44/MWh, while onshore wind spans $37 to $66/MWh. In contrast, gas combined-cycle plants come in at $48 to $109/MWh, and coal is significantly higher at $109 to $157/MWh. Nuclear power remains the costliest, ranging from $141 to $251/MWh.

When current US tax incentives – like the Investment Tax Credit (ITC) and Production Tax Credit (PTC) – are factored in, these costs reduce significantly. Utility-scale solar with full incentives can fall to just $15 to $24/MWh. However, under the Trump administration, the US tax incentive regime is experiencing some uncertainty and change.

This price competitiveness, coupled with speed to deploy, explains why renewables continue to dominate new-build generation – even as supply chain volatility and inflation have slightly pushed prices upward.

LCOE in integrated energy planning

In Integrated Resource Planning (IRP), utilities project decades into the future to identify the least-cost mix of generation. Here, LCOE provides a financial lens for choosing between technologies – balancing cost, emissions and reliability, while also considering the time value of money.

For example, planners might weigh the LCOE of a solar + battery hybrid system against that of a new gas peaker. This helps determine not only cost-optimal investments but also implications for transmission needs, grid stability and carbon goals.

LCOE also supports policy decisions, such as structuring auctions, determining feed-in tariffs or prioritising transmission expansion.

LCOE has its limits

Despite its popularity, LCOE has well-known blind spots – especially as energy systems evolve.

Most critically, LCOE does not account for unplanned intermittency of coal and nuclear, or the variability of renewable energy. It assumes all kilowatt-hours are equal, regardless of when they are generated. This obscures the grid value – or lack thereof – of resources like solar and wind that don’t generate on demand.

It also ignores the cost of integrating renewables: firming capacity, curtailment, congestion and storage. Nor does it capture locational constraints, grid upgrade needs or emissions externalities.

LCOE also overlooks market value. Two resources with identical LCOEs might deliver vastly different profits or emissions benefits depending on when and where their electricity is delivered into the grid.

In Lazard’s own words, LCOE “is not a forecasting tool” and does not reflect “the complexities of our evolving grid and resource needs.”

Lazard’s broader view: LCOE+

Recognising these challenges, Lazard has expanded its 2025 report beyond traditional LCOE to include system-level costs and sensitivities.

One key addition is the Cost of Firming Intermittency – a measure of the extra cost to ensure reliability when using solar, wind or hybrid systems. For instance, in California (CAISO), firming a standalone solar plant with a four-hour battery raises the total system cost from around $43/MWh to over $70/MWh.

Lazard also quantifies the impact of fuel and carbon pricing. A $40 to $60 per ton carbon price adds up to $60/MWh to coal and gas costs, further improving the competitiveness of zero-carbon technologies.

The report goes further to examine how LCOE is affected by capital cost assumptions. At higher interest rates, LCOEs for capital-intensive renewables rise more than for fuel-intensive gas plants – highlighting the financial exposure of clean energy projects.

What about energy storage?

Lazard’s Levelised Cost of Storage (LCOS), now in its 10th edition, shows declining costs across the board. A 100 MW, 4-hour battery system has an unsubsidised LCOS of $132/MWh, dropping to $83/MWh with full tax incentives. Smaller commercial and residential systems cost more, but are also falling due to oversupply of battery cells and improvements in energy density.

The role of storage in balancing renewables, providing grid services and avoiding curtailment makes it a growing complement to LCOE-based planning. LCOS adds a critical dimension to understanding long-term grid economics.

So, how is LCOE used?

One can think of LCOE as the foundation, but not the roof, nor the totality of energy analysis.

In markets with modest renewable penetration, LCOE still serves as a strong guidepost. But as systems mature and require greater flexibility, LCOE must be integrated with broader metrics – firming costs, ELCC (Effective Load Carrying Capability), locational value, emissions intensity, and market signals.

Lazard’s 2025 analysis reaffirms that a diverse portfolio – renewables, storage, flexible gas, with the possibility of future emerging technologies like small modular reactors and geothermal – offers the best hedge against volatility and aligns with both affordability and resilience goals.

Conclusions

The energy sector is navigating a major transformation. In this environment, LCOE remains an essential compass – but it cannot navigate the journey alone.

Used wisely, LCOE helps identify least-cost technologies. But to truly guide the energy transition, it must be paired with real-world operational insights and system-wide thinking.

The key is not to discard LCOE, but to expand the toolkit. Lazard’s 2025 report does exactly that, providing a more integrated, actionable view of what it takes to build the power system of the future. DM

Source: Full report (1.8 MB PDF): Lazard “Levelized Cost of Energy+” Version 18.0, June 2025. 

Chris Yelland is managing director of EE Business Intelligence

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