Different methods of electricity generation can incur significantly different costs, and these costs can occur at significantly different times relative to when the power is used. The costs include the initial capital, and the costs of continuous operation, fuel, and maintenance as well as the costs of de-commissioning and remediating any environmental damage. Calculations of these costs can be made at the point of connection to a load or to the electricity grid, so that they may or may not include the transmission costs.
For comparing different methods, it is useful to compare costs per unit of energy which is typically given per kilowatt-hour or megawatt-hour. This type of calculation assists policymakers, researchers and others to guide discussions and decision making but is usually complicated by the need to take account of differences in timing by means of a discount rate. The consensus of recent major global studies of generation costs is that wind and solar power are the lowest-cost sources of electricity available today.
The levelized cost of energy (LCOE) is a measure of a power source that allows comparison of different methods of electricity generation on a consistent basis. The LCOE can also be regarded as the minimum constant price at which electricity must be sold in order to break even over the lifetime of the project. This can be roughly calculated as the net present value of all costs over the lifetime of the asset divided by an appropriately discounted total of the energy output from the asset over that lifetime.
Typically the LCOE is calculated over the design lifetime of a plant, which is usually 20 to 40 years. However, care should be taken in comparing different LCOE studies and the sources of the information as the LCOE for a given energy source is highly dependent on the assumptions, financing terms and technological deployment analyzed. In particular, assumption of capacity factor has significant impact on the calculation of LCOE. Thus, a key requirement for the analysis is a clear statement of the applicability of the analysis based on justified assumptions.
In 2014, the US Energy Information Administration recommended that levelized costs of non-dispatchable sources such as wind or solar be compared to the "levelized avoided cost of energy" (LACE) rather than to the LCOE of dispatchable sources such as fossil fuels or geothermal. LACE is the avoided costs from other sources divided by the annual yearly output of the non-dispatchable source. The EIA hypothesized that fluctuating power sources might not avoid capital and maintenance costs of backup dispatchable sources. The ratio of LACE to LCOE is referred to as the value-cost ratio. When LACE (value) is greater than LCoE (cost), then value-cost ratio is greater than 1, and the project is considered economically feasible.
While calculating costs, several internal cost factors have to be considered. Note the use of "costs," which is not the actual selling price, since this can be affected by a variety of factors such as subsidies and taxes:
To evaluate the total cost of production of electricity, the streams of costs are converted to a net present value using the time value of money. These costs are all brought together using discounted cash flow.
For power generation capacity capital costs are often expressed as overnight cost per watt. Estimated costs are:
Running costs include the cost of any fuel, maintenance costs, repair costs, wages, handling any wastes etc.
Fuel costs can be given per kWh and tend to be highest for oil fired generation, with coal being second and gas being cheaper. Nuclear fuel is much cheaper per kWh.
Many scholars, such as Paul Joskow, have described limits to the "levelized cost of electricity" metric for comparing new generating sources. In particular, LCOE ignores time effects associated with matching production to demand. This happens at two levels:
Thermally lethargic technologies like coal and solid-fuel nuclear are physically incapable of fast ramping. However, many designs of Generation 4 molten fuel nuclear reactors will be capable of fast ramping because (A) the neutron poison xenon-135 can be removed from the reactor while it runs leaving no need to compensate for xenon-135 concentrations  and (B) the large negative thermal and void coefficients of reactivity automatically reduce or increase fission output as the molten fuel heats or cools, respectively. Nevertheless, capital intensive technologies such as wind, solar, and nuclear are economically disadvantaged unless generating at maximum availability since the LCOE is nearly all sunk-cost capital investment. Grids with very large amounts of intermittent power sources, such as wind and solar, may incur extra costs associated with needing to have storage or backup generation available. At the same time, intermittent sources can be even more 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. Despite these time limitations, leveling costs is often a necessary prerequisite for making comparisons on an equal footing before demand profiles are considered, and the levelized-cost metric is widely used for comparing technologies at the margin, where grid implications of new generation can be neglected.
Another limitation of the LCOE metric is the influence of energy efficiency and conservation (EEC). EEC has caused the electricity demand of many countries[which?] to remain flat or decline. Considering only the LCOE for utility scale plants will tend to maximise generation and risks overestimating required generation due to efficiency, thus "lowballing" their LCOE. For solar systems installed at the point of end use, it is more economical to invest in EEC first, then solar. This results in a smaller required solar system than what would be needed without the EEC measures. However, designing a solar system on the basis of LCOE would cause the smaller system LCOE to increase, as the energy generation drops faster than the system cost. The whole of system life cycle cost should be considered, not just the LCOE of the energy source. LCOE is not as relevant to end-users than other financial considerations such as income, cashflow, mortgage, leases, rent, and electricity bills. Comparing solar investments in relation to these can make it easier for end-users to make a decision, or using cost-benefit calculations "and/or an asset’s capacity value or contribution to peak on a system or circuit level".
Typically pricing of electricity from various energy sources may not include all external costs – that is, the costs indirectly borne by society as a whole as a consequence of using that energy source. These may include enabling costs, environmental impacts, usage lifespans, energy storage, recycling costs, or beyond-insurance accident effects.
The US Energy Information Administration predicts that coal and gas are set to be continually used to deliver the majority of the world's electricity. This is expected to result in the evacuation of millions of homes in low-lying areas, and an annual cost of hundreds of billions of dollars' worth of property damage.
According to a 2021 Harvard Business Review study costs of recycling solar panels will reach $20-30 per panel in 2035 which would increase the LCOE fourfold for PV solar power, which presents a significant policy challenge because if the recycling is made legal duty of the manufacturers it will dramatically reduce profit margins on this already competitive market, and if it's not then massive amounts of panels containing toxic heavy metals may end up in landfills unprocessed. According to IRENA 2016 study the amount of PV-related waste is estimated to grow by 78 million tons by 2050.
An EU funded research study known as ExternE, or Externalities of Energy, undertaken over the period of 1995 to 2005 found that the cost of producing electricity from coal or oil would double over its present value, and the cost of electricity production from gas would increase by 30% if external costs such as damage to the environment and to human health, from the particulate matter, nitrogen oxides, chromium VI, river water alkalinity, mercury poisoning and arsenic emissions produced by these sources, were taken into account. It was estimated in the study that these external, downstream, fossil fuel costs amount up to 1%–2% of the EU's entire Gross Domestic Product (GDP), and this was before the external cost of global warming from these sources was even included. Coal has the highest external cost in the EU, and global warming is the largest part of that cost.
A means to address a part of the external costs of fossil fuel generation is carbon pricing — the method most favored by economists for reducing global-warming emissions. Carbon pricing charges those who emit carbon dioxide for their emissions. That charge, called a "carbon price", is the amount that must be paid for the right to emit one tonne of carbon dioxide into the atmosphere. Carbon pricing usually takes the form of a carbon tax or a requirement to purchase permits to emit (also called "allowances").
Depending on the assumptions of possible accidents and their probabilities external costs for nuclear power vary significantly and can reach between 0.2 and 200 ct/kWh. Furthermore, nuclear power is working under an insurance framework that limits or structures accident liabilities in accordance with the Paris convention on nuclear third-party liability, the Brussels supplementary convention, and the Vienna convention on civil liability for nuclear damage and in the U.S. the Price-Anderson Act. It is often argued that this potential shortfall in liability represents an external cost not included in the cost of nuclear electricity; but the cost is small, amounting to about 0.1% of the levelized cost of electricity, according to a CBO study.
These beyond-insurance costs for worst-case scenarios are not unique to nuclear power, as hydroelectric power plants are similarly not fully insured against catastrophic events like a large dam failure. For example, the 1975 Banqiao Dam disaster took the homes of 11 million people and killed between 26,000 and 230,000. As private insurers base dam insurance premiums on limited scenarios, major disaster insurance in this sector is likewise provided by the state.
Because externalities are diffuse in their effect, external costs can not be measured directly, but must be estimated. One approach estimate external costs of environmental impact of electricity is the Methodological Convention of Federal Environment Agency of Germany. That method arrives at external costs of electricity from lignite at 10.75 Eurocent/kWh, from hard coal 8.94 Eurocent/kWh, from natural gas 4.91 Eurocent/kWh, from photovoltaic 1.18 Eurocent/kWh, from wind 0.26 Eurocent/kWh and from hydro 0.18 Eurocent/kWh. For nuclear the Federal Environment Agency indicates no value, as different studies have results that vary by a factor of 1,000. It recommends the nuclear given the huge uncertainty, with the cost of the next inferior energy source to evaluate. Based on this recommendation the Federal Environment Agency, and with their own method, the Forum Ecological-social market economy, arrive at external environmental costs of nuclear energy at 10.7 to 34 ct/kWh.
Calculations often do not include wider system costs associated with each type of plant, such as long-distance transmission connections to grids, or balancing and reserve costs. Calculations do not include externalities such as health damage by coal plants, nor the effect of CO2 emissions on the climate change, ocean acidification and eutrophication, ocean current shifts. Decommissioning costs of power plants are usually not included (nuclear power plants in the United States is an exception, because the cost of decommissioning is included in the price of electricity per the Nuclear Waste Policy Act), is therefore not full cost accounting. These types of items can be explicitly added as necessary depending on the purpose of the calculation. It has little relation to actual price of power, but assists policy makers and others to guide discussions and decision making.
These are not minor factors but very significantly affect all responsible power decisions:
|Hydro||Geothermal||Coal||Gas CC||Gas peaker||Storage (1:4)|
|NEA 2020 (at 7% discount rate)||56||126||50||88||100||68||32||72||99||88||71||-||-|
|NEA 2018 (at 3% discount rate)||100||160||60||135||-||55||-||-||-||90||100||-||-|
|IPCC 2018 (at 5% discount rate)||110||150||59||120||60||65||-||22||60||61||71||-||-|
In March 2021, Bloomberg New Energy Finance found that "renewables are the cheapest power option for 71% of global GDP and 85% of global power generation. It is now cheaper to build a new solar or wind farm to meet rising electricity demand or replace a retiring generator, than it is to build a new fossil fuel-fired power plant. ... On a cost basis, wind and solar is the best economic choice in markets where firm generation resources exist and demand is growing." They further reported "the levelized cost of energy from lithium-ion battery storage systems is competitive with many peak-demand generators." BNEF did not disclose the detailed methodology and LCOE calculation assumptions, apart from declaring it was "derived from selected public sources".
In December 2020 IEA and OECD NEA published a joint Projected Costs of Generating Electricity study which looks at a very broad range of electricity generating technologies based on 243 power plants in 24 countries. The primary finding was that "low-carbon generation is overall becoming increasingly cost competitive" and "new nuclear power will remain the dispatchable low-carbon technology with the lowest expected costs in 2025". The report calculated LCOE with assumed 7% discount rate and adjusted for systemic costs of generation. The report also contains a modeling utility that produces LCOE estimates based on user-selected parameters such as discount rate, carbon price, heat price, coal price and gas price. The report's main conclusions:
In October 2020, the investment bank Lazard compared renewable and conventional sources of energy, including comparison between existing and new generation (see table). Lazard study assumes "60% debt at 8% interest rate and 40% equity at 12% cost" for its LCOE calculation.
The International Renewable Energy Agency (IRENA) released a study of 2019 renewable power generation costs based states that "new solar and wind projects are undercutting the cheapest of existing coal-fired plants". No data for non-renewable sources is presented in the report. IRENA study assumes 7.5% cost of capital in OECD countries and 10% in China for the LCOE calculations.
|Source||Solar||Wind onshore||Gas CC||Wind plus storage||Solar plus storage||Storage (4hr)||Gas peaker|
The International Energy Agency and EDF have estimated for 2011 the following costs. For nuclear power, they include the costs due to new safety investments to upgrade the French nuclear plant after the Fukushima Daiichi nuclear disaster; the cost for those investments is estimated at 4 €/MWh. Concerning solar power, the estimate of 293 €/MWh is for a large plant capable of producing in the range of 50–100 GWh/year located in a favorable location (such as in Southern Europe). For a small household plant that can produce around 3 MWh/year, the cost is between 400 and 700 €/MWh, depending on location. Solar power was by far the most expensive renewable source of electricity among the technologies studied, although increasing efficiency and longer lifespan of photovoltaic panels together with reduced production costs have made this source of energy more competitive since 2011. By 2017, the cost of photovoltaic solar power had decreased to less than 50 €/MWh.
|Technology||Cost in 2011||Cost in 2017|
|Nuclear (with state-covered insurance costs)||50||50|
|Natural gas turbines without CO2 capture||61|
In November 2013, the Fraunhofer Institute for Solar Energy Systems ISE assessed the levelised generation costs for newly built power plants in the German electricity sector. PV systems reached LCOE between 0.078 and 0.142 Euro/kWh in the third quarter of 2013, depending on the type of power plant (ground-mounted utility-scale or small rooftop solar PV) and average German insolation of 1000 to 1200 kWh/m2 per year (GHI). There are no LCOE-figures available for electricity generated by recently built German nuclear power plants as none have been constructed since the late 1980s. An update of the ISE study was published in March 2018.
|ISE (2013)||ISE (2018)|
|Technology||Low cost||High cost||Low cost||High cost|
|Coal-fired power plants||brown coal||38||53||46||80|
|CCGT power plants||75||98||78||100|
|Wind power||Onshore wind farms||45||107||40||82|
|Offshore wind farms||119||194||75||138|
|Biogas power plant||135||250||101||147|
|Source: Fraunhofer ISE (2013) – Levelized cost of electricity renewable energy technologies|
Source: Fraunhofer ISE (2018) – Stromgestehungskosten erneuerbare Energien
The capital investment costs, fixed and variable costs, and the average capacity factor of utility-scale wind and photovoltaic electricity supplies from 2000 to 2018 have been obtained using overall variable renewable electricity production of the countries in the Middle East and 81 examined projects.
|Year||Wind CF||Photovoltaic CF||Wind LCOE ($/MWh)||Photovoltaic LCOE($/MWh)|
As of March 2021[update] for projects starting generating electricity in Turkey from renewable energy in Turkey in July feed-in-tariffs in lira per kWh are: wind and solar 0.32, hydro 0.4, geothermal 0.54, and various rates for different types of biomass: for all these there is also a bonus of 0.08 per kWh if local components are used. Tariffs will apply for 10 years and the local bonus for 5 years. Rates are determined by the presidency, and the scheme replaces the previous USD-denominated feed-in-tariffs for renewable energy.
A 2010 study by the Japanese government (pre-Fukushima disaster), called the Energy White Paper, concluded the cost for kilowatt hour was ¥49 for solar, ¥10 to ¥14 for wind, and ¥5 or ¥6 for nuclear power.
Masayoshi Son, an advocate for renewable energy, however, has pointed out that the government estimates for nuclear power did not include the costs for reprocessing the fuel or disaster insurance liability. Son estimated that if these costs were included, the cost of nuclear power was about the same as wind power.
More recently, the cost of solar in Japan has decreased to between ¥13.1/kWh to ¥21.3/kWh (on average, ¥15.3/kWh, or $0.142/kWh).
The Institution of Engineers and Shipbuilders in Scotland commissioned a former Director of Operations of the British National Grid, Colin Gibson, to produce a report on generation levelised costs that for the first time would include some of the transmission costs as well as the generation costs. This was published in December 2011. The institution seeks to encourage debate of the issue, and has taken the unusual step among compilers of such studies of publishing a spreadsheet.
On 27 February 2015 Vattenfall Vindkraft AS agreed to build the Horns Rev 3 offshore wind farm at a price of 10.31 Eurocent per kWh. This has been quoted as below £100 per MWh.
In 2013 in the United Kingdom for a new-to-build nuclear power plant (Hinkley Point C: completion 2023), a feed-in tariff of £92.50/MWh (around US$142/MWh) plus compensation for inflation with a running time of 35 years was agreed.
The Department for Business, Energy and Industrial Strategy (BEIS) publishes regular estimates of the costs of different electricity generation sources, following on the estimates of the merged Department of Energy and Climate Change (DECC). Levelized cost estimates for new generation projects begun in 2015 are listed in the table below.
|Power generating technology||Low||Central||High|
|Solar Large-scale PV (Photovoltaic)||71||80||94|
|Nuclear PWR (Pressurized Water Reactor)(a)||82||93||121|
|Natural Gas||Combined Cycle Gas Turbine||65||66||68|
|CCGT with CCS (Carbon capture and storage)||102||110||123|
|Open-Cycle Gas Turbine||157||162||170|
|Coal||Advanced Supercritical Coal with Oxy-comb. CCS||124||134||153|
|IGCC (Integrated Gasification Combined Cycle) with CCS||137||148||171|
|(a) new nuclear power: guaranteed strike price of £92.50/MWh for Hinkley Point C in 2023|
Since 2010, the US Energy Information Administration (EIA) has published the Annual Energy Outlook (AEO), with yearly LCOE projections for future utility-scale facilities to be commissioned in about five years' time. In 2015, EIA has been criticized by the Advanced Energy Economy (AEE) Institute after its release of the AEO 2015-report to "consistently underestimate the growth rate of renewable energy, leading to 'misperceptions' about the performance of these resources in the marketplace". AEE points out that the average power purchase agreement (PPA) for wind power was already at $24/MWh in 2013. Likewise, PPA for utility-scale solar PV are seen at current levels of $50–$75/MWh. These figures contrast strongly with EIA's estimated LCOE of $125/MWh (or $114/MWh including subsidies) for solar PV in 2020.
The following data are from the Energy Information Administration's (EIA) Annual Energy Outlook released in 2020 (AEO2020). They are in dollars per megawatt-hour (2019 USD/MWh). These figures are estimates for plants going into service in 2025, exclusive of tax credits, subsidies, or other incentives. The LCOE below is calculated based on a 30-year recovery period using a real after tax weighted average cost of capital (WACC) of 6.1%. For carbon intensive technologies 3 percentage points are added to the WACC. (This is approximately equivalent to a fee of $15 per metric ton of carbon dioxide CO2.) Federal tax credits and various state and local incentive programs would be expected to reduce some of these LCOE values. For example, EIA expects the federal investment tax credit program to reduce the capacity weighted average LCOE of solar PV built in 2025 by an additional $2.41, to $30.39.
|Solar photovoltaic (PV)||29.75||35.74||32.80||48.09|
The electricity sources which had the most decrease in estimated costs over the period 2010 to 2019 were solar photovoltaic (down 88%), onshore wind (down 71%) and advanced natural gas combined cycle (down 49%).
For utility-scale generation put into service in 2040, the EIA estimated in 2015 that there would be further reductions in the constant-dollar cost of concentrated solar power (CSP) (down 18%), solar photovoltaic (down 15%), offshore wind (down 11%), and advanced nuclear (down 7%). The cost of onshore wind was expected to rise slightly (up 2%) by 2040, while natural gas combined cycle electricity was expected to increase 9% to 10% over the period.
|Estimate in $/MWh||Coal
|Nat. gas combined cycle||Nuclear
|of year||ref||for year||convent'l||advanced||onshore||offshore||PV||CSP|
|Nominal change 2010–2020||NB||−56%||−54%||NB||−77%||-40%||−92%||NB|
|Note: Projected LCOE are adjusted for inflation and calculated on constant dollars based on two years prior to the release year of the estimate.|
Estimates given without any subsidies. Transmission cost for non-dispatchable sources are on average much higher.
NB = "Not built" (No capacity additions are expected.)
OpenEI, sponsored jointly by the US DOE and the National Renewable Energy Laboratory (NREL), has compiled a historical cost-of-generation database covering a wide variety of generation sources. Because the data is open source it may be subject to frequent revision.
|Plant type (USD/MWh)||Min||Median||Max||Data source year|
|Wind||Onshore (land based)||40||80||2014|
|Natural gas||Combined cycle||50||80||2014|
Only median value = only one data point.
Only max + min value = only two data points
LCOE data from the California Energy Commission report titled "Estimated Cost of New Renewable and Fossil Generation in California". The model data was calculated for all three classes of developers: merchant, investor-owned utility (IOU), and publicly owned utility (POU).
|Type||Year 2013 (nominal $$) ($/MWh)||Year 2024 (nominal $$) ($/MWh)|
|Generation turbine 49.9 MW||662.81||2215.54||311.27||884.24||2895.90||428.20|
|Generation turbine 100 MW||660.52||2202.75||309.78||881.62||2880.53||426.48|
|Generation turbine – Advanced 200 MW||403.83||1266.91||215.53||533.17||1615.68||299.06|
|Combined-cycle 2CTs no duct firing 500 MW||116.51||104.54||102.32||167.46||151.88||150.07|
|Combined-cycle 2CTs with duct firing 500 MW||115.81||104.05||102.04||166.97||151.54||149.88|
|Biomass fluidized bed boiler 50 MW||122.04||141.53||123.51||153.89||178.06||156.23|
|Geothermal binary 30 MW||90.63||120.21||84.98||109.68||145.31||103.00|
|Geothermal flash 30 MW||112.48||146.72||109.47||144.03||185.85||142.43|
|Solar parabolic trough without storage 250 MW||168.18||228.73||167.93||156.10||209.72||156.69|
|Solar parabolic trough with storage 250 MW||127.40||189.12||134.81||116.90||171.34||123.92|
|Solar power tower without storage 100 MW||152.58||210.04||151.53||133.63||184.24||132.69|
|Solar power tower with storage 100 MW 6HR||145.52||217.79||153.81||132.78||196.47||140.58|
|Solar power tower with storage 100 MW 11HR||114.06||171.72||120.45||103.56||154.26||109.55|
|Solar photovoltaic (thin-film) 100 MW||111.07||170.00||121.30||81.07||119.10||88.91|
|Solar photovoltaic (single-axis) 100 MW||109.00||165.22||116.57||98.49||146.20||105.56|
|Solar photovoltaic (thin-film) 20 MW||121.31||186.51||132.42||93.11||138.54||101.99|
|Solar photovoltaic (single-axis) 20 MW||117.74||179.16||125.86||108.81||162.68||116.56|
|Wind class 3 100 MW||85.12||104.74||75.8||75.01||91.90||68.17|
|Wind class 4 100 MW||84.31||103.99||75.29||75.77||92.88||68.83|
|Tech Type||Method type to Calculate LCOE||Min (2018 $/Mwh)||Median||Max (2018 $/Mwh)|
|Solar PV Single Axis 100MW||Deterministic||33||49||106|
|Solar PV Single Axis 100MW||Probabilistic||44||52||61|
|Solar Tower with Storage||Deterministic||81||159||339|
|Solar Tower with Storage||Probabilistic||128||158||195|
|Wind 80m hub Hight||Deterministic||30||57||136|
|Wind 80m hub Hight||Probabilistic||52||65||81|
|Combined Cycle no duct firing||Deterministic||77||119||187|
|Combined Cycle no duct firing||Probabilistic||111||123||141|
In November 2015, the investment bank Lazard headquartered in New York, published its ninth annual study on the current electricity production costs of photovoltaics in the US compared to conventional power generators. The best large-scale photovoltaic power plants can produce electricity at US$50 per MWh. The upper limit at US$60 per MWh. In comparison, coal-fired plants are between US$65 and $150 per MWh, nuclear power at US$97 per MWh. Small photovoltaic power plants on roofs of houses are still at 184–300 USD per MWh, but which can do without electricity transport costs. Onshore wind turbines are 32–77 USD per MWh. One drawback is the intermittency of solar and wind power. The study suggests a solution in batteries as a storage, but these are still expensive so far.
Lazard's long standing Levelized Cost of Energy (LCOE) report is widely considered and industry benchmark. In 2015 Lazard published its inaugural Levelized Cost of Storage (LCOS) report, which was developed by the investment bank Lazard in collaboration with the energy consulting firm, Enovation.
Below is the complete list of LCOEs by source from the investment bank Lazard.
|Plant type (USD/MWh)||Low||High|
|Solar PV – thin-film utility-scale||50||60|
|Solar PV – crystalline utility-scale||58||70|
|Solar PV – rooftop residential||184||300|
|Solar PV – rooftop C&I||109||193|
|Solar thermal with storage||119||181|
|Natural gas reciprocating engine||68||101|
|Gas combined cycle||52||78|
|Diesel reciprocating engine||212||281|
NOTE: ** Battery storage is no longer included in this report (2015). It has been rolled into its own separate report LCOS 1.0, developed in consultation with Enovation Partners (see charts below).
Below are the LCOSs for different battery technologies. This category has traditionally been filled by diesel engines. These are "behind the meter" applications.
|Purpose||Type||Low ($/MWh)||High ($/MWh)|
|Commercial and industrial||Flow battery||349||1083|
|Commercial and industrial||Lead-acid||529||1511|
|Commercial and industrial||Lithium-ion||351||838|
|Commercial and industrial||Sodium||444||1092|
|Commercial and industrial||Zinc||310||452|
|Commercial appliance||Flow battery||974||1504|
|All of the above
|Diesel reciprocating engine||212||281|
Below are the LCOSs for different battery technologies. This category has traditionally been filled by natural-gas engines. These are "in front of the meter" applications.
|Purpose||Type||Low ($/MWh)||High ($/MWh)|
|Transmission system||Compressed air||192||192|
|Transmission system||Flow battery||290||892|
|Transmission system||Pumped hydro||188||274|
|Peaker replacement||Flow battery||248||927|
|Distribution services||Flow battery||288||923|
|PV integration||Flow battery||373||950|
|All of the above
|Type||Low ($/MWh)||High ($/MWh)|
|Solar PV – crystalline utility-scale||49||61|
|Solar PV – thin-film utility-scale||46||56|
|Solar PV – community||78||135|
|Solar PV – rooftop residential||138||222|
|Solar PV – rooftop C&I||88||193|
|Solar thermal tower with storage||119||182|
|Natural gas reciprocating engine||68||101|
|Gas combined cycle||48||78|
|Diesel reciprocating engine||212||281|
|Generation type||Low ($/MWh)||High ($/MWh)|
|Solar PV – crystalline utility-scale||46||53|
|Solar PV – thin-film utility-scale||43||48|
|Solar PV – community||76||150|
|Solar PV – rooftop residential||187||319|
|Solar PV – rooftop C&I||85||194|
|Solar thermal tower with storage||98||181|
|Natural gas reciprocating engine||68||106|
|Gas combined cycle||42||78|
|Diesel reciprocating engine||197||281|
Below are the unsubsidized LCOSs for different battery technologies for "behind the meter" (BTM) applications.
|Use case||Storage type||Low ($/MWh)||High ($/MWh)|
Below are the unsubsidized LCOSs for different battery technologies "front of the meter" (FTM) applications.
|Use case||Storage type||Low ($/MWh)||High ($/MWh)|
|Peaker replacement||Flow battery (V)||209||413|
|Peaker replacement||Flow battery (Zn)||286||315|
|Distribution||Flow battery (V)||184||338|
|Microgrid||Flow battery (V)||273||406|
Note: Flow battery value range estimates
|Tech Type||Min ($/MWh)||Max ($/MWh)|
|Solar PV—Roof top Residential||160||267|
|Solar PV—Roof top C&I||81||170|
|Solar PV—Crystalline Utility Scale||40||46|
|Solar PV—Thin Film Utility Scale||36||44|
|Solar Thermal Tower with Storage||98||181|
|Wind – Onshore||29||56|
|Wind – Offshore *(Only midpoint)||92||92|
|Gas Combined Cycle||41||74|
|Tech Type||Min ($/MWh)||Max ($/MWh)|
|Solar PV—Roof top Residential||151||242|
|Solar PV—Roof top C&I||75||154|
|Solar PV—Crystalline Utility Scale||36||44|
|Solar PV—Thin Film Utility Scale||32||42|
|Solar Thermal Tower with Storage||126||156|
|Wind – Onshore||28||54|
|Wind – Offshore (Only Midpoint cost)||89||89|
|Gas Combined Cycle||44||68|
In 2020, IEA declared that solar PV power is the cheapest electricity in history.
Photovoltaic prices have fallen from $76.67 per watt in 1977 to nearly $0.085 per watt in October 2020, for multi crystalline silicon solar cells and module price to $0.193 per watt. This is seen as evidence supporting Swanson's law, which states that solar cell prices fall 20% for every doubling of cumulative shipments. The famous Moore's law calls for a doubling of transistor count every two years.
By 2011, the price of PV modules per MW had fallen by 60% since 2008, according to Bloomberg New Energy Finance estimates, putting solar power for the first time on a competitive footing with the retail price of electricity in some sunny countries; an alternative and consistent price decline figure of 75% from 2007 to 2012 has also been published, though it is unclear whether these figures are specific to the United States or generally global. The levelised cost of electricity (LCOE) from PV is competitive with conventional electricity sources in an expanding list of geographic regions, particularly when the time of generation is included, as electricity is worth more during the day than at night. There has been fierce competition in the supply chain, and further improvements in the levelised cost of energy for solar lie ahead, posing a growing threat to the dominance of fossil fuel generation sources in the next few years. As time progresses, renewable energy technologies generally get cheaper, while fossil fuels generally get more expensive:
The less solar power costs, the more favorably it compares to conventional power, and the more attractive it becomes to utilities and energy users around the globe. Utility-scale solar power [could in 2011] be delivered in California at prices well below $100/MWh ($0.10/kWh) less than most other peak generators, even those running on low-cost natural gas. Lower solar module costs also stimulate demand from consumer markets where the cost of solar compares very favourably to retail electric rates.
In the year 2015, First Solar agreed to supply solar power at 3.87 cents/kWh levelised price from its 100 MW Playa Solar 2 project which is far cheaper than the electricity sale price from conventional electricity generation plants. From January 2015 through May 2016, records have continued to fall quickly, and solar electricity prices, which have reached levels below 3 cents/kWh, continue to fall. In August 2016, Chile announced a new record low contract price to provide solar power for $29.10 per megawatt-hour (MWh). In September 2016, Abu Dhabi announced a new record breaking bid price, promising to provide solar power for $24.2 per MWh In October 2017, Saudi Arabia announced a further low contract price to provide solar power for $17.90 per MWh. In July 2019, Portugal announced a lowest contract price of $16.54 per MWh. In April 2020, Abu Dhabi Power Corporation (ADPower) secured $13.5 per MWh tariff for its 2GW solar PV project.
With a carbon price of $50/ton (which would raise the price of coal-fired power by 5c/kWh), solar PV is cost-competitive in most locations. The declining price of PV has been reflected in rapidly growing installations, totaling a worldwide cumulative capacity of 297 GW by end 2016. According to some estimates total investment in renewables for 2011 exceeded investment in carbon-based electricity generation.
In the case of self consumption, payback time is calculated based on how much electricity is not brought from the grid. Additionally, using PV solar power to charge DC batteries, as used in Plug-in Hybrid Electric Vehicles and Electric Vehicles, leads to greater efficiencies, but higher costs. Traditionally, DC generated electricity from solar PV must be converted to AC for buildings, at an average 10% loss during the conversion. Inverter technology is rapidly improving and current equipment has reached 99% efficiency for small scale residential, while commercial scale three-phase equipment can reach well above 98% efficiency. However, an additional efficiency loss occurs in the transition back to DC for battery driven devices and vehicles, and using various interest rates and energy price changes were calculated to find present values that range from $2,060 to $8,210[needs update] (analysis from 2009, based on a panel price of $9 per watt, about 90 times the October 2019 price listed above).
It is also possible to combine solar PV with other technologies to make hybrid systems, which enable more stand alone systems. The calculation of LCOEs becomes more complex, but can be done by aggregating the costs and the energy produced by each component. As for example, PV and cogen and batteries while reducing energy- and electricity-related greenhouse gas emissions as compared to conventional sources. In May 2020, the discovered first year tariff in India is ₹2.90 (3.9¢ US) per KWh with ₹3.60 (4.8¢ US) per KWh levelized tariff for round the clock power supply from hybrid renewable power plants with energy storage. The tariff is cheaper than new coal, natural gas, nuclear, etc. power plants for base load application.
LCOE of solar thermal power with energy storage which can operate round the clock on demand, has fallen to AU$78/MWh (US$61/MWh) in August 2017. Though solar thermal plants with energy storage can work as stand alone systems, combination with solar PV power can deliver further cheaper power. Cheaper and dispatchable solar thermal storage power need not depend on costly or polluting coal/gas/oil/nuclear based power generation for ensuring stable grid operation.
When a solar thermal storage plant is forced to idle due to lack of sunlight locally during cloudy days, it is possible to consume the cheap excess infirm power from solar PV, wind and hydro power plants (similar to a lesser efficient, huge capacity and low cost battery storage system) by heating the hot molten salt to higher temperature for converting the stored thermal energy in to electricity during the peak demand hours when the electricity sale price is profitable. Biomass fuel firing can also be incorporated in solar thermal plants economically to enhance their dispatchable generation capability.
In 2020, solar thermal heat prices (US cents/kWh-thermal) at 600 °C above temperature with round the clock availability has fallen below 2 cents/kwh-thermal which is cheaper than heat energy derived from fossil fuels.
This cost has additionally reduced as wind turbine technology has improved. There are now longer and lighter wind turbine blades, improvements in turbine performance and increased power generation efficiency. Also, wind project capital and maintenance costs have continued to decline.
In the windy great plains expanse of the central United States new-construction wind power costs in 2017 are compellingly below costs of continued use of existing coal burning plants. Wind power can be contracted via a power purchase agreement at two cents per kilowatt hour while the operating costs for power generation in existing coal-burning plants remain above three cents.
In 2016 the Norwegian Wind Energy Association (NORWEA) estimated the LCoE of a typical Norwegian wind farm at 44 €/MWh, assuming a weighted average cost of capital of 8% and an annual 3,500 full load hours, i.e. a capacity factor of 40%. NORWEA went on to estimate the LCoE of the 1 GW Fosen Vind onshore wind farm which is expected to be operational by 2020 to be as low as 35 €/MWh to 40 €/MWh. In November 2016, Vattenfall won a tender to develop the Kriegers Flak windpark in the Baltic Sea for 49.9 €/MWh, and similar levels were agreed for the Borssele offshore wind farms. As of 2016, this is the lowest projected price for electricity produced using offshore wind.
MSRs have large negative temperature and void coefficients of reactivity, and are designed to shut down due to expansion of the fuel salt as temperature increases beyond design limits. . . . The MSR thus has a significant load-following capability where reduced heat abstraction through the boiler tubes leads to increased coolant temperature, or greater heat removal reduces coolant temperature and increases reactivity.
Desirable shifts in how we as a nation and as individual consumers—whether a residential home or commercial real estate property—manage, produce, and consume electricity can actually make LCOE numbers look worse, not better. This is particularly true when considering the influence of energy efficiency...If you’re planning a new, big central power plant, you want to get the best value (i.e., lowest LCOE) possible. For the cost of any given power-generating asset, that comes through maximizing the number of kWh it cranks out over its economic lifetime, which runs exactly counter to the highly cost-effective energy efficiency that has been a driving force behind the country’s flat and even declining electricity demand. On the flip side, planning new big, central power plants without taking continued energy efficiency gains (of which there’s no shortage of opportunity—the February 2014 UNEP Finance Initiative report Commercial Real Estate: Unlocking the energy efficiency retrofit investment opportunity identified a $231–$300 billion annual market by 2020) into account risks overestimating the number of kWh we’d need from them and thus lowballing their LCOE... If I’m a homeowner or business considering purchasing rooftop solar outright, do I care more about the per-unit value (LCOE) or my total out of pocket (lifetime system cost)?...The per-unit value is less important than the thing considered as a whole...LCOE, for example, fails to take into account the time of day during which an asset can produce power, where it can be installed on the grid, and its carbon intensity, among many other variables. That’s why, in addition to [levelized avoided cost of energy (LACE)], utilities and other electricity system stakeholders...have used benefit/cost calculations and/or an asset’s capacity value or contribution to peak on a system or circuit level.