Cost of electricity by source

The cost of electricity generated by different sources is a calculation of the cost of generating electricity at the point of connection to a load or electricity grid. It includes the initial capital, return on investment, as well as the costs of continuous operation, fuel, and maintenance. The cost is normally stated in units of local currency per unit of electricity, for example cents-per-kilowatt-hour for small numbers, or dollars-per-megawatt-hour for larger quantities.

Missing costs factors

Extraction, emissions, transmission, health

This is not full cost accounting: the calculation does not include wider system costs associated with each type of plant, such as long distance transmission connections to grids, balancing and reserve costs, and does not include externalities such as health damage by coal plants, nor the effect of CO2 emissions on the whole biosphere (climate change, ocean acidification and eutrophication, ocean current shifts), nor decommissioning costs of nuclear plant These type of items can be explicitly added if necessary. In North America, where explicit charges for these externalities are rare (except for BC and Quebec carbon tax) it has little relation to actual price of power, but assists policy makers and others to guide discussions and decision making.

Timing (peak vs. off-peak)

Critically, the timing of the electricity market itself is also not considered. The time when the power is generated, and its match to the load or ability to be matched to the load, is the single biggest factor in wholesale pricing. Private market wholesale power rates can vary by as much as one hundred times depending on when the power is required versus when it is consumed. For instance, peak wholesale rates for emergency load balancing during summer air conditioning peaks in the US Northeast often exceed $1.00/KwH. However, large baseload sources such as nuclear fission plants or large hydroelectric dams, which cannot be throttled down easily without creating maintenance and safety problems, often have power to literally give away or sell for nominal rates (under $0.01/KwH) in the middle of the night - a major factor that drove factories to 24x7 three-shift operations to take advantage of very low off-peak rates throughout the 20th century. The more stable public wholesale market reflects the predictable variance in demand (and thus price) during the day for instance in Ontario but is highly regulated so the price variance is typically between .02c-0.05c most of the year. This still represents a daily price variance that radically exceeds that of any other commodity. This phenomema and the way timing of the generation and use of power affects markets hsa been widely studied [1] and is still the subject of much original research [2] and not easy to summarize for the layperson.

However, the less predictable intermittent sources such as solar and wind, which require significant monitoring (see smart grid) and demand response to deploy efficiently, suffer a disadvantage given the lack of efficient large-scale energy storage options compared to those that burn fuels on demand. Some part of the costs of deploying a more flexible distribution system should reasonably be assumed in the costs of deploying larger scale solar and wind.

Cost factors

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):

• Capital costs (including waste disposal and decommissioning costs for nuclear energy) - tend to be low for fossil fuel power stations; high for wind turbines, solar PV and nuclear; very high for waste to energy, wave and tidal, solar thermal.
• Fuel costs - high for fossil fuel and biomass sources, very low for nuclear and renewables.
• Factors such as the costs of waste (and associated issues) and different insurance costs are not included in the following: Works power, own use or parasitic load - i.e. the portion of generated power actually used to run the stations pumps and fans has to be allowed for.

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 here. and here.

Operational costs of wind power are rarely covered on the net. On the 10th of June 2011, DECC published a report, ‘Review of the generation costs and deployment potential of renewable electricity technologies in the UK, available at . This study into the projected costs of renewable development, up to 2030, provides baseline data to inform support levels for a range of technologies over the coming years. In section 3.8.3 of DECC's report, wind operating costs are identified. Large-scale onshore wind projects median (central) operational costs are cited at £57,000/MW/year which for an annual average load factor of 0.23 (the British onshore wind fleet load factor in 2011 according to DUKES, the average with offshore being 25%), works out at £28.29p/MWh. These operational costs do not include capital cost recovery or interest on debt – they are operational costs.

Table 9 of the report shows the projected future path of these operating costs. They are shown increasing slightly to £60,000/MW/year by 2030 (a very slow rate of increase). The preceding text explains that that slow rate of increase is due to slight parts and labour increases. There is some other text explaining that operating costs seem to increase quite fast after a wind farm is five years old (because the model becomes dated and you are single-sourcing major component replacements).

For offshore wind farms of >100 MW (Round 3), table 17 indicates £168,700 per MW per year operational costs for offshore wind. Assuming an excellent 50% load factor for Round 3 offshore wind, that would amount to just £38.51/MWh operational costs for offshore (median round 3 figure 2010 basis, in table 17 in DECC’s report). These operational costs do not include capital cost recovery or interest on debt – they are operational costs.

Another collection of cost calculations is shown here:, here, and, and.

Another collection of cost calculations was made in December 2011 by the Institution of Engineers and Shipbuilders in Scotland, which commissioned a former Director of Operations of the British National Grid, Colin Gibson, to produce a report on generation levelised costs. This was published in December 2011 and is available on the internet : . The institution seeks to encourage debate of the issue, and has taken the unusual step among compilers of such studies of publishing a spreadsheet showing its data available on the internet :

Calculations

Levelised energy cost (LEC, also commonly abbreviated as LCOE ) is the price at which electricity must be generated from a specific source to break even. It is an economic assessment of the cost of the energy-generating system including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, cost of capital, and is very useful in calculating the costs of generation from different sources.

It can be defined in a single formula as:

$\mathrm {LEC} ={\frac {\sum _{t=1}^{n}{\frac {I_{t}+M_{t}+F_{t}}{\left({1+r}\right)^{t}}}}{\sum _{t=1}^{n}{\frac {E_{t}}{\left({1+r}\right)^{t}}}}}$

where

• $\mathrm {LEC}$ = Average lifetime levelised electricity generation cost
• $I_{t}$ = Investment expenditures in the year t
• $M_{t}$ = Operations and maintenance expenditures in the year t
• $F_{t}$ = Fuel expenditures in the year t
• $E_{t}$ = Electricity generation in the year t
• $r$ = Discount rate
• $n$ = Life of the system

Typically LECs are calculated over 20 to 40 year lifetimes, and are given in the units of currency per kilowatt-hour, for example AUD/kWh or EUR/kWh or per megawatt-hour, for example AUD/MWh (as tabulated below). 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. Thus, a key requirement for the analysis is a clear statement of the applicability of the analysis based on justified assumptions. See a recent review on the subject stating reporting requirements and clearing up misconceptions about inputs : A Review of Solar Photovoltaic Levelized Cost of Electricity, Renewable and Sustainable Energy Reviews, 15, pp.4470-4482 (2011)

System boundaries

When comparing LECs for alternative systems, it is very important to define the boundaries of the 'system' and the costs that are included in it. For example, should transmissions lines and distribution systems be included in the cost? Typically only the costs of connecting the generating source into the transmission system is included as a cost of the generator. But in some cases wholesale upgrade of the Grid is needed. Careful thought has to be given to whether or not these costs should be included in the cost of power.

Should R&D, tax, and environmental impact studies be included? Should the costs of impacts on public health and environmental damage be included? Should the costs of government subsidies be included in the calculated LEC?

Discount rate

Another key issue is the decision about the value of the discount rate $r$. The value that is chosen for $r$ can often 'weigh' the decision towards one option or another, so the basis for choosing the discount must clearly be carefully evaluated. See internal rate of return. The discount rate depends on the cost of capital, including the balance between debt-financing and equity-financing, and an assessment of the financial risk.

US Department of Energy estimates

The tables below list the estimated cost of electricity by source for plants entering service in 2016. The tables are from a December 16, 2010 report of the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE) called "Levelized Cost of New Generation Resources in the Annual Energy Outlook 2011".

• Total System Levelized Cost (the rightmost column) gives the dollar cost per megawatt-hour that must be charged over time in order to pay for the total cost. Divide by 1000 to get the cost per kilowatt-hour (move the decimal point 3 places to the left).

These calculations reflect an adjustment to account for the high level of carbon dioxide produced by coal plants. From the EIA report:

"a 3-percentage point increase in the cost of capital is added when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). While the 3-percentage point adjustment is somewhat arbitrary, in levelized cost terms its impact is similar to that of a $15 per metric ton of carbon dioxide (CO2) emissions fee. ... As a result, the levelized capital costs of coal-fired plants without CCS are higher than would otherwise be expected."

No tax credits or incentives are incorporated in the tables. From the EIA report (emphasis added):

"Levelized cost represents the present value of the total cost of building and operating a generating plant over an assumed financial life and duty cycle, converted to equal annual payments and expressed in terms of real dollars to remove the impact of inflation. Levelized cost reflects overnight capital cost, fuel cost, fixed and variable O&M cost, financing costs, and an assumed utilization rate for each plant type. The availability of various incentives including state or federal tax credits can also impact the calculation of levelized cost. The values shown in the tables below do not incorporate any such incentives."

Incentives, tax credits, production mandates, etc. are discussed in the overall comprehensive EIA report: "Annual Energy Outlook 2011".

Estimated Levelized Cost of New Generation Resources, 2016

Plant Type	Capacity Factor (%)	U.S. Average Levelized Cost for Plants Entering Service in 2016 (2009 USD/MWh)
		Levelized Capital Cost	Fixed O&M	Variable O&M (including fuel)	Transmission Investment	Total System Levelized Cost
Conventional Coal	85	65.3	3.9	24.3	1.2	94.8
Advanced Coal	85	74.6	7.9	25.7	1.2	109.4
Advanced Coal with CCS	85	92.7	9.2	33.1	1.2	136.2
Natural Gas Fired
Conventional Combined Cycle	87	17.5	1.9	45.6	1.2	66.1
Advanced Combined Cycle	87	17.9	1.9	42.1	1.2	63.1
Advanced CC with CCS	87	34.6	3.9	49.6	1.2	89.3
Conventional Combustion Turbine	30	45.8	3.7	71.5	3.5	124.5
Advanced Combustion Turbine	30	31.6	5.5	62.9	3.5	103.5
Advanced Nuclear	90	90.1	11.1	11.7	1.0	113.9
Wind	34	83.9	9.6	0.0	3.5	97.0
Wind — Offshore	34	209.3	28.1	0.0	5.9	243.2
Solar PV	25	194.6	12.1	0.0	4.0	210.7
Solar Thermal	18	259.4	46.6	0.0	5.8	311.8
Geothermal	92	79.3	11.9	9.5	1.0	101.7
Biomass	83	55.3	13.7	42.3	1.3	112.5
Hydro	52	74.5	3.8	6.3	1.9	86.4

Regional Variation in Levelized Costs of New Generation Resources, 2016

Plant Type	Range for Total System Levelized Costs (2009 USD/MWh)
	Minimum	Average	Maximum
Conventional Coal	85.5	94.8	110.8
Advanced Coal	100.7	109.4	122.1
Advanced Coal with CCS	126.3	136.2	154.5
Natural Gas Fired
Conventional Combined Cycle	60.0	66.1	74.1
Advanced Combined Cycle	56.9	63.1	70.5
Advanced CC with CCS	80.8	89.3	104.0
Conventional Combustion Turbine	99.2	124.5	144.2
Advanced Combustion Turbine	87.1	103.5	118.2
Advanced Nuclear	109.7	113.9	121.4
Wind	81.9	97.0	115.0
Wind — Offshore	186.7	243.2	349.0
Solar PV	158.7	210.7	323.9
Solar Thermal	191.7	311.8	641.6
Geothermal	91.8	101.7	115.7
Biomass	99.5	112.5	133.4
Hydro	58.5	86.4	121.4

• O&M = operation and maintenance.
• CC = combined cycle.
• CCS = carbon capture and sequestration.
• PV = photovoltaics.
• GHG = greenhouse gas.

UK 2010 estimates

In March 2010, a new report on UK levelised generation costs was published by Parsons Brinckerhoff. It puts a range on each cost due to various uncertainties. Combined cycle gas turbines without CO2 capture are not directly comparable to the other low carbon emission generation technologies in the PB study. The assumptions used in this study are given in the report.

UK energy costs for different generation technologies in pounds per megawatt hour (2010)

Technology	Cost range (£/MWh)
New nuclear	80–105
Onshore wind	80–110
Biomass	60–120
Natural gas turbines with CO2 capture	60–130
Coal with CO2 capture	100–155
Offshore wind	150–210
Natural gas turbine, no CO2 capture	55–110
Tidal power	155–390

Divide the above figures by 1000 to obtain the price in pence per kilowatt-hour.

More recent UK estimates are the Mott MacDonald study released by DECC in June 2010 and the Arup study for DECC published in 2011.

French 2011 estimates

The International Agency for the Energy and EDF have estimated for 2011 the following costs. For the 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 the solar power the estimate at 293 €/MWh is for a large plant capable to produce in the range of 50-100 GWh/year located in a favorable location (such as in Southern Europe). For a small household plant capable to produce typically around 3 MWh/year the cost is according to the location between 400 and 700 €/MWh. Currently solar power is by far the most expensive renewable source to produce electricity, although increasing efficiency and longer lifespan of photovoltaic pannels together with reduced production costs could make this source of energy more competitive.

French energy costs for different generation technologies in Euros per megawatt hour (2011)

Technology	Cost (€/MWh)
Hydro power	20
Nuclear	50
Natural gas turbines without CO2 capture	61
Onshore wind	69
Solar farms	293

Analysis from different sources

Template:Cost of energy sources

A draft report of LECs used by the California Energy Commission is available. From this report, the price per MWh for a municipal energy source is shown here:

California levelized energy costs for different generation technologies in US dollars per megawatt hour (2007)

Technology	Cost (USD/MWh)
Advanced Nuclear	067  67
Coal	074  74–88
Gas	087  87–346
Geothermal	067  67
Hydro power	048  48–86
Wind power	060  60
Solar	116  116–312
Biomass	047  47–117
Fuel Cell	086  86–111
Wave Power	611  611

Note that the above figures incorporate tax breaks for the various forms of power plants. Subsidies range from 0% (for Coal) to 14% (for nuclear) to over 100% (for solar).

Other sources are given here,

The following table gives a selection of LECs from two major government reports from Australia. Note that these LECs do not include any cost for the greenhouse gas emissions (such as under carbon tax or emissions trading scenarios) associated with the different technologies.

Levelised energy costs for different generation technologies in Australian dollars per megawatt hour (2006)

Technology	Cost (AUD/MWh)
Nuclear (to COTS plan)	040  40–70
Nuclear (to suit site; typical)	040  75–105
Coal	028  28–38
Coal: IGCC + CCS	053  53–98
Coal: supercritical pulverized + CCS	064  64–106
Open-cycle Gas Turbine	101  101
Hot fractured rocks	089  89
Gas: combined cycle	037  37–54
Gas: combined cycle + CCS	053  53–93
Small Hydro power	055  55
Wind power: high capacity factor	055  63
Solar thermal	085  85
Biomass	088  88
Photovoltaics	120  120

In 1997 the Trade Association for Wind Turbines (Wirtschaftsverband Windkraftwerke e.V. –WVW) ordered  a study into the costs of electricity production in newly constructed conventional power plants from the Rheinisch-Westfälischen Institute for Economic Research –RWI). The RWI predicted costs of electricity production per kWh for the basic load for the year 2010 as follows:

Fuel	Cost per kilowatt hour in euro cents.
Nuclear Power	10.7 €ct – 12.4 €ct
Brown Coal (Lignite)	8.8 €ct – 9.7 €ct
Black Coal (Bituminous)	10.4 €ct – 10.7 €ct
Natural gas	11.8 €ct – 10.6 €ct.

The part of a base load represents approx. 64% of the electricity production in total. The costs of electricity production for the mid-load and peak load are considerably higher. There is a mean value for the costs of electricity production for all kinds of conventional electricity production and load profiles in 2010 which is 10.9 €ct to 11.4 €ct per kWh. The RWI calculated this on the assumption that the costs of energy production would depend on the price development of crude oil and that the price of crude oil would be approx. 23 US$ per barrel in 2010. In fact the crude oil price is about 80 US$ in the beginning of 2010. This means that the effective costs of conventional electricity production still need to be higher than estimated by the RWI in the past.

The WVW takes the legislative feed-in-tariff as basis for the costs of electricity production out of renewable energies because renewable power plants are economically feasible under the German law (German Renewable Energy Sources Act-EEG).

The following figures arise for the costs of electricity production in newly constructed power plants in 2010:

Energy source	Costs of electricity production in euros per megawatt hour
Nuclear Energy	107.0 – 124.0
Brown Coal	88.0 –   97.0
Black Coal	104.0 – 107.0
Domestic Gas	106.0 – 118.0
Wind Energy Onshore	49.7 –   96.1
Wind Energy Offshore	35.0 – 150.0
Hydropower	34.7 – 126.7
Biomass	77.1 – 115.5
Solar Electricity	284.3 – 391.4

Other estimates

A 2010 study by the Japanese government, 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.

Beyond the power station terminals, or system costs

The raw costs developed from the above analysis are only part of the picture in planning and costing a large modern power grid. Other considerations are the temporal load profile, i.e. how load varies second to second, minute to minute, hour to hour, month to month. To meet the varying load, generally a mix of plant options is needed, and the overall cost of providing this load is then important. Wind power has poor capacity contribution, so during windless periods, some form of back up must be provided. All other forms of power generation also require back up, though to a lesser extent. To meet peak demand on a system, which only persist for a few hours per year, it is often worth using very cheap to build, but very expensive to operate plant - for example some large grids also use load shedding coupled with diesel generators at peak or extreme conditions - the very high kWh production cost being justified by not having to build other more expensive capacity and a reduction in the otherwise continuous and inefficient use of spinning reserve.

In the case of wind energy, the additional costs in terms of increased back up and grid interconnection to allow for diversity of weather and load may be substantial. This is because wind stops blowing frequently even in large areas at once and for prolonged periods of time. Some wind advocates have argue that in the pan-European case back up costs are quite low, resulting in overall wind energy costs about the same as present day power. However, such claim are generally considered too optimistic, except possibly for some marginal increases that, in particular circumstances, may take advantage of the existing infrastructure.

The cost in the UK of connecting new offshore wind in transmission terms, has been consistently put by Grid/DECC/Ofgem at £15billion by 2020. This £15b cost does not include the cost of any new connections to Europe - interconnectors, or a supergrid, as advocated by some. The £15b cost is the cost of connecting offshore wind farms by cables typically less than 12 km in length, to the UK's nearest suitable onshore connection point. There are total forecast onshore transmission costs of connecting various new UK generators by 2020, as incurred from 2010, of £4.7 billion, by comparison.

When a new plant is being added to a power system or grid, the effects are quite complex - for example, when wind energy is added to a grid, it has a marginal cost associated with production of about £20/MWh (most incurred as lumpy but running-related maintenance - gearbox and bearing failures, for instance, and the cost of associated downtime), and therefore will always offer cheaper power than fossil plant - this will tend to force the marginally most expensive plant off the system. A mid range fossil plant, if added, will only force off those plants that are marginally more expensive. Hence very complex modelling of whose systems is required to determine the likely costs in practice of a range of power generating plant options, or the effect of adding a given plant.

With the development of markets, it is extremely difficult for would-be investors to estimate the likely impacts and cost benefit of an investment in a new plant, hence in free market electricity systems, there tends to be an incipient shortage of capacity, due to the difficulties of investors accurately estimating returns, and the need to second guess what competitors might do.

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 and is available on the internet : . The institution seeks to encourage debate of the issue, and has taken the unusual step among compilers of such studies of publishing a spreadsheet showing its data available on the internet :

Additional nuclear power costs

Main article: Economics of new nuclear power plants

Nuclear power plants built recently, or in the process of being built, have incurred many cost overruns. Those being built now are expected to incur further cost overruns due to design changes after the Fukushima Daiichi nuclear disaster.

Nuclear power has in the past been granted indemnity from the burden of carrying full third party insurance 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.

The limited insurance that is required does not cover the full cost of a major nuclear accident of the kind that occurred at Chernobyl or Fukushima. An April 2011 report by Versicherungsforen Leipzig, a Leipzig company that specializes in actuarial calculations states that full insurance of German power plants against nuclear disasters would increase the price of nuclear electricity by €0.14/kWh ($0.20/kWh) to €2.36/kWh ($3.40/kWh), if the full potential damage sum of 6 trillion Euro is to be paid as insurance fee over a time span of 10 to 100 years.

See also

• Comparisons of life-cycle greenhouse gas emissions
• Distributed generation
• Economics of new nuclear power plants
• Demand response
• Intermittent energy source
• National Grid Reserve Service
• Nuclear power in France
• List of thermal power station failures
• Calculating the cost of the UK Transmission network: cost per kWh of transmission
• List of countries by electricity production from renewable sources
• List of U.S. states by electricity production from renewable sources
• Environmental concerns with electricity generation
• Grid parity

Further reading

• Nuclear Power: Still Not Viable without Subsidies. February 2011. By Doug Koplow. Union of Concerned Scientists.
• How to Calculate the Levelized Cost of Energy – a simplified approach | Energy Technology Expert. Engineer Marcial T. Ocampo.
• Levelized Cost of New Electricity Generating Technologies. Institute for Energy Research.