The Cost of Renewable Power: A Survey of Recent Estimates

Ignacio Mauleón

doi:10.1007/978-3-319-03632-8_10

Green Energy and Efficiency pp 235-268 | Cite as

The Cost of Renewable Power: A Survey of Recent Estimates

Authors
Authors and affiliations

Ignacio MauleónEmail author

Chapter

First Online: 06 November 2014

Part of the Green Energy and Technology book series (GREEN)

Abstract

This paper presents the results of an overview and survey of recent, up-to-date estimates of the cost of generating electric power from renewables. The results are based on actual data from projects already implemented or commissioned, and are organised as homogeneously and comparably as possible. Two main cost measures are considered: total capital costs, and its two main components, equipment, and remaining installation costs, and the Levelised Cost of Electricity (LCOE). An extended discussion on the definition and meaning of this latter cost measure is also provided in an appendix. The chapter closes with some reflections and forecasts of the likely scenario for the power business in the coming years.

Keywords

Renewable power technologies Levelized cost of electricity Capital cost Learning rates Dispatchability

List of Acronyms

BNEF: Bloomberg New Energy Finance
BIPV: Building Integrated Photo Voltaic
BoS: Balance of system cost
CCS: Carbon Capture and Storage
CdTe: Cadmium-Telluride (PV cell)
CHP: Concentrated Heat and Power
CSP: Concentrated Solar Power
c-Si: Crystalline Silicon (PV cell)
DLC: Discounted Lifetime Cost
DLG: Discounted Lifetime Generation
DNI: Direct Normal Irradiance, (kWh/m²/year)
EIA: US Energy Information Administration
EPIA: European Photovoltaic Industry Association
EWEA: European Wind Energy Association
GCCT: Gas Combined Cycle Turbine
GHG: Greenhouse Gasses
IMF: International Monetary Fund
IPCC: Intergovernmental Panel on Climate Change
IRENA: International Renewable Energy Association
kW: MW, kilowatt, Megawatt
kWh: MWh, kilowatt hour, Megawatt hour
LCE: Levelised Cost of Energy (same as LCOE)
LCOE: Levelised Cost of Energy
NREL: National Renewable Energy Laboratory
O&M_t: Operating and Management costs in period t
PTC: Parabolic Trough Collector (also denoted simply as PT)
PV: Photo Voltaic
PwC: Price waterhouse Coopers
REN 21: Renewable Energy Policy Network for the Twentyfirst Century
SLCOE: Total System LCOE
TES: Thermal Electricity Storage
USD: US Dollar
vRES: Variable Renewable Energy Sources
WACC: Weighted Average Cost of Capital
WEC: World Energy Council

JEL codes

Q00 Q20

This is a preview of subscription content, to check access.

Appendix

The Meaning and Calculation of the LCOE Cost Measure

This appendix seeks to shed some light on the advantages, pitfalls, and precise meaning of the electricity cost measure provided by the Levelised Cost of Energy, or LCOE, sometimes also abbreviated to LCE. Standard cost measures are needed that everybody can easily understand so that the relative costs of different technologies and investments can be communicated and assessed. The measure is perfectly valid, once it is established precisely what it means and what it does not mean. There are other accepted, standard measures, most notably the cost of the kW for a given technology, that enable the initial capital investment required in a specific project to be calculated. This is clearly also relevant, since the amount of resources required to finance a project, independently of its expected rate of return, may be a serious hurdle if it is large (e.g. nuclear or large hydroelectric dams).

The LCOE, by contrast, is intended to provide a measure of cost that can be compared with the selling price of electricity for a given project, that is, its competitiveness. This measure is highly dependent on several factors, including the specific country and geographical site, and on the type of technology and sub-technology within the relevant category: it is very different for rooftop FV and large utility-scale ground-mounted installations, for example. The specific country may have an impact on costs of deployment, labour costs, degree of market competition and other factors that are directly linked to the profit margins of suppliers, and so on. Sites affect mostly the capacity factor, i.e. the amount of time within a given period, usually one calendar year, that a plant will be working and producing electricity. For example, the number of effective sun hours for solar energy, and hours of wind for windpower, suitably weighted for ‘intensity’ in both cases (speed in the case of wind and irradiance for solar).

The LCOE can be defined generally as the discounted lifetime cost divided by the discounted lifetime generation. It is therefore expressed as a monetary value for a certain specified amount of energy generated during a specified period (e.g. USD/MWh). It is intended to represent the total life-cycle costs of producing one MWh of power using a specific technology. Another more meaningful way to define the LCOE is as the price of electricity required for a project to yield revenues equal to its costs, including a return on the capital invested, i.e. to break even. A higher electricity price would yield a greater return on capital, while a lower price would yield a lower return on capital, or even a loss, i.e. the value at which one particular investment breaks even or equals the current selling price of electricity. This point is frequently referred to as ‘grid-parity’, or the moment and cost at which the specified technology becomes competitive at a given site, i.e. needs no further financial support from the state or elsewhere. This way of looking at matters enables certain concepts to be discussed, notably the discount rate that should be applied, the possible inflation rate and other forecasts for future trends in the monetary magnitudes that appear in the definition.

The specific expression for calculating the LCOE of an energy investment is given by

$${\text{LCOE}} = \frac{{\sum\nolimits_{t = 1}^{t = n} {\left( {\frac{{I_{t} + {\text{O}} \& {\text{M}}_{t} + F_{t} }}{{\left( {1 + d} \right)^{t} }}} \right)} }}{{\sum\nolimits_{t = 1}^{t = n} {\left( {\frac{{E_{t} }}{{\left( {1 + d} \right)^{t} }}} \right)} }}$$

where

I _t represents the capital cost expenditures in year t
O&M _t is the operating and management costs in year t
F _t is the cost of fuel in year t
E _t is the amount of energy generated in year t
d is the discount rate
n, is the expected lifetime of the investment

The time unit usually taken for renewables is one calendar year, since over that period the natural cycle of resources will usually be repeated, to some extent, but this is arbitrary. The cost of fuel, F_t, is zero for most renewables energies, except in the case of biomass. The capital cost includes all forms of financing that may be involved, possibly including equity. The return on capital applied to each category of financial source may be different, and will include a risk premium. In the case of equity, this premium will usually be higher. The return on capital applied in the calculation of LCOE is usually a Weighted Average Cost of Capital or WACC. The LCOE therefore includes a positive return on equity if any. It can be understood as an opportunity cost, so that the current return on capital in the relevant market and an appropriate risk premium are taken into account. This is the most commonly accepted definition [18, 29, 41], though there may be some minor changes in some cases (the EIA follows a slightly different approach: see [8]).

The concept of LCOE deserves some discussion in order to provide a better understanding of its meaning. It can be written in a compact way as follows:

$${\text{LCOE}} = \frac{\text{DLC}}{\text{DLG}}$$

where the numerator is the discounted lifetime cost (DLC) and the denominator the discounted lifetime generation (DLG). Now rewrite this last expression in the following way:

$${\text{LCOE}} \times {\text{DLG}} - {\text{DLC}} = 0$$

If the LCOE is now replaced by the current selling price of energy, PE, the following is obtained:

$${\text{PE}} \times {\text{DLG}} - {\text{DLC}} \ge 0$$

when the selling price is above the LCOE (PE > LCOE). This implies that the investment will yield a greater return on capital than the ‘normal’ or current market return, and a lower return if it is lower. If the two are equal the ‘excess return’ is zero and the investment breaks even (‘excess’ here means ‘above what is taken as standard in the market’). This point is what is commonly referred to as ‘grid-parity’, a time and amount at which the specific technology considered reaches market competitiveness, and therefore requires no further public (financial) support in any form. It may require other kinds of support, however, in the form of easing administrative barriers, or otherwise.

Another point that has been brought to the discussion recently is the very concept of an electricity price. This may be unfair to technologies with storage capacities, since they can sell electricity at different times, taking advantage of the changing prices of electricity over time (e.g. hydro power with pumped storage and CSP with TES in molten salts). Indeed, this applies to all technologies with intermittent or non constant output, i.e. all renewable technologies to a greater or lesser degree. This point deserves some discussion: consider the present discounted value of all future energy proceeds, DLP for short, generated by a specific investment and given by

$${\text{DLP}} = \sum\limits_{t = 1}^{t = n} {\left( {\frac{{P_{t} \times E_{t} }}{{\left( {1 + d} \right)^{t} }}} \right)}$$

where P _t is the selling price of electricity at a specified future time t (the remaining symbols are defined above in the expression for the LCOE). Now denote D _t = (1/(1 + d)^t). For ease of notation, this expression can be conveniently rearranged as follows:

$$\begin{aligned} {\text{DLP}} & = \sum\limits_{t = 1}^{t = n} {P_{t} \times E_{t} \times D_{t} } \\ & = \left( {\sum\limits_{t = 1}^{t = n} {E_{t} \times D_{t} } } \right) \times \left( {\sum\limits_{t = 1}^{t = n} {P_{t} \times \left( {\frac{{E_{t} \times D_{t} }}{{\sum\nolimits_{1}^{n} {E_{t} \times D_{t} } }}} \right)} } \right) \\ \end{aligned}$$

The first summation term in brackets is precisely the present discounted amount of all energy generated in the future, i.e. the denominator in the standard definition of LCOE; the second is a weighted average of all future electricity prices, where the weights themselves are discounted to the present. A very similar distinction is made in finance: see, for example, Bierwag [2]. Finally, this weighted price is what should be compared to the LCOE in order to arrive at a meaningful conclusion, rather than to an abstract concept of “electricity price” which in practice is rarely a constant value.

In practice, the concept of LCOE is used with no in-depth consideration of its many underpinnings. A thorough discussion of all those underpinnings is beyond the scope of this chapter, but some mention, however preliminary, should be made of them. A brief comment on some of the main points follows: (1) the price P _t, and the electricity E _t, both refer to a future calendar year, and both will change over time; even within a given year the price changes hour by hour. Thus, the method for forecasting P _t, and E _t, will have an impact on the final calculation; (2) a context of likely increases in the prices of non renewables should be considered when calculating the LCOE for these technologies; (3) calculations are customarily performed assuming constant prices (one exception is [41]); however, even if inflation rates are low, for long time frames they may be relevant, so they should be dealt with appropriately; (4) the discount rate may have a strong impact on the final calculated value; Irena, for example, uses the WACC, which is 10 % in their case; a study conducted on behalf of the British Government recommends using a 3.5 % discount rate [38], finally, [9] suggests a declining discount rate, since otherwise future distant revenues will play no role; (5) when making international comparisons, the choice of the conversion rate is another factor that may have a decisive impact on the final assessment. A discussion of this point can be found in [30]; (6) the value assigned to the average cost of capital, or WACC, is more relevant in the case of renewable energies, since capital costs are the largest fraction of all costs and therefore have a strong impact on the calculated value for LCOE. A common value assumed in many reports is 10 % [18, 29, 41]; (7) whether the cost is measured from the point of view of a producer-investor or a consumer is another relevant point. In the latter case the price paid by consumers may be as much as four times higher than the price obtained by an investor who sells directly to the grid. Note also in passing that this distinction is also crucial when discussing the concept of ‘grid-parity’.

References

1.
Alvarado-Ancieta CA (2009) Estimating E and M powerhouse costs, international water power and dam construction, pp 21–25. (http://www.waterpowermagazine.com/storyprint.asp?sc=2052186)
2.
Bierwag GO (1987) Duration analysis. Managing interest rate risk, Ballinger, Cambridge, MassachussetsGoogle Scholar
3.
Breyer CH (2010) The photovoltaic reality ahead: terawatt scale market potential powered by pico to gigawatt PV systems and enabled by high learning and growth rates. 26th European photovoltaic solar energy conference, Hamburg, Germany, 5–9 Sept 2010Google Scholar
4.
Corden WM (1984) Boom sector and dutch disease economics: survey and consolidation, vol 36. Oxford Economic Papers, Oxford, pp 362Google Scholar
5.
Denholm P, Hand M (2011) Grid flexibility and storage required to achieve very high penetration of variable renewable energy, Energy Policy, vol 39. Elsevier, Amsterdam, pp 1817–1830Google Scholar
6.
Denholm P, Wan Y, Hummon M, Mehos M (2013) An analysis of concentrating solar power with thermal energy storage in a california 33 % Renewable Scenario, Technical Report 6A20-58186, National Renewable Energy Laboratory (NREL), Golden, Colorado, USAGoogle Scholar
7.
Ecofys, Fraunhofer ISI, TU Vienna EEG and Ernst and Young (2011) Financing Renewable Energy in the European Energy Market: Final Report, Ecofys, UtrechtGoogle Scholar
8.
Energy Information Administration (2013) Levelized Cost of New Generation Resources, in the Annual Energy Outlook 2013. US Energy Information Administration, US Department of Energy Washington, DC 20585Google Scholar
9.
Evans D (2008) Social project appraisal and discounting for the very long term. Econ Issues 13(1):61–70Google Scholar
10.
European Photovoltaic Industry Association (EPIA) (2012) Connecting the sun: How Europe’s electricity grid can integrate solar photovoltaics, EPIA Brussels, Belgium (www.epia.org)
11.
European Wind Energy Association (EWEA) (2010) Wind energy and electricity prices. Exploring the ‘merit order effect’. EWEA, Brussels, BelgiumGoogle Scholar
12.
Heide D et al. (2010) Seasonal optimal mix of wind and solar power in a future, highly renewable europe. Renewable Energy 35(11):2483–2489Google Scholar
13.
Hirth L (2012a) Integration costs and the value of wind power. Thoughts on a valuation framework for variable renewable electricity sources. In USAEE-Working Paper. http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2187632
14.
Hirth L (2012b) The market value of variable renewables. in USAEE-Working Paper. http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2110237
15.
International Monetary Fund (IMF) (2013) Energy subsidy reform: lessons and implications. IMF, WashingtonGoogle Scholar
16.
International Energy Agency (IEA) (2008) Energy technology perspectives 2008. IEA, ParisGoogle Scholar
17.
IPCC (2011) IPCC Special Report on Renewable Energy Sources and Climate Change Mitigation. International Panel on Climate Change, GenevaGoogle Scholar
18.
Irena (2013) Renewable power generation costs in 2012: an overview, Abu Dhabi, United Arab Emirates. (www.irena.org)
19.
Irena (2012a) Biomass for power generation, Cost Analysis series, issue 1/5, Abu Dhabi, United Arab Emirates (www.irena.org)
20.
Irena (2012b) Concentrating solar power, Cost Analysis series, issue 2/5, Abu Dhabi, United Arab Emirates (www.irena.org)
21.
Irena (2012c) Hydropower, Cost Analysis series, issue 3/5, Abu Dhabi, United Arab Emirates (www.irena.org)
22.
Irena (2012d) Solar Photovoltaic, Cost Analysis series, issue 4/5, Abu Dhabi, United Arab Emirates (www.irena.org)
23.
Irena (2012e) Wind Power, Cost Analysis series, issue 5/5, Abu Dhabi, United Arab Emirates (www.irena.org)
24.
Jackson T (2009) Prosperity without growth. Economics for a finite planet. Earthscan, LondonGoogle Scholar
25.
Jäger-Waldau A (2013) PV Status Report 2013, European Commission, DG Joint Research Centre, (September 2013). Ispra, ItalyGoogle Scholar
26.
Joskow PL (2011) Comparing the costs of intermittent and dispatchable electricity generating technologies. Am Econ Rev 101(3):238–241CrossRefGoogle Scholar
27.
Kearney AT, Estela (2010) Solar thermal electricity 2025, ESTELA, Brussels. (http://www.estelasolar.eu/index.php?id=22)
28.
Kersten F (2010) PV learning curves: past and future drivers of cost reduction, 26th European photovoltaic solar energy conference, Hamburg, Germany, 5–9 Sept 2010Google Scholar
29.
Kost CH et al (2012) Levelized cost of electricity renewables energies, Fraunhofer Institute for Solar Energy Systems ISE, Heidenhofstraße 2, 79110 Freiburg, GermanyGoogle Scholar
30.
Mauleón I, Sardá J (2000) Income measurements and comparisons. Int Adv Econ Res 6(3):475–488CrossRefGoogle Scholar
31.
Naam, R. (2011) Smaller-cheaper-faster-does-moores-law-apply to solar cells? http://blogs.scientificamerican.com/guest-blog/2011/03/16/
32.
Nelder CH (2012) Designing the grid for renewables. http://www.smartplanet.com/blog/take/designing-the-grid-for-renewables
33.
Philibert C (2012) Solar integration. Econ Energy Enviro Policy 1(2):37–45Google Scholar
34.
PwC Annual Global Power and Utilities Survey (2013) Energy transformation. The impact on the power sector business model, PricewaterhouseCoopers. http://www.pwc.com/gx/en/utilities/index.jhtml)
35.
REN 21 (2013) Renewables Global Futures Report, Renewable Energy Policy Network for the 21st Century, ParisGoogle Scholar
36.
Schaeffer R (2010) Can renewable energies be vulnerable to climate change?, mimeo, energy planning program, COPPE. Federal University of Rio de Janeiro, BrazilGoogle Scholar
37.
Scheer H (2005) The solar economy. Renewable energy for a sustainable global future, reprint, first published in English in 2002, Earthscan, LondonGoogle Scholar
38.
The Green Book Appraisal and Evaluation in Central Government (2011) HM treasury, London. http://www.hm-treasury.gov.uk/d/green_book_complete.pdf)
39.
Ueckerdt F, Hirth L, Luderer G, Edenhofer O (2012) System LCOE: what are the costs of variable renewables?, Electronic copy. http://ssrn.com/abstract=2200572
40.
Wiser R, Bolinger M (2011) 2010 Wind Technologies Market Report. DOE/GO-102011-3322. Washington, DC, USAGoogle Scholar
41.
World Energy Council—Bloomberg New Energy Finance (WEC-BNEF) (2013) Cost of Energy Technologies, Joseph Salvatore, (lead author). WEC, LondonGoogle Scholar

Copyright information

Authors and Affiliations

Ignacio Mauleón
- 1
Email author

1.Dpto. de Fundamentos del Análisis Económico.Universidad Rey Juan CarlosVicálvaro, MadridSpain

The Cost of Renewable Power: A Survey of Recent Estimates

Abstract

Keywords

List of Acronyms

JEL codes

References

Copyright information

Authors and Affiliations

Personalised recommendations

Cite chapter