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Hydropower

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Climate change is one of the great challenges of the 21st century. Its most severe impacts may still be avoided if efforts are made to transform current energy systems. Renewable energy sources have a large potential to displace emissions of greenhouse gases from the combustion of fossil fuels and thereby to mitigate climate change. If implemented properly, renewable energy sources can contribute to social and economic development, to energy access, to a secure and sustainable energy supply, and to a reduction of negative impacts of energy provision on the environment and human health. This Special Report on Renewable Energy Sources and Climate Change Mitigation (SRREN) impartially assesses the scientifi c literature on the potential role of renewable energy in the mitigation of climate change for policymakers, the private sector, academic researchers and civil society. It covers six renewable energy sources – bioenergy, direct solar energy, geothermal energy, hydropower, ocean energy and wind energy – as well as their integration into present and future energy systems. It considers the environmental and social consequences associated with the deployment of these technologies, and presents strategies to overcome technical as well as non-technical obstacles to their application and diffusion. The authors also compare the levelized cost of energy from renewable energy sources to recent non-renewable energy costs. The Intergovernmental Panel on Climate Change (IPCC) is the leading international body for the assessment of climate change. It was established by the United Nations Environment Programme (UNEP) and the World Meteorological Organization (WMO) to provide the world with a clear scientifi c view on the current state of knowledge on climate change and its potential environmental and socio-economic impacts.
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5
Hydropower
CoordinatingLeadAuthors:
ArunKumar(India)andTormodSchei(Norway)
LeadAuthors:
AlfredAhenkorah(Ghana),RodolfoCaceresRodriguez(ElSalvador),JeanMichelDevernay(France),
MarcosFreitas(Brazil),DouglasHall(USA),ÅnundKillingtveit(Norway),ZhiyuLiu(China)
ContributingAuthors:
EmmanuelBranche(France),JohnBurkhardt(USA),GarvinHeath(USA),KarinSeelos(Norway)
ReviewEditors:
CristobalDiazMorejon(Cuba)andThelmaKrug(Brazil)
Thischaptershouldbecitedas:
Kumar,A.,T.Schei,A.Ahenkorah,R.CaceresRodriguez,J.M.Devernay,M.Freitas,D.Hall,
Å.Killingtveit,Z.Liu,2011:Hydropower.InIPCCSpecialReportonRenewableEnergySourcesand
ClimateChangeMitigation[O.Edenhofer,R.PichsMadruga,Y.Sokona,K.Seyboth,P.Matschoss,
S.Kadner,T.Zwickel,P.Eickemeier,G.Hansen,S.Schlömer,C.vonStechow(eds)],CambridgeUniversity
Press,Cambridge,UnitedKingdomandNewYork,NY,USA.
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Chapter 5: Hydropower
CONTENTS
CHAPTER 5: HYDROPOWER .......................................................................................................... 2
5.1 Introduction ................................................................................................................................6
5.1.1 Source of energy ............................................................................................................6
5.1.2 History of hydropower development .............................................................................6
5.2 Resource potential ......................................................................................................................7
5.2.1 Global Technical Potential............................................................................................. 8
5.2.2 Possible impact of climate change on resource potential ............................................11
5.2.2.1 Projected changes in precipitation and runoff ...................................................... 11
5.2.2.2 Projected impacts on hydropower generation....................................................... 12
5.3 Technology and applications...................................................................................................15
5.3.1 Classification by head and size ....................................................................................15
5.3.2 Classification by facility type ......................................................................................16
5.3.2.1 Run-of-River.........................................................................................................16
5.3.2.2 Storage Hydropower............................................................................................. 17
5.3.2.3 Pumped storage..................................................................................................... 17
5.3.2.4 In-stream technology using existing facilities ......................................................18
5.3.3 Status and current trends in technology development ................................................. 18
5.3.3.1 Efficiency.............................................................................................................. 19
5.3.3.2 Tunnelling capacity .............................................................................................. 20
5.3.3.3 Technical challenges related to sedimentation management................................ 21
5.3.4 Renovation, modernization and upgrading ..................................................................21
5.4 Global and regional status of market and industry development........................................22
5.4.1 Existing generation ...................................................................................................... 22
5.4.2 The hydropower industry............................................................................................. 24
5.4.3 Impact of policies......................................................................................................... 25
5.4.3.1 International carbon markets ................................................................................ 25
5.4.3.2 Project financing................................................................................................... 25
5.4.3.3 Administrative and licensing process ...................................................................26
5.4.3.4 Classification by size ............................................................................................26
5.5 Integration into broader energy systems................................................................................27
5.5.1 Grid-independent applications .....................................................................................27
5.5.2 Rural electrification...................................................................................................... 27
5.5.3 Power system services provided by hydropower......................................................... 28
5.5.4 Hydropower support of other generation including renewable energy........................ 29
5.5.5 Reliability and interconnection needs for hydropower ................................................ 31
5.6 Environmental and social impacts..........................................................................................31
5.6.1 Typical impacts and possible mitigation measures...................................................... 31
5.6.1.1 Hydrological regimes ........................................................................................... 33
5.6.1.2 Reservoir creation................................................................................................. 34
5.6.1.3 Water quality ........................................................................................................ 34
5.6.1.4 Sedimentation ....................................................................................................... 35
5.6.1.5 Biological diversity............................................................................................... 36
5.6.1.6 Barriers for fish migration and navigation............................................................37
5.6.1.7 Involuntary population displacement ...................................................................38
5.6.1.8 Affected people and vulnerable groups ................................................................38
5.6.1.9 Public health .........................................................................................................39
5.6.1.10 Cultural heritage ...................................................................................................40
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5.6.1.11 Sharing development benefits............................................................................... 40
5.6.2 Guidelines and regulations...........................................................................................41
5.6.3 Lifecycle assessment of environmental impacts.......................................................... 43
5.6.3.1 Current lifecycle estimates of greenhouse gas emissions..................................... 44
5.6.3.2 Quantification of gross and net emissions from reservoirs ..................................45
5.7 Prospects for technology improvement and innovation........................................................48
5.7.1 Variable-speed technology........................................................................................... 49
5.7.2 Matrix technology ........................................................................................................49
5.7.3 Fish-friendly turbines................................................................................................... 49
5.7.4 Hydrokinetic turbines................................................................................................... 50
5.7.5 New materials .............................................................................................................. 50
5.7.6 Tunnelling technology ................................................................................................. 51
5.7.7 Dam technology ...........................................................................................................51
5.7.8 Optimization of operation ............................................................................................ 51
5.8 Cost trends ................................................................................................................................52
5.8.1 Investment cost of hydropower projects and factors that affect it............................... 56
5.8.2 Other costs occurring during the lifetime of hydropower projects ..............................59
5.8.3 Performance parameters affecting the levelized cost of hydropower.......................... 59
5.8.4 Past and future cost trends for hydropower projects....................................................61
5.8.5 Cost allocation for other purposes ...............................................................................62
5.9 Potential deployment................................................................................................................63
5.9.1 Near-term forecasts ......................................................................................................63
5.9.2 Long-term deployment in the context of carbon mitigation ........................................64
5.9.3 Conclusions regarding deployment.............................................................................. 68
5.10 Integration into water management systems.........................................................................68
5.10.1 The need for climate-driven water management...................................................... 68
5.10.2 Multipurpose use of reservoirs and regulated rivers ................................................69
5.10.3 Regional cooperation and sustainable watershed management ...............................70
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EXECUTIVE SUMMARY
Hydropower offers significant potential for carbon emissions reductions. The installed capacity of
hydropower by the end of 2008 contributed 16% of worldwide electricity supply, and hydropower
remains the largest source of renewable energy in the electricity sector. On a global basis, the
technical potential for hydropower is unlikely to constrain further deployment in the near to
medium term. Hydropower is technically mature, is often economically competitive with current
market energy prices and is already being deployed at a rapid pace. Situated at the crossroads of two
major issues for development, water and energy, hydro reservoirs can often deliver services beyond
electricity supply. The significant increase in hydropower capacity over the last 10 years is
anticipated in many scenarios to continue in the near term (2020) and medium term (2030), with
various environmental and social concerns representing perhaps the largest challenges to continued
deployment if not carefully managed.
Hydropower is a renewable energy source where power is derived from the energy of water
moving from higher to lower elevations. It is a proven, mature, predictable and typically price-
competitive technology. Hydropower has among the best conversion efficiencies of all known
energy sources (about 90% efficiency, water to wire). It requires relatively high initial investment,
but has a long lifespan with very low operation and maintenance costs. The levelized cost of
electricity for hydropower projects spans a wide range but, under good conditions, can be as low as
3 to 5 US cents2005 per kWh. A broad range of hydropower systems, classified by project type,
system, head or purpose, can be designed to suit particular needs and site-specific conditions. The
major hydropower project types are: run-of-river, storage- (reservoir) based, pumped storage and in-
stream technologies. There is no worldwide consensus on classification by project size (installed
capacity, MW) due to varying development policies in different countries. Classification according
to size, while both common and administratively simple, is—to a degree—arbitrary: concepts like
‘small’ or ‘large hydro’ are not technically or scientifically rigorous indicators of impacts,
economics or characteristics. Hydropower projects cover a continuum in scale and it may ultimately
be more useful to evaluate hydropower projects based on their sustainability or economic
performance, thus setting out more realistic indicators.
The total worldwide technical potential for hydropower generation is 14,576 TWh/yr (52.47
EJ/yr) with a corresponding installed capacity of 3,721 GW, roughly four times the current
installed capacity. Worldwide total installed hydropower capacity in 2009 was 926 GW, producing
annual generation of 3,551 TWh/y (12.8 EJ/y), and representing a global average capacity factor of
44%. Of the total technical potential for hydropower, undeveloped capacity ranges from about 47%
in Europe and North America to 92% in Africa, which indicates large opportunities for continued
hydropower development worldwide, with the largest growth potential in Africa, Asia and Latin
America. Additionally, possible renovation, modernization and upgrading of old power stations are
often less costly than developing a new power plant, have relatively smaller environment and social
impacts, and require less time for implementation. Significant potential also exists to rework
existing infrastructure that currently lacks generating units (e.g., existing barrages, weirs, dams,
canal fall structures, water supply schemes) by adding new hydropower facilities. Only 25% of the
existing 45,000 large dams are used for hydropower, while the other 75% are used exclusively for
other purposes (e.g., irrigation, flood control, navigation and urban water supply schemes). Climate
change is expected to increase overall average precipitation and runoff, but regional patterns will
vary: the impacts on hydropower generation are likely to be small on a global basis, but significant
regional changes in river flow volumes and timing may pose challenges for planning.
In the past, hydropower has acted as a catalyst for economic and social development by
providing both energy and water management services, and it can continue to do so in the
future. Hydro storage capacity can mitigate freshwater scarcity by providing security during lean
flows and drought for drinking water supply, irrigation, flood control and navigation services.
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Multipurpose hydropower projects may have an enabling role beyond the electricity sector as a
financing instrument for reservoirs that help to secure freshwater availability. According to the
World Bank, large hydropower projects can have important multiplier effects, creating an additional
USD2005 0.4 to 1.0 of indirect benefits for every dollar of value generated. Hydropower can serve
both in large, centralized and small, isolated grids, and small-scale hydropower is an option for rural
electrification.
Environmental and social issues will continue to affect hydropower deployment opportunities.
The local social and environmental impacts of hydropower projects vary depending on the project’s
type, size and local conditions and are often controversial. Some of the more prominent impacts
include changes in flow regimes and water quality, barriers to fish migration, loss of biological
diversity, and population displacement. Impoundments and reservoirs stand out as the source of the
most severe concerns but can also provide multiple beneficial services beyond energy supply. While
lifecycle assessments indicate very low carbon emissions, there is currently no consensus on the
issue of land use change-related net emissions from reservoirs. Experience gained during past
decades in combination with continually advancing sustainability guidelines and criteria, innovative
planning based on stakeholder consultations and scientific know-how can support high
sustainability performance in future projects. Transboundary water management, including the
management of hydropower projects, establishes an arena for international cooperation that may
contribute to promoting sustainable economic growth and water security.
Technological innovation and material research can further improve environmental
performance and reduce operational costs. Though hydropower technologies are mature,
ongoing research into variable-speed generation technology, efficient tunnelling techniques,
integrated river basin management, hydrokinetics, silt erosion resistive materials and environmental
issues (e.g., fish-friendly turbines) may ensure continuous improvement of future projects.
Hydropower can provide important services to electric power systems. Storage hydropower
plants can often be operated flexibly, and therefore are valuable to electric power systems.
Specifically, with its rapid response load-following and balancing capabilities, peaking capacity and
power quality attributes, hydropower can play an important role in ensuring reliable electricity
service. In an integrated system, reservoir and pumped storage hydropower can be used to reduce
the frequency of start-ups and shutdowns of thermal plants; to maintain a balance between supply
and demand under changing demand or supply patterns and thereby reduce the load-following
burden of thermal plants; and to increase the amount of time that thermal units are operated at their
maximum thermal efficiency, thereby reducing carbon emissions. In addition, storage and pumped
storage hydropower can help reduce the challenges of integrating variable renewable resources such
as wind, solar photovoltaics, and wave power.
Hydropower offers significant potential for carbon emissions reductions. Baseline projections
of the global supply of hydropower rise from 12.8 EJ in 2009 to 13 EJ in 2020, 15 EJ in 2030 and
18 EJ in 2050 in the median case. Steady growth in the supply of hydropower is therefore projected
to occur even in the absence of greenhouse gas (GHG) mitigation policies, though demand growth
is anticipated to be even higher, resulting in a shrinking percentage share of hydropower in global
electricity supply. Evidence suggests that relatively high levels of deployment over the next 20
years are feasible, and hydropower should remain an attractive renewable energy source within the
context of global GHG mitigation scenarios. That hydropower can provide energy and water
management services and also help to manage variable renewable energy supply may further
support its continued deployment, but environmental and social impacts will need to be carefully
managed.
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5.1 Introduction
This chapter describes hydropower technology. It starts with a brief historical overview of how the
technology has evolved (Section 5.1), a discussion of resource potential and how it may be affected by
climate change (Section 5.2), and a description of the technology (Section 5.3) and its social and
environmental impacts (Section 5.6). Also included is a summary of the present global and regional
status of the hydropower industry (Section 5.4) and the role of hydropower in the broader energy system
(Section 5.5), as well as a summary of the prospects for technology improvement (Section 5.7), cost
trends (Section 5.8), and potential deployment in both the near term (2020) and long term (2050)
(Section 5.9). The chapter also covers the integration of hydropower into broader water management
solutions (Section 5.10). In this chapter, the focus is largely on the generation and storage of electrical
energy from water; the use of hydropower in meeting mechanical energy demands is covered only
peripherally.
5.1.1 Source of energy
Hydropower is generated from water moving in the hydrological cycle, which is driven by solar
radiation. Incoming solar radiation is absorbed at the land or sea surface, heating the surface and creating
evaporation where water is available. A large percentage—close to 50% of all the solar radiation
reaching the Earth’s surface—is used to evaporate water and drive the hydrological cycle. The potential
energy embedded in this cycle is therefore huge, but only a very limited amount may be technically
developed. Evaporated water moves into the atmosphere and increases the water vapour content in the
air. Global, regional and local wind systems, generated and maintained by spatial and temporal
variations in the solar energy input, move the air and its vapour content over the surface of the Earth, up
to thousands of kilometres from the origin of evaporation. Finally, the vapour condenses and falls as
precipitation, about 78% on oceans and 22% on land. This creates a net transport of water from the
oceans to the land surface of the Earth, and an equally large flow of water back to the oceans as river and
groundwater runoff. It is the flow of water in rivers that can be used to generate hydropower, or more
precisely, the energy of water moving from higher to lower elevations on its way back to the ocean,
driven by the force of gravity.
5.1.2 History of hydropower development
Prior to the widespread availability of commercial electric power, hydropower was used for irrigation
and operation of various machines, such as watermills, textile machines and sawmills. By using water
for power generation, people have worked with nature to achieve a better lifestyle. The mechanical
power of falling water is an old resource used for services and productive uses. It was used by the
Greeks to turn water wheels for grinding wheat into flour more than 2,000 years ago. In the 1700s,
mechanical hydropower was used extensively for milling and pumping. During the 1700s and 1800s,
water turbine development continued. The first hydroelectric power plant was installed in Cragside,
Rothbury, England in 1870. Industrial use of hydropower started in 1880 in Grand Rapids, Michigan,
when a dynamo driven by a water turbine was used to provide theatre and storefront lighting. In 1881, a
brush dynamo connected to a turbine in a flour mill provided street lighting at Niagara Falls, New York.
The breakthrough came when the electric generator was coupled to the turbine and thus the world’s first
hydroelectric station (of 12.5 kW capacity) was commissioned on 30 September 1882 on Fox River at
the Vulcan Street Plant, Appleton, Wisconsin, USA, lighting two paper mills and a residence.1
Early hydropower plants were much more reliable and efficient than the fossil fuel-fired plants of the
day (Baird, 2006). This resulted in a proliferation of small- to medium-sized hydropower stations
distributed wherever there was an adequate supply of moving water and a need for electricity. As
1 United States Bureau of Reclamation: www.usbr.gov/power/edu/history.html.
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electricity demand grew, the number and size of fossil fuel, nuclear and hydropower plants increased. In
parallel, concerns arose around environmental and social impacts (Thaulow et al., 2010).
Hydropower plants (HPP) today span a very large range of scales, from a few watts to several GW. The
largest projects, Itaipu in Brazil with 14,000 MW2 and Three Gorges in China with 22,400 MW,3 both
produce between 80 to 100 TWh/yr (288 to 360 PJ/yr). Hydropower projects are always site-specific and
thus designed according to the river system they inhabit. Historical regional hydropower generation from
1965 to 2009 is shown in Figure 5.1.
Figure 5.1 | Hydropower generation (TWh) by region (BP, 2010).
The great variety in the size of hydropower plants gives the technology the ability to meet both large
centralized urban energy needs as well as decentralized rural needs. Though the primary role of
hydropower in the global energy supply today is in providing electricity generation as part of centralized
energy networks, hydropower plants also operate in isolation and supply independent systems, often in
rural and remote areas of the world. Hydro energy can also be used to meet mechanical energy needs, or
to provide space heating and cooling. More recently hydroelectricity has also been investigated for use
in the electrolysis process for hydrogen fuel production, provided there is abundance of hydropower in a
region and a local goal to use hydrogen as fuel for transport (Andreassen et al., 2002; Yumurtacia and
Bilgen, 2004; Silva et al., 2005)
Hydropower plants do not consume the water that drives the turbines. The water, after power generation,
is available for various other essential uses. In fact, a significant proportion of hydropower projects are
designed for multiple purposes (see Section 5.10.2). In these instances, the dams help to prevent or
mitigate floods and droughts, provide the possibility to irrigate agriculture, supply water for domestic,
municipal and industrial use, and can improve conditions for navigation, fishing, tourism or leisure
activities. One aspect often overlooked when addressing hydropower and the multiple uses of water is
that the power plant, as a generator of revenue, in some cases can help pay for the facilities required to
develop other water uses that might not generate sufficient direct revenues to finance their construction.
5.2 Resource potential
Hydropower resource potential can be derived from total available flow multiplied by head and a
conversion factor. Since most precipitation usually falls in mountainous areas, where elevation
2 Itaipu Binacional hydroelectric power plant (www.itaipu.gov.br).
3 China Three Gorges Project Corporation Annual Report 2009 (www.ctgpc.com).
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differences (head) are the largest, the largest potential for hydropower development is in mountainous
regions, or in rivers coming from such regions. The total annual runoff has been estimated as 47,000
km3, out of which 28,000 km3 is surface runoff, yielding a theoretical potential for hydropower
generation of 41,784 TWh/yr (147 EJ/yr) (Rogner et al., 2004). This value of theoretical potential is
similar to a more recent estimate of 39,894 TWh/yr (144 EJ/yr) (IJHD, 2010) (see Chapter 1).
Section 5.2.1 discusses the global technical potential, considering that gross theoretical potential is of no
practical value and what is economically feasible is variable depending on energy supply and pricing,
which can vary with time and by location.
5.2.1 Global Technical Potential
The International Journal on Hydropower & Dams 2010 World Atlas & Industry Guide (IJHD, 2010)
provides the most comprehensive inventory of current hydropower installed capacity and annual
generation, and hydropower resource potential. The Atlas provides three measures of hydropower
resource potential, all in terms of annual generation (TWh/yr): gross theoretical, technically feasible,4
and economically feasible. The total worldwide technical potential for hydropower is estimated at
14,576 TWh/yr (52.47 EJ/yr) (IJHD, 2010), over four times the current worldwide annual generation.5
This technical potential corresponds to a derived estimate of installed capacity of 3,721 GW.6 Technical
potentials in terms of annual generation and estimated capacity for the six world regions7 are shown in
Figure 5.2. Pie charts included in the figure provide a comparison of current annual generation to
technical potential for each region and the percentage of undeveloped potential compared to total
technical potential. These charts illustrate that the percentages of undeveloped potential range from 47%
in Europe and North America to 92% in Africa, indicating large opportunities for hydropower
development worldwide.
Table 5.1 | Regional hydropower technical potential in terms of annual generation and installed
capacity (GW); and current generation, installed capacity, average capacity factors in percent and
resulting undeveloped potential as of 2009. Source: IJHD (2010).
World region
Technical
potential, annual
generation
TWh/yr (EJ/yr)
Technical
potential,
installed
capacity
(GW)
2009
Total
generation
TWh/yr (EJ/yr)
2009
Installed
capacity
(GW)
Un-
developed
potential
(%)
Average
regional
capacity
factor (%)
North America 1,659 (5.971) 388 628 (2.261) 153 61 47
Latin America 2,856 (10.283) 608 732 (2.635) 156 74 54
Europe 1,021 (3.675) 338 542 (1.951) 179 47 35
Africa 1,174 (4.226) 283 98 (0.351) 23 92 47
Asia 7,681 (27.651) 2,037 1,514 (5.451) 402 80 43
Australasia/Oceania 185 (0.666) 67 37(0.134) 13 80 32
World 14,576 (52.470) 3,721 3,551 (12.783) 926 75 44
There are several notable features of the data in Figure 5.2. North America and Europe, which have been
developing their hydropower resources for more than a century, still have sufficient technical potential to
4 Equivalent to the technical potential definition provided in Annex I (Glossary).
5 Chapter 1 presents current and future technical potential estimates for all RE sources as assessed by Krewitt et al. (2009),
based on a review of several studies. There, hydropower technical potential by 2050 is estimated to be 50 EJ/y. However, this
chapter will exclusively rely on IJHD (2010) for technical potential estimates.
6 Derived value of potential installed nameplate capacity based on regional generation potentials and average capacity factors
shown in Figure 5.3.
7 The Latin America region includes Central and South America, consistent with the IEA world regions. This differs from the
regions in IJHD (2010), which includes Central America as part of North America. Data from the reference have been re-
aggregated to conform to regions used in this document.
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double their hydropower generation, belying the perception that the hydropower resources in these
highly developed parts of the world are exhausted. However, how much of this untapped technical
potential is economically feasible is subject to time-dependent economic conditions. Actual development
will also be impacted by sustainability concerns and related policies. Notably, Asia and Latin America
have comparatively large technical potentials and, along with Australasia/Oceania, the fraction of total
technical potential that is undeveloped is quite high in these regions. Africa has a large technical
potential and could develop 11 times its current level of hydroelectric generation in the region. An
overview of regional technical potentials for hydropower is given in Table 5.1.
Figure 5.2 | Regional hydropower technical potential in terms of annual generation and installed
capacity, and percentage of undeveloped technical potential in 2009. Source: IJHD (2010).
Understanding and appreciation of hydropower technical potential can also be obtained by considering
the current (2009) total regional hydropower installed capacity and annual generation shown in Figure
5.3. The reported worldwide total installed hydropower capacity is 926 GW producing a total annual
generation of 3,551 TWh/yr (12.8 EJ/yr) in 2009. Figure 5.3 also includes regional average capacity
factors calculated using current regional total installed capacity and annual generation (capacity factor =
generation/(installed capacity x 8,760 hrs)).
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Figure 5.3 | Total regional installed hydropower capacity and annual generation in 2009, and average
regional capacity factors (derived as stated above). Source: IJHD (2010).
It is interesting to note that North America, Latin America, Europe and Asia have the same order of
magnitude of total installed capacity while Africa and Australasia/Oceania have an order of magnitude
less—Africa due in part to the lack of available investment capital and Australasia/Oceania in part
because of size, climate and topography. The average capacity factors are in the range of 32 to 55%.
Capacity factor can be indicative of how hydropower is employed in the energy mix (e.g., peaking
versus base-load generation), water availability, or an opportunity for increased generation through
equipment upgrades and operation optimization. Generation increases that have been achieved by
equipment upgrades and operation optimization have generally not been assessed in detail, but are
briefly discussed in Sections 5.3.4 and 5.8.
The regional technical potentials presented above are for conventional hydropower corresponding to
sites on natural waterways where there is significant topographic elevation change to create useable
hydraulic head. Hydrokinetic technologies that do not require hydraulic head but rather extract energy
in-stream from the current of a waterway are being developed. These technologies increase the potential
for energy production at sites where conventional hydropower technology cannot operate. Non-
traditional sources of hydropower are also not counted in the regional technical potentials presented
above. Examples are constructed waterways such as water supply and treatment systems, aqueducts,
canals, effluent streams and spillways. Applicable conventional and hydrokinetic technologies can
produce energy using these resources. While the total technical potentials of in-stream and constructed
waterway resources have not been assessed, they may prove to be significant given their large extent.
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5.2.2 Possible impact of climate change on resource potential
The resource potential for hydropower is currently based on historical data for the present climatic
conditions. With a changing climate, this resource potential could change due to:
Changes in river flow (runoff) related to changes in local climate, particularly in precipitation
and temperature in the catchment area. This may lead to changes in runoff volume, variability of
flow and seasonality of the flow (e.g., by changing from spring/summer high flow to more winter
flow), directly affecting the resource potential for hydropower generation.
Changes in extreme events (floods and droughts) may increase the cost and risk for the
hydropower projects.
Changes in sediment loads due to changing hydrology and extreme events. More sediment could
increase turbine abrasions and decrease efficiency. Increased sediment load could also fill up
reservoirs faster and decrease the live storage, reducing the degree of regulation and decreasing
storage services.
The work of IPCC Working Group II (reported in IPCC, 2007b) includes a discussion of the impact of
climate change on water resources. Later, a technical paper on water was prepared based on the material
included in the previous IPCC reports as well as other sources (Bates et al., 2008). The information
presented in this section is mostly based on these two sources, with a few additions from more recent
papers and reports, as presented, for example, in a recent review by Hamududu et al. (2010).
5.2.2.1 Projected changes in precipitation and runoff
A wide range of possible future climatic projections have been presented, with corresponding variability
in projection of precipitation and runoff (IPCC, 2007c; Bates et al., 2008). Climate projections using
multi-model ensembles show increases in globally averaged mean water vapour, evaporation and
precipitation over the 21st century. At high latitudes and in part of the tropics, nearly all models project
an increase in precipitation, while in some subtropical and lower mid-latitude regions, precipitation is
projected to decrease. Between these areas of robust increase or decrease, even the sign of projected
precipitation change is inconsistent across the current generation of models (Bates et al., 2008).
Changes in river flow due to climate change will primarily depend on changes in volume and timing of
precipitation, evaporation and snowmelt. A large number of studies of the effect on river flow have been
published and were summarized in IPCC (2007b). Most of these studies use a catchment hydrological
model driven by climate scenarios based on climate model simulations. Before data can be used in the
catchment hydrological models, it is necessary to downscale data, a process where output from the
global climate model is converted to corresponding climatic data in the catchments. Such downscaling
can be both temporal and spatial, and it is currently a high priority research area to find the best methods
for downscaling.
A few global-scale studies have used runoff simulated directly by climate models (Egré and Milewski,
2002; IPCC, 2007b). The results of these studies show increasing runoff in high latitudes and the wet
tropics and decreasing runoff in mid-latitudes and some parts of the dry tropics. Figure 5.4 illustrates
projected changes in runoff by the end of the century, based on the IPCC A1B scenario8 (Bates et al.,
2008).
Uncertainties in projected changes in the hydrological systems arise from internal variability in the
climatic system, uncertainty about future greenhouse gas and aerosol emissions, the translations of these
8 Four scenario families or ‘storylines’ (A1, A2, B1 and B2) were developed by the IPCC and reported in the IPCC Special
Report On Emission Scenarios (SRES) as a basis for projection of future climate change, where each represents different
demographic, social, economic, technological and environmental development over the 21st century (IPCC, 2000). Therefore,
a wide range of possible future climatic projections have been presented based on the resulting emission scenarios, with
corresponding variability in projections of precipitation and runoff (IPCC, 2007b).
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emissions into climate change by global climate models, and hydrological model uncertainty.
Projections become less consistent between models as the spatial scale decreases. The uncertainty of
climate model projections for freshwater assessments is often taken into account by using multi-model
ensembles (Bates et al., 2008). The multi-model ensemble approach is, however, not a guarantee of
reducing uncertainty in mathematical models.
Figure 5.4 | Large-scale changes in annual runoff (water availability, in percent) for the period 2090 to
2099, relative to 1980 to 1999. Values represent the median of 12 climate model projections using the
SRES A1B scenario. White areas are where less than 66% of the 12 models agree on the sign of
change and hatched areas are where more than 90% of models agree on the sign of change. Source:
IPCC (2007a).
Global estimates as shown in Figure 5.4 represent results at a large scale, and cannot be applied to
shorter temporal and smaller spatial scales. In areas where rainfall and runoff are very low (e.g., desert
areas), small changes in runoff can lead to large percentage changes. In some regions, the sign of
projected changes in runoff differs from recently observed trends. Moreover, in some areas with
projected increases in runoff, different seasonal effects are expected, such as increased wet season runoff
and decreased dry season runoff. Studies using results from fewer climate models can be considerably
different from the results presented here (Bates et al., 2008).
5.2.2.2 Projected impacts on hydropower generation
Though the average global or continent-wide impacts of climate change on hydropower resource
potential might be expected to be relatively small, more significant regional and local effects are
possible. Hydropower resource potential depends on topography and the volume, variability and
seasonal distribution of runoff. Not only are these regionally and locally determined, but an increase in
climate variability, even with no change in average runoff, can lead to reduced hydropower production
unless more reservoir capacity is built and operations are modified to account for the new hydrology that
may result from climate change.
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In order to make accurate quantitative predictions of regional effects it is therefore necessary to analyze
both changes in average flow and changes in the temporal distribution of flow, using hydrological
models to convert time series of climate scenarios into time series of runoff scenarios. In catchments
with ice, snow and glaciers it is of particular importance to study the effects of changes in seasonality,
because a warming climate will often lead to increasing winter runoff and decreasing runoff in spring
and summer. A shift in winter precipitation from snow to rain due to increased air temperature may lead
to a temporal shift in peak flow and winter conditions (Stickler and Alfredsen, 2009) in many continental
and mountain regions. The spring snowmelt peak would then be brought forward or eliminated entirely,
with winter flow increasing. As glaciers retreat due to warming, river flows would be expected to
increase in the short term but decline once the glaciers disappear (Bates et al., 2008; Milly et al., 2008).
Summarizing available studies up to 2007, IPCC (2007b) and Bates et al. (2008) found examples of both
positive and negative regional effects on hydropower production, mainly following the expected changes
in river runoff. Unfortunately, few quantitative estimates of the effects on technical potential for
hydropower were found. The regional distribution of studies was also skewed, with most studies done in
Europe and North America, and a weak literature base for most developing country regions, in particular
for Africa. The summary below is based on findings summarized in Bates et al. (2008) and IPCC
(2007b) unless additional sources are given.
In Africa, the electricity supply in a number of states is largely based on hydroelectric power. However,
few available studies examine the impacts of climate change on hydropower resource potential in Africa.
Observations deducted from general predictions for climate change and runoff point to a reduction in
hydropower resource potential with the exception of East Africa (Hamududu et al., 2010).
In major hydropower-generating Asian countries such as China, India, Iran, Tajikistan etc., changes in
runoff are found to potentially have a significant effect on the power output. Increased risks of landslides
and glacial lake outbursts, and impacts of increased variability, are of particular concern to Himalayan
countries (Agrawala et al., 2003). The possibility of accommodating increased intensity of seasonal
precipitation by increasing storage capacities may become of particular importance (Iimi, 2007).
In Europe, by the 2070s, hydropower potential for the whole of Europe has been estimated to potentially
decline by 6%, translated into a 20 to 50% decrease around the Mediterranean, a 15 to 30% increase in
northern and Eastern Europe, and a stable hydropower pattern for western and central Europe (Lehner et
al., 2005).
In New Zealand, increased westerly wind speed is very likely to enhance wind generation and spill over
precipitation into major South Island watersheds, and to increase winter rain in the Waikato catchment.
Warming is virtually certain to increase melting of snow, the ratio of rainfall to snowfall, and to increase
river flows in winter and early spring. This is very likely to increase hydroelectric generation during the
winter peak demand period, and to reduce demand for storage.
In Latin America, hydropower is the main electrical energy source for most countries, and the region is
vulnerable to large-scale and persistent rainfall anomalies due to El Niño and La Niña, as observed in
Argentina, Colombia, Brazil, Chile, Peru, Uruguay and Venezuela. A combination of increased energy
demand and droughts caused a virtual breakdown of hydroelectricity in most of Brazil in 2001 and
contributed to a reduction in gross domestic product (GDP). Glacier retreat is also affecting hydropower
generation, as observed in the cities of La Paz and Lima.
In North America, hydropower production is known to be sensitive to total runoff, to its timing, and to
reservoir levels. During the 1990s, for example, Great Lakes levels fell as a result of a lengthy drought,
and in 1999, hydropower production was down significantly both at Niagara and Sault St. Marie. For a
2°C to 3°C warming in the Columbia River Basin and BC Hydro service areas, the hydroelectric supply
under worst-case water conditions for winter peak demand is likely to increase (high confidence).
Similarly, Colorado River hydropower yields are likely to decrease significantly, as will Great Lakes
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hydropower. Northern Québec hydropower production would be likely to benefit from greater
precipitation and more open-water conditions, but hydropower plants in southern Québec would be
likely to be affected by lower water levels. Consequences of changes in the seasonal distribution of
flows and in the timing of ice formation are uncertain.
In a recent study (Hamududu and Killingtveit, 2010), the regional and global changes in hydropower
generation for the existing hydropower system were computed, based on a global assessment of changes
in river flow by 2050 (Milly et al., 2005, 2008) for the SRES A1B scenario using 12 different climate
models. The computation was done at the country or political region (USA, Canada, Brazil, India, China,
Australia) level, and summed up to regional and global values (see Table 5.2).
Table 5.2 | Power generation capacity in GW and TWh/yr (2005) and estimated changes (TWh/yr) due
to climate change by 2050. Results are based on an analysis using the SRES A1B scenario in 12
different climate models (Milly et al., 2008), UNEP world regions and data for the hydropower system in
2005 (US DOE, 2009) as presented in Hamududu and Killingtveit (2010).
Power Generation Capacity (2005)Region
GW TWh/yr (PJ/yr)
Change by 2050
TWh/yr (PJ/yr)
Africa 22 90 (324) 0.0 (0)
Asia 246 996 (3,586) 2.7 (9.7)
Europe 177 517 (1,861) -0.8 (-2.9)
North America 161 655 (2,358) 0.3 (1)
South America 119 661 (2,380) 0.3 (1)
Oceania 13 40 (144) 0.0 (0)
TOTAL 737 2931 (10,552) 2.5 (9)
In general the results given in Table 5.2 are consistent with the (mostly qualitative) results given in
previous studies (IPCC, 2007b; Bates et al., 2008). For Europe, the computed reduction (-0.2%) has the
same sign, but is less than the -6% found by Lehner et al. (2005). One reason could be that Table 5.2
shows changes by 2050 while Lehner et al. (2005) give changes by 2070, so a direct comparison is
difficult.
It can be concluded that the overall impacts of climate change on the existing global hydropower
generation may be expected to be small, or even slightly positive. However, results also indicated
substantial variations in changes in energy production across regions and even within countries
(Hamududu and Killingtveit, 2010).
Insofar as a future expansion of the hydropower system will occur incrementally in the same general
areas/watersheds as the existing system, these results indicate that climate change impacts globally and
averaged across regions may also be small and slightly positive.
Still, uncertainty about future impacts as well as increasing difficulty of future systems operations may
pose a challenge that must be addressed in the planning and development of future HPP (Hamududu et
al., 2010).
Indirect effects on water availability for energy purposes may occur if water demand for other uses such
as irrigation and water supply for households and industry rises due to the climate change. This effect is
difficult to quantify, and it is further discussed in Section 5.10.
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5.3 Technology and applications
Head and also installed capacity (size) are often presented as criteria for the classification of hydropower
plants. The main types of hydropower, however, are run-of-river, reservoir (storage hydro), pumped
storage, and in-stream technology. Classification by head and classification by size are discussed in
Section 5.3.1. The main types of hydropower are presented in Section 5.3.2. Maturity of the technology,
status and current trends in technology development, and trends in renovation and modernization follow
in Sections 5.3.3 and 5.3.4 respectively.
5.3.1 Classification by head and size
A classification by head refers to the difference between the upstream and the downstream water levels.
Head determines the water pressure on the turbines that together with discharge are the most important
parameters for deciding the type of hydraulic turbine to be used. Generally, for high heads, Pelton
turbines are used, whereas Francis turbines are used to exploit medium heads. For low heads, Kaplan
and Bulb turbines are applied. The classification of what ‘high head’ and ‘low head are varies widely
from country to country, and no generally accepted scales are found.
Classification according to size has led to concepts such as ‘small hydro’ and ‘large hydro’, based on
installed capacity measured in MW as the defining criterion. Small-scale hydropower plants (SHP) are
more likely to be run-of-river facilities than are larger hydropower plants, but reservoir (storage)
hydropower stations of all sizes will utilize the same basic components and technologies. Compared to
large-scale hydropower, however, it typically takes less time and effort to construct and integrate small
hydropower schemes into local environments (Egré and Milewski, 2002). For this reason, the
deployment of SHPs is increasing in many parts of the world, especially in remote areas where other
energy sources are not viable or are not economically attractive.
Nevertheless, there is no worldwide consensus on definitions regarding size categories (Egré and
Milewski, 2002). Various countries or groups of countries define ‘small hydro’ differently. Some
examples are given in Table 5.3. From this it can be inferred that what presently is named ‘large hydro’
spans a very wide range of HPPs. IJHD (2010) lists several more examples of national definitions based
on installed capacity.
Table 5.3 | Small-scale hydropower by installed capacity (MW) as defined by various countries.
Country Small-scale hydro as
defined by installed
capacity (MW)
Reference Declaration
Brazil 30 Brazil Government Law No. 9648, of May 27, 1998
Canada <50 Natural Resources Canada, 2009: canmetenergy-
canmetenergie.nrcan-
rncan.gc.ca/eng/renewables/small_hydropower.html
China 50 Jinghe (2005); Wang (2010)
EU Linking
Directive
20 EU Linking directive, Directive 2004/101/EC, article 11a, (6)
India 25 Ministry of New and Renewable Energy, 2010:
www.mnre.gov.in/
Norway 10 Norwegian Ministry of Petroleum and Energy. Facts 2008.
Energy and Water Resources in Norway; p.27
Sweden 1.5 European Small Hydro Association, 2010:
www.esha.be/index.php?id=13
USA 5–100 US National Hydropower Association. 2010 Report of State
Renewable Portfolio Standard Programs (US RPS)
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This broad spectrum in definitions of size categories for hydropower may be motivated in some cases by
national licensing rules (e.g., Norway9) to determine which authority is responsible for the process or in
other cases by the need to define eligibility for specific support schemes (e.g., US Renewable Portfolio
Standards). It clearly illustrates that different countries have different legal definitions of size categories
that match their local energy and resource management needs.
Regardless, there is no immediate, direct link between installed capacity as a classification criterion and
general properties common to all HPPs above or below that MW limit. Hydropower comes in manifold
project types and is a highly site-specific technology, where each project is a tailor-made outcome for a
particular location within a given river basin to meet specific needs for energy and water management
services. While run-of-river facilities may tend to be smaller in size, for example, large numbers of
small-scale storage hydropower stations are also in operation worldwide. Similarly, while larger
facilities will tend to have lower costs on a USD/kW basis due to economies of scale, that tendency will
only hold on average. Moreover, one large-scale hydropower project of 2,000 MW located in a remote
area of one river basin might have fewer negative impacts than the cumulative impacts of 400 5-MW
hydropower projects in many river basins (Egré and Milewski, 2002). For that reason, even the
cumulative relative environmental and social impacts of large versus small hydropower development
remain unclear, and context dependent.
All in all, classification according to size, while both common and administratively simple, is—to a
degree—arbitrary: general concepts like ‘small’ or ‘large hydro’ are not technically or scientifically
rigorous indicators of impacts, economics or characteristics (IEA, 2000c). Hydropower projects cover a
continuum in scale, and it may be more useful to evaluate a hydropower project on its sustainability or
economic performance (see Section 5.6 for a discussion of sustainability), thus setting out more realistic
indicators.
5.3.2 Classification by facility type
Hydropower plants are often classified in three main categories according to operation and type of flow.
Run-of-river (RoR), storage (reservoir) and pumped storage HPPs all vary from the very small to the
very large scale, depending on the hydrology and topography of the watershed. In addition, there is a
fourth category called in-stream technology, which is a young and less-developed technology.
5.3.2.1 Run-of-River
A RoR HPP draws the energy for electricity production mainly from the available flow of the river. Such
a hydropower plant may include some short-term storage (hourly, daily), allowing for some adaptations
to the demand profile, but the generation profile will to varying degrees be dictated by local river flow
conditions. As a result, generation depends on precipitation and runoff and may have substantial daily,
monthly or seasonal variations. When even short-term storage is not included, RoR HPPs will have
generation profiles that are even more variable, especially when situated in small rivers or streams that
experience widely varying flows.
In a RoR HPP, a portion of the river water might be diverted to a channel or pipeline (penstock) to
convey the water to a hydraulic turbine, which is connected to an electricity generator (see Figure 5.5).
RoR projects may form cascades along a river valley, often with a reservoir-type HPP in the upper
reaches of the valley that allows both to benefit from the cumulative capacity of the various power
stations. Installation of RoR HPPs is relatively inexpensive and such facilities have, in general, lower
environmental impacts than similar-sized storage hydropower plants.
9 Norwegian Water Resources and Energy Directorate, Water resource act and regulations, 2001.
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Figure 5.5 | Run-of-river hydropower plant.
5.3.2.2 Storage Hydropower
Hydropower projects with a reservoir are also called storage hydropower since they store water for later
consumption. The reservoir reduces the dependence on the variability of inflow. The generating stations
are located at the dam toe or further downstream, connected to the reservoir through tunnels or pipelines.
(Figure 5.6). The type and design of reservoirs are decided by the landscape and in many parts of the
world are inundated river valleys where the reservoir is an artificial lake. In geographies with mountain
plateaus, high-altitude lakes make up another kind of reservoir that often will retain many of the
properties of the original lake. In these types of settings, the generating station is often connected to the
lake serving as reservoir via tunnels coming up beneath the lake (lake tapping). For example, in
Scandinavia, natural high-altitude lakes are the basis for high pressure systems where the heads may
reach over 1,000 m. One power plant may have tunnels coming from several reservoirs and may also,
where opportunities exist, be connected to neighbouring watersheds or rivers. The design of the HPP and
type of reservoir that can be built is very much dependent on opportunities offered by the topography.
Figure 5.6 | Typical hydropower plant with reservoir.
5.3.2.3 Pumped storage
Pumped storage plants are not energy sources, but are instead storage devices. In such a system, water is
pumped from a lower reservoir into an upper reservoir (Figure 5.7), usually during off-peak hours, while
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flow is reversed to generate electricity during the daily peak load period or at other times of need.
Although the losses of the pumping process make such a plant a net energy consumer overall, the plant
is able to provide large-scale energy storage system benefits. In fact, pumped storage is the largest-
capacity form of grid energy storage now readily available worldwide (see Section 5.5.5).
Figure 5.7 | Typical pumped storage project.
5.3.2.4 In-stream technology using existing facilities
To optimize existing facilities like weirs, barrages, canals or falls, small turbines or hydrokinetic turbines
can be installed for electricity generation. These basically function like a run-of-river scheme, as shown
in Figure 5.8. Hydrokinetic devices being developed to capture energy from tides and currents may also
be deployed inland in both free-flowing rivers and in engineered waterways (see Section 5.7.4).
Figure 5.8 | Typical in-stream hydropower plant using existing facilities.
5.3.3 Status and current trends in technology development
Hydropower is a proven and well-advanced technology based on more than a century of experience—
with many examples of hydropower plants built in the 19th century still in operation today. Hydropower
today is an extremely flexible power technology with among the best conversion efficiencies of all
energy sources (~90%, water to wire) due to its direct transformation of hydraulic energy to electricity
(IEA, 2004). Still, there is room for further improvements, for example, by improving operation,
reducing environmental impacts, adapting to new social and environmental requirements and by
developing more robust and cost-effective technological solutions. The status and current trends are
presented below, and options and prospects for future technology innovations are discussed in Section
5.7.
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5.3.3.1 Efficiency
The potential for energy production in a hydropower plant is determined by the following parameters,
which are dependent on the hydrology, topography and design of the power plant:
The amount of water available;
Water loss due to flood spill, bypass requirements or leakage;
The difference in head between upstream intake and downstream outlet;
Hydraulic losses in water transport due to friction and velocity change; and
The efficiency in energy conversion of electromechanical equipment.
The total amount of water available at the intake will usually not be possible to utilize in the turbines
because some of the water will be lost or will not be withdrawn. This loss occurs because of water spill
during high flows when inflow exceeds the turbine capacity, because of bypass releases for
environmental flows, and because of leakage.
In the hydropower plant the potential (gravitational) energy in water is transformed into kinetic energy
and then mechanical energy in the turbine and further to electrical energy in the generator. The energy
transformation process in modern hydropower plants is highly efficient, usually with well over 90%
mechanical efficiency in turbines and over 99% in the generator. The inefficiency is due to hydraulic
loss in the water circuit (intake, turbine and tailrace), mechanical loss in the turbo-generator group and
electrical loss in the generator. Old turbines can have lower efficiency, and efficiency can also be
reduced due to wear and abrasion caused by sediments in the water. The rest of the potential energy is
lost as heat in the water and in the generator.
In addition, some energy losses occur in the headrace section where water flows from the intake to the
turbines, and in the tailrace section taking water from the turbine back to the river downstream. These
losses, called head loss, reduce the head and hence the energy potential for the power plant. These losses
can be classified either as friction losses or singular losses. Friction losses depend mainly on water
velocity and the roughness in tunnels, pipelines and penstocks.
The total efficiency of a hydropower plant is determined by the sum of these three loss components.
Hydraulic losses can be reduced by increasing the turbine capacity or by increasing the reservoir
capacity to get better regulation of the flow. Head losses can be reduced by increasing the area of
headrace and tailrace, by decreasing the roughness in these and by avoiding too many changes in flow
velocity and direction. The efficiency of electromechanical equipment, especially turbines, can be
improved by better design and also by selecting a turbine type with an efficiency profile that is best
adapted to the duration curve of the inflow. Different turbine types have quite different efficiency
profiles when the turbine discharge deviates from the optimal value (see Figure 5.9). Improvements in
turbine design by computational fluid dynamics software and other innovations are discussed in Section
5.7.
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Figure 5.9 | Typical efficiency curves for different types of hydropower turbines (Vinogg and Elstad,
2003).
5.3.3.2 Tunnelling capacity
In hydropower projects, tunnels in hard and soft rock are often used for transporting water from the
intake to the turbines (headrace), and from the turbine back to the river, lake or fjord downstream
(tailrace). In addition, tunnels are used for a number of other purposes when the power station is placed
underground, for example for access, power cables, surge shafts and ventilation. Tunnels are
increasingly favoured for hydropower construction as a replacement for surface structures like canals
and penstocks.
Tunnelling technology has improved greatly due to the introduction of increasingly efficient equipment,
as illustrated by Figure 5.10 (Zare and Bruland, 2007). Today, the two most important technologies for
hydropower tunnelling are the drill and blast method and the use of tunnel-boring machines (TBM).
The drill and blast method is the conventional method for tunnel excavation in hard rock. Thanks to the
development in tunnelling technology, excavation costs have been reduced by 25%, or 0.8%/yr, over the
past 30 years (see Figure 5.10).
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Figure 5.10 | Developments in tunnelling technology: the trend in excavation costs for a 60 m2 tunnel,
in USD2005 per metre (adapted from Zare and Bruland, 2007).
TBMs excavate the entire cross section in one operation without the use of explosives. TBMs carry out
several successive operations: drilling, support of the ground traversed and construction of the tunnel.
The diameter of tunnels constructed can be from <1 m (‘micro tunnelling’) up to 15 m. The excavation
progress of the tunnel is typically from 30 up to 60 m/day.
5.3.3.3 Technical challenges related to sedimentation management
Although sedimentation problems are not found in all rivers (see Section 5.6.1.4), operating a
hydropower project in a river with a large sediment load comes with serious technical challenges.
Specifically, increased sediment load in the river water induces wear on hydraulic machinery and other
structures of the hydropower plant. Deposition of sediments can obstruct intakes, block the flow of water
through the system and also impact the turbines. The sediment-induced wear of the hydraulic machinery
is more serious when there is no room for storage of sediments.
In addition, for HPPs with reservoirs, their storage capacity can be filled up by sediments, which
requires special technical mitigation measures or plant design.
Lysne et al. (2003) reported that the effects of sediment-induced wear of turbines in power plants can be,
among others:
Generation loss due to reduction in turbine efficiency;
Increase in frequency of repair and maintenance;
Increase in generation losses due to downtime;
Reduction in lifetime of the turbine; and
Reduction in regularity of power generation.
All of these effects are associated with revenue losses and increased maintenance costs. Several
promising concepts for sediment control at intakes and mechanical removal of sediment from reservoirs
and for settling basins have been developed and practised. A number of authors (Mahmood, 1987;
Morris and Fan, 1997; ICOLD, 1999; Palmieri et al., 2003; White, 2005) have reported measures to
mitigate the sedimentation problems by better management of land use practices in upstream watersheds
to reduce erosion and sediment loading, mechanical removal of sediment from reservoirs and design of
hydraulic machineries aiming to resist the effect of sediment passing through them.
5.3.4 Renovation, modernization and upgrading
Renovation, modernization and upgrading (RM&U) of old power stations is often less costly than
developing a new power plant, often has relatively smaller environment and social impacts, and requires
less time for implementation. Capacity additions through RM&U of old power stations can therefore be
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attractive. Selective replacement or repair of identified hydro powerhouse components like turbine
runners, generator windings, excitation systems, governors, control panels or trash cleaning devices can
reduce costs and save time. It can also lead to increased efficiency, peak power and energy availability
of the plant (Prabhakar and Pathariya, 2007). RM&U may allow for restoring or improving
environmental conditions in already-regulated areas. Several national programmes for RM&U are
available. For example, the Research Council of Norway recently initiated a program with the aim to
increase power production in existing hydropower plants and at the same time improve environmental
conditions.10 The US Department of Energy has been using a similar approach to new technology
development since 1994 when it started the Advanced Hydropower Turbine Systems Program that
emphasized simultaneous improvements in energy and environmental performance (Odeh, 1999; Cada,
2001; Sale et al., 2006a).
Normally the life of hydroelectric power plants is 40 to 80 years. Electromechanical equipment may
need to be upgraded or replaced after 30 to 40 years, however, while civil structures like dams, tunnels
etc. usually function longer before they requires renovation. The lifespan of properly maintained
hydropower plants can exceed 100 years. Using modern control and regulatory equipment leads to
increased reliability (Prabhakar and Pathariya, 2007). Upgrading hydropower plants calls for a
systematic approach, as a number of hydraulic, mechanical, electrical and economic factors play a vital
role in deciding the course of action. For techno-economic reasons, it can also be desirable to consider
up-rating (i.e., increasing the size of the hydropower plant) along with RM&U/life extension.
Hydropower generating equipment with improved performance can also be retrofitted, often to
accommodate market demands for more flexible, peaking modes of operation. Most of the existing
worldwide hydropower equipment in operation will need to be modernized to some degree by 2030
(SER, 2007). Refurbished or up-rated hydropower plants also result in incremental increases in
hydropower generation due to more efficient turbines and generators.
In addition, existing infrastructure without hydropower plants (like existing barrages, weirs, dams, canal
fall structures, water supply schemes) can also be reworked by adding new hydropower facilities. The
majority of the world’s 45,000 large dams were not built for hydropower purposes, but for irrigation,
flood control, navigation and urban water supply schemes (WCD, 2000). Retrofitting these with turbines
may represent a substantial potential, because only about 25% of large reservoirs are currently used for
hydropower production. For example, from 1997 to 2008 in India, about 500 MW have been developed
on existing facilities. A recent study in the USA indicated some 20 GW could be installed by adding
hydropower capacity to 2,500 dams that currently have none (UNWWAP, 2006).
5.4 Global and regional status of market and industry development
5.4.1 Existing generation
In 2008, the generation of electricity from hydroelectric plants was 3,288 TWh (11.8 EJ)11 compared to
1,295 TWh (4.7 EJ) in 1973 (IEA, 2010a), which represented an increase of roughly 25% in this period,
and was mainly a result of increased production in China and Latin America, which reached 585 TWh
(2.1 EJ) and 674 TWh (2.5 EJ), respectively (Figures 5.11 and 5.12).
10 Centre for Environmental Design of Renewable Energy: www.cedren.no/.
11 These figures differ slightly from those presented in Chapter 1.
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Figure 5.11 | 1973 and 2008 regional shares of hydropower production (IEA, 2010a).
Hydropower provides some level of power generation in 159 countries. Five countries make up more
than half of the world’s hydropower production: China, Canada, Brazil, the USA and Russia. The
importance of hydroelectricity in the electricity mix of these countries is, however, different (Table 5.4).
On the one hand, Brazil and Canada are heavily dependent on this source, with a percentage share of
total domestic electricity generation of 83.9% and 59%, respectively, whereas in Russia the share is
19.0% and in China 15.5%.
Table 5.4 | Major hydroelectricity producer countries with total installed capacity and percentage of
hydropower generation in the electricity mix. Source: IJHD (2010).
Country Installed
Capacity (GW)
Country Based on
Top 10 Producers Percent of Hydropower
in Total Domestic
Electricity Generation
(%)
China 200 Norway 99
Brazil 84 Brazil 83.9
USA 78.2 Venezuela 73.4
Canada 74.4 Canada 59.0
Russia 49.5 Sweden 48.8
India 38 Russia 19.0
Norway 29.6 India 17.5
Japan 27.5 China 15.5
France 21 Italy 14.0
Italy 20 France 8.0
Rest of the world 301.6 Rest of the world** 14.3
World 926.1 World 15.9
Notes: **Excluding countries with no hydropower production
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China, Canada, Brazil and the USA together account for over 46% of the production (TWh/EJ) of
hydroelectricity in the world and are also the four largest in terms of installed capacity (GW) (IEA,
2010a). Figure 5.12 shows hydropower generation by country. It is noteworthy that 5 out of the 10 major
producers of hydroelectricity are among the world’s most industrialized countries: Canada, the USA,
Norway, Japan and Sweden. This is no coincidence, given that the possibility of drawing on the
hydroelectric resource was important for the introduction and consolidation of the main electro-intensive
sectors on which the industrialization process in these countries was based during a considerable part of
the 20th century.
Figure 5.12 | Hydropower generation in 2008 by country, indicating total generation (TWh) and
respective global share (IEA, 2010a).
Despite the significant growth in hydroelectric production, the percentage share of hydroelectricity on a
global basis has dropped during the last three decades (1973 to 2008), from 21 to 16%. This is because
electricity demand and the deployment of other energy technologies have increased more rapidly than
hydropower generating capacity.
5.4.2 The hydropower industry
In developed markets such as the Europe, the USA, Canada, Norway and Japan, where many
hydropower plants were built 30 to 60 years ago, the hydropower industry is focused on re-licensing and
renovation as well as on adding new hydropower generation to existing dams. In emerging markets such
as China, Brazil, Ethiopia, India, Malaysia, Iran, Laos, Turkey, Venezuela, Ecuador and Vietnam,
utilities and private developers are pursuing large-scale new hydropower construction (116 GW of
capacity is under construction; IJHD, 2010). Canada is still on the list of the top five hydropower
markets for new installations worldwide. Orders for hydropower equipment were lower in 2009 and
2010 compared to the peaks in 2007 and 2008, though the general high level after 2006, when the
hydropower market almost doubled, is anticipated to continue for the near future. With increasing policy
support of governments for new hydropower (see Sections 5.4.3 and 5.10.3) construction,
hydropower industrial activity is expected to be higher in the coming years compared to the average
since 2000 (IJHD, 2010). As hydropower and its industry are mature, it is expected that the industry will
be able to meet the demand that materializes (see Section 5.9). In 2008, the hydropower industry
installed more than 40 GW of new capacity worldwide (IJHD, 2010), with 31 GW added in 2009
(REN21, 2010; see Chapter 1).
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5.4.3 Impact of policies12
Hydropower infrastructure development is closely linked to national, regional and global development
policies. Beyond its role in contributing to a secure energy supplysecurity and reducing a country’s
dependence on fossil fuels, hydropower offers opportunities for poverty alleviation and sustainable
development. Hydropower also can contribute to regional cooperation, as good practice in managing
water resources requires a river basin approach regardless of national borders (see also Section 5.10). In
addition, multipurpose hydropower can strengthen a country’s ability to adapt to climate change-induced
hydrological variability (World Bank, 2009).
The main challenges for hydropower development are linked to a number of associated risks such as
poor identification and management of environmental and social impacts, insufficient hydrological data,
unexpected adverse geological conditions, lack of comprehensive river basin planning, shortage of
financing, scarcity of local skilled human resources and lack of regional collaboration. These challenges
can be and are being addressed to varying degrees at the policy level by a number of governments,
international financing institutions, professional associations and nongovernmental organizations
(NGOs). Examples of policy initiatives dealing with the various challenges can be found in Sections
5.6.2 and 5.10.
Challenges posed by various barriers can be addressed and met by public policies, bearing in mind the
need for an appropriate environment for investment, a stable regulatory framework and incentives for
research and technological development (Freitas and Soito, 2009; see Chapter 11). A variety of policies
have been enacted in individual countries to support certain forms and types of hydropower, as
highlighted generally in Chapter 11. More broadly, in addition to country-specific policies, several larger
policy issues have been identified as particularly important for the development of hydropower,
including carbon markets, financing, administration and licensing procedures, and size-based
classification schemes.
5.4.3.1 International carbon markets
As with other carbon reduction technologies, carbon credits can benefit hydropower projects by bringing
additional funding and thus helping to reduce project risk and thereby secure financing. Though the
Clean Development Mechanism (CDM) is not unique to hydropower, hydropower projects are one of the
largest contributors to the CDM and Joint Implementation (JI) mechanisms and therefore to existing
carbon credit markets. In part, this is due to the fact that new hydropower development is targeted
towards developing countries that are in need of investment capital, and international carbon markets
offer one possible route to that capital. Out of the 2,062 projects registered by the CDM Executive Board
(EB) by 1 March 2010, 562 were hydropower projects. When considering the predicted volumes of
Certified Emission Reductions to be delivered, registered hydropower projects are expected to avoid
more than 50 Mt of carbon dioxide (CO2) emissions per year by 2012. China, India, Brazil and Mexico
represent roughly 75% of the hosted projects.
5.4.3.2 Project financing
Hydropower projects can often deliver electricity at comparatively low costs relative to existing market
energy prices (see Section 5.8). Nonetheless, many otherwise economically feasible hydropower projects
are financially challenging because high upfront costs are often a deterrent to investment. Related to this,
hydropower projects tend to have lengthy lead times for planning, permitting and construction,
increasing development risk and delaying revenue generation. A key challenge, then, is to create
sufficient private sector confidence in hydropower investment, especially prior to project permitting.
Deployment policies of the types described in Chapter 11 are being used in some countries to encourage
investment. Also, in developing regions such as Africa, interconnection between countries and the
12 Non-technology-specific policy issues are covered in Chapter 11 of this report.
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formation of larger energy markets is helping to build investor confidence by reducing the risk of a
monopsony buyer. Feasibility and impact assessments carried out by the public sector, prior to developer
tendering, can also help ensure greater private sector interest in hydropower development (WEC, 2007;
Taylor, 2008). Nonetheless, the development of appropriate financing models that consider the
uncertainty imposed by long planning and regulatory processes, and finding the optimum roles for the
public and private sectors, remain key challenges for hydropower development.
5.4.3.3 Administrative and licensing process
Hydropower is often regarded as a public resource (Sternberg, 2008), emphasized by the operating life
of a reservoir that may be more than 100 years. Legal frameworks vary from country to country,
however, including practices in the award and structuring of concessions, for instance, regarding
concession periods, royalties, water rights etc. Environmental licensing procedures also vary greatly.
With growing involvement of the private sector in what was previously managed by public sector,
contractual arrangements surrounding hydropower have become increasingly complex. There are now
more parties involved and much greater commercial accountability, with a strong awareness of
environmental and social indicators and licensing processes. Clearly, the policies and procedures
established by governments in granting licenses and concessions will impact hydropower development
outcomes.
5.4.3.4 Classification by size
Finally, many governments and international bodies have relied upon various distinctions between
‘small’ and ‘large’ hydro, as defined by installed capacity (MW), in establishing the eligibility of
hydropower plants for certain programs. While it is well known that large-scale HPPs can create
conflicts and concerns (WCD, 2000), the environmental and social impacts of a HPP cannot be deduced
by size in itself, even if increasing the physical size may increase the overall impacts of a specific HPP
(Egré and Milewski, 2002; Sternberg, 2008). Despite their lack of robustness (see Section 5.3.1), these
classifications have had significant policy and financing consequences (Egré and Milewski, 2002).
In the UK Renewables Obligation,13 eligible hydropower plants must be below 20 MW in size.
Likewise, in several countries, feed-in tariffs are targeted only towards smaller projects. For example, in
France, only projects with an installed capacity not exceeding 12 MW are eligible,14 and in Germany, a 5
MW maximum capacity has been established.15 In India, projects below 5 and 25 MW in capacity obtain
promotional support that is unavailable to projects of larger sizes. Similar approaches exist in many
developed and developing countries around the world, for example, in Indonesia.16 Because project size
is neither a perfect indicator of environmental and social impact nor of the financial need of a project for
addition policy support, these categorizations may, at times, impede the development of socially
beneficial projects.
Similar concerns have been raised with respect to international and regional climate policy. Though
hydropower is recognized as a contributor to reducing GHG emissions and is included in the Kyoto
Protocol’s flexible mechanisms, those mechanisms differentiate HPPs depending on size and type. The
United Nations Framework Convention on Climate Change (UNFCCC) CDM EB, for example, has
established that storage hydropower projects are to follow the power density indicator (PDI), W/m2
(installed capacity/reservoir area), to be eligible for CDM credits. The PDI indicates tentative GHG
emissions from reservoirs. The CDM Executive Board stated (February 2006) that “Hydroelectric power
plants with power densities greater than 4 W/m2 but less than or equal to 10 W/m2 can use the currently
13 The Renewables Obligation Order 2006, No. 1004 (ROO 2006): www.statutelaw.gov.uk.
14 Décret n°2000-1196, Decree on capacity limits for different categories of systems for the generation of electricity from
renewable sources that are eligible for the feed-in tariff: www.legifrance.gouv.fr.
15 EEG, 2009 - Act on Granting Priority to Renewable Energy and Mineral Sources: bundesrecht.juris.de/eeg_2009/.
16 Regulation of the Minister of Energy and Mineral Resources, No.31, 2009.
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approved methodologies, with an emission factor of 90 g CO2eq/kWh for projects with reservoir
emissions”, while “less than or equal to 4 W/m2 cannot use current methodologies”. There is little link,
however, between installed capacity, the area of a reservoir and the various biogeochemical processes
active in a reservoir. Hypothetically, two identical storage HPPs would, according to the PDI, have the
same emissions independent of climate zones or of inundated biomass and carbon fluxes (see Section
5.6.3). As such, the PDI rule may inadvertently impede the development of socially beneficial
hydropower projects, while at the same time supporting less beneficial projects. The European Emission
Trading Scheme and related trading markets similarly treat small- and large-scale hydropower stations
differently.17
5.5 Integration into broader energy systems
Hydropower’s large capacity range, flexibility, storage capability when coupled with a reservoir, and
ability to operate in a stand-alone mode or in grids of all sizes enables hydropower to deliver a broad
range of services. Hydropower’s various roles in and services to the energy system are discussed below
(see also Chapter 8).
5.5.1 Grid-independent applications
Hydropower can be delivered through national and regional interconnected electric grids, through local
mini-grids and isolated grids, and can also serve individual customers through captive plants. Water
mills in England, Nepal, India and elsewhere, which are used for grinding cereals, for lifting water and
for powering machinery, are early testimonies of hydropower being used as captive power in mechanical
and electrical form. The tea and coffee plantation industries as well as small islands and developing
states have used and still make use of hydropower to meet energy needs in isolated areas.
Captive power plants (CPPs) are defined here as plants set up by any person or group of persons to
generate electricity primarily for the person or the group’s members (Indian Electricity Act, 2003). CPPs
are often found in decentralized isolated systems and are generally built by private interests for their own
electricity needs. In deregulated electricity markets that allow open access to the grid, hydropower plants
are also sometimes installed for captive purposes by energy-intensive industries such as aluminium
smelters, pulp and paper mills, mines and cement factories in order to weather short-term market
uncertainties and volatility (Shukla et al., 2004). For governments of emerging economies such as India
facing shortages of electricity, CPPs are also a means to cope with unreliable power supply systems and
higher industrial tariffs by encouraging decentralized generation and private participation (Shukla et al.,
2004).
5.5.2 Rural electrification
According to the International Energy Agency (IEA, 2010c), 1.4 billion people have no access to
electricity (see Section 9.3.2). Related to the discussion in Section 5.5.1, small-scale hydropower (SHP)
can sometimes be an economically viable supply source in these circumstances, as SHP can provide a
decentralized electricity supply in those rural areas that have adequate hydropower technical potential
(Egré and Milewski, 2002). In fact, SHPs already play an important role in the economic development of
some remote rural areas. Small-scale hydropower-based rural electrification in China has been one of the
most successful examples, where over 45,000 small hydropower plants totalling 55 GW have been built
that are producing 160 TWh (0.58 EJ) annually. Though many of these plants are used in centralized
electricity networks, SHPs constitute one-third of China’s total hydropower capacity and are providing
services to over 300 million people (Liu and Hu, 2010). More generally, SHP is found in isolated grids
as well as in off-grid and central-grid settings. As 75% of costs are site-specific, proper site selection is a
key challenge. Additionally, in isolated grid systems, natural seasonal flow variations might require that
17 Directive 2004/101/E, C article 11a(6), www.eur-lex.europa.eu.
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hydropower plants be combined with other generation sources in order to ensure continuous supply
during dry periods (World Bank, 2008) and may have excess production during wet seasons; such
factors need to be considered in the planning process (Sundqvist and Wårlind, 2006).
In general, SHPs
are often but certainly not always RoR schemes;
can use existing infrastructure such as dams or irrigation channels;
are located close to villages to avoid expensive high-voltage distribution equipment;
can use pumps as turbines and motors as generators for a turbine/generator set; and
have a high level of local content both in terms of materials and work force during the
construction period and local materials for the civil works.
A recent example from western Canada18 shows that SHP might also be a solution for remote
communities in developed countries by replacing fossil-fired diesel generation with hydropower
generation.
All in all, the development of SHP for rural areas involves environmental, social, technical and
economic considerations. Local management, ownership and community participation, technology
transfer and capacity building are basic issues for sustainable SHP plants in such circumstances.
5.5.3 Power system services provided by hydropower
Hydroelectric generation differs from thermal generation in that the quantity of ‘fuel’ (i.e., water) that is
available at any given time is determined by river flows leading to the hydroelectric plant. Run-of-river
HPPs lack a reservoir to store large quantities of water, though large RoR HPPs may have some limited
ability to regulate river flow. Storage hydropower, on the other hand, can largely decouple the timing of
hydropower generation and variable river flows. For large storage reservoirs, the storage may be
sufficient to buffer seasonal or multi-seasonal changes in river flows, whereas for smaller reservoirs the
storage may buffer river flows on a daily or weekly basis.
With a very large reservoir relative to the size of the hydropower plant (or very consistent river flows),
HPPs can generate power at a near-constant level throughout the year (i.e., operate as a base-load plant).
Alternatively, in the case that the hydropower capacity far exceeds the amount of reservoir storage, the
hydropower plant is sometimes referred to as energy-limited. An energy-limited hydropower plant
would exhaust its ‘fuel supply’ by consistently operating at its rated capacity throughout the year. In this
case, the use of reservoir storage allows hydropower generation to occur at times that are most valuable
from the perspective of the power system rather than at times dictated solely by river flows. Since
electrical demand varies during the day and night, during the week and seasonally, storage hydropower
generation can be timed to coincide with times where the power system needs are the greatest. In part,
these times will occur during periods of peak electrical demand. Operating hydropower plants in a way
that generates power during times of high demand is referred to as peaking operation (in contrast to
base-load). Even with storage, however, hydropower generation will still be limited by the size of the
storage, the rated electrical capacity of the hydropower plant, and downstream flow constraints for
irrigation, recreation or environmental uses of the river flows. Hydropower peaking may, if the outlet is
directed to a river, lead to rapid fluctuations in river flow, water-covered area, depth and velocity. In turn
this may, depending on local conditions, lead to negative impacts in the river (see Section 5.6.1.5) unless
properly managed.
Hydropower generation that consistently occurs during periods with high system demand can offset the
need for thermal generation to meet that same demand. The ratio of the amount of demand that can be
reliably met by adding hydropower to the nameplate capacity of the hydropower plant is called the
18 Natural Resources Canada. 2009. Isolated-grid case study: the Hluey Lake project in British Columbia:
www.retscreen.net/ang/case_studies_2900kw_isolated_grid_internal_load_canada.php.
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capacity credit. Even RoR hydropower that consistently has river flows during periods of high demand
can earn a high capacity credit, while adding reservoir storage can increase the capacity credit to levels
comparable to thermal power plants (see Section 8.2.1.2).
In addition to providing energy and capacity to meet electrical demand, hydropower generation often has
several characteristics that enable it to provide other services to reliably operate power systems. Because
hydropower plants utilize gravity instead of combustion to generate electricity, hydropower plants are
often less susceptible to the sudden loss of generation than is thermal generation. Hydropower plants
also offer operating flexibility in that they can start generating electricity with very short notice and low
start-up costs, provide rapid changes in generation, and have a wide range of generation levels over
which power can be generated efficiently (i.e., high part-load efficiency) (Haldane and Blackstone,
1955; Altinbilek et al., 2007). The ability to rapidly change output in response to system needs without
suffering large decreases in efficiency makes hydropower plants well suited to providing the balancing
services called regulation and load-following. RoR HPPs operated in cascades in unison with storage
hydropower in upstream reaches may similarly contribute to the overall regulating and balancing ability
of a fleet of HPPs. With the right equipment and operating procedures, hydropower can also provide the
ability to restore a power station to operation without relying on the electric power transmission network
(i.e., black start capability) (Knight, 2001).
Overall, with its important load-following and balancing capabilities, peaking capacity and power
quality attributes, hydropower can play a significant role in ensuring reliable electricity service (US
Department of the Interior, 2005).
5.5.4 Hydropower support of other generation including renewable energy
Electricity systems worldwide rely upon widely varying amounts of hydropower today. In this range of
hydropower capabilities, electric system operators have developed economic dispatch methodologies
that take into account the unique role of hydropower, including coordinating the operation of
hydropower plants with other types of generating units. In particular, many thermal power plants (coal,
gas or liquid fuel, or nuclear energy) require considerable lead times (often four hours for gas turbines
and over eight hours for steam turbines) before they attain an optimum thermal efficiency at which point
fuel consumption and emissions per unit output are minimum. In an integrated system, the considerable
flexibility provided by storage HPPs can be used to reduce the frequency of start ups and shut downs of
thermal plants; to maintain a balance between supply and demand under changing demand or supply
patterns and thereby reduce the load-following burden on thermal plants; and to increase the amount of
time that thermal units are operated at their maximum thermal efficiency. In some regions, for instance,
hydroelectric power plants are used to follow varying peak load demands while nuclear or fossil fuel
power plants are operated as base-load units.
Pumped hydropower storage can further increase the support of other resources. In cases with pumped
hydropower storage, pumps can use the output from thermal plants during times that they would
otherwise operate less efficiently at part load or be shut down (i.e., low load periods). The pumped
storage plant then keeps water in reserve for generating power during peak period demands. Pumped
storage has much the same ability as storage HPPs to provide balancing and regulation services.
Pumped storage hydropower is usually not a source for energy, however. The hydraulic, mechanical and
electrical efficiencies of pumped storage determine the overall cycle efficiency, ranging from 65 to 80%
(Egré and Milewski, 2002). If the upstream pumping reservoir is also used as a traditional reservoir the
inflow from the watershed may balance out the energy loss caused by pumping. If not, net losses lead to
pumped hydropower being a net energy consumer. A traditional storage HPP may also be retrofitted
with pump technologies to combine the properties of storage and pump storage HPPs (SRU, 2010). The
use and benefit of pumped storage hydropower in the power system will depend on the overall mix of
existing generating plants and the architecture of the transmission system. Pumped storage represents
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about 2.2% of all generation capacity in the USA, 10.2 % in Japan and 18.7 % in Austria (Deane et al.,
2010). Various technologies for storing electricity in the grid are compared by Vennemann et al. (2010)
in Figure 5.13 for selected large storage sites in different parts of the world.
Figure 5.13 | Storage and installed capacity of selected large electricity storage sites (Vennemann et
al., 2010).
Note: PSP = Pumped storage plants; CAES = compressed air energy storage, AA-CAES = advanced adiabatic compressed
air energy storage; Batteries: NaS = sodium-sulphur, NiCd = nickel cadmium, VRB = vanadium redox battery.
In addition to hydropower supporting fossil and nuclear generation technologies, hydropower can also
help reduce the challenges of integrating variable renewable resources. In Denmark, for example, the
high level of variable wind (>20% of the annual energy demand) is managed in part through strong
interconnections (1 GW) to Norway, where there is substantial storage hydropower (Nordel, 2008).
More interconnectors to Europe may further support increasing the share of wind power in Denmark and
Germany (SRU, 2010; see also Section 11.6.5). From a technical viewpoint, Norway alone has a long-
term potential to establish pumped storage facilities in the 10 to 25 GW range, enabling energy storage
over periods from hours to several weeks in existing reservoirs, and more or less doubling the present
installed capacity of 29 GW (IEA-ENARD, 2010).
Increasing variable generation will also increase the amount of balancing services, including regulation
and load following, required by the power system (e.g., Holttinen et al., 2009). In regions with new and
existing hydropower facilities, providing these services with hydropower may avoid the need to rely on
increased part-load and cycling of thermal plants to provide these services. Similarly, in systems with
high shares of variable renewable resources that provide substantial amounts of energy but limited
capacity, the potential for a high capacity credit of hydropower can be used to meet peak demand rather
than requiring peaking thermal plants.
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5.5.5 Reliability and interconnection needs for hydropower
Though hydropower has the potential to offer significant power system services in addition to energy
and capacity, interconnecting and reliably utilizing hydropower plants may also require changes to
power systems. The interconnection of hydropower to the power system requires adequate transmission
capacity from hydropower plants to demand centres. Adding new hydropower plants has in the past
required network investments to extend the transmission network (see Section 8.2.1.3). Without
adequate transmission capacity, hydropower plant operation can be constrained such that the services
offered by the hydropower plant are less than what it could offer in an unconstrained system.
Aside from network expansion, changes in the river flow between a dry year and a wet year can be a
significant concern for ensuring that adequate total annual energy demand can be met. Strong
interconnections between diverse hydropower resources or between hydro-dominated and thermal-
dominated power systems have been used in existing systems to ensure adequate energy generation (see
Section 8.2.1.3). In the future, interconnection to other renewable resources could also ensure adequate
energy. Wind and direct solar power, for instance, can be used to reduce demands on hydropower, either
by allowing dams to save their water for later release in peak periods or letting storage or pumped
storage HPPs consume excess energy produced in off-peak hours.
5.6 Environmental and social impacts19
Like all energy and water management options, hydropower projects have negative and positive
environmental and social impacts. On the environmental side, hydropower may have a significant
environmental footprint at local and regional levels but offers advantages at the macro-ecological level.
With respect to social impacts, hydropower projects may entail the relocation of communities living
within or nearby the reservoir or the construction sites, compensation for downstream communities,
public health issues etc. A properly designed hydropower project may, however, be a driving force for
socioeconomic development (see Box 5.1), though a critical question remains about how these benefits
are shared.
Because each hydropower plant is uniquely designed to fit the site-specific characteristics of a given
geographical site and the surrounding society and environment, the magnitude of environmental and
social impacts as well as the extent of their positive and negative effects is highly site dependent.
Though the size of a HPP is not, alone, a relevant criterion to predict environmental performance, many
impacts are related to the impoundment and existence of a reservoir, and therefore do not apply to all
HPP types (see Table 5.5). Section 5.6.1 summarizes the main environmental and social impacts that can
arise from development of the various types of hydropower projects, as well as a number of practicable
mitigation measures that can be implemented to minimize negative effects and maximize positive
outcomes. More information about existing guidance for sustainable hydropower development is
provided in Section 5.6.2. Hydropower creates no direct atmospheric pollutants or waste during
operation, and GHG emissions associated with most lifecycle stages are minor. However, methane
(CH4) emissions from reservoirs might be substantial under certain conditions. Thus, there is a need to
properly assess the net change in GHG emissions induced by the creation of such reservoirs. The
lifecycle GHG emissions of hydropower are discussed in Section 5.6.3, including the scientific status of
the carbon balances of reservoirs and other lifecycle aspects.
5.6.1 Typical impacts and possible mitigation measures
Although the type and magnitude of impacts will vary from project to project, it is possible to describe
some typical effects, along with the experience that has been gained throughout the past decades in
managing and solving problems. Though some impacts are unavoidable, they can be minimized or
19 A comprehensive assessment of social and environmental impacts of all RE sources covered in this report can be found in
Chapter 9.
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compensated for, as experience in successful mitigation demonstrates. Information has been
systematically gathered on effective assessment and management of impacts related to various types of
hydropower (IEA, 2000a; UNEP, 2007). By far the most effective measure is impact avoidance, by
weeding out less sustainable alternatives early in the design stage.
All hydroelectric structures affect a river’s ecology mainly by inducing a change in its hydrologic
characteristics and by disrupting the ecological continuity of sediment transport and fish migration
through the building of dams, dikes and weirs. However the extent to which a river’s physical, chemical
and biological characteristics are modified depends largely on the type of HPP. Whereas run-of-river
HPPs do not alter a river’s flow regime, the creation of a reservoir for storage hydropower entails a
major environmental change by transforming a fast-running fluvial ecosystem into a still-standing
lacustrine one. The extent to which a hydropower project has adverse impacts on the riverbed
morphology, on water quality and on fauna and flora is highly site-specific and to a certain degree
dependent on what resources can be invested into mitigation measures. A more detailed summary of
ecological impacts and their possible management measures are discussed in Sections 5.6.1.1 though
5.6.1.6.
Similar to a HPPs environmental effects, the extent of its social impacts on the local and regional
communities, land use, the economy, health and safety or heritage varies according to project type and
site-specific conditions. While run-of-river projects generally introduce little social change, the creation
of a reservoir in a densely populated area can entail significant challenges related to resettlement and
impacts on the livelihoods of the downstream populations. Restoration and improvement of living
standards of affected communities is a long-term and challenging task that has been managed with
variable success in the past (WCD, 2000). Whether HPPs can contribute to fostering socioeconomic
development depends largely on how the generated services and revenues are shared and distributed
among different stakeholders. As documented by Scudder (2005), HPPs can also have positive impacts
on the living conditions of local communities and the regional economy, not only by generating
electricity but also by facilitating, through the creation of freshwater storage schemes, multiple other
water-dependent activities, such as irrigation, navigation, tourism, fisheries or sufficient water supply to
municipalities and industries while protecting against floods and droughts. Yet, inevitably questions
arise about the sharing of these revenues among the local affected communities, government, investors
and the operator. Key challenges in this domain are the fair treatment of affected communities and
especially vulnerable groups like indigenous people, resettlement if necessary, and public health issues,
as well as appropriate management of cultural heritage values that will be discussed in more detail in
Sections 5.6.1.7 through 5.6.1.11.
All in all, for the sake of sustainability it is important to assess the negative and positive impacts of a
hydropower project in the light of a region’s needs for energy and water management services. An
overview of the main energy and water management services and distinctive environmental
characteristics in relation to the different HP project types are presented in the Table 5.5.
According to the results of decade-long IEA research focusing on hydropower and the environment, 11
sensitive issues have been identified that need to be carefully assessed and managed to achieve
sustainable hydropower projects. These peer-reviewed reports were produced under the IEA
Implementing Agreement on Hydropower Technologies between 1996 and 2006 in collaboration with
private agencies, governmental institutions, universities, research institutions and international
organizations with relevance to the subject. They are based on more than 200 case studies, involving
more than 112 experts from 16 countries, and are considered to be the most comprehensive international
information source presently available with regard to managing social and environmental issues related
to hydropower. Unless a different reference is mentioned, Sections 5.6.1.1 to 5.6.1.11 are based on the
outcomes of these five IEA reports (IEA, 2000a,b,c,d,e).
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Table 5.5 | Types of hydropower projects, their main services and distinctive environmental and social
characteristics (adapted from IEA, 2000d; Egré and Milewski, 2002). The number of subsections within
section 5.6.1 that address specific impacts are given in parentheses.
HPP Type Energy and water management
services Main environmental and social characteristics
(corresponding subsection)
All Renewable electricity generation
Increased water management options
Barrier for fish migration and navigation (1,6), and
sediment transport (4)
Physical modification of riverbed and shorelines (1)
Run-of-river
Limited flexibility and increased
variability in electricity generation
output profile
Water quality (but no water quantity)
management
Unchanged river flow when powerhouse in dam toe;
when localized further downstream reduced flow
between intake and powerhouse (1)
Reservoir
(Storage)
Storage capacity for energy and water
Flexible electricity generation output
Water quantity and quality
management; groundwater
stabilization; water supply and flood
management, see also Section 5.10
Alteration of natural and human environment by
impoundment (2), resulting in impacts on ecosystems
and biodiversity (1, 5, 6) and communities (7–11)
Modification of volume and seasonal patterns of river
flow (1), changes in water temperature and quality (3),
land use change-related GHG emissions (see Section
5.6.2)
Multipurpose As for reservoir HPPs; Dependent on
water consumption of other uses
As for reservoir HPP;
Possible water use conflicts;
Driver for regional development (see Box 5.1)
Pumped storage Storage capacity for energy and
water; net consumer of electricity due
to pumping
No water management options
Impacts confined to a small area; often operated outside
the river basin as a separate system that only exchanges
the water from a nearby river from time to time
5.6.1.1 Hydrological regimes
A hydropower project may modify a river’s flow regime if the project includes a reservoir. Run-of-river
projects change the river’s flow pattern marginally, thus creating fewer impacts downstream from the
project.
Hydropower plants with reservoirs significantly modify the downstream flow regime (i.e., the magnitude
and timing of discharge and hence water levels), and may also alter water temperature over short
stretches downstream. Some RoR hydropower projects with river diversions may alter flows along the
diversion routes. Physical and biological changes are related to such variations in water level, timing and
temperature. Major changes in the flow regime may also cause changes in the river’s estuary, where the
extent of salt water intrusion depends on the freshwater discharge.
The slope, current velocity and water depth are also important factors influencing sediment-carrying
capacity and erosion (Section 5.6.1.4). The construction of a major dam decreases in general the
sediment loading to river deltas.
The change in the annual flow pattern may affect significantly natural aquatic and terrestrial habitats in
the river and along the shore. The disappearance of heavy natural floods as the result of regulating
watercourses alters the natural lifecycle of the floodplains located downstream from the structure. This
may affect vegetation species and community structure, which in turn affect the mammalian and avian
fauna. On the other hand, frequent (daily or weekly) fluctuations in the water level downstream from a
hydropower reservoir and a tailrace area might create problems for both mammals and birds. Sudden
water releases could not only drown animals and wash away waterfowl nests, but also represent a public
security issue for other water users. The magnitude of these changes can be mitigated by proper power
plant operation and discharge management, regulating ponds, information and warning systems as well
as access limitations. A thorough flow-management program can prevent loss of habitats and resources.
Further possible mitigation measures might be the release of controlled floods in critical periods and
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building of weirs in order to maintain water levels in rivers with reduced flow or to prevent salt intrusion
from the estuary.
5.6.1.2 Reservoir creation
Creating a reservoir entails not only the transformation of a terrestrial ecosystem into an aquatic one, it
also makes important modifications to river flow regimes by transforming a relatively fast-flowing water
course into a still-standing water body: an artificial lake. For this reason, the most suitable site for a
reservoir needs to be thoroughly studied, as the most effective impact avoidance action is to limit the
extent of flooding on the basis of technical, economic, social and environmental considerations.
Fluctuations in water levels often lead to erosion of the reservoir shoreline (draw-down zone) and along
the downstream riverbanks. Measures to promote vegetation or erosion control following reservoir
impoundment include bank restoration, riparian vegetation enhancement, installation of protective
structures (e.g., gravel embankments, riprap, gabions) as well as bioengineering for shore protection and
enhancement.
The creation of a reservoir causes profound changes in fish habitats. Generally, the transformation of a
river into a lake favours species that are adapted to still-standing waters to the detriment of those species
requiring faster flowing water (see Section 5.6.1.5).Due to the high phytoplankton productivity of
reservoirs, the fish biomass tends to increase overall. However, the impacts of reservoirs on fish species
may only be perceived as positive if species are of commercial value or appreciated for sport and
subsistence fishing. If water quality proves to be inadequate, measures to enhance the quality of other
water bodies for valued species should be considered in cooperation with affected communities. Other
options to foster the development of fish communities and fisheries in and beyond the reservoir zone are,
for example, to create spawning and rearing habitat; to install fish incubators; to introduce fish farming
technologies; to stock fish species of commercial interest that are well adapted to reservoirs as long as
this is compatible with the conservation of biodiversity within the reservoir and does not conflict with
native species; to develop facilities for fish harvesting, processing and marketing; to build access roads,
ramps and landing areas or to cut trees prior to impoundment along navigation corridors and fishing
sites; to provide navigation maps and charts; and to recover floating debris.
As reservoirs replace terrestrial habitats, it is also important to protect and/or recreate the types of
habitats lost through inundation (WCD, 2000). In general, long-term compensation and enhancement
measures have turned out to be beneficial. Further possible mitigation measures might be to protect areas
and wetlands that have an equivalent or better ecological value than the land lost; to preserve valuable
land bordering the reservoir for ecological purposes and erosion prevention; to conserve flooded
emerging forest in some areas for brood-rearing waterfowl; to enhance the habitat of reservoir islands for
conservation purposes; to develop or enhance nesting areas for birds and nesting platforms for raptors; to
practice selective wood cutting for herbivorous mammals; and to implement wildlife rescue and
management plans. Good-practice examples show that some hydropower reservoirs have even been
recognized as new, high-value ecosystems by being registered as ‘Ramsar’ reservoirs in the Ramsar List
of Wetlands of International Importance.20
5.6.1.3 Water quality
In some densely populated areas with rather poor water quality, RoR hydropower plants are regularly
used to improve oxygen levels and filter tonnes of floating waste out of the river, or to reduce high water
temperature levels from thermal power generating outlets. However, maintaining the water quality of
reservoirs is often a challenge, as reservoirs constitute a focal point for the river basin catchment. In
20 The Ramsar Convention on Wetlands of International Importance is an intergovernmental treaty that provides the
framework for national action and international cooperation on the conservation and wise use of wetlands and their resources.
The convention was signed in Ramsar, Iran, in 1971 and entered into force in 1975. The Ramsar List of Wetlands of
International Importance (2009) and other information is available at http://www.ramsar.org.
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cases where municipal, industrial and agricultural waste waters entering the reservoir are exacerbating
water quality problems, it might be relevant that proponents and stakeholders cooperate in the context of
an appropriate land and water use plan encompassing the whole catchment area, preventing, for
example, excessive usage of fertilizers and pesticides.
Water quality issues related to reservoirs depend on several factors: climate, reservoir morphology and
depth, water retention time in the reservoir, water quality of tributaries, quantity and composition of the
inundated soil and vegetation, and rapidity of impounding, which affects the quantity of biomass
available over time. Also, the operation of the HPP and thus the reservoir can significantly affect water
quality, both negatively and positively
Water quality issues can often be managed by site selection and appropriate design, taking the future
reservoir morphology and hydraulic characteristics into consideration. The primary goals are to reduce
the submerged area and to minimize water retention in the reservoir. The release of poor-quality water
(due to thermal stratification, turbidity and temperature changes both within and downstream of the
reservoir) may be reduced by the use of selective or multi-level water intakes. This may also help to
reduce oxygen depletion and the volume of anoxic waters. Since the absence of oxygen may contribute
to the formation of methane during the first few years after impoundment, especially in warm climates,
measures to prevent the formation of anoxic reservoir zones will also help mitigate potential methane
emissions (see Section 5.6.3 for more details).
Spillways, stilling basins or structures that promote degassing, such as aeration weirs, may help to avoid
downstream gas super-saturation. While some specialists recommend pre-impoundment clearing of the
reservoir area, this must be carried out carefully because (i) in some cases, significant re-growth may
occur prior to impoundment (and will be rapidly degraded once flooded) and (ii) the massive and sudden
release of nutrients (in the case of vegetation clearance through burning) may lead to algal blooms and
water quality problems. In some situations, filling up and then flushing out the reservoir prior to
commercial operation might contribute to water quality improvement. Planning periodic peak flows can
increase aquatic weed drift and decrease suitable substrates for weed growth, reducing problems with
undesired invasive species. Increased water turbidity can be mitigated by protecting shorelines that are
highly sensitive to erosion, or by managing flow regimes in a manner that reduces downstream erosion.
5.6.1.4 Sedimentation
The sediment-carrying capacity of a river depends on its hydrologic characteristics (slope, current
velocity, water depth), the nature of the sediments in the riverbed and the material available in the
catchment. In general, a river’s sediment load is composed of sediments from the riverbed and sediments
generated by erosion in the drainage basin. Dams reduce current velocity and the slope of the water
body. The result is a decrease in sediment-carrying capacity. Flow reduction contributes to lower
sediment transport capacity and increased sediment deposition, which could lead to the raising of
riverbed and an increase in flood risk, as, for example, experienced in the lower reaches of the Yellow
River (Xu, 2002). The scope of the impact depends on the natural sediment load of the river basin, which
varies according to geomorphologic composition of the riverbed, as well as the soil composition and the
vegetation coverage of the drainage basin. In areas dominated by rocky granite, such as in Canada and
Norway, sedimentation is generally not an issue. Rivers with large sediment loads are found mainly in
arid and semi-arid or mountainous regions with fine soil composition. A World Bank study (Mahmood,
1987) estimated that about 0.5 to 1% of the total freshwater storage capacity of existing reservoirs is lost
each year due to sedimentation. Similar conditions were also reported by WCD (2000) and ICOLD
(2004). Climate change may affect sediment generation, transport processes, sediment flux in a river and
sedimentation in reservoirs, due to changes in hydrological processes and, in particular, floods (Zhu et
al., 2007).
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In countries with extensive sediment control works such as Japan, the riverbed is often lowered in the
middle to downstream reaches of rivers, causing serious scoring of bridge piers and disconnection
between water use or intake facilities and the lowered river water table (Takeuchi, 2004). Virtually no
sediment has been discharged from the Nile River below Aswan High Dam since its construction
(completed in 1970), which has resulted in a significant erosion of the riverbed and banks and retreat of
its estuary (Takeuchi et al., 1998). The bed of the Nile, downstream of the High Aswan Dam, was
reported to be lowered by some 2 to 3 m in the years following completion of the dam, with irrigation
intakes left high and dry and bridges undermined (Helland-Hansen et al., 2005).
Besides exposing the machinery and other technical installations to significant wear and tear (see
Section 5.3.3.3), sedimentation also has a major impact on reservoirs by depleting not only their storage
capacity over time due to sediment deposition, but also by increasing the risk of upstream flooding due
to continuous accumulation of sediments in the backwater region (Goodwin et al., 2001; Wang and Hu,
2004).
In order to gain precise knowledge about long-term sediment inflow characteristics and to support
proper site selection, the Revised Universal Soil Loss Equation is a method that is widely utilized to
estimate soil erosion from a particular land area (Renard et al., 1997). The Geographic Information
System (GIS)-based model includes calibration and the use of satellite images to determine vegetation
coverage for the entire basin, which determines the erosion potential of the sub-basins as well as the
critical areas. If excessive reservoir sedimentation cannot be avoided by proper site selection,
appropriate provision of storage volume that is compatible with the required project life has to be
planned. If sediment loading occurs, it can be reduced by opening the spillway gates to allow for
sediment flushing during flooding or by adding sluices to the main dam. Different sediment-trapping
devices or conveyance systems have also been used with success, along with extraction of coarse
material from the riverbed and dredging of sediment deposits However, adequate bank protection in the
catchment area and the protection of the natural vegetation in the watershed is one of the best ways to
minimize erosion and prevent sediment loading.
5.6.1.5 Biological diversity
Although existing literature related to ecological effects of river regulations on wildlife is extensive
(Nilsson and Dynesius, 1993; WCD, 2000), the knowledge is mainly restricted to and based on
environmental impact assessments. A restricted number of long-term studies have been carried out that
enable predictions of species-specific effects of hydropower development on fish, mammals and birds.
In general, four types of environmental disturbances are singled out:
habitat changes;
geological and climatic changes;
direct mortality; and
increased human use of the area.
Most predictions are, however, very general and only able to focus on the type of change, without
quantifying the short- and long-term effects. Thus, it is generally realized that current knowledge cannot
provide a basis for precise predictions. The impacts are, however, highly species-, site-, seasonal- and
construction-specific.
The most serious causes of ecological effects from hydropower development on wildlife are, in general:
permanent loss of habitat and special biotopes through inundation;
loss of flooding;
fluctuating water levels (and habitat change);
introduction and dispersal of exotic species; and
obstacles to fish migration.
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Fish are among the main organisms of aquatic wildlife to be affected by a HPP. Altered flow regimes,
changes in temperature and habitat modifications are known types of negative impacts (Helland-Hansen
et al., 2005) impacting fish. Rapidly changing water levels following hydropower peaking operations are
another type of impact that may also affect the downstream fish populations. Yet, in some cases, the
effects on the river system from various alterations following regulation may also be positive. For
instance, L’Abée-Lund et al. (2006) compared 22 Norwegian rivers, both regulated and non-regulated,
based on 128 years of catch statistics. For the regulated rivers they observed no significant effect of
hydropower development on the annual catch of anadromous salmonids. For two of the regulated rivers
the effect was positive. In addition, enhancement measures such as stocking and building fish ladders
significantly increased annual catches. A review by Bain (2007) looking at several hydropower peaking
cases in North America and Europe indicates clearly that the impacts from HPPs in the operational phase
are variable, but may have a positive effect on downstream areas.
On the other hand, peaking may lead to rapid shifts in the water level where the HPP discharges into a
river (as opposed to lakes or the ocean). Sudden shutdown of the peaking HPP may lead to a rapid fall in
the water table downstream and a possibility for so-called stranding of fish, where especially small
species or fry may be locked in pools, between rocks of various sizes, or in the gravel. An example is
salmonid fry that may use dewatered areas. Experiments indicate that if the water level, after a shutdown
of the HPP, falls at a rate of below 10 to 15 cm/hr, stranding in most cases will not be a problem,
depending on local conditions (Saltveit et al., 2001). However, there are individual differences and fish
may also be stranded at lower rates (Halleraker et al., 2003), and even survive for several hours in the
substrate after dewatering (Saltveit et al., 2001).
A submerged land area loses all terrestrial animals, and many animals will be dispelled or sometimes
drown when a new reservoir is filled. This can be partly mitigated through implementation of a wildlife
rescue program, although it is generally recognized that these programs may have a limited effect on the
wild populations on the long term (WCD, 2000; Ledec and Quintero, 2003). Endangered species
attached to specific biotopes require particular attention and dedicated management programs prior to
impoundment. Increased aquatic production caused by nutrient leakage from the inundated soil
immediately after damming has been observed to affect both invertebrates and vertebrates positively for
some time, that is, until the soil nutrients have been washed out. An increase in aquatic birds associated
with this damming effect in the reservoir has also been observed.
Whereas many natural habitats are successfully transformed for human purposes, the natural value of
certain other areas is such that they must be used with great care or left untouched. The choice can be
made to preserve natural environments that are deemed sensitive or exceptional. To maintain biological
diversity, the following measures have proven to be effective: establishing protected areas; choosing a
reservoir site that minimizes loss of ecosystems; managing invasive species through proper
identification, education and eradication; and conducting specific inventories to learn more about the
fauna, flora and specific habitats within the studied area.
5.6.1.6 Barriers for fish migration and navigation
Dams may create obstacles for the movement of migratory fish species and for river navigation. They
may reduce access to spawning grounds and rearing zones, leading to a decrease in migratory fish
populations and fragmentation of non-migratory fish populations. However, natural waterfalls also
constitute obstacles to upstream fish migration and river navigation. Dams that are built on such
waterfalls therefore do not constitute an additional barrier to passage. Solutions for upstream fish
migrations are now widely available: a variety of solutions have been tested for the last 30 years and
have shown acceptable to high efficiency. Fish ladders can partly restore the upstream migration, but
they must be carefully designed, and well suited to the site and species considered (Larinier and
Marmulla, 2004). High-head schemes are usually off limits for fish ladders. Conversely, downstream
fish migration remains more difficult to address. Most fish injuries or mortalities during downstream
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movement are due to their passage through turbines and spillways. In low-head HPPs, improvement in
turbine design (for instance ‘fish-friendly turbines’), spillway design or overflow design has proven to
successfully reduce fish injury or mortality rates, especially for eels, and to a lesser extent salmonids
(Amaral et al., 2009). More improvements may be obtained by adequate management of the power plant
flow regime or through spillway openings during downstream movement of migratory species. Once the
design of the main components (plant, spillway, overflow) has been optimized for fish passage, some
avoidance systems may be installed (screens, strobe and laser lights, acoustic cannons, bubbles, electric
fields etc.). However, their efficiency is highly site- and species-dependent, especially in large rivers. In
some cases, it may be more useful to capture fish in the headrace or upstream and release the individuals
downstream. Other common devices include bypass channels, fish elevators with attraction flow or
leaders to guide fish to fish ladders and the installation of avoidance systems upstream of the power
plant.
To ensure navigation at a dam site, ship locks are the most effective technique available. For small craft,
lifts and elevators can be used with success. Navigation locks can also be used as fish ways with some
adjustments to the equipment. Sometimes, it is necessary to increase the upstream attraction flow. In
some projects, bypass or diversion channels have been dug around the dam.
5.6.1.7 Involuntary population displacement
Although not all hydropower projects require resettlement, involuntary displacement is one of the most
sensitive socioeconomic issues surrounding hydropower development (WCD, 2000; Scudder, 2005). It
consists of two closely related, yet distinct processes: displacing and resettling people as well as
restoring their livelihoods through the rebuilding or ‘rehabilitation’ of their communities.
When involuntary displacement cannot be avoided, the following measures might contribute to optimize
resettlement outcomes:
involving affected people in defining resettlement objectives, in identifying reestablishment
solutions and in implementing them; rebuilding communities and moving people in groups, while
taking special care of indigenous peoples and other vulnerable social groups;
publicizing and disseminating project objectives and related information through community
outreach programs, to ensure widespread acceptance and success of the resettlement process;
improving livelihoods by fostering the adoption of appropriate regulatory frameworks, by
building required institutional capacities, by providing necessary income restoration and
compensation programs and by ensuring the development and implementation of long-term
integrated community development programs;
allocating resources and sharing benefits, based upon accurate cost assessments and
commensurate financing, with resettlement timetables tied to civil works construction and
effective executing organizations that respond to local development needs, opportunities and
constraints.
5.6.1.8 Affected people and vulnerable groups
Like in all other large-scale interventions, it is important during the planning of hydropower projects to
identify through a proper social impact study who will benefit from the project and especially who will
be exposed to negative impacts. Project-affected people are individuals living in the region that is
impacted by a hydropower project’s preparation, implementation and/or operation. These may be within
the catchment, reservoir area, downstream, or in the periphery where project-associated activities occur,
and also can include those living outside of the project-affected area who are economically affected by
the project.
A massive influx of workers and creation of transportation corridors also have a potential impact on the
environment and surrounding communities if not properly controlled and managed. In addition, workers
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should be in a position once demobilized at least to return to their previous activities, or to have access
to other construction sites due to their increased capacities and experience.
Particular attention needs to be paid to groups that might be considered vulnerable with respect to the
degree to which they are marginalized or impoverished and their capacity and means to cope with
change. Although it is very difficult to mitigate or fully compensate the social impacts of reservoir
hydropower projects on indigenous or other culturally vulnerable communities for whom major
transformations to their physical environment run contrary to their fundamental beliefs, special attention
has to be paid to those groups in order to ensure that their needs are integrated into project design and
adequate measures are taken.
Negative impacts can be minimized for such communities if they are willing partners in the development
of a hydropower project, rather than perceiving it as a development imposed on them by an outside
agency with conflicting values. Such communities require sufficient lead time, appropriate resources and
communication tools to assimilate or think through the project’s consequences and to define on a
consensual basis the conditions in which they would be prepared to proceed with the proposed
development. Granting long-term financial support for activities that define local cultural specificities
may also be a way to minimize impacts as well as ensure early involvement of concerned communities
in project planning in order to reach agreements on proposed developments and economic spin-offs
between concerned communities and proponents. Furthermore, granting legal protections so that affected
communities retain exclusive rights to the remainder of their traditional lands and to new lands obtained
as compensation might be an appropriate mitigation measure as well as to restrict access of non-residents
to the territory during the construction period while securing compensation funds for the development of
community infrastructure and services such as access to domestic water supply or to restore river
crossings and access roads. Also, it is possible to train community members for project-related job
opportunities.
5.6.1.9 Public health
In warmer climate zones, the creation of still-standing water bodies such as reservoirs can lead to
increases in waterborne diseases like malaria, river blindness, dengue or yellow fever, which need to be
taken into account when designing and constructing reservoirs for supply security, which may be one of
the most pressing needs in these regions.
In other zones, a temporary increase in mercury may have to be managed in the reservoir, due to the
liberation of mercury from the soil through bacteria, which can then enter the food chain in the form of
methyl mercury. In some areas, human activities like coal burning (North America) and mining
represent a significant contributor.
Moreover, higher incidences of behavioural diseases linked to increased population densities are
frequent consequences of large construction sites. Therefore, public health impacts should be considered
and addressed from the outset of the project.
Reservoirs that are likely to become the host of waterborne disease vectors require provisions for
covering the cost of health care services to improve health conditions in affected communities. In order
to manage health effects related to substantial population growth around hydropower reservoirs, options
may include controlling the influx of migrant workers or migrant settlers as well as planning the
announcement of the project in order to avoid early population migration to an area not prepared to
receive them. Moreover, mechanical and/or chemical treatment of shallow reservoir areas could be
considered to reduce the proliferation of insects carrying diseases, while planning and implementing
disease prevention programs. Additional options include increasing access to good quality medical
services in project-affected communities and in areas where population densities are likely to increase as
well as establishing detection and epidemiological monitoring programs, establishing public health
education programs directed at the populations affected by the project and implementing a health plan
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for the work force and along the transportation corridor to reduce the risk of transmittable diseases (e.g.,
sexually transmitted diseases).
5.6.1.10 Cultural heritage
Cultural heritage is the present manifestation of the human past and refers to sites, structures and
remains of archaeological, historical, religious, cultural and aesthetic value (World Bank, 1994).
Exceptional natural landscapes or physical features of the environment are also an important part of
human heritage as landscapes are endowed with a variety of meanings. The creation of a reservoir might
lead to the disappearance of valued exceptional landscapes such as spectacular waterfalls and canyons.
Long-term landscape modifications can also occur through soil erosion, sedimentation and low water
levels in reservoirs as well as through associated infrastructure impacts (e.g., new roads, transmission
lines). It is therefore important that appropriate measures be taken to preserve natural beauty in the
project area and to protect cultural properties with high historic value.
Possible measures to minimize negative impacts are, for example: ensuring on- site protection;
conserving and restoring, relocating and/or re-creating important physical and cultural resources;
creating a museum in partnership with local communities to make archaeological findings,
documentation and record keeping accessible; including landscape architecture competences into the
project design to optimize harmonious integration of the infrastructure into the landscape; using borrow
pits and quarries for construction material that will later disappear through impoundment; re-vegetating
dumping sites for soil and excavation material with indigenous species; putting transmission lines and
power stations underground in areas of exceptional natural beauty; incorporating residual flows to
preserve important waterfalls at least during the tourism high season; keeping as much as possible the
natural appearance of river landscapes by constructing weirs to adjust the water level using local rocks
instead of concrete; and by constructing small islands in impounded areas, which might be of ecological
interest for waterfowl and migrating birds
5.6.1.11 Sharing development benefits
The economic importance of hydropower and irrigation dams for densely populated countries that are
affected by scarce water resources for agriculture and industry, limited access to indigenous sources of
oil, gas or coal, and frequent shortages of electricity may be substantial. In many cases, however,
hydropower projects have resulted both in winners and losers: affected local communities have often
born the brunt of project-related economic and social losses, while people outside the project area have
benefited from better access to affordable power and improved flood/drought protection. Although the
overall economic gains may be substantial, special attention has to be paid to those local and regional
communities that have to cope with the negative impacts of a HPP to ensure that they get a faire share of
benefits from the project as compensation. This may take many forms including business partnerships,
royalties, development funds, equity sharing, job creation and training, jointly managed environmental
mitigation and enhancement funds, improvements of roads and other infrastructure, recreational and
commercial facilities (e.g., tourism, fisheries), sharing of revenues, payment of local taxes, or granting
preferential electricity rates and fees for other water-related services to local companies and project-
affected populations.
Box 5.1 | Possible multiplier effects of hydropower projects.
Dam projects generate numerous impacts both on the region where they are located, as well as at an inter-regional,
national and even global level (socioeconomic, health, institutional, environmental, ecological and cultural
impacts). The World Commission on Dams (WCD) and numerous other studies have discussed the importance
and difficulties of evaluating a number of these impacts. One of the issues raised by these studies is the need to
extend consideration to indirect benefits and costs of dam projects (Bhatia et al., 2003). According to the WCD’s
Final Report (WCD, 2000) “a simple accounting for the direct benefits provided by large dams—the provision of
irrigation water, electricity, municipal and industrial water supply, and flood control—often fails to capture the
full set of social benefits associated with these services. It also misses a set of ancillary benefits and indirect
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economic (or multiplier) benefits of dam projects”. Indirect impacts are called multiplier impacts, and result from
both inter-industry linkage impacts (increase in the demand for an increase in outputs of other sectors) and
consumption-induced impacts (increase in incomes and wages generated by the direct outputs). Multipliers are
summary measures expressed as a ratio of the total effects (direct and indirect) of a project to its direct effects. A
multi-country study on multiplier effects of large hydropower projects was performed by the World Bank (2005),
which estimates that the multiplier values for large scale hydropower projects vary from 1.4 to 2.0, meaning that
for every dollar of value generated by the sectors directly involved in dam-related activities, another 40 to 100
cents could be generated indirectly in the region. Though these multiplier benefits are not unique to hydropower
projects, but accompany—to varying degrees—any energy project, they nonetheless represent benefits that might
be considered by communities considering hydropower development.
5.6.2 Guidelines and regulations
The assessment and management of the above impacts represents a key challenge for hydropower
development. The issues at stake are complex and have long been the subject of intense controversy
(Goldsmith and Hilyard, 1984). Moreover, unsolved socio-political issues, which are often not project
related, tend to come to the forefront of the decision-making process in a large-scale infrastructure
development (Beauchamp, 1997).
Throughout the past decades, project planning has increasingly witnessed a paradigm shift from a
technocratic approach to a participative one (Healey, 1992). This shift is also reflected in the evolution
of the environmental and social impact assessment and management process that is summarized in
Figure 5.14. Today, stakeholder consultation has become an essential tool to improve project outcomes.
It is therefore important to identify key stakeholders such as local, national or regional authorities,
affected populations, or environmental NGOs, early in the development process in order to ensure
positive and constructive consultations, and develop a clear and common understanding of the associated
environmental and social impacts, risks and opportunities. Emphasizing transparency and an open,
participatory decision-making process, this new approach is driving both present-day and future
hydropower projects towards increasingly more environment-friendly and sustainable solutions. At the
same time, the concept and scope of environmental and social management associated with hydropower
development and operation have changed, moving from a mere impact assessment process to a global
management plan encompassing all sustainability aspects.
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Figure 5.14 | Evolution of environmental and social impact assessment and management (adapted
from UNEP, 2007).
In particular, the planning of larger hydropower developments mandates guidelines and regulations to
ensure that impacts are assessed as objectively as possible and managed in an appropriate manner. In
many countries a strong national legal and regulatory framework has been put in place to determine how
hydropower projects shall be developed and operated, through a licensing process and follow-up
obligations enshrined into the operating permit often also known as concession agreement. Yet,
discrepancies between various national regulations as well as controversies have lead to the need to
establish international guidelines on how to avoid, minimize or compensate negative impacts while
maximizing the positive ones.
Besides the international financing agencies’ safeguard policies, one of the first initiatives was launched
in 1996 by countries like Canada, Norway, Sweden, Spain and the USA for which hydropower is an
important energy resource. Their governments set up, in collaboration with their mainly state-owned
hydropower utilities and research institutions, a five-year research program under the auspices of the
International Energy Agency (IEA, 2000c) called ‘Hydropower and the Environment’. In 1998, the
World Commission on Dams (WCD) was established to review the development effectiveness of large
dams, to assess alternatives for water and power development, and to develop acceptable criteria,
guidelines and standards, where appropriate, for the planning, design, appraisal, construction, operation,
monitoring and decommissioning of dams. As a result, 5 core values,21 8 strategic priorities22 and 26
guidelines were suggested (WCD, 2000). While governments, financiers and the industry have widely
endorsed the WCD core values and strategic priorities, they consider the guidelines to be only partly
21 Equity, efficiency, participatory decision making, sustainability, and accountability.
22 Gaining public acceptance, comprehensive options assessment, addressing existing dams, sustaining rivers and livelihoods,
recognizing entitlements and sharing benefits, ensuring compliance, sharing rivers for peace, development and security.
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applicable to hydropower dams. As a consequence, international financial institutions such as the World
Bank, the Asian Development Bank, the African Development Bank and the European Bank for
Reconstruction and Development have not endorsed the WCD report as a whole, in particular not its
guidelines, but they have kept or developed their own guidelines and criteria (World Bank, 2001). All
major export credit agencies have done the same (Knigge et al., 2008). Whereas the WCD’s work
focused on analyzing the reasons for shortcomings with respect to poorly performing dams, its follow-up
initiative, the ‘Dams and Development Project’ hosted by the UN Environment Programme (UNEP), put
an emphasis on gathering good practice into a compendium (UNEP, 2007). With a similar goal, the IEA
launched in 2000 a second hydropower-specific five-year research program called ‘Hydropower Good
Practice’ (IEA, 2006) to further document effective management of key environmental and social issues.
Even though each financing agency has developed its own set of quality control criteria to ensure
acceptable environmental and social project performance (e.g., World Bank Safeguard, International
Finance Corporation’s Performance Standards, etc.), there is still no broadly accepted standard to assess
the economic, social and environmental performance specifically for hydropower projects. In order to
meet this need, the International Hydropower Association (IHA) has produced Sustainability Guidelines
(IHA, 2004) and a Hydropower Sustainability Assessment Protocol (IHA, 2006), both of which are
based on the broadly shared five core values and seven strategic priorities of the WCD report, taking the
hydropower-specific previous IEA study as starting point. This industry-initiated process may be further
improved by a multi-stakeholder review initiative called the Hydropower Sustainability Assessment
Forum. This cross-sector working group is comprised of representatives from governments of developed
and developing countries, as well as from international financial institutions, NGOs and industry
groups.23 A recommended Final Draft Protocol was published in November 2010 (IHA, 2010) and a
continuous improvement process has been put in place for its further application and review.
5.6.3 Lifecycle assessment of environmental impacts
Life cycle assessment (LCA) aims at comparing the full range of environmental impacts assignable to
products and services, across their lifecycle, including all processes upstream and downstream of
operation or use of the product/service. The following subsection focuses on LCA for GHG emissions,
while other metrics are briefly discussed in Box 5.2, and more comprehensively in Section 9.3.4.
The lifecycle of hydropower plants consists of three main stages:
Construction: In this phase, GHGs are emitted from the production and transportation of
materials (e.g., concrete, steel etc.) and the use of civil work equipment and materials for
construction of the facility (e.g., diesel engines).
Operation and maintenance: GHG emissions can be generated by operation and maintenance
activities, for example, building heating/cooling systems, auxiliary diesel generating units, or
onsite staff transportation for maintenance activities. Furthermore, land use change induced by
reservoir creation and the associated modification of the terrestrial carbon cycle must be
considered, and may lead to net GHG emissions from the reservoir during operation (see Section
5.6.3.1).
Dismantling: Dams can be decommissioned for economic, safety or environmental reasons. Up
to now, only a small number of small-size dams have been removed, mainly in the USA.
Therefore, emissions related to this stage have rarely been included in LCAs so far.
23 For example, the World Bank, the Equator Principles Financial Institutions, the World Wide Fund for Nature, the Nature
Conservancy, Transparency International, Oxfam and the IHA.
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Box 5.2 | Energy payback and lifecycle water use.
The energy payback ratio is the ratio of total energy produced during a system’s normal lifespan to the energy
required to build, maintain and fuel that system. Other metrics that refer to the same basic calculation include the
energy returned on energy invested, or the energy ratio (see Annex II). A high energy payback ratio indicates
good performance. Lifecycle energy payback ratios for well-performing hydropower plants reach the highest
values of all energy technologies, ranging from 170 to 267 for run-of-river, and from 205 to 280 for reservoirs
(Gagnon, 2008). However, the range of performances is wider, with literature reporting minimum values of 30 to
50 (Gagnon et al., 2002) or even lower values (Kubiszewski et al., 2010; see also Box 9.2).
Hydropower relies upon water in large quantities, but the majority of this is simply passed through the
turbines with negligible losses. As up- and downstream stages require little water, lifecycle water use is
close to zero for run-of-river hydropower plants (Fthenakis and Kim, 2010). However, consumptive use
in the form of evaporation can occur from hydroelectric reservoirs. Global assessments for lifecycle
water consumption of reservoirs are not available, and published regional results show high ranges for
different climatic and project conditions (Gleick, 1993; LeCornu, 1998; Torcellini et al., 2003; Mielke et al.,
2010). Allocation schemes for determining water consumption from various reservoir uses in the case of
multipurpose reservoirs can significantly influence reported water consumption values (see also Section 9.3.4.4).
Also, research may be needed to determine the net effect of reservoir construction on the evaporation in the
specific watershed.
5.6.3.1 Current lifecycle estimates of greenhouse gas emissions
LCAs carried out on hydropower projects up to now have demonstrated the difficulty of generalizing
estimates of lifecycle GHG emissions for hydropower projects across climatic conditions, pre-
impoundment land cover types and hydropower technologies. An important issue for hydropower is the
multipurpose nature of most reservoir projects, and allocation of total impacts to the several purposes
that is then required. Many LCAs to date allocate all impacts to the electricity generation function,
which in some cases may overstate the emissions for which they are ‘responsible’.
Figure 5.15 displays results of a review of the LCA literature reporting estimates of lifecycle GHG
emissions from hydropower technologies published since 1980 (see Annex II for further description of
review methods and list of references). The majority of lifecycle GHG emission estimates for
hydropower cluster between about 4 and 14 g CO2eq/kWh, but under certain scenarios there is the
potential for much larger quantities of GHG emissions, as shown by the outliers. Note that the
distributions shown in Figure 5.15 do not represent an assessment of likelihood; the figure simply
reports the distribution of currently published literature estimates passing screens for quality and
relevance. As depicted in Figure 5.15, reservoir hydropower has been shown to potentially emit over 150
g CO2eq/kWh, which is significantly higher than run-of-river or pumped storage, though fewer GHG
emission estimates exist for the latter two technologies.
The outliers stem from studies that included assessments of GHG emissions from land use change
(LUC) from reservoir hydropower. While the magnitude of potential LUC-related emissions from
reservoir hydropower (caused by inundation) is significant, uncertainty in the quantification of these
emissions is also high. LUC emissions can be both ongoing, (i.e., methane emitted from the reservoir
from soil and vegetation decomposition), and from decommissioning (release of GHGs from large
quantities of silt collected over the life of the plant). The LCAs evaluated in this assessment only
accounted for gross LUC-related GHG emissions. Characterizing a reservoir as a net emitter of GHGs
implies consideration of emissions that would have occurred without the reservoir, which is an area of
active research and currently without consensus (see Section 5.6.4.2). LUC-related emissions from
decommissioning have only been evaluated in two studies (Horvath, 2005; Pacca, 2007) that provided
three estimates (see Figure 5.15). Both reported significantly higher estimates of lifecycle GHG
emissions than the other literature owing to this differentiating factor. However, caution should be used
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in applying these two estimates of the impact of decommissioning broadly to all hydropower systems as
they may not be representative of other technologies, sites, or dam sizes.
Figure 5.15 | Lifecycle GHG emissions of hydropower technologies (unmodified literature values, after
quality screen). See Annex II for details of literature search and citations of literature contributing to the
estimates displayed. Emissions from reservoirs are referred to as gross GHG emissions.
Variability in estimates stems from differences in study context (e.g., climate, carbon stock of flooded
area), technological performance (e.g., turbine efficiency, lifetime, residence time of water) and methods
(e.g., LCA system boundaries) (UNESCO/IHA, 2008). For instance, the assumed operating lifetime of a
dam can significantly influence the estimate of lifecycle GHG emissions as it amortizes the construction-
and dismantling-related emissions over a shorter or longer period. Completion of additional LCA studies
is needed to increase the number of estimates and the breadth of their coverage in terms of climatic
zones, technology types, dam sizes etc.
5.6.3.2 Quantification of gross and net emissions from reservoirs
With respect to studies that have explored GHG impacts of reservoirs, research and field surveys on
GHG balances of freshwater systems involving 14 universities and 24 countries (Tremblay et al., 2005)
have led to the following conclusions:
All freshwater systems, whether they are natural or manmade, emit GHGs due to decomposing
organic material. This means that lakes, rivers, estuaries, wetlands, seasonal flooded zones and
reservoirs emit GHGs. They also bury some carbon in the sediments (Cole et al., 2007).
Within a given region that shares similar ecological conditions, reservoirs and natural water
systems produce similar levels of CO2 emissions per unit area. In some cases, natural water
bodies and freshwater reservoirs absorb more CO2 than they emit.
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Reservoirs are collection points for material coming from the whole drainage basin area upstream. As
part of the natural cycle, organic matter is flushed into these collection points from the surrounding
terrestrial ecosystems. In addition, domestic sewage, industrial waste and agricultural pollution may also
enter these systems and produce GHG emissions. Therefore, the assessment of man-made net emissions
involves a) appropriate estimation of the natural emissions from the terrestrial ecosystem, wetlands,
rivers and lakes that were located in the area before impoundment; and b) abstracting the effect of
carbon inflow from the terrestrial ecosystem, both natural and related to human activities, on the net
GHG emissions before and after impoundment.
The main GHGs produced in freshwater systems are CO2 and methane (CH4). Nitrous oxide (N2O) may
be of importance, particularly in reservoirs with large drawdown zones24 or in tropical areas, but no
global estimate of these emissions presently exists. Results from reservoirs in boreal environments
indicate a low quantity of N2O emissions, while a recent study of tropical reservoirs does not give clear
evidence of whether tropical reservoirs act as sources of N2O to the atmosphere (Guerin et al., 2008).
Two pathways of GHG emissions to the atmosphere are usually studied: diffusive fluxes from the
surface of the reservoir and bubbling (Figure 5.16). Bubbling refers to the discharge of gaseous
substances resulting from carbonation, evaporation or fermentation from a water body (UNESCO/IHA,
2010). In addition, studies at Petit-Saut, Samuel and Balbina have investigated GHG emissions
downstream of the dams (degassing just downstream of the dam and diffusive fluxes along the river
course downstream of the dam). CH4 transferred through diffusive fluxes from the bottom to the water
surface of the reservoir may undergo oxidation (i.e., be transformed into CO2) in the water column
nearby the oxycline when methanotrophic bacteria are present. Regarding N2O, Guerin et al. (2008) have
identified several possible pathways for N2O emissions: these could occur via diffusive flux, degassing
and possibly through macrophytes, but this last pathway has never been quantified for either boreal or
tropical environments.
Figure 5.16 | Carbon dioxide and methane pathways in a freshwater reservoir with an anoxic
hypolimnion (adapted from Guerin, 2006).
24 The drawdown zone is defined as the area temporarily inundated depending on the reservoir level variation during
operation.
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Still, for the time being, only a limited amount of studies appraising the net emissions from freshwater
reservoirs (i.e., excluding unrelated anthropogenic sources and pre-existing natural emissions) is
available, whereas gross fluxes have been investigated in boreal (e.g., Rudd et al., 1993; Tremblay et al.,
2005), temperate (Casper et al., 2000; Soumis et al., 2004; Therrien et al., 2005) and tropical/subtropical
(e.g., Guerin et al., 2008) regions. Gross emissions measurements are summarized in Table 5.6.
Table 5.6 | Range of gross CO2 and CH4 emissions from hydropower freshwater reservoirs; numbers of
studied reservoirs are given in parentheses (UNESCO-RED, 2008).
GHG pathway Boreal and temperate Tropical
CO2
(mmol/m2/d)
CH4
(mmol/m2/d)
CO2
(mmol/m2/d)
CH4
(mmol/m2/d)
Diffusive
fluxes
-23 to 145 (107) -0.3 to 8 (56) -19 to 432 (15) 0.3 to 51 (14)
Bubbling 0 0 to 18 (4) 0 0 to 88 (12)
Degassing1 ~0.2 (2) to 0.1 (2) n.a. 4 to 23 (1) 4 to 30 (2)
River below the
dam
n.a. n.a. 500 to 2500 (3) 2 to 350 (3)
Notes: 1The degassing (generally in mg/d) is attributed to the surface of the reservoir and is expressed in the same units as the
other fluxes (mmol/m2/d).
Gross emissions measurements in boreal and temperate regions from Canada, Finland, Iceland, Norway,
Sweden and the USA imply that highly variable results can be obtained for CO2 emissions, so that
reservoirs can act as sinks, but also can present significant CO2 emissions. In some cases, small CH4
emissions were observed in these studies. Under boreal and temperate conditions, significant CH4
emissions are expected only for reservoirs with large drawdown zones and high organic and nutrient
inflows.
In tropical regions, high temperatures coupled with important demand for oxygen due to the degradation
of substantial organic matter (OM) amounts favour the production of CO2, the establishment of anoxic
conditions, and thus the production of CH4. In new reservoirs, OM mainly comes from submerged
biomass and soil organic carbon with different absolute and relative contents of OM (Galy-Lacaux et al.,
1999; Blais et al., 2005; Descloux et al., 2010). Later, OM may also come from primary production or
other biological processes within the reservoir.
According to the UN Educational, Scientific and Cultural Organization (UNESCO) and the IHA
(UNESCO/IHA, 2008), measurements of gross emissions have been taken in the tropics at four
Amazonian locations and 16 additional sites in central and southern Brazil. They have shown, in some
cases, significant gross GHG emissions. Measurements are not available from reservoirs in other regions
of the tropics or subtropics except for Gatum in Panama, Petit-Saut in French Guyana and Nam Theun 2,
Nam Ngum and Nam Leuk in Lao People’s Democratic Republic (UNESCO/IHA, 2009). Preliminary
studies of Nam Ngum and Nam Leuk indicate that an old reservoir might act as a carbon sink under
certain conditions (Harby et al., 2009). This underlines the necessity to also monitor old reservoirs. The
age of the reservoir has proven to be an important issue as well as the organic carbon standing stock,
water residence time, type of vegetation, season, temperature, oxygen and local primary production,
themselves dependent on the geographic area (Fearnside, 2002). According to the IPCC (2006),
evidence suggests that CO2 emissions for approximately the first 10 years after flooding are the results
of decay of some of the organic matter on the land prior to flooding, but, beyond this time period, these
emissions are sustained by the input of inorganic and organic carbon material transferred into the
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flooded area from the watershed or by internal processes in the reservoir. In boreal and temperate
conditions, GHG emissions have been observed to return to the levels found in neighbouring natural
lakes after the two to four years following impoundment (Tremblay et al., 2005). Further measurements
could resolve this question for tropical conditions. Comparisons of these results are not easy to achieve,
as different methodologies and data (e.g., concerning equipment, procedures, units of measurement)
were applied for each study. Few measurements of material transported into or out of the reservoir have
been reported, and few studies have measured carbon accumulation in reservoir sediments (UNESCO-
RED, 2008).
Since 2008, UNESCO and IHA have been hosting an international research project, with the aim of
establishing a robust methodology to accurately estimate the net effect on GHG emissions caused by the
creation of a reservoir, and to identify gaps in knowledge. The project published GHG Measurement
Guidelines for Freshwater Reservoirs in 2010 (UNESCO/IHA, 2010) to enable standardized
measurements and calculations worldwide, and aims at delivering a database of results and
characteristics of the measurement specification guidance being applied to a representative set of
reservoirs worldwide. The final outcome will be building predictive modelling tools to assess the GHG
status of unmonitored reservoirs and new reservoir sites, and guidance on mitigation for vulnerable sites.
Recently, the IEA has set up a program called IEA Hydropower Agreement Annex XII that will work in
parallel with IHA and UNESCO to solve the GHG issue regarding reservoirs
5.7 Prospects for technology improvement and innovation25
Though hydropower is a proven and well-advanced technology, there is still room for further
improvement, for example, through optimization of operation, mitigating or reducing environmental
impacts, adapting to new social and environmental requirements and more robust and cost-effective
technological solutions.
Large hydropower turbines are now close to the theoretical limit for efficiency, with up to 96%
efficiency when operated at the best efficiency point, but this is not always possible and continued
research is needed to make more efficient operation possible over a broader range of flows. Older
turbines can have lower efficiency by design or reduced efficiency due to corrosion and cavitation
damage.
Potential therefore exists to increase energy output by retrofitting new equipment with improved
efficiency and usually also with increased capacity. Most of the existing hydropower equipment in
operation today will need to be modernized during the next three decades, allowing for improved
efficiency and higher power and energy output (UNWWAP, 2006) but also for improved environmental
solutions by utilizing environmental design principles.
The structural elements of a hydropower project, which tend to take up to 70% of the initial investment
cost for large hydropower projects, have a projected life of up to 100 years or more. On the equipment
side, some refurbishment can be an attractive option after 30 years. Advances in technology can justify
the replacement of key components or even complete generating sets. Typically, generating equipment
can be upgraded or replaced with more technologically advanced electromechanical equipment two or
three times during the life of the project, making more effective use of the same flow of water
(UNWWAP, 2006).
The US Department of Energy reported that a 6.3% generation increase could be achieved in the USA
from efficiency improvements if plant units fabricated in 1970 or prior years, having a total capacity of
30,965 MW, are replaced. Based on work done for the Tennessee Valley Authority and other
hydroelectric plant operators, a generation improvement of 2 to 5.2% has also been estimated for
conventional hydropower in the USA (75,000 MW) from installing new equipment and technology, and
25 Section 10.5 offers a complementary perspective on drivers and trends of technological progress across RE technologies.
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optimizing water use (Hall et al., 2003). In Norway it has been estimated that an increase in energy
output from existing hydropower of 5 to 10% is possible with a combination of improved efficiency in
new equipment, increased capacity, reduced head loss and reduced water losses and improved operation.
There is much ongoing research aiming to extend the operational range in terms of head and discharge,
and also to improve environmental performance and reliability and reduce costs. Some of the promising
technologies under development are described briefly in the following section. Most of the new
technologies under development aim at utilizing low (<15 m) or very low (<5 m) head, opening up many
sites for hydropower that have not been possible to use with conventional technology. Use of
computational fluid dynamics (CFD) is an important tool, making it possible to design turbines with
high efficiency over a broad range of discharges. Other techniques like artificial intelligence, neural
networks, fuzzy logic and genetic algorithms are increasingly used to improve operation and reduce the
cost of maintenance of hydropower equipment.
Most of the data available on hydropower technical potential are based on field work produced several
decades ago, when low-head hydropower was not a high priority. Thus, existing data on low-head
hydropower technical potential may not be complete. As an example, in Canada, a market potential of
5,000 MW has recently been identified for low-head hydropower (in Canada, low head is defined as
below 5 m) alone (Natural Resources Canada, 2009). As another example, in Norway, the
environmentally feasible small-scale hydropower (<10 MW) market potential was previously assumed to
be 7 TWh (25.2 PJ). A study conducted from 2002 to 2004, however, revealed this market potential to
be nearly 25 TWh (90 PJ) at a cost below 6 US cents per kWh, and 32 TWh (115 PJ) at a cost below 9
US cents per kWh (Jensen, 2009).
5.7.1 Variable-speed technology
Usually, hydropower turbines are optimized for an operating point defined by speed, head and discharge.
At fixed-speed operation, any head or discharge deviation involves some decrease in efficiency. The
application of variable-speed generation in hydroelectric power plants offers a series of advantages,
based essentially on the greater flexibility of the turbine operation in situations where the flow or the
head deviate substantially from their nominal values. In addition to improved efficiency, the abrasion
from silt in the water will also be reduced. Substantial increases in production in comparison to a fixed-
speed plant have been found in simulation studies (Terens and Schafer, 1993; Fraile et al., 2006).
5.7.2 Matrix technology
A number of small identical units comprising turbine and generator can be inserted in a frame in the
shape of a matrix where the number of (small) units is adapted to the available flow. During operation, it
is possible to start and stop any number of units so those in operation can always run under optimal flow
conditions. This technology can be installed at existing structures, for example, irrigation dams, low-
head weirs, ship locks etc where water is released at low heads (Schneeberger and Schmid, 2004).
5.7.3 Fish-friendly turbines
Fish-friendly turbine technology is an emerging technology that provides a safe approach for fish
passing though low-head hydraulic turbines by minimizing the risk of injury or death (Cada, 2001).
While conventional hydropower turbine technologies focus solely on electrical power generation, a fish-
friendly turbine brings about benefits for both power generation and protection of fish species.26 Alden
Laboratory (USA) predicts that their fish-friendly turbine will have a maximum efficiency of 90.5% with
a survival rate for fish of between 94 and 100% (Amaral et al., 2009). One turbine manufacturer predicts
approximately 98% fish survival through fish-friendly improvements on their Kaplan turbines.27
26 See: canmetenergy-canmetenergie.nrcan-rncan.gc.ca/eng/renewables/small_hydropower/fishfriendly_turbine.html.
27 Fish friendliness, Voith Hydro, June 2009, pp 18-21; www.voithhydro.com/media/Hypower_18_18.pdf.
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5.7.4 Hydrokinetic turbines
Generally, projects with a head under 1.5 or 2 m are not viable with traditional technology. New
technologies are being developed to take advantage of these small water elevation changes, but they
generally rely on the kinetic energy in the stream flow as opposed to the potential energy due to
hydraulic head. These technologies are often referred to as kinetic hydropower or hydrokinetic (see
Section 6.3 for more details on this technology). Hydrokinetic devices being developed to capture
energy from tides and currents may also be deployed inland in both free-flowing rivers and in
engineered waterways such as canals, conduits, cooling water discharge pipes or tailraces of existing
dams. One type of these systems relies on underwater turbines, either horizontal or vertical. Large
turbine blades would be driven by the moving water, just as windmill blades are moved by the wind;
these blades would turn the generators and capture the energy of the water flow (Wellinghoff et al.,
2008).
‘Free flow’ or ‘hydrokinetic’ generation captures energy from moving water without requiring a dam or
diversion. While hydrokinetic technology includes generation from ocean tides, currents and waves, it is
believed that its most practical application in the near term is likely to be in rivers and streams (see
Section 6.3.4). Hydrokinetic turbines have low energy density.
A study from 2007 concluded that the current generating capacity of hydropower of 75,000 MW in the
USA (excluding pumped storage) could be nearly doubled, including a contribution from hydrokinetic
generation in rivers and constructed waterways of 12,800 MW (EPRI, 2007).
In a ‘Policy Statement’ issued on 30 November 2007 by the US Federal Energy Regulatory Commission
(FERC, 2007) it is stated that:
“Estimates suggest that new hydrokinetic technologies, if fully developed, could double the amount of
hydropower production in the United States, bringing it from just under 10 percent to close to 20 percent
of the national electric energy supply. Given the potential benefits of this new, clean power source, the
Commission has taken steps to lower regulatory barriers to its development.”
The potential contributions from very low head projects and hydrokinetic projects are usually not
included in existing resource assessments for hydropower (see Section 5.2). The assessments are also
usually based on rather old data and lower energy prices than today and future values. It is therefore
highly probable that the hydropower resource potential will increase significantly as these new sources
are more closely investigated and technology is improved.
5.7.5 New materials
Corrosion, cavitation damages and abrasion are major wearing effects on hydropower equipment. An
intensified use of suitable proven materials such as stainless steel and the invention of new materials for
coatings limit the wear on equipment and extend lifespan. Improvements in material development have
been performed for almost every plant component. Examples include: a) penstocks made of fibreglass;
b) better corrosion protection systems for hydro-mechanical equipment; c) better understanding of
electrochemical corrosion leading to a suitable material combination; and d) trash rack systems with
plastic slide rails.
Water in rivers often contains large amounts of sediments, especially during flood events when soil
erosion creates high sediment loads. In reservoirs the sediments may have time to settle, but in run-of-
the-river projects most of the sediments may follow the water flow up to the turbines. If the sediments
contain hard minerals like quartz, the abrasive erosion of guide vanes, runners and other steel parts may
become very high and quickly reduce efficiency or destroy turbines completely within a very short time
(Lysne et al., 2003; Gummer, 2009). Erosive wear of hydropower turbine runners is a complex
phenomenon, depending on different parameters such as particle size, density and hardness,
concentration, velocity of water and base material properties. The efficiency of the turbine decreases
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with the increase in the erosive wear. The traditional solution to the problem has been to build de-silting
chambers to trap the silt and flush it out in bypass outlets, but it is very difficult to trap all particles,
especially the fines. New solutions are being developed by coating steel surfaces with a very hard
ceramic coating, protecting against erosive wear or delaying the process.
The problem of abrasive particles in hydropower plants is not new, but is becoming more acute with
increasing hydropower development in developing countries with sediment-rich rivers. For example,
many new projects in India, China and South America are planned in rivers with high sediment
concentrations (Gummer, 2009). The problem may also become more important in cases of increased
use of hydropower plants in peaking applications.
Modern turbine design using three-dimensional flow simulation provides not only better efficiencies in
energy conversion by improved shape of turbine runners and guide/stay vanes, but also leads to a
decrease in cavitation damages at high-head power plants and to reduced abrasion effects when dealing
with heavy sediment-loaded propulsion water. Other inventions concern, for example, improved self-
lubricating bearings with lower damage potential and the use of electrical servo motors instead of
hydraulic ones.
5.7.6 Tunnelling technology
Recently, new equipment for very small tunnels (0.7 to 1.3 m diameter) based on oil-drilling technology
has been developed and tested in hard rock in Norway, opening up the possibility of directional drilling
of ‘penstocks’ for small hydropower directly from the power station up to intakes, up to 1 km or more
from the power station (Jensen, 2009). This could lower cost and reduce the environmental and visual
impacts from above-ground penstocks for small hydropower, and open up even more sites for small
hydropower.
5.7.7 Dam technology
The International Commission on Large Dams (ICOLD) recently decided to focus on better planning of
existing and new (planned) hydropower dams. It is believed that the annual worldwide investment in
dams will be about USD 30 billion during the next decade, and the cost can be reduced by 10 to 20% by
more cost-effective solutions. ICOLD also wants to promote multipurpose dams and better planning
tools for multipurpose water projects (Berga, 2008). Another main issue ICOLD is focusing on is that of
small-scale dams between 5 and 15 m high.
The roller-compacted concrete dam is relatively new dam type, originating in Canada in the 1970s. This
dam type is built using much drier concrete than in other gravity dams, and it allows a quicker and more
economical dam construction (as compared to conventional concrete placing methods). It is assumed
that this type of dams will be much more used in the future, lowering the construction cost and thereby
also the cost of energy for hydropower projects.
5.7.8 Optimization of operation
Hydropower generation can be increased at a given plant by optimizing a number of different aspects of
plant operations, including the settings of individual units, the coordination of multiple unit operations,
and release patterns from multiple reservoirs. Based on the experience of federal agencies such as the
Tennessee Valley Authority and on strategic planning workshops with the hydropower industry, it is
clear that substantial operational improvements can be made in hydropower systems, given new
investments in R&D and technology transfer (Sale et al., 2006b). In the future, improved hydrological
forecasts combined with optimization models are likely to improve operation and water use, increasing
the energy output from existing power plants significantly.
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5.8 Cost trends28
Hydropower generation is a mature RE technology and can provide electricity as well as a variety of
other services at low cost compared to many other power technologies. A variety of prospects for
improvement of currently available technology as outlined in the above section exist, but these are
unlikely to result in a clear and sustained cost trend due to other counterbalancing factors.
This section describes the fundamental factors affecting the levelized cost of electricity (LCOE) of
hydropower plants: a) upfront investment costs; b) operation and maintenance (O&M) costs; c)
decommissioning costs; d) the capacity factor; e) the economic lifetime of the investment; and f) the cost
of project financing (discount rate).
Discussion of costs in this section is largely limited to the perspective of private investors. Chapters 1, 8,
10 and 11 offer complementary perspectives on cost issues covering, for example, costs of integration,
external costs and benefits, economy-wide costs and costs of policies.
Historic and probable future cost trends are presented throughout this section drawing mainly on a
number of studies that were published from 2003 up to 2010 by the IEA and other organizations. Box
5.3 contains brief descriptions of each of those studies to provide an overview of the material assessed
for this section. The LCOEs provided in the studies themselves are not readily comparable, but have to
be considered in conjunction with the underlying cost parameters that affect them. The parameters and
resulting study-specific LCOE estimates range are summarized in Table 5.7a for recent conditions and
Table 5.7b with a view to future costs.
Later in this section, some of the underlying cost and performance parameters that impact the delivered
cost of hydroelectricity are used to estimate recent LCOE figures for hydropower plants across a range
of input assumptions. The methodology used in these calculations is described in Annex II, while the
input parameters and the resulting range of LCOEs are also listed in Annex III to this report and are
reported in Chapters 1 and 10.
It is important to recognize, however, that the LCOE is not the sole determinant of the economic value
or profitability of hydropower projects. Hydropower plants designed to meet peak electricity demands,
for instance, may have relatively high LCOEs. However, in these instances, not only is the cost per unit
of power usually higher, but also average power prices during periods of peak demand and thus revenues
per unit of power sold to the market.
Since hydropower projects may provide multiple services in addition to the supply of electric power, the
allocation of total cost to individual purposes also matters for the resulting LCOE. Accounting for costs
of multipurpose projects is dealt with in Section 5.8.5.
28 Chapter 10.5 offers a complementary perspective on drivers and trends of technological progress across RE technologies.
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Box 5.3 | Brief description of some important hydropower cost studies.
Hall et al. (2003) published a study for the USA where 2,155 sites with a total potential capacity of
43,036 MW were examined and classified according to investment cost. The distribution curve shows
investment costs that vary from less than USD 500/kW up to over USD 6000/kW (Figure 5.18). Except
for a few projects with very high cost, the distribution curve is nearly linear for up to 95% of the
projects. The investment cost of hydropower as defined in the study included the cost of licensing, plant
construction, fish and wildlife mitigation, recreation mitigation, historical and archaeological mitigation
and water quality monitoring cost.
VLEEM-2003 (Very Long Term Energy-Environment Model) was an EU-funded project executed by a
number of research institutions in France, Germany, Austria and the Netherlands. One of the reports
contains detailed information, including cost estimates, for 250 hydropower projects worldwide with a
total capacity of 202,000 MW, with the most in-depth focus on Asia and Western Europe (Lako et al.,
2003). The projects were planned for commissioning between 2002 and 2020.
WEA-2004. The World Energy Assessment (WEA) was first published in 2000 by the United Nations
Development Programme (UNDP), the United Nations Department of Economic and Social Affairs
(UNDESA) and the World Energy Council (WEC). An update to the original report
(UNDP/UNDESA/WEC, 2000) was issued in 2004 (UNDP/UNDESA/WEC, 2004), and data from this
version are used here. The report gives cost estimates for both current and future hydropower
development. The cost estimates are given both as turnkey investment cost in USD per kW and as
energy cost in US cents per kWh. Both cost estimates and capacity factors are given as a range with
separate values for small and large hydropower.
IEA has published several reports, including World Energy Outlook 2008 (IEA, 2008a), Energy
Technology Perspectives 2008 (IEA, 2008b) and Projected Costs of Generating Electricity 2010 Edition
(IEA, 2010b) where cost data can be found both for existing and future hydropower projects.
EREC/Greenpeace. The European Renewable Energy Council (EREC) and Greenpeace presented a
study in 2008 called Energy [R]evolution: A Sustainable World Energy Outlook (Teske et al., 2010).
The report presents a global energy scenario with increasing use of renewable energy, in particular wind
and solar energy. It contains a detailed analysis up to 2050 and perspectives for beyond, up to 2100.
Hydropower is included and future scenarios for cost are given from 2008 up to 2050.
BMU Lead Study 2008. Further development of the strategy to increase the use of renewable energies
within the context of the current climate protection goals of Germany and Europe (BMU, 2008) was
commissioned by the German Federal Ministry for the Environment, Nature Conservation and Nuclear
Safety (BMU) and published in October 2008. It contains estimated cost for hydropower development
up to 2050.
Krewitt et al. (2009) reviewed and summarized findings from a number of studies from 2000 through
2008. The main sources of data for future cost estimates were UNDP/UNDESA/WEC (2000), Lako et
al. (2003), UNDP/UNDESA/WEC (2004) and IEA (2008).
REN21. The global status reports by the Renewable Energy Policy Network for the 21st Century
(REN21) are published regularly, with the last update in 2010 (REN21, 2010).
ECOFYS 2008. In the background paper Global Potential of Renewable Energy sources: A Literature
Assessment, provided by Ecofys for REN21, data can be found both for assumed hydropower resource
potential and cost of development for undeveloped technical potential (Hoogwijk and Graus, 2008).
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Table 5.7a |Cost ranges for hydropower: Summary of main cost parameters from 10 studies.
1
Investment cost (IC) O&M cost Capacity Lifetime Discount LCOE Comments
Source
(USD2005/kW) (% of IC) Factor
(%) (years) rate (%) (cents/kWh)
Hall et al. 2003 <500 – 6,200 2,155 Projects in USA
Ref: Hall et al. (2003) Median 1,650 41 – 61 43,000 MW in total
90% below 3,250
Annual Capacity factor (except
Rhode Island)
VLEEM-2003 <500 – 4,500 250 Projects for commissioning 2002–2020
Ref: Lako et al. (2003) Median 1,000 55 – 60 Total Capacity 202,000 MW
90% below 1,700 Worldwide but mostly Asia and Europe
WEA 2004 1,000 – 3,500 35 – 60 2 – 10 Large Hydro
Ref: UNDP/UNDESA/WEC (2004) 700 – 8,000 20 – 90 2 – 12 Small Hydro (<10 MW)
(Not explicitly stated as levelized cost
in report)
IEA-WEO 2008 2,184 2.5 45 40 10 7.1
Ref: IEA (2008a)
IEA-ETP 2008 1,000 – 5,500 2.2 – 3 10 3 – 12 Large Hydro
Ref: IEA (2008b) 2,500 – 7,000 10 5.6 – 14 Small Hydro
EREC/Greenpeace
Ref: Teske et al. (2010) 2,880 in 2010 4 45 40 10 10.4
BMU Lead Study 2008 2,440 6 7.3 Study applies to Germany only
Ref: BMU (2008)
Krewitt et al 2009 1,000 – 5,500 4 33 30 9,8 Indicative average LCOE year 2000
Ref: Krewitt et al. (2009)
IEA-2010 750 – 19,000 in 2010 80 2.3 – 45.9 Range for 13 projects from 0.3 to
18,000 MW
Ref: IEA (2010b) (1,278 average) 51 80 4.8 Weighted average for all projects
REN21 5 – 12 Small Hydro (<10 MW)
Ref: REN21 (2010) 3 – 5 Large Hydro (>10 MW)
5 – 40 Off-Grid (<1 MW)
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Table 5.7b | Future cost of hydropower: Summary of main cost parameters from five studies. 1
Investment cost (IC) O&M
cost Capacity Lifetime Discount LCOE Comments
Source
(USD2005/kW) (% of
IC) Factor
(%) (years) rate (%) (cent/kWh)
WEA 2004
2 – 10
No trend—Future
cost same as in
2004
Ref: UNDP/UNDESA/WEC
(2004) Same for small and
large hydro
IEA-WEO 2008 2,194 in 2030 2.5 45 40 10 7.1
Ref: IEA (2008a) 2,202 in 2050 2.5 45 40 10 7.1
IEA-ETP 2008 1,000 – 5,400 in 2030 2.2 – 3 10 3 – 11.5 Large Hydro
1,000 – 5,100 in 2050 10 3 – 11 Large Hydro
2,500 – 7,000 in 2030 10 5.2 – 13 Small Hydro
Ref: IEA (2008b)
2,000 – 6,000 in 2050 10 4.9 – 12 Small Hydro
EREC/Greenpeace 3,200 in 2030 4 45 40 10 11.5
Ref: Teske et al. (2010) 3,420 in 2050 4 45 40 10 12.3
Krewitt et al 2009
1,000 – 5,400 in 2030 4 33 30 10.8 Indicative average
LCOE in 2030
Ref: Krewitt et al. (2009)
1,000 – 5,100 in 2050 4 33 30 11.9 Indicative average
LCOE in 2050
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5.8.1 Investment cost of hydropower projects and factors that affect it
Basically, there are two major cost groups for hydropower projects: a) the civil construction costs,
which normally are the major costs of the hydropower project, and b) the cost related to
electromechanical equipment for energy transformation. Additionally, investment costs include the
costs of planning, environmental impact analysis, licensing, fish and wildlife mitigation, recreation
mitigation, historical and archaeological mitigation and water quality monitoring and mitigation.
The civil construction costs follow the price trend of the country where the project is going to be
developed. In the case of countries with economies in transition, the civil construction costs are
usually lower than in developed countries due to the use of local labour and local construction
materials.
Civil construction costs are always site specific, mainly due to the inherent characteristics of the
topography, geological conditions and the construction design of the project. This could lead to
different investment cost and LCOE even for projects of the same capacity.
The costs of electromechanical equipment—in contrast to civil construction cost—follow world
market prices for these components. Alvarado-Ancieta (2009) presents the typical cost of
electromechanical equipment from various hydropower projects in Figure 5.17.
Figure 5.17 | Costs of electrical and mechanical equipment as a function of installed capacity in 81
hydropower plants in America, Asia, Europe and Africa in USD2008. Source: Alvarado-Ancieta
(2009).
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Figure 5.18 shows the investment cost trend for a large number of investigated projects of different
sizes in the USA. The figure is from a study by Hall et al. (2003) that presents typical plant
investment costs for new sites.
Figure 5.18 | Hydropower plant investment cost as a function of plant capacity for undeveloped
sites. Adapted from Hall et al. (2003) (Note: both axes have a logarithmic scale).
Figure 5.18 shows that while there is a general tendency of increasing investment cost as the
capacity increases, there is also a wide range of cost for projects of the same capacity, given by the
spread from the general (blue) trend line. For example, a project of 100 MW in size has an average
investment cost of USD2002 200 million (USD2002 2,000/kW) but the range of costs is from less than
USD2002 100 million (USD2002 1,000/kW) and up to more than USD2002 400 million (USD2002
4,000/kW). (There could of course also be projects with higher costs, but these have already been
excluded from analysis in the selection process).
In hydropower projects where the installed capacity is less than 5 MW, the electromechanical
equipment costs tend to dominate. As the capacity increases, the costs are increasingly influenced
by the cost of civil structures. The components of the construction project that impact the civil
construction costs most are dams, intakes, hydraulic pressure conduits (tunnels and penstocks) and
power stations; therefore, these elements have to be optimized carefully during the engineering
design stage.
The same overall generating capacity can be achieved with a few large or several smaller generating
units. Plants using many small generating units have higher costs per kW than plants using fewer,
but larger units. Higher costs per kW installed capacity associated with a higher number of
generating units are justified by greater efficiency and flexibility of the hydroelectric plants’
integration into the electric grid.
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Specific investment costs (per installed kW) tend to be reduced for a higher head and higher
installed capacity of the project. With higher head, the hydropower project can be set up to use less
volume flow, and therefore smaller hydraulic conduits or passages. The size of the equipment is
also smaller and related costs are lower.
Results from two of the studies listed in Box 5.3 and Table 5.7a can be used to illustrate the
characteristic distribution of investment costs within certain geographic areas. The detailed
investment cost surveys provide an assessment of how much of the technical potential can be
exploited at or below specific investment costs. Such studies are not readily available in the
published literature for many regions. The results of two studies on cumulative investment costs are
presented in Fig 5.19. A summary from a study of investment cost typical of the USA by Hall et al.
(2003) shows a range of investment costs for 2,155 hydropower projects with a total capacity of
43,000 MW from less than USD2005 500/kW up to more than USD2005 6,000/kW. Twenty-five
percent of the assessed technical potential can be developed at an investment cost of up to USD2005
960/kW, an additional 25% at costs between USD2005 960 and 1,650/kW, and another 25% at costs
between USD2005 1,650 and 2,700/kW.
Figure 5.19 | Distribution of investment cost (USD2005/kW) for 2,155 hydropower project sites
studied in the USA (Hall et al., 2003), and for 250 hydropower project sites worldwide studied in
the VLEEM project (Lako et al., 2003). This graph is also called a cumulative capacity curve.
A similar summary of cost estimates for 250 projects worldwide with a total capacity of 202,000
MW has been compiled in the VLEEM-2003 study (Lako et al., 2003). Here, the range of
investment costs are from USD2005 450/kW up to more than USD2005 4500/kW. Weighted costs
(percentiles) are: 25% can be developed at costs up to USD2005 660/kW, 50% (median) at costs up
to USD2005 1,090/kW, and 75% at costs up to USD2005 1,260/kW. In general, these and other studies
suggest average recent investment cost figures for storage hydropower projects of USD2005 1,000 to
3,000/kW. Small projects in certain areas may sometimes have investment costs that exceed these
figures, while lower investment costs are also sometimes feasible. For the purpose of the LCOE
calculations that follow, however, a range of USD2005 1,000 to 3,000/kW is considered
representative of most hydropower projects.
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5.8.2 Other costs occurring during the lifetime of hydropower projects
Operation and maintenance (O&M) costs: Once built and put in operation, hydropower plants
usually require very little maintenance and operation costs can be kept low, since hydropower
plants do not have recurring fuel costs. O&M costs are usually given as a percentage of investment
cost per kW. The EREC/Greenpeace study (Teske et al., 2010) and Krewitt et al. (2009) used 4%,
which may be appropriate for small-scale hydropower but is too high for large-scale hydropower
plants. The IEA WEO used 2.5% (IEA, 2008a) and 2.2% for large hydropower increasing to 3% for
smaller and more expensive projects in IEA-ETP (IEA, 2008b). A typical average O&M cost for
hydropower is 2.5%, and this figure is used in the LCOE calculations that follow.
Decommissioning cost: Hydropower plants are rarely decommissioned and it is therefore very
difficult to find information about decommissioning costs in the literature. An alternative to
decommissioning is project re-licensing and continued operation. A few cases of dam
decommissioning are reported in the literature, but these dams are usually not hydropower dams.
Due to the long lifetime of hydropower projects (see Section 5.8.3), the decommissioning costs
occurring 40 to 80 years into the future are unlikely to contribute significantly to the LCOE.
Therefore, decommissioning costs are usually not included in LCOE analyses for hydropower.
5.8.3 Performance parameters affecting the levelized cost of hydropower
Capacity factor: For variable energy sources like solar, wind and waves, the statistical distribution
of the energy resource will largely determine the capacity factor. For hydropower, however, the
capacity factor is usually designed in the planning and optimization of the project, by considering
both the statistical distribution of flow and the market demand characteristics for power. A peaking
power plant will be designed to have a low capacity factor, for example 10 to 20%, in order to
supply peaking power to the grid only during peak hours. On the other hand, a power plant designed
for supplying energy to aluminium plants may be designed to have a capacity factor of 80% or
more, in order to supply a nearly constant base load. Reservoirs may be built in order to increase the
stability of flow for base-load production, but could also be designed for supplying highly variable
(but reliable) flow to a peaking power plant.
A low capacity factor gives low production and higher LCOE. Krewitt et al. (2009) used a low
value for hydropower, 2,900 hours or 33%, while, for example, IEA (2010b) used an average of
4,470 hours or 51%. An analysis of energy statistics from the IEA shows that typical capacity
factors for existing hydropower systems are in the range from below 40 to nearly 60% (USA 37%,
China 42%, India 41%, Russia 43%, Norway 49%, Brazil 56%, Canada 56%). In Figure 5.3,
average capacity factors are given for each region, with 32% in Australasia/Oceania, 35% in
Europe, 43% in Asia, 47% in North America, 47% in Africa and 54% in Latin America. The
weighted world average in 2009 was roughly 44%.
Based on the parameters listed in Annex III and methods described in Annex II, Figure 5.20(a)
illustrates the effect of capacity factors in the range of 30 to 60% on the LCOE of hydropower
under three different investment cost scenarios: USD2005 1,000/kW, 2,000/kW and 3,000/kW; other
parameter assumptions include a 2.5%/yr O&M cost as a proportion of investment cost, a 60-year
economic design lifetime, and a 7% discount rate. Average regional hydropower capacity factors
from Figure 5.3 are also shown in the graph.
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(a)
(b)
Figure 5.20 | Recent estimated levelized cost of hydropower: (a) cost of hydropower as a function
of capacity factor and investment cost; and (b) cost of hydropower as a function of capacity factor
and discount rate. Source: Annex III.
Notes: In (a) the discount rate is assumed to equal 7%, in (b) investment cost is assumed to be USD
2,000/kW, and in both (a) and (b) annual O&M cost is assumed at 2.5%/yr of investment cost and plant
lifetime as 60 years.
Lifetime: For hydropower, and in particular large hydropower, the largest cost components are civil
structures with very long lifetimes, like dams, tunnels, canals, powerhouses etc. Electrical and
mechanical equipment, with much shorter lifetimes, usually contribute less to the cost. It is
therefore common to use a longer lifetime for hydropower than for other electricity generation
sources. Krewitt et al. (2009) used 30 years, IEA-WEO 2008 (IEA, 2008a) and Teske et al. (2010)
used 40 years and the IEA (2010b) used 80 years as the lifetime for hydropower projects. A range
of 40 to 80 years is used in the LCOE calculations presented in Annex III as well as in Chapters 1
and 10.
Discount rate:29 The discount rate is not strictly a performance parameter. Nonetheless, it can have
a critical influence on the LCOE depending on the patterns of expenditures and revenues that
typically occur over the lifetime of the investment. Private investors usually choose discount rates
according to the risk-return characteristics of available investment alternatives. A high discount rate
will be beneficial for technologies with low initial investment and high running costs. A low
29 For a general discussion of the effect of the choice of the discount rate on LCOE, see Section 10.5.1.
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discount rate will generally favour RE sources, as many of these, including hydropower, have
relatively high upfront investment cost and low recurring costs. This effect will be even more
pronounced for technologies with long lifetimes like hydropower. In some of the studies, it is not
stated clearly what discount rate was used to calculate the LCOE. The BMU Lead Study 2008
(BMU, 2008) used 6%. In IEA (2010b) energy costs were computed for both 5 and 10% discount
rates. For hydropower, an increase from 5 to 10% gives an increase in the LCOE of nearly 100%.
The relationship between the discount rate and resulting LCOE is illustrated in Figure 5.20(b) for
discount rates of 3, 7 and 10% as used in this report over a range of capacity factors, and using other
input assumptions as follows: investment costs of USD2005 2,000/kW, O&M cost of 2.5%/yr of
investment cost, and an economic design lifetime of 60 years.
5.8.4 Past and future cost trends for hydropower projects
There is relatively little information on historical trends of hydropower cost in the literature. Such
information could be compiled by studying a large number of already-implemented projects, but
because hydropower projects are so site-specific it would be difficult to identify trends in project
component costs unless a very detailed and time-consuming analysis was completed for a large
sample of projects. It is therefore difficult to present historical trends in investment costs and
LCOE.
As a general trend, it can be assumed that projects with low cost will tend to be developed first, and
once the best projects have been developed, increasingly costly projects will be developed. (There
are, however, many barriers and the selection of the ‘cheapest projects first’ may not always be
possible. Some of these barriers are discussed in Section 5.4.5.) Overall, this general trend could
lead to a gradually increasing cost for new projects.
On the other hand, technological innovation and improvements (as discussed in Section 5.7) could
lower the cost in the future. Empirical evidence for reductions in the cost of specific components of
hydropower systems is provided for tunnelling costs in Figure 5.10. However, evidence for an
overall trend with respect to the specific investment cost of hydropower projects or the levelized
cost of hydropower cannot be deduced from such information and is very limited. Kahouli-Brahmi
(2008) found historical learning rates in the range from 0.5 to 2% for the investment cost of
hydropower (for different types of hydropower with varying regional scope and time periods).
In the studies included in Box 5.3 and Table 5.7b, there is no consensus on the future cost trend.
Some studies predict a gradually lowering cost (IEA, 2008b; Krewitt et al., 2009), some a gradually
increasing cost and one no trend (UNDP/UNDESA/WEC, 2004).
A reason for this may be the complex cost structure of hydropower plants, where some components
may have decreasing cost trends (for example tunnelling costs), while other may have increasing
cost trends (for example social and environmental mitigation costs). This is discussed, for example,
in WEA-2004 (see Box 5.3) where the conclusion is that these factors probably balance each other.
There is significant technical potential for increased hydropower development, as discussed in other
sections of this chapter. Since hydropower projects are site-specific, this technical potential
necessarily includes projects with widely varying costs, likely ranging from under USD2005 500/kW
up to and over USD2005 5,000/kW.
Investment costs based on studies in Table 5.7a (recent) and Table 5.7b (future) are typically in the
range from USD2005 1,000 to 3,000/kW, though higher and lower cost possibilities exist, as
discussed earlier. Since different studies do not agree on trends in future cost, the present cost range
is assumed as typical for the near-term future up to 2020. With investment costs ranging from
USD2005 1,000 to 3,000/kW and capacity factor and O&M costs as discussed earlier, typical values
for the LCOE of hydropower can be computed for different discount rates (3, 7, 10) and lifetimes
(40 and 80 years). The results are shown in Table 5.8, giving an indication of the typical LCOE for
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hydropower in the near-term future up to 2020. The O&M cost was fixed at 2.5% per year and
capacity factor at 45% for the purpose of the results presented in the table.
The LCOE values in Table 5.8 are well within the typical range of cost estimates given in Table
5.7a, (UNDP/UNDESA/WEC, 2004; BMU, 2008; IEA, 2008b; IEA, 2010b; REN21, 2010) but
somewhat lower than the values found by Teske et al. (2010) and Krewitt et al. (2009). The results
demonstrate that LCOE is very sensitive to investment costs and interest rates, but less sensitive to
lifetime, within the lifetime range typical for hydropower (40 to 80 years). Particularly small
projects would be expected to have higher investment costs on a dollar per kW basis, and therefore
may tend towards the higher end of the range presented in Table 5.8, and may in some instances fall
above that range.
Table 5.8 | LCOE estimation for parameters typical of current and near-term future hydropower
projects in US cents2005 (2010 up to 2020).
Investment
cost
(USD2005/kW)
Discount
rate (%)
O&M
cost
(%/yr)
Capacity
factor
(%)
Lifetime
(years)
LCOE
(cents/kWh)
Lifetime
(years)
LCOE
(cents/kWh)
1,000 3 2.5 45 40 1.7 80 1.5
1,000 7 2.5 45 40 2.5 80 2.4
1,000 10 2.5 45 40 3.2 80 3.2
2,000 3 2.5 45 40 3.5 80 2.9
2,000 7 2.5 45 40 5.1 80 4.8
2,000 10 2.5 45 40 6.5 80 6.3
3,000 3 2.5 45 40 5.2 80 4.4
3,000 7 2.5 45 40 7.6 80 7.3
3,000 10 2.5 45 40 9.7 80 9.5
5.8.5 Cost allocation for other purposes
Hydropower stations can be installed along with multiple purposes such as irrigation, flood control,
navigation, provision of roads, drinking water supply, fish supply and recreation. Many of the
purposes cannot be served alone as they have consumptive use of water and may have different
priority of use. There are different methods of allocating the cost to individual purposes, each of
which has advantages and drawbacks. The basic rules for cost allocation are that the allocated cost
to any purpose does not exceed the benefit of that purpose and each purpose will carry its separable
cost. Separable cost for any purpose is obtained by subtracting the cost of a multipurpose project
without that purpose from the total cost of the project with the purpose included (Dzurik, 2003).
Three commonly used cost allocation methods are: the separable cost-remaining benefits method
(US Inter-Agency Committee on Water Resources, 1958), the alternative justifiable expenditure
method (Petersen, 1984) and the proportionate use-of-facilities method (Hutchens, 1999).
Historically, reservoirs were mostly funded and owned by the public sector, thus project
profitability was not the highest consideration or priority in the decision. Today, the liberalization of
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the electricity market has set new economic standards for the funding and management of dam-
based projects. The investment decision is based on an evaluation of viability and profitability over
the full lifecycle of the project. The merging of economic elements (energy and water selling prices)
with social benefits (flood protection, supplying water to farmers in case of lack of water) and the
value of the environment (to preserve a minimum environmental flow) are becoming tools for
consideration of cost sharing for multipurpose reservoirs (Skoulikaris, 2008).
Votruba et al. (1988) reported the practice in Czechoslovakia for cost allocation in proportion to
benefits and side effects expressed in monetary units. In the case of the Hirakund project in India,
the principle of the alternative justifiable expenditure method was followed, with the allocation of
the costs of storage capacities between flood control, irrigation and power in the ratio of 38:20:42
(Jain, 2007). The Government of India later adopted the use-of-facilities method for allocation of
joint costs of multipurpose river valley projects (Jain, 2007).
5.9 Potential deployment30
Hydropower offers significant potential for near- and long-term carbon emissions reductions. The
hydropower capacity installed by the end of 2008 delivered roughly 16% of worldwide electricity
supply: hydropower is by far the largest current source of RE in the electricity sector (representing
86% of RE electricity in 2008). On a global basis, the hydropower resource is unlikely to constrain
further development in the near to medium term (Section 5.2), though environmental and social
concerns may limit deployment opportunities if not carefully managed (Section 5.6). Hydropower
technology is already being deployed at a rapid pace (see Sections 5.3 and 5.4), therefore offering
an immediate option for reducing carbon emissions from the electricity sector. With good
conditions, the LCOE can be around 3 to 5 cents/kWh (see Section 5.8). Hydropower is a mature
technology and is at the crossroads of two major issues for development: water and energy. This
section begins by highlighting near-term forecasts (2015) for hydropower deployment (Section
5.9.1). It then discusses the prospects for and potential barriers to hydropower deployment in the
longer term (up to 2050) and the potential role of that deployment in reaching various GHG
concentration stabilization levels (Section 5.9.2). Both sections are largely based on energy market
forecasts and carbon and energy scenarios literature published in the 2006 to 2010 time period.
5.9.1 Near-term forecasts
The rapid increase in hydropower capacity over the last 10 years is expected by several studies,
among them EIA (2010) and IEA (2010c), to continue in the near term (see Table 5.9). Much of the
recent global increase in renewable electricity supply has been fuelled by hydropower and wind
power. From the 945 GW of hydropower capacity, including pumped storage power plants,
installed at the end of 2008, the IEA (2010c) and US Energy Information Administration (EIA,
2010) reference-case forecasts predict growth to 1,119 and 1,047 GW, respectively, by 2015 (e.g.,
and additional 25 and 30 GW/yr, respectively, by 2015).
Table 5.9 | Near-term (2015) hydropower energy forecasts.
Hydropower situation Hydropower forecast for 2015
Study Reference
year
Installed
capacity
(GW)
Electricity
generation
(TWh/EJ)
Percent of
global
electricity
supply (%)
Installed
capacity
(GW)
Electricity
generation
(TWh/EJ)
Percent of
global
electricity
supply (%)
IEA
(2010c) 2008 945a 3 208/11.6 16 1,119 3,844/13.9 16%
30 Complementary perspectives on potential deployment based on a comprehensive assessment of numerous model
based scenarios of the energy system are presented in Sections 10.2 and 10.3 of this report.
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EIA
(2010) 2006 776 2 997/10.8 17 1,047 3,887/14 17%
Notes: a Including pumped storage hydropower plants.
Non-OECD countries, and in particular Asia (China and India) and Latin America, are projected to
lead in hydropower additions over this period.
5.9.2 Long-term deployment in the context of carbon mitigation
The IPCC’s Fourth Assessment Report (AR4) assumed that hydropower could contribute 17% of
global electricity supply by 2030, or 5,382 TWh/yr (~19.4 EJ/yr) (Sims et al., 2007). This figure is
not much higher than some commonly cited business-as-usual cases. The IEA’s World Energy
Outlook 2010 reference scenario, for example, projects 5,232 TWh/yr (18.9 EJ/yr) of hydropower
by 2030, or 16% of global electricity supply (IEA, 2010c). The EIA forecasts 4,780 TWh/yr (17.2
EJ/yr) of hydropower in its 2030 reference case projection, or 15% of net electricity production
(EIA, 2010).
Beyond the reference scenario, the IEA’s World Energy Outlook 2010 presents three additional
GHG mitigation scenarios (IEA, 2010c). In the most stringent 450 ppm stabilization scenarios in
2030, installed capacity of new hydropower increases by 689 GW compared to 2008 or 236 GW
compared to the Existing Policies scenario in 2030. The report highlights that there is an increase in
hydropower supply with increasingly low GHG concentration stabilization levels. Hydropower is
estimated to increase annually by roughly 31 GW in the most ambitious mitigation scenario (i.e.,
450 ppm) until 2030.
A summary of the literature on the possible future contribution of RE supplies in meeting global
energy needs under a range of GHG concentration stabilization scenarios is provided in Chapter 10.
Focusing specifically on hydro energy, Figures 5.21 and 5.22 present modelling results on the
global supply of hydro energy in EJ/yr and as a percent of global electricity demand, respectively.
About 160 different long-term scenarios underlie Figures 5.21 and 5.22. Those scenario results
derive from a diversity of modelling teams, and span a wide range of assumptions for—among
other variables—energy demand growth, the cost and availability of competing low-carbon
technologies and the cost and availability of RE technologies (including hydro energy). Chapter 10
discusses how changes in some of these variables impact RE deployment outcomes, with Section
10.2.2 providing a description of the literature from which the scenarios have been taken. In Figures
5.21 and 5.22, the hydro energy deployment results under these scenarios for 2020, 2030 and 2050
are presented for three GHG concentration stabilization ranges, based on the AR4: Baselines (>600
ppm CO2), Categories III and IV (440 to 600 ppm CO2) and Categories I and II (<440 ppm CO2),
all by 2100. Results are presented for the median scenario, the 25th to 75th percentile range among
the scenarios, and the minimum and maximum scenario results.31
The baseline projections of hydropower’s role in global energy supply span a broad range, with
medians of roughly 13 EJ in 2020,32 15 EJ in 2030 and 18 EJ in 2050 (Figure 5.21). Some growth
of hydropower is therefore projected to occur even in the absence of GHG mitigation policies, but
with hydropower’s median contribution to global electricity supply dropping from about 16% today
to less than 10% by 2050.The decreasing share of hydroelectricity despite considerable absolute
31In scenario ensemble analyses such as the review underlying the figures, there is a constant tension between the fact
that the scenarios are not truly a random sample and the sense that the variation in the scenarios does still provide real
and often clear insights into collective knowledge or lack of knowledge about the future (see Section 10.2.1.2 for a
more detailed discussion).
32 12.78 EJ was reached already in 2009 and thus the average estimates of 13 EJ for 2020 will be exceeded soon,
probably already in 2010. Also, some scenario results provide lower values than the current installed capacity for 2020,
2030 and 2050, which is counterintuitive given, for example, hydropower’s long lifetimes, its significant market
potential and other important services. These results could maybe be explained by model/scenario weaknesses (see
discussions in Section 10.2.1.2 of this report).
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growth in hydropower supply is a result of expected energy demand growth and continuing
electrification. The contribution of hydropower grows to some extent as GHG mitigation policies
are assumed to become more stringent: by 2030, hydropower’s median contribution equals roughly
16.5 EJ in the 440 to 600 and <440 ppm CO2 stabilization ranges (compared to the median of 15 EJ
in the baseline cases), increasing to about 19 EJ by 2050 (compared to the median of 18 EJ in the
baseline cases).
Figure 5.21 | Global primary energy supply from hydro energy in long-term scenarios (median,
25th to 75th percentile range, and full range of scenario results; colour coding is based on
categories of atmospheric CO2 concentration level in 2100; the specific number of scenarios
underlying the figure is indicated in the right upper corner) (adapted from Krey and Clarke, 2011;
see also Chapter 10).
Figure 5.22 | Hydropower electricity share of total global electricity supply in the long-term
scenarios (median, 25th to 75th percentile range, and full range of scenario results; colour coding
is based on categories of atmospheric CO2 concentration level in 2100; the specific number of
scenarios underlying the figure is indicated in the right upper corner) (adapted from Krey and
Clarke, 2011; see also Chapter 10).
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The large diversity of approaches and assumptions used to generate these scenarios results in a wide
range of findings. Baseline results for hydropower supply in 2050 range from 14 to 21 EJ at the
25th and 75th percentiles (median 18 EJ), or 7 to 11% (median 9%) of global electricity supply. In
the most stringent <440 ppm stabilization scenarios, hydropower supply in 2050 ranges from 16 to
24 EJ at the 25th and 75th percentiles (median 19 EJ), equivalent to 8 to 12% (median 10%) of
global electricity supply.
Despite this wide range, hydropower has the lowest range compared to other renewable energy
sources (see Chapter 10). Moreover, the AR4 estimate for potential hydropower supply of 19.4 EJ
by 2030 appears somewhat conservative compared to the more recent scenarios literature presented
above, which reaches 24 EJ in 2030 for the IEA’s 450 ppm scenario (IEA, 2010c).
Although the literature summarized in Figure 5.21 shows an increase in hydropower supply for
scenarios aiming at lower GHG concentration stabilization levels, that impact is smaller than for
bioenergy, geothermal, wind and solar energy, where increasingly stringent GHG concentration
stabilization ranges lead to more substantial increases in technology deployment (Section 10.2.2.5).
One explanation for this result is that hydropower is already mature and economically competitive;
as a result, deployment is projected to proceed steadily even in the absence of ambitious efforts to
reduce GHG emissions.
The scenarios literature also shows that hydropower could play an important continuing role in
reducing global carbon emissions: by 2050, the median contribution of hydropower in the two
stabilization categories is around 19 EJ, increasing to 23 EJ at the 75th percentile, and to 35 EJ in
the highest scenario. To achieve this contribution requires hydropower to deliver around 11% of
global electricity supply in the medium case, or 14% at the 75th percentile. Though this implies a
decline in hydropower's contribution to the global electricity supply on a percentage basis, it would
still require significant absolute growth in hydropower generation.
Assuming that lower hydropower costs prevail and that growth continues based on the current trend
(e.g., the same used in the IEA (2010c) 450 ppm scenario), the hydropower industry forecasts a
hydropower market potential of more than 8,700 TWh/yr or 32.2 EJ/yr (IJHD, 2010) to be reached
in 2050. The long lifetime of HPPs (in many cases more than 100 years, no/or very few
decommissioning cases), along with hydropower’s significant market potential, the ability of
storage hydropower as a controllable RE source to be used to balance variable RE, and the
multipurpose aspects of hydropower, could be taken as support for this view. However, to achieve
these levels of deployment, a variety of possible challenges to the growth of hydropower deserve
discussion.
Resource Potential: Even the highest estimates for long-term hydropower production are within
the global technical potential presented in Section 5.2, suggesting that—on a global basis, at least—
technical potential is unlikely to be a limiting factor to hydropower deployment. Moreover, ample
market potential exists in most regions of the world to enable significant hydro energy development
on an economic basis. In certain countries or regions, however, higher deployment levels will begin
to constrain the most economical resource supply, and hydro energy will therefore not contribute
equally to meeting the needs of every country (see Section 10.3).
Regional Deployment: Hydropower would need to expand beyond its current status, where most of
the resource potential developed so far has been in Europe and North America. The IEA reference
case forecast projects the majority (57%) of hydropower deployment by 2035 to come from non-
OECD Asia countries (e.g., 33% in China and 13% in India), 16% from non-OECD Latin America
(e.g., 7% in Brazil) and only 11% in OECD countries (see Table 5.10). Regional collaboration
would be required to combine power systems development with sound integrated water resources
management, as was observed, for example, in the Nile Basin Initiative and the Greater Mekong
Subregion program (see Section 5.10.3).
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Table 5.10 | Regional distribution of global hydropower generation in 2008 and projection for 2035
in TWh and EJ (percentage of hydropower generation in regional electricity generation, CAAGR:
‘compounded average annual growth rate’ from 2008 to 2035) for the IEA New Policies Scenario33
(IEA, 2010c).
2008 2035