Review of literature on impacts of climate change on Energy Systems

Nathalie RoussetLEPII, Grenoble

Grant Agreement: Project acronym: Project title:Research area:

212774 ClimateCostFull Costs of Climate ChangeENV.2007.1.1.6.1.

Deliverable Number: 2C1Actual submission date: 7.05.2009

Laboratoire d’Economie de la Production et de l’Intégration Internationale

UM UMR 5252- Université de Grenoble – CNRS

Title: Review of literature on impacts of climate change on Energy Systems

Purpose: Review of the literature on climate impacts in the energy sector in order to identify key climate impacts in this sector, the way the relationships are estimated, what parameters have been used, what databases exists and overview the existing results of impacts of climate change.

Filename: ClimateCost_D2C1

Date: 7.05.2009

Authors: Nathalie Rousset

Document history:

Status: Final

Citation:

Copyright:

Copyright statement:

Working paper number:

ISBN:

Project Coordinator: Thomas E DowningStockholm Environment Institute, Oxford266 Banbury Road, Suite 193 Oxford OX2 7DL, U.K.

Tel: +44 1865 426316; Fax: +44 1865 421898 Mobile: +44 7968 065957tomdowning.sei@gmail.com,www.sei.se/oxford

Technical Coordinator: Paul WatkissPaul Watkiss AssociatesPaul_watkiss@btinternet.comTel +44 797 1049682http://www.climatecost.cc/

Page 2

Abstract

The document makes a review of the literature in the following areas : Assessment of energy consumption, with different degrees of climate change and adaptation of

heating and cooling demand in the residential and service sector. Assessment of the impact of climate change on hydroelectricity production Assessment of changes in water regimes on the costs of cooling in thermal power production,

either by fossil or nuclear fuels. Taking into account of the growing requirements of energy in the water supply systems, with a

probable amplification by climate change.

Even if research efforts involved in analyzing effects of climate change on energy consumption by end-user sectors and related GHG emissions remain scarce, a large consensus in the methodology to be used to forecasting the impacts of changing temperatures on heating and cooling demands appears clear from this state-of-the-art literature. Thus the general relationship between temperature change and heating and cooling related requirement, related with anticipated changes in heating and cooling degree days and cooling market penetration are detailed in the first chapter. Then the effects of climate change on energy use and CO2 emissions are summarized.

Global warming and changes in precipitation patterns will alter the timing and magnitude of river flows. Despite the limited literature, the approximate potential changes in gross hydroelectric potential and installed capacity to anticipated changes in runoff consecutive to different climate change scenarios are identified, as are analyzed the potential effects of risks on anticipated hydropower investment.

The third chapter yields a background on water use for thermoelectric generation, analysis the potential impacts of climate change on plants output and efficiency, namely the direct effects of ambient and cooling water temperature changes, the issues of water withdrawal and consumption for thermoelectric generation in the context of increased water stress and competing uses, and the impacts of climate change on output in the context of thermal discharge regulation. Finally, analyze the economic, environmental and performance trade-offs, that arise from choices between the alternative cooling configurations in the context of climate change.

The last chapter reviews the literature on impacts of climate change on energy requirement for water supply (change on irrigation needs, increased call in desalinization water where water becomes scarce).

Page 3

Table of Contents

1. Assessment of energy consumption, with different degrees of climate change and adaptation of heating and cooling demand in the residential and service sector 11

1.1. State of-the-art of methodology used in the literature..............................................11

1.2. Overview of results of impacts of climate change....................................................19

1.2.1. Impacts of climate change on HDD and CDD...................................................19

1.2.2. Impacts of climate change on energy demand and CO2 emissions.................20

1.2.3. Impacts of climate change on seasonal patterns of energy demand................22

2. Assessment of the impact of climate change on hydroelectricity production..................25

2.1. Impacts of climate change on gross and developed hydropower potentials............25

2.1.1. Hydropower potential indicators and station types............................................25

2.1.2. Literature on climate change impacts on hydropower generation overview.....27

2.2. Effects of climate change on hydrological systems and run-off...............................35

2.2.1. The hydroelectricity potential and runoff nexus.................................................35

2.2.2. Overview of potential effects of climate change on regional runoffs.................35

2.3. Potential effects of climate change on anticipated hydropower investment.............43

2.3.1. Effects of climate change on attractiveness and viability of hydropower investments.....................................................................................................................44

2.3.2. Climate change and adaptation of management/design of hydropower investments.....................................................................................................................46

3. Assessment of changes in water regimes on the costs of cooling in thermal power production, either by fossil or nuclear fuels............................................................................49

3.1. Background: Water use for thermoelectric generation.............................................49

3.1.1. Supplying energy requires water.......................................................................49

3.1.2. Cooling technologies.........................................................................................50

Page 4

3.1.3. Water use for thermoelectric generation...........................................................51

3.2. Direct effects of ambient and cooling water temperature changes on output and thermal efficiency of power plants.......................................................................................55

3.2.1. Impacts of changes in ambient temperatures...................................................55

3.2.2. Impacts of changes in water cooling temperatures...........................................59

3.3. Trends in water stress, competing uses in the context of climate change...............61

3.3.1. Water demand projections: The EPRI (2002) and DOE-NETL (2008) studies. 62

3.3.2. Characterizing the main regions at risk.............................................................65

3.4. Impacts of climate change in the context of thermal discharge regulation...............65

3.4.1. Heatwaves and output reduction impacts.........................................................65

3.4.2. Trends in cooling systems choice and energy penalties potential impacts.......68

3.5. Technological adaptation and Cooling choices: Economic, environmental and performance tradeoffs.........................................................................................................71

4. Assessment of impacts of climate change on energy consumption for water use..........76

4.1. Technical coefficients of energy requirement for water delivery and treatment.......76

4.1.1. Conventional waters..........................................................................................76

4.1.2. Desalinated waters............................................................................................84

4.2. Expected impacts of climate change on electricity consumption for water needs. . .97

4.2.1. Impacts of climate change on electricity requirement relating to change in irrigation needs................................................................................................................97

4.2.2. Impacts of CC on electricity requirement due to increased call in desalination100

Page 5

List of Tables

Table 1: Percentage change in HDD and CDD compared to baseline for different level of climate change...........16

Table 2: Examples of potential changes in annual hydroelectric generation resulting from changes in temperature

and precipitation...................................................................................................................................................... 26

Table 3: Gross and installed hydropower potentials in Europe and response changes due to climate change......27

Table 4: Sensitivity of water-supply variables to climate change in the Colorado river basin ................................32

Table 5: Increase in global average temperature relative to 1961-1990.................................................................37

Table 6: Maximum, medium and minimum percent change of different levels of climate change on runoff on a

regional basis ......................................................................................................................................................... 43

Table 7: Connections between the energy/thermoelectricity sector and water availability and quality...................52

Table 8: Summary of cooling water needs (DOE-NETL, 2004)...............................................................................54

Table 9: Cooling water withdrawal and consumption rates for common thermal power plant and cooling system

types (EPRI, 2002).................................................................................................................................................. 54

Table 10: Cooling water withdrawal and consumption rates for common thermal power plant and cooling system

types (DOE-NETL, 2008)........................................................................................................................................55

Table 11: Water consumption and withdrawal for three types of nuclear reactor (Gossens and Bonnet, 2001).....56

Table 12: Water consumption and withdrawal for classical and expected thermal power plants (Gossens and

Bonnet, 2001).......................................................................................................................................................... 57

Table 13: Estimated France freshwater withdrawal by sectors, 2002, (Vicaud, 2008)............................................58

Table 14: Performance, cost and heat rate at design points of different climatic stations.......................................60

Table 15: Hot day performance comparisons of power plants at different climatic stations....................................61

Table 16: Method for estimating generation-weighted breakouts of cooling system types for current and future

generation by plant type in the EPRI (2002) study..................................................................................................67

Table 17: Case description for the water needs analysis in DOE-NETL (2008) report...........................................69

Table 18: Wet cooling tower energy penalties and impact at one percent highest temperature conditions............76

Table 19: Indirect-dry cooling tower energy penalties and impact at one percent highest temperature conditions 76

Table 20: Summary of advantages and disadvantages of alternative cooling systems..........................................78

Table 21: Summary of unit of electricity consumption for water supply and wastewater treatment in kWh/million

gallons (and kWh/cubic meters)..............................................................................................................................85

Table 22: Public vs. end-users supplied water by sectors in million gallons per day (and percent)........................85

Page 6

Table 23: Surface vs. ground water sources of self-supplied water by sectors.......................................................86

Table 24: Unit electricity consumption for wastewater treatment by processes and plant sizes.............................90

Table 25: Energy for water .....................................................................................................................................92

Table 26: Energy consumption for freshwater production.......................................................................................92

Table 27: Energy requirement for agriculture production following different irrigation configuration.......................93

Table 28: Summary of worldwide desalination capacity by process, 1998...........................................................102

Table 29: Energy requirements of different desalination technology and plant capacity ......................................103

Table 30: Energy use by various desalination processes.....................................................................................104

Table 31: Desalination costs for various technologies ($/m3) reported by Miller (2003) state-of-the-art..............105

Table 32: Comparative Total Cost Data for the Desalination Process for 100,000 m3 of Seawater by Reverse

Osmosis, Multistage Flash Distillation, and Multi-Effect Distillation.......................................................................106

Table 33: Changes in projected net irrigation water requirement (Gm3) under climate change scenario A2r

compared with the a2r reference scenario (no climate change), for Hadley and CSIRO climates........................113Table 34: Projected changes in renewable internal water resources (WRI) under climate change scenarios A2r and B2 in 2080 compared with the A2r reference scenario (no climate change)...............................................................................................113

Page 7

List of figures

Figure 1: Harnessing discharge for power generation in run-of-river stations.........................................................24

Figure 2: Relative change of average (1961-90) total discharge volumes calculated with WaterGAP 2.1 for the

2070s (HadCM3 climate model and Baseline-A water use scenario), superimposed by georeferenced European

hydropower plants................................................................................................................................................... 29

Figure 3: Relative change of average (1961-90) total discharge volumes calculated with WaterGAP 2.1 for the

2020s and 2070s (ECHAM4 and HadCM3 climate models and Baseline-A water use scenario)...........................30

Figure 4: Large-scale relative changes in annual runoff for the period 2090–2099, relative to 1980–1999. Values

represent the median of 12 models using the SRES A1B scenario. White areas are where less than 66% of the

ensemble of 12 models agree on the sign of change, and hatched areas are where more than 90% of models

agree on the sign of change....................................................................................................................................36

Figure 5: Percentage change in average annual runoff, “2050s” compared with 1961-1990. HadCM3 model, 7

scenarios................................................................................................................................................................. 38

Figure 6: Consistency in change in average annual runoff by the 2020s, 2050s and 2080s with A2 emissions

scenarios. More than half of GCMs show significant increase or decrease............................................................38

Figure 7: Change in “drought” runoff: percent change in 10-year return period annual runoff, and percentage of

years that watershed annual runoff is below the current 10-year return period annual runoff................................39

Figure 8: Average monthly runoff under current and 2050s climates (HadCM3-A1F1) for individual grid cells......40

Figure 9: Change in runoff as a function of variation in global mean temperature for each of the GCMs used......41

Figure 10: Variation of project NPV with climate and project parameter changes..................................................47

Figure 11: Estimated U.S freshwater withdrawal by sector, 2000...........................................................................57

Figure 12: Estimated U.S freshwater consumption by sector, 1995........................................................................58

Figure 13: Output vs. ambient temperature for wet cooled plants...........................................................................62

Figure 14: Output vs. ambient temperature for dry cooled plants...........................................................................62

Figure 15: Variation of net power output Wnet and thermal efficiency ηth with cooling water inlet temperature Tcw;I for

∆Thot = 2, 4 and 6°C................................................................................................................................................. 64

Figure 16: Efficiency loss due to higher cooling water temperatures......................................................................65

Figure 17: Representative surface water treatment plant process (with typical daily electricity consumption for a

10 million gallon/day facility)....................................................................................................................................87

Figure 18: Diagram of multi effect distillation...........................................................................................................95

Figure 19: Diagram of mechanical vapor compression...........................................................................................96

Page 8

Figure 20: Diagram of membrane processes..........................................................................................................97

Figure 21: Components of an electrodialysis plant..................................................................................................98

Figure 22: Basic components of a reverse osmosis plant.......................................................................................99

Figure 23: Countries with more than 1% of global desalination capacity..............................................................101

Figure 24: Total capacity and capacity added between 1988 and 1997 by process.............................................102

Figure 25: Unit cost of desalinated water by MSF process depending on year of installation and cumulate installed

capacity................................................................................................................................................................. 108Figure 26: Unit cost of desalinated water by RO process depending on year of installation and cumulate installed capacity 109

Page 9

Page 10

1. Assessment of energy consumption, with different degrees of climate change and adaptation of heating and cooling demand in the residential and service sector.

Following IEA data (IEA, 2004), one third of all end-use energy is consumed by households, and in temperate regions, more than half of this energy is used for heating. Although space cooling is currently a much less important energy use, it is growing rapidly both in high income countries and in emerging economies such as India and China. Heating and cooling are also an important energy use of commercial and service sector. Trends in energy demand for heating and cooling could therefore be very important for the development of the energy system and associated emissions. One of the factors influencing this development is climate change. The two following sections summarize the effects of climate change on the determinants of energy use that would be the basis of further analysis, and the major effects of climate change on energy use that would result from such analyzes. Numbers of studies have been attempted to project residential and commercial building energy consumption for the next decades. However these routine projections do not account for the effects of any temperature increases on building energy use that may occur as a result of global warming, nor do they account for consumer reactions to a warmer climate, such as an increase in the adoption of air conditioning. In fact, climate change is expected to impact directly energy demands of residential and commercial sectors as their heating and cooling needs are highly connected to temperature conditions and variations. Indeed, this topic appears as a really new issue for the climate change, and more generally for the energy literature, but several studies have nevertheless focus on this important question. Even if research efforts involved in analyzing effects of climate change on energy consumption by end-user sectors and related GHG emissions remain scarce, particularly when compared to the very large literature on long term energy sector uses trends and expected impacts on climate change, a large consensus in the methodology to be used to forecasting the impacts of changing temperatures on heating and cooling demands appears clear from this state-of-the-art literature. Thus the general relationship between temperature change and heating and cooling related requirement, related with anticipated changes in heating and cooling degree days and cooling market penetration is detailed here. Then the effects of climate change on energy use and CO2 emissions are summarized.

1.1. State of-the-art of methodology used in the literature

Several studies have attempted to evaluate the impact of climate and/or climate change on energy consumption, and more particularly on heating and cooling energy demand of residential and/or commercial sectors. The methodology followed is traditionally based on a formal relationship based on (changes in) heating and cooling degree days, expected change in cooling market penetration, and related heating and cooling energy demand. We summarize here the literature on this topic, with a particular focus on models used to forecast energy demand in relation to climate parameters. A special attention is given to the study of Isaac

Page 11

and vanVuuren (2008) that is particularly detailed, global in scope, and focused on the effects of climate change scenario.

It has been well documented that weather-related factors play an important role in affecting electricity consumption. For many years, utility companies and the electric power industry have been interested in the relation between energy consumption and climate, and have developed empirical weather normalization algorithms aimed at improving load forecasting subject to variations in regional climate. Many of these studies, however, exhibited a narrow regional focus, with limited documentation in the open literature.

Several researchers have recently published estimates of climatic influences on energy consumption. Many of the publications in this area, however, focus on energy consumption at the level of the individual residential or commercial building under idealized conditions (Scott et al, 1994 ; Huang et al, 1986). In recent years there has been an abundance of load forecasting literature focusing on the use of Neural Networks (NN) to predict loads (Chow and Leung, 1996 ; Dash et al, 1996 ; Islam et al, 1995). Neural network approaches have also been applied in the energy consumption problem at the building scale (Kreider et al, 1995), as well as many other areas of science and engineering.

Many of the studies that have investigated the sensitivity of electricity consumption to weather have focused on short-term load forecasting. Some have extended this sort of analysis to investigate the role of weather variability on carbon emissions (Considine, 2000). Other studies have extended weather sensitivity to address issues of electricity consumption response to climate variability and change (Sailor, 2000; Sailor and Munoz, 1997 ; Scott et al, 1994 ; Segal et al, 1992).

At the regional scale, some studies have been performed on modeling heating and cooling demand in relation to the present climate and future climate change. For instance for the USA, the most extensive effort to evaluate end-use electricity consumption sensitivity to climate at regional scales can be found in several publications of the US Energy Information Administration (EIA), the Residential Energy Consumption Survey (RECS) and the Commercial Building Energy Consumption Survey (CBECS), respectively. These surveys gathered energy-related data for a statistical sample of residential and commercial buildings (RECS, 1996 ; CBECS, 1992). They include national level information about building construction, occupancy, and load schedules. The data are aggregated into five broad climatic zones based on levels of cooling and heating degree days (CDD and HDD) for the entire US. This sample survey approach has been used along with projections of climate change and projections of future (2030) commercial building stock to investigate the potential impact of climate change on commercial building energy consumption (Belzer et al, 1996).

Sailor (2001) developed a methodology to evaluate relating residential and commercial sector electricity loads to climate and analyzed effects of climate perturbations and specific climate

Page 12

change scenarios on model results for eight states of the U.S.A. The present paper builds upon the previously published methodology (Sailor and Munoz, 1997). The approach isolates weather-related factors that determine electricity consumption and generates appropriate regression models that utilize degree day data as the primary independent variables. The electricity consumption data in this approach have been trend-adjusted for non-climatic factors, which include historical changes in energy usage patterns, air conditioning market saturation, and related factors. The response of the individual sectors is often of interest, and residential and commercial consumption can exhibit distinctly different responses to climate. Therefore, the authors have disaggregated the residential and commercial sector consumption data for this analysis. The electricity consumption models all depend upon temperatures, humidity and wind speed, with temperature being the most important variable. The general form used to develop regression models has the form of:

E = β0 + β1*CDD + β2*HDD + β3*U + β4*ELD

where E is the trend-adjusted statewide per capita monthly electricity consumption (kWh), U is mean monthly wind speed (m/s) and CDD and HDD are monthly totals of the traditional cooling and heating degree day variables (°C-day) defined by:

Nd CDD = ∑ (αd) (T - Tb)

d=1and,

Nd HDD = ∑ (1 - αd) (Tb - T)

d=1

In these equations Nd is the number of days in a particular month, and T is the mean daily temperature. The base temperature, Tb, for degree days is 18.3°C for all states in this study except Florida, where satisfactory models required a higher threshold value of 21°C. The binary multiplier α takes on a value of 1 if the daily temperature is higher than the base, and zero otherwise. Enthalpy latent days (ELD) were introduced to account for the possible humidity effects on summer air conditioning demand. Conceptually, ELD represents just the amount of energy required to lower the humidity to the comfort level established by the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE), without reducing air temperature. Cooling degree days can then be used as a good index for the energy required to reducing temperature alone. One important characteristic of these models is that the coefficient of cooling degree days is greater than the coefficient of heating degree days. This is due in large part to the fact that heating demand is dominated in most states by natural gas or fuel oil. Sailor and Pavlova (2003) improve the models structure by introducing an equation representing the air conditioning market saturation. Air conditioning market saturation depends on a large number of factors including economic, social, and climatic conditions. While the electricity consumption models discussed above deal solely with sensitivity to short-term weather variations, the response of market saturation to long term shifts in climate may play an important role in determining how electricity consumption on the whole will respond to global warming. The equation is given by:

Page 13

S0 = 0.944 - 1.17 exp(- 0.00298*CDD)This equation has permitted the authors to estimate the potential increase in market saturation associated with long-term increases in CDD. Thus, to investigate the impacts of climate parameters on per capita residential air conditioning electricity consumption, the authors separate the climate-sensitive and the climate-insensitive components of consumption, and next isolate the effects of change in CDD (from heating) from this climate-sensitive component :

ΔE’r-AC = Δ (β1 CDD)

Where E’r-AC is the energy consumption climate sensitive component relating to air conditioning. Thus, If the electricity consumption models are applied to two climate scenarios that only differ with respect to the number of CDD the difference in E’r can be attributed solely to the air-conditioning component E’r-AC. Thus, allowing for future changes in saturation the total future air conditioning consumption can be written as:

E’r-AC, future = Sfuture * E’r-AC/S0

Using this expression it is possible to generate projections of how residential air conditioning electricity consumption would respond to changes in saturation and cooling degree days. Specifically, the study can alternately isolate the short-term response associated with baseline sensitivity of the electricity consumption models, and the long-term response associated with adjustments to the saturation, S. The response of market saturation to long-term increases in CDD is assumed to follow the slope of the saturation curve described by Eq. of S0. Thus, projected future S is given by:

Sfuture = S0 + (dS/dCDD) ΔCDD = S0 + (0.00349) exp(-0.00298CDD) ΔCDD

The most interesting result of the study is to show in detailed analysis of 12 cities in 4 states of the USA that changes in market saturation may be two or three times more important than the role of weather sensitivity of current loads.

In the case of Europe, Aebischer et al (2006, 2007) analyzed the effects of climate change on energy demand for 2035 in the Swiss service sector and then extent the methodology for different climate zones in Europe. The future energy demand is evaluated with SERVE04, a bottom-up model developed in the 1990s and recently used by CEPE in the new energy scenarios for Switzerland (Aebischer and Catenazzi, 2007). The structure is mainly a widely used bottom-up approach:

Energy demand = Σ (Floor area ij) * (specific demand per unit of floor area ij).

The major assumptions and inputs for a scenario BAU (business as usual) are documented in Aebischer et al (2006): moderate economic growth, low energy prices and “business as usual” regarding technological development and energy policy. Energy demand in this scenario BAU

Page 14

is evaluated first for the case “no change in mean yearly temperature” and then for the case “steadily mean temperature increase due to climate change”.

In the case with “no climate change”, for heat demand the calculations are done on the level of six economic sectors (denoted i) using a double cohort approach describing the dynamics of the demand of useful heat demand (building shell) and of the efficiency of the heating system (denoted j). The electricity use for air conditioning is determined by the cooled area and the specific electricity demand for cooling. In order to estimate the cooled areas, the authors postulate that “high tech” areas tend to be fully air conditioned, while “medium tech” spaces tend to be partially air-conditioned. The specific electricity use for cooling in office buildings is based on 100 office buildings study. A special analysis (Aebischer, 2005) produced the following values: 6.3 kWh/m².year for partially air conditioned office buildings, and 26.7 kWh/m².year for fully air-conditioned office buildings. As with the other technologies, the paper assumes an “autonomous” annual reduction of the specific energy requirements of -0.5 %. For calculating the specific electricity use in the other building types and economic sectors, they apply the Adnot et al (2003) simulation calculations. This leads to the following values (relative to the office buildings): trade = 129%, hospitality sector = 68%, schools = 100%, health sector = 116%, other sectors = 100%.

In the variant with “climate change”, the paper assumes an increase in average temperature of 1°C in the months from September to May, and 2°C from June through August; and an increase of 5% in solar radiation. For the years between 2005 and 2035 they apply a linear interpolation. In the case of demand for heating, they use the correction factors calculated by Hofer (2006) to quantify the effects of these new weather data on the demand for heating energy. These factors are based on building simulation models using monthly degree days and radiation values. The increase of the average temperature leads to a reduction of average heating degree days of 11%. The demand for heating decreases continuously compared to the variant no climate change and by 2035, it is 13% lower than without temperature increase, and the CO2 emissions are accordingly lower as well. In this calculation, the inventory of buildings remains unchanged relative to the trend development. In order to arrive at a value for the electricity requirements for cooling under the climate change variant, two factors have been taken into consideration: higher specific electricity use (in cooled buildings) due to higher average temperature, and faster increase of partially and fully air conditioned spaces. The impact of the first factor is evaluated using the correlation between electricity demand for cooling and the corresponding Cooling Degree Days (CDD). The correlation is determined by using results of simulations of energy demand for cooling office of Adnot et al (2003). The corresponding Cooling Degree Days (CDD) were calculated by Henderson (2005). The fit of Adnot’s energy data to Henderson’s CDD results in a very good linear dependence (eq.1).

Specific electricity demand for cooling = 12.7 + 0.103 * CDD,

in kWh/m2 of fully cooled floor area/y (1)

This linear dependence was applied when calculating the higher electricity usage under climate change. The climate change scenario leads an increase of CDD of about 199%

Page 15

between 2005 and 2035 (Hofer, 2006), and conducts to an increase in specific electricity demand for cooling, due to higher temperature of 46% in 2035 (eq.1). This increase, relative to the “no climate change” scenario, is then computed by a linear interpolation between 0 in 2005 and 46% in 2035. The second factor, the rapid increase of partially and fully air conditioned space, is based on an ad-hoc assumption that by 2035 half of the spaces that are non-cooled under “no-climate change” will be partially air conditioned, and half of the partially air-conditioned spaces will be fully so under 2035. The methodology developed in this study is extended to nine locations in Europe.

At the global scale, very few studies have performed on modeling heating and cooling demand in relation to the present climate and future climate change. Some work has been done in the context of cost-benefit models for climate change, but this is mostly on the basis of direct relationships between temperature increase and residential energy demand, obscuring underlying trends (Mendelsohn et al., 2000). Recently some work has also been performed on cooling in developing countries under present climate (McNeil and Letschert, 2007). In that way, the only and the most comprehensive work on this topic is the study conducted by Isaac and vanVuuren (2008) that modeling global residential sector energy use for heating and air conditioning in the context of climate change.

This study gives us a very detailed methodology that we summarize in the following sections. The model is based on a description of energy demand and regional changes in HDD and CDD calculated on the basis of IMAGE model for the years 2000 and 2050 for 11 aggregated regions. Energy demand for a specific end-use is described by Isaac and vanVuuren (2008) as a function of three basic elements:

E = A* S * I (1)

Activity (A) expresses the underlying driving force of energy demand for a particular sector. Structure (S) refers to other elements that determine energy demand, and Energy intensity (I) refers to the amount of energy used per unit of activity. For household cooling and heating energy demand, (1) can be rewritten as:

E = Population * Structure * ClimateParameter * Intensity / Efficiency (2)

In the residential sector the activity indicator is population, expressed as total population or as the number of households. An important structural parameter for both cooling and heating is climate –for which we use cooling degree days and heating degree days. Other parameters are slightly different for cooling and heating. For space heating, the most important structural parameter is the amount of heated floor area. Energy consumption for cooling is, however, strongly determined by appliance ownership. The corresponding intensity parameters for heating and cooling are, respectively, the actual amount of heat delivered per floor area and the energy consumption per air conditioned household. In both cases, intensity includes an efficiency component of the equipment and other factors such as the quality of house insulation, lifestyle, etc.

Page 16

The most common climatic indicator of the demand for heating and cooling services is the degree day, which is a measure of the average temperature’s departure from a base temperature. Hence the most logical choice for the base temperature is the temperature at which energy use is minimal. This is related to the desired indoor temperature and can be determined empirically. This, in turn, is influenced by factors such as lifestyle and income, and hence varies in both space and time. In this paper the base temperature taken is 18°C worldwide, for the whole period of the analysis for both heating and cooling. Heating degree days (HDD) are then calculated as follows:

If Tm <18°C then HDD = (18°C – Tm) * d Else HDD = 0 (3)

Where, Tm is the mean outdoor temperature over a period of d days.

Cooling degree days (CDD) are calculated analogously:

If Tm >18°C then CDD = (Tm -18°C) * d Else CDD = 0 (4)

IMAGE output of mean monthly temperature at a geographic resolution of 0.5°x0.5° have been used to calculate monthly degree days for each year. In order to determine regional HDD and CDD values, the gridded values were weighted by population to take into account unequal distribution of the population.

Modeling heating energy demand: As shown in eq.2, several parameters need to be defined in order to model heating energy demand. In the case of residential space heating the activity indicator is population, floor area per capita is a structure indicator and heat per floor area per degree day is the intensity indicator. Annual energy demand is then described as follows:

Final Energy = Population * m2/capita * HDD * UEh/m2/HDD / Efficiency of heating (6)

Where UEh is Useful Energy for heating, and UEh/m2/HDD is the Useful Energy heating intensity (kJ UE/m2/°C/yr). Data on current average floor areas have been collected worldwide by the Global Urban Indicators Database of UN Habitat (Urban Indicators Program, 1998), and for Europe in the Urban Audit of Eurostat (Eurostat, 2006). IEA also reports historic data for the countries included in the IEA energy indicators project (IEA 2004). The relation between floor space and GDP per capita suggests a very reasonable correlation that is used in the model. Since in the scenario used here GDP per capita increases for all regions, floor area per capita increases along with it. Heating intensity is influenced by both insulation and heating practices. Data on historic space heating energy intensity in kJ useful energy/m2/DD have been collected in the IEA energy indicator project (IEA, 2004). Because for most developing country regions data was lacking, historic heating energy intensity was estimated by assuming that in the residential sector fuels only are used for heating, cooking, and water heating. By subtracting a constant consumption level for cooking and water heating from the total fuel use, estimates of heating intensity have been derived, and used to set historical values of heating intensity in the model. A minimum of 40 and a maximum of 200 kJ UE/m2/DD was assumed. For all regions, future development is assumed to lead to a convergence of intensity at 100 kJ UE/m2/HDD in the year 2100. To calculate

Page 17

final energy demand from useful energy demand the efficiency of heating equipment needs to be taken into account. The efficiency of heating equipment is defined as the amount of useful heat that emanates from a heating device as a percentage of final energy used. Historic values for the efficiency of heating using the various energy carriers, and the assumed development of efficiency in future.

Modeling air conditioning energy demand: The authors use a model in which energy demand for air conditioning depends both on the average energy consumption per household using air conditioning (Unit Energy Consumption, UEC, kWh/Household/yr) and on the fraction of households who own air conditioners (penetration):

Final Energy = Households * Penetration * UEC / Efficiency improvement (7)

This model is based on the model described by McNeil and Letschert (2007). The number of households was calculated by dividing total population by average household size. The paper assumes that both Unit Energy Consumption and the proportion of households owning air conditioners (penetration) depend on climate and on income. Penetration in a certain region is formulated as a function of the climate maximum saturation for that region and of the percentage of the climate maximum saturation achieved at that time in the region (availability):

Penetration = Availability * Climate maximum saturation (8)

The climate maximum saturation is derived from the assumption that current penetration rates in the United States are the maximum for a climate with a given amount of CDD’s. The relationship between maximum saturation and CDD is exponential, as developed by Sailor and Pavlova (2003). Availability of air conditioners as a function of income is assumed to develop following a logistic function, with a threshold point beyond which ownership increases rapidly. Using data on present day air conditioner penetration in various countries, they describe availability as a function of income:

Availability = (9)

Where income is defined as GDP per capita. The paper next estimates the region-specific UEC based on UEC data from the literature, while assuming a linear relationship between UEC and CDD and a logarithmic relationship with income:

UEC = CDD* (0.865* ln (Income) - 6.04) (10)

UEC (kWh/household/yr) calculated with this equation increases rapidly with income at low income levels and slowly at high income levels. The slowing of growth at high income levels reflects the fact that at a certain level of income people will have their home air-conditioned as much as they wish to, after which consumption grows only with further increase of cooled surface area. It should be noted that here only energy use for conventional electric air

Page 18

conditioning is taken into account. The UEC is calculated for air conditioners with a constant efficiency level. This is adjusted to take into account the improvement of energy efficiency.

Scenario: The model described above was used with scenario results taken from the TIMER/IMAGE reference scenario for the ADAM project (MNP, 2007). The ADAM reference scenario describes a world that develops according to medium assumptions, although economic growth – especially in developing countries, is relatively high. Population follows the medium variant of the UN population projections. This scenario was developed as a reference for other scenarios. Autonomous technological progress and the worldwide diffusion of goods and services result in a convergence between world regions, which become more similar to each other in time. Under this scenario, global primary energy use increases from about 400 EJ in 2000 to about 1100 EJ in 2100, while greenhouse gas emissions from energy use increase from 8 PgC eq./yr to 20 PgC eq./yr. As a consequence, global surface temperature rise in 2100 compared to pre-industrial era is of 3.7°C.

1.2. Overview of results of impacts of climate change

1.2.1. Impacts of climate change on HDD and CDD

Modeling the impacts of climate change on energy demand is typically based on the general relationship between temperature and heating and cooling demand. Thus expected changes in HDD and CDD that would follow different scenarios or extent of climate change are an essential input or factor of any future work or attempt to forecast the impacts of potential temperature change on energy demand.

In that way, it appears interesting to report the results of Warren et al (2006) on potential changes in HDD and CDD, because they are regionally detailed and breaking down for each degree increase in global temperature between 0 to 5°C. Thus these results would be the basis of further efforts in modeling the impacts of climate change on energy use. These results are more detailed but consistent with those of Isaac and vanVuuren (2008)

Table 1: Percentage change in HDD and CDD compared to baseline for different level of climate change (Warren et al, 2006)

AMERICA Baseline 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

North America

HDD 2605 to 2615 -10 to -5% -19 to -15% -28 to -24% -36 to -32% -43 to -39%

CDD 600 to 602 +16% to +33% +50% to +69% +88% to +108% +129% to +150% +172% to +195%

Central America

HDD 424 to 428 -30% to -16% -53% to -42% -68% to -61% -79% to -74% -87% to -83%

CDD 1304 to 1305 +11% to +24% +36% to +49% +63% to +77% +92% to +107% +122% to +137%

South America

HDD 495 to 500 -20% to -10% -36% to -28% -49% to -43% -60% to -55% -68% to -64%

CDD 1464 to 1468 +10% to +20% +30% to +40% +51% to +62% +73% to +85% +96% to +108%

Page 19

ASIA Baseline 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

South AsiaHDD 296 to 305 -18% to -9% -32% to -25% -43% to -38% -52% to -48% -59% to -55%

CDD 2684 to 2691 +6% to +11% +17% to +23% +29% to +35% +41% to +47% +54% to +60%

East AsiaHDD 2083 to 2105 -10% to -5% -19% to -14% -27% to -23% -35% to -31% -42% to -38%

CDD 1056 to 1075 +9% to 19% +29% to +40% +50% to +62% +73% to +85% +97% to +109%

West AsiaHDD 632 to 649 -18% to -9% -34% to -26% -47% to -40% -58% to -52% -67% to -63%

CDD 1887 to 1912 +8% to +17% +25% to +34% +43% to +52% +61% to +71% +80% to+ 90%

Russia & Central Asia

HDD 4626 to 4664 -9% to -4% -16% to -13% -24% to -20% -31% to -27% -37% to -34%

CDD 160 to 163 +34% to 75% +120% to +169% +223% to +279% +338% to + 400% +464% to +530%

AustralasiaHDD 846 to 880 -14% to -7% -26% to -20% -37% to -32% -47% to -43% -55% to -52%

CDD 920 to 974 +9% to +18% +27% to +36% +46% to +57% +68% to +78% +89% to +100%

EUROPE Baseline 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

EuropeHDD 2942 to 2960 -10% to -5% -19% to -14% -27% to -23% -34% to -30% -41% to -38%

CDD 186 to 191 26% to +56% +89% to +126% +166% to +208% +252% to +299% +348% to 98%

AFRICA Baseline 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

North AfricaHDD 775 to 782 -19% to -9% -35% to -27% -49% to -42% -61% to -56% -71% to -66%

CDD 1253 to 1260 +9% to +19% +29% to +39% +49% to +60% +71% to +83% +95% to +107%)

South and East Africa

HDD 183 to 217 -37% to -20% -61% to -50% -76% to -69% -86% to -82% -92% to -89%

CDD 1403 to 1512 +10% to +21% +32% to +44% +55% to +67% +79% to +92% +104% to +117%

West AfricaHDD 9 -67% to -40% -90% to -82% -98% to -95% -100% to -99% -100%

CDD 2835 to 2844 +6% to +13% +20% to +26% +33% to +39% +46% to +52% +59% to +66%

1.2.2. Impacts of climate change on energy demand and CO2 emissions

The Isaac and vanVuuren (2008) study assesses the potential development of energy use for future residential heating and air conditioning in the context of climate change. In the scenario used, global energy demand for heating is projected to increase until 2030 and then stabilize. In contrast, energy demand for air conditioning is projected to increase rapidly between 2000 and 2100, mostly driven by income growth. The associated CO2 emissions for both heating and cooling increase from 0.8 GtC in 2000 to 2.2 GtC in 2100, i.e. about 12% of total CO2

emissions from energy use.

More precisely, we summarize here the results of Isaac and vanVuuren (2008) relating to the net effects of climate change on energy demand following impacts on heating and cooling needs, and resulting CO2 emissions. Increasing temperatures conduct to a reduction in the

Page 20

demand for heating and an increase in the demand for cooling, as shown in the equations used to build the model. The climate change scenario used in the study is considerate as a medium one, and generate an increase of temperature of about 3.7 °C in 2100. The net effect of climate change on global energy use and emissions is relatively small as decreases in heating are compensated for by increases in cooling. However, impacts on heating and cooling individually are considerable in this scenario, with heating energy demand decreased by 34% worldwide by 2100 as a result of climate change, and air conditioning energy demand increased by 72%.

The impact of climate change on heating energy demand is substantial in this scenario. The relative decrease in heating energy demand due to climate change is largest in those regions which already have very low heating demand. However, the absolute reductions are much larger in temperate regions: the expected reduction in heating energy demand is, for instance, more than 20% in Canada and Russia. Worldwide, the reduction in heating energy demand by 2100 is 34%.

In contrast worldwide demand for cooling energy in 2100 is about 70% greater than projected demand without climate change. At the regional scale considerable impacts can be seen, particularly in South Asia, where energy demand for residential air conditioning could increase by around 50% due to climate change, compared to the situation without climate change. The relative increase in the demand for cooling as a result of climate change is highest in cold regions. These increases are close to the percentage increase of CDDs in each region (as Unit Energy Consumption depends linearly on CDDs in the model).

While changes in heating and in cooling demand due to climate change are both substantial, the changes are in different directions, and globally the net effect is relatively small compared to the total energy demand. Thus, the results are highly sensitive to the scenario assumptions. For the scenario described in this study, at the global scale, during the first half of the century the decline in heating energy demand is larger than the increase in cooling energy demand. As a result there is a net reduction in energy demand due to climate change during this period. During the second half of the century this pattern is reversed, and by the end of the century the net effect is an increase in energy demand.

This canceling out of increase in cooling and decrease in heating occurs, however, only at the global scale. At the regional scale, the effect of climate change is distributed unequally across the globe. In general, temperate regions experience in reduction in energy demand, while tropical regions experience an increase. There are several regions for which an initial decrease is reversed in the second half of the century. The model suggests a decrease in energy demand for the USA, which is in accordance with regional studies summarized by USCCSP (2006). In the tropical regions of South America, Africa, India and the rest of Asia climate change causes a substantial increase in energy demand.

Compared to a mitigation scenario that would stabilize at 450 ppm CO2 Eq., resulting in a temperature increase of 2°C in 2100 instead of almost 4°C., effects on energy demand is

Page 21

reduced. Hence, the reduction in energy demand seen in the reference scenario in the first decades appears though to a lesser degree in the stabilization scenario, but the increase in energy demand in the later decades of the century is absent in the stabilization scenario.

In contrast to energy demand, the impact of climate change on global CO2 emissions in the reference scenario is clearly upward during the second half of the century: emissions increase by more than 0.3 Gt C in 2100. This is equal to about half of the total CO2 emissions from the residential sector in 2000. The reason for the stronger increase in CO2 emissions is that a large part of the reduction in energy demand is achieved through a reduced use of heating fuels, while electricity use for cooling increases. As in this scenario the emissions factor for electricity is significantly above that of fuels, this leads to an increase in emissions.

At the regional scale, the model suggests that in the very long run the most strongly affected region is India, which accounts for more than two thirds of the global increase in emissions associated with increased air conditioning as a result of climate change. In India the rate of emissions increase grows gradually, as does air conditioner ownership. In China, on the other hand, the initial increase is much more rapid, but is followed by stabilization. This reflects the earlier adoption of air conditioning in China than in India (as a result of higher incomes), and the larger potential for a reduction in heating energy demand in China. The end result is that until about 2050 the emissions increase is larger in China than in India, but after that emissions increase much more strongly in India. In the rest of Asia there are also clear increases in emissions. For the USA, increasing temperature will result in lower emissions, in agreement with the finding of USCCSP (2006). In other regions the net effect is small.

1.2.3. Impacts of climate change on seasonal patterns of energy demand

The development of air conditioning and change in relative importance of heating and cooling will also have consequences for the seasonal pattern of energy demand, with the current global peak in residential energy consumption during the northern hemisphere winter becoming much less pronounced, and many regions gaining a summer peak in addition to, or instead of, the winter peak.

The annual patterns of energy demand would change due to climate change, particularly in China, West Europe and India. While currently the energy consumption pattern for residential energy heating and cooling is dominated by the winter peak, this winter peak becomes less pronounced over time, and there is a growing summer peak in those regions with warm summers.

This profile obviously differs significantly between regions. The USA currently already has a very small summer peak, while Europe remains dominated by the single winter peak. China gains a summer peak in the coming decades, and India currently has a very small winter peak but gains, with its increasing energy demand, a single, summer peak.

Page 22

This impact of climate change appears as a major trend for the entire energy sector. This would leads to important system and management adaptation, particularly when the effects of climate change on energy production, like impacts on hydropower production and thermoelectric cooling (particularly in the context of thermal regulation) are taken in account.

ReferencesAdnot et al, 2003, Energy Efficiency and Certification of Central Air Conditioners (EECCAC), A study for the D.G. Transportation-Energy (DGTREN) of the Commission of the E.U., Paris

Aebischer B., 2005, Spezialauswertung der Daten in Weber (2002), CEPE internal report

Aebischer B., Catenazzi G., 2007, Energieverbrauch der Dienstleistungen und der Landwirtschaft. Ergebnisse der Szenarien I-IV. Schlussbericht. Bundesamt fur Energie, Bern

Aebischer B., Henderson, G., Jakob, M., Catenazzi, G., 2007, Impact of climate change on thermal comfort, heating and cooling energy demand in Europe, ECEEE 2007 Summer Study, 12 p.

Aebischer B., Henderson G., Catenazzi G., 2006, Impact of climate change on energy demand in the Swiss service sector - and application to Europe, Paper presented at the International Conference on Improving Energy Efficiency in Commercial Buildings, Frankfurt, Germany, 26-27 April 2006, 14 p.

Amato A.D., Ruth M., Kirshen P., Horwitz J., 2005, Regional energy demand responses to climate change: Methodology and application to the commonwealth of Massachusetts, Climatic Change, 71, pp.175-201

Belzer D.B., Scott M.J., Sands R.D., 1996, Climate change impacts on U.S. commercial building energy consumption: an analysis using sample survey data, Energy Sources, 18, p. 177–201

Chow T.W.S., Leung C.T., 1996, Neural network based short term load forecasting using weather compensation, IEEE Trans Power Syst, 11(4), p. 1736–1742

Commercial Building Energy Consumption Survey (CBECS), 1992, US Energy Information Administration, DoE/EIA-0318(89), Washington, DC US Department of Energy

Considine T.J., 2000, The impacts of weather variations on energy demand and carbon emissions, Resource and Energy Economics, 22, p.295–314

Dash P.K., Liew A.C., Rahman S., 1996, Fuzzy neural network and fuzzy expert system for load forecasting, IEEE Proc—Generation Transmission and Distribution, 143(1), p. 106–114

Eurostat, 2006, Urban Audit, European Commission

Hofer P., 2006, Der Energieverbrauch der Privaten Haushalte, 1990–2035, Ergebnisse der Szenarien I bis IV und der zugehorigen Sensitivitaten BIP hoch, Preise hoch und Klima warmer, Bundesamt fur Energie, Bern

Huang Y.J., Ritschard R., Bull J., Chang L., 1986, Climatic indicators for estimating residential heating and cooling loads, Lawrence Berkeley Laboratory report LBL-21101

IEA, 2004, Oil Crises and Climate challenges: 30 Years of Energy Use in IEA Countries, International Energy Agency, Paris

Isaac M.., van Vuuren D., 2008, Modeling global residential sector energy demand for heating and air conditioning in the context of climate change, 61 p.

Islam S.M., Alalawi S.M., Ellithy K.A., 1995, Forecasting monthly electric load and energy for a fast growing utility using an artificial neural network, Electric Power System Research, 34(1), p. 1–9.

Kreider J.F., Claridge D.E., Curtiss P., Dodier R., Haberl J.S., Krarti M., 1995 , Building energy use prediction and system identification using recurrent neural networks, Journal of Solar Energy Engineering, 117, p. 161–166.

McNeil M.A., Letschert V.E., 2007, Future air conditioning energy consumption in developing countries and what can be done about it: the potential of efficiency in the residential sector, ECEE 2007 Summer Study, 12 p.

Mendelsohn R., Morrison W., Schlesinger M.E., Andronova N.G., 2000, Country-specific market impacts of climate change, Climatic Change, 45, pp. 553-569.

MNP, 2007, D-S.1 Preliminary ADAM scenarios (deliverable for the ADAM project)

Residential Energy Consumption Survey (RECS), 1996, US Energy Information Administration, DoE/EIA-0314(93), Washington DC

Rong F., Clarke L. Smith S., 2007, Climate Change and the Long-Term Evolution of the U.S. Buildings Sector, Pacific Northwest National Laboratory, Richland, Washington

Sailor D.J., 2001. Relating residential and commercial sector electricity loads to climate - evaluating state level sensitivities and vulnerabilities, Energy, 26, pp. 645-657.

Page 23

Sailor D.J., Munoz J.R., 1997, Sensitivity of electricity and natural gas consumption to climate in the U.S – Methodology and results for eight states, Energy, 22(10), p. 987-998

Sailor D.J. Pavlova A.A., 2003, Air conditioning market saturation and long-term response of residential cooling energy demand to climate change. Energy, 28, pp. 941-951.

Scott M.J., Wrench L.E., Hadley D.L., 1994, Effects of climate change on commercial building energy demand, Energy Sources, 16, p. 317–332.

Segal M., Shafer H., Mandel M., Alpert P., Balmor V., 1992, Climatic-related evaluations of the summer peak-hours’ electric load in Israel, Journal of Applied Meteorology, 31, p. 1492–1498

Urban Indicators Programme, 1998, Global Urban Indicators Database. UN Habitat

USCCSP, 2006, Effects of climate change on energy production and use in the USA

Warren R., Arnell N., Nicholls R., Levy R., Price J., 2006, Understanding the regional impacts of climate change. Research Report Prepared for the Stern Review on the Economics of Climate Change, Working Paper 90, Tyndall Center for climate change research, 223 p.

Page 24

2. Assessment of the impact of climate change on hydroelectricity production

Electricity generation from hydropower makes a substantial contribution to meet the increasing world electricity demands. In the mid 1990s hydropower plants accounted for some 19% of total electricity production worldwide. The installed capacity amounted to 22% of the total installed capacity for electricity generation. The role of hydropower, along with other renewable energy sources, is expected to become increasingly important in future. Worldwide average growth rates of hydroelectricity generation in the future are estimated (par qui) from about 3.6% per year between 1990 and 2020. The highest growth rates are expected in developing countries. The increased use of renewable energy is critical to reducing emissions of GHG. Hydropower is currently the major renewable source contributing to electricity supply, and its future contribution is anticipated to increase significantly. However, the successful expansion of hydropower is dependent on the availability of the resource and the perceptions of those financing it. Global warming and changes in precipitation patterns will alter the timing and magnitude of river flows. This will affect the ability of hydropower stations to harness the resource, and may reduce production, but also implying lower revenues and poorer returns. The very fact that renewable energy resources harness the natural climate means that they are at risk from changes in climatic patterns. As such, changes in climate due to higher greenhouse concentrations may frustrate efforts to limit the extent of future climatic changes.The methodology that has guided this literature overview on the assessment of potential effects of climate change on hydropower is three-fold: (i) we describe first literature that directly focuses on the impacts of climate change scenarios on hydroelectricity generation, (ii) given the limited literature, particularly regarding regions covered, we propose to approximate potential changes in gross hydroelectric potential and installed capacity to anticipated changes in runoff consecutive to different climate change scenarios, (iii) finally we analyze the potential effects of risks on anticipated hydropower investment.

2.1. Impacts of climate change on gross and developed hydropower potentials

2.1.1. Hydropower potential indicators and station types

Hydropower potential indicatorsNumerous attempts have been made to assess the hydropower potential of countries. But the results reveal striking inconsistencies. Partly, ambiguous definitions of energy terms have been deemed responsible. In this literature overview on climate change impacts on hydropower, we focus broadly on two types of hydropower potentials, the gross hydropower potential and the developed hydropower potential.The gross hydropower potential is defined as the annual energy that is potentially available if all natural runoff at all locations were to be harnessed down to the sea level without any energy losses. The share of this highly theoretical potential which has been or could be developed under current technology, regardless of economic and other restrictions forms the technical hydropower potential. From this, the economic hydropower potential is the portion, which can or has been developed at costs competitive with other energy sources. Finally, the exploitable hydropower potential takes into account environmental or other special

Page 25

restrictions. For comparison of magnitudes, Eurelectric (1997) estimates the world’s gross hydropower potential at 51 000 TWh/a, the economic hydropower potential at 13 100 TWh/a, and the exploitable hydropower potential at 10 500 TWh/a. The gross hydropower potential gives a first impression of total resources of hydropower. However, it is just a theoretical value, only a small part of which is actually developed at existing power stations. Hence the impact of climate change on the gross hydropower potential will provide an indication of the general trends, but cannot be directly interpreted as a proportional change in actual hydroelectricity production. For example, a decrease of discharges in a part of the world with no hydropower stations will not alter the existing hydroelectricity production; thus it is important for a comprehensive assessment to know where the hydropower stations are located.Therefore a focus on the developed hydropower potential of existing hydropower stations (actually supplied electricity by hydropower) completes information given by gross hydropower potential. With some 2240 TWh/a, the developed global hydropower potential in 1990 accounted for about 21% of the world’s estimated exploitable hydropower potential, or about 4% of the world’s gross hydropower potential. As for Europe, from the estimated exploitable hydropower potential of 1670 TWh/a only 745 TWh/a were actually supplied by hydropower in 1990, and some 1080 TWh/a are expected to be available in 2020.

Types of hydropower stationsImpacts of climate change and related expected variations of runoff on hydropower generation would be different for “run-of-river” and “reservoir” station. The main difference is that reservoir stations are generally assumed to be able to store and to fully harness today’s as well as (even increasing) future inflow volumes (in reasonable limits). Hence all discharge is utilizable discharge. Conversely, a run-of-river station cannot utilize the portion of flood discharges that overflows the station, independent of the magnitude of discharge excess. Likewise in case of low flow events, reservoir stations would be less susceptible to runoff variability than run-of-river station because of storage possibility in reservoirs. Characteristics and utilizable discharge of reservoir and run-of-river stations would be distinguished as follows:Run-of-river stations operate on base load and use the incoming river flow continuously with a filling period of less than 2 hours. The advantage of low-cost investments and constructions is countered by fluctuations in energy production. During low flow periods the stations cannot operate at their full installed capacity. Flood flows, on the other hand, overflow the installation unexploited. A run-of-river station cannot utilize the portion of flood discharges that overflows the station, independent of the magnitude of discharge excess. Hence, a cut-off or threshold level has to be taken into account, above which discharge cannot be harnessed, neither today nor in the future (Figure 1). The cut-off level is difficult to estimate as it depends on various factors, in particular the given technical installations and the maximum load of the station. In the Lehner et al (2005) analysis of climate change impacts for hydropower in Europe (see below), due to insufficient data, and thus the impossibility to assign an individual cut-off level to each station throughout Europe, a “representative” level is applied. To derive this level, the seasonal regime was calculated for each grid cell of the WaterGAP model based on the time series 1961-90, and the second highest mean monthly discharge within the year was then chosen as the cell representative cut-off level.

Page 26

Figure 1: Harnessing discharge for power generation in run-of-river stations

Source: Lehner et al, 2005

Reservoir stations store their cumulative flows wholly or partly in their retaining works in order to generate electricity during times of higher demand. Depending on their storage capacity and operational management, reservoir stations can store water over long time periods and generate a steady supply of electricity, relatively independent from variations in short-term inflow. It should be noted that the main purpose of a reservoir is often not the production of electricity, but for example flood control, forcing the type of operation to be adaptive (e.g. no full exploitation of storage capacity).Thus it is generally assumed that reservoir stations are able to store and to fully harness today’s as well as (even increasing) future inflow volumes (in reasonable limits). In the study of Lehner et al (2005) for Europe, all discharges are supposed to be utilizable discharge. This assumption is based on data supplied by UCTE and NORDEL that show that the maximum possible work load of UCTE and NORDEL reservoirs is only utilized by about 10-25%. At the same time the storage capacity of the reservoir stations is in the range of 30% or more of the total annual energy production. This combination of large storage capacities and not fully exploited work load allows a management of the reservoirs in a way such that they can balance increasing inflows. In certain cases, however, this “average” finding might not be applicable or an adaptation in reservoir management might be restricted by other objectives, e.g flood control.

Others issues relating to multipurpose of reservoir station When thinking about the potential impacts of climate change on hydropower, it is important to keep in mind the multipurpose character of reservoir station water management. Electricity production is generally the lattest objective, after flood regulation, irrigation needs and recreationnal uses. Thus the impacts of climate change on utilities have to be understood in the full context of competitive or alternative water uses. Note that climate change may also modify the hierarchy of priorities, as it changes regional water management issues.

2.1.2. Literature on climate change impacts on hydropower generation overview

Hydropower potential is defined by the river flow, and therefore changes in flow due to climate change will alter the energy potential. More importantly, as most hydropower schemes are designed for a particular river flow distribution, plant operation may become non-optimal under altered flow conditions. The capability of a given hydro installation to generate electricity is limited by its storage and turbine capacities. These place limits on the amount of carry-over storage to allow generation during dry spells, and also the degree to which benefit can be derived from high flows. Several studies have examined the impact of

Page 27

climate change on hydropower potential and production and representative examples often mentioned in the literature are listed in Table 2.

Table 2: Examples of potential changes in annual hydroelectric generation resulting from changes in temperature and precipitation

Region/River Temperature change Precipitation change Hydropower production change

Nile River* + 4.7 °C + 22 % - 21 %

Indus River* + 4.7 °C + 20 % + 19 %

Colorado River** + 2.0°C - 20 % - 49 %

New Zealand*** + 2.0°C + 10 % + 12 %

Source: *Reibsame et al (1995), **Nash & Gleick (1993), ***Garr & Fitzharris (1994)

Literature on EuropeLehner et al (2005) analyze the potential impacts of two global climate change scenarios on hydropower potential in Europe. The approach of the study is two-fold: (i) it analyses the change in Gross Hydropower Potential as a general indicator, and (ii) then focuses on the change in Developed Hydropower Potential of existing power plants in order to get a more realistic view. The goal of both approaches is not to provide quantitative results in terms of absolute capacities or electricity production. Rather the aim is to analyze “in which European countries can we expect a significant increase or decrease of the potential to generate hydroelectricity due to climate change?”. The study is based on the global integrated model WaterGAP 2.1. - Gross hydropower potential: In order to calculate Europe’s gross hydropower potential, the potential of each single 0.5° grid cell of the WaterGAP model has been derived. Two methods were applied: (A) The total gross hydropower potential down to sea level is assigned to each cell. According to the general relationship hydropower potential, runoff and elevation, 1 m3 of runoff generated at an elevation of 1000 m above sea level represents 2.8 KWh of potential energy, regardless of whether this potential can be harnessed within the cell or not. (B) Only that portion of the gross hydropower potential that can be locally utilized down to the next downstream cell is allocated to each cell. The standard approach of method A mainly describes where the hydropower potential is formed, but does not indicate where the potential can actually be utilized. Despite this limitation, the approach is still adequate when looking for total sums, e.g. for a basin or a continent. The method B, on the other hand, locates the gross hydropower potential and thus leads to a more realistic distribution of the potential on a cell-to-cell basis.Table 3 lists the calculated gross hydropower potentials for both methods by country. In order to estimate the impact of climate change on the gross hydropower potential, runoff and river discharge for all grid cells of Europe are calculated for different climate and water use scenarios and different time slices. As for water use, the study applied the Baseline-A scenario; for climate change, the results of the two state-of-the-art GCMs ECHAM4 and HadCM3 (which consider an average annual increase of global CO2 by about 1% per year until 2100) for the time slices of the 2020s and the 2070s are used. The induced changes in gross hydropower potential are directly proportional to the changes in runoff or discharge. Figure 2 presents the relative changes in total discharge for the described scenarios. Table 3

Page 28

lists, for the HadCM3 climate model in the 2070s, the changes of gross hydropower potentials by country. In total, the gross hydropower potential of Europe in the 2070s is derived at approx. 2400 TWh/a, hence about 4% lower than today.

Table 3: Gross and installed hydropower potentials in Europe and response changes due to climate change

- Developed hydropower potential: The calculated changes of the gross hydropower potential due to climate change provide a first indicator of a country’s trend in its future hydropower situation. But only that part of the gross potential which is or will be utilized through power plants will affect future hydropower production. In order to assess the developed hydropower potential, detailed information is required on existing hydropower stations, including their location, installed capacity and type of power generation. The study generated a new data set which geo-references 5991 hydropower stations in Europe where run-of-river and reservoir stations are distinguished. Accordingly, the supplied hydroelectricity can be increased (or decreased) in the future by changes in the installed capacity and/or changes in available discharge. However, due to lack of adequate data and the difficulties in quantifying expected

Page 29

refurbishment or new constructions, the study was not able to estimate the future development of total installed hydropower capacities. The future change in developed hydropower potential is thus only assessed by changes in discharge. Nevertheless, this is believed to provide a representative indicator to whether the impacts of global change will lead to a general growth or decline in the overall developed hydropower potential.For this assessment, two general assumptions are made: (i) All existing hydropower stations are assumed to have comparable efficiency-rates of discharge utilization and they are designed to match today’s discharge. (ii) A change in utilizable discharge has a directly proportional effect on electricity production, independent from its installed capacity. Utilizable discharge of run-of-river and reservoir stations is distinguished, and a threshold level is defined, above which discharge cannot be harnessed by run-of-river stations, neither today nor in the future. In order to estimate the impact of climate change on the developed hydropower potential, the utilizable river discharges were calculated with WaterGAP for present and future scenarios for all grid cells. Figure 2 shows an example for the 2070s, where the relative change of total discharge are superimposed with geo-referenced hydropower plants. In the case of a reservoir station, the relative change in utilizable discharge at its location directly represents the power plant’s relative change in power potential. In the case of a run-of-river station, the relative change in utilizable discharge would somewhat differ from the relative change in total discharge but shows similar tendencies.A strong tendency for declining discharge volumes occurs in Southern and parts of East-Central Europe, with maximum decreases of more than 25%. Conversely, strong increases in discharge volumes apply for large areas in Northern Europe with maximum rises of more than 25%. Table 3 summarizes the changes in developed hydropower potentials on a country basis. The most significant decreases occur in Spain, Bulgaria, Ukraine, and Turkey, while increases are strongest in Norway, Sweden, Finland and Russia. The predictions of changes in discharge of both models are contradictory in several regions for their respective 2020s and 2070s (Italy, Northern Germany, Bulgaria, Greece for ECHAM4; Norway, Sweden, Iceland, Portugal, Spain, Bulgaria, Greece for HadCM3). ECHAM4 and HadCM3 lead to opposite results for large areas in Western Europe (Iberian Peninsula, Great Britain, France, Germany, Norway, Sweden, and Iceland). In the 2070s, the Mediterranean region around Italy and Southern Great Britain develop differently depending on which of the two GCMs is applied, but commonly the agreement is closer than in the 2020s.Table 3 additionally lists the gross hydropower potential and its change for the HadCM3 scenario in the 2070s, both for method A and B. Comparison of these relative changes with the corresponding changes in developed hydropower potential indicates that in most cases the trends and the order of magnitude are similar. Generally, method B shows a closer agreement, as it accounts for the located gross hydropower potential on a cell-to-cell basis – this seems to better reflect the concept underlying the calculations for the developed hydropower potential. In Portugal, for example, method A leads to a reduction of about 5% in gross hydropower potential, which refers to all runoff generated within Portugal. Method B, on the other hand, leads to a reduction of about 20%, as it takes the largely reduced inflows from Spain into account. The developed hydropower potential of Portugal, which is dominated by reservoirs along inflowing rivers from Spain, shows a similar tendency with a reduction of about 22%. Thus, the relative change in gross hydropower potential calculated according to method B provides a good indicator for the change in developed hydropower potential.

Page 30

Figure 2: Relative change of average (1961-90) total discharge volumes calculated with WaterGAP 2.1 for the 2070s (HadCM3 climate model and Baseline-A water use scenario), superimposed by georeferenced European hydropower plants

Figure 3: Relative change of average (1961-90) total discharge volumes calculated with WaterGAP 2.1 for the 2020s and 2070s (ECHAM4 and HadCM3 climate models and Baseline-A water use scenario).

Page 31

Other than energy volume, the impact on generation reliability has been examined by Mimikou and Baltas (1997) that focalize on the climate change impacts on the reliability of hydroelectric energy production of large multipurpose reservoirs in northern Greece. This paper presents an assessment of climate change impacts on water management issues such as reservoir storage and hydroelectric production. Two equilibrium scenarios (UK Meteorological Office High Resolution model, UKHI, and Canadian Climate Centre model, CCC) referring to years 2020, 2050 and 2100 and one transient scenario (UK High Resolution Transient output, UKTR) referring to years 2032 and 2080 were applied to represent climate change potential impacts on precipitation and potential evapotranspiration. By using these scenarios, the sensitivity of the risk associated with the annual hydroelectric energy production of a large multipurpose reservoir has been evaluated under conditions of altered runoff. It is shown that the operational characteristics of the reservoir designed and operated under current climatic conditions are, in general, affected by the climate change scenarios examined. Increases of the risks associated with the annual quantities of energy production have been observed, particularly under the UKHI and the UKTR scenarios. For the UKHI scenario, increases of reservoir storage volumes of up to about 12% and 38% are required in order to maintain at current risk levels the minimum and mean annual energy yields respectively, while for the UKTR scenario the corresponding increases are estimated to be about 25% and 50%.

Literature on the United States of AmericaSubstantial amounts of electricity are produced by hydroelectric facilities in U.S. Variability in climate already causes variations in hydroelectric generation. During a recent multi-year drought in California, Gleick and Nash (1991) show that decreased hydropower generation led to increases in fossil-fuel combustion and higher costs to consumers. Between 1987 and 1991, these changes cost rate payers more than $3 billion. Because of conflicts between flood-control functions and hydropower objectives, climate change in California may require more water to be released from California reservoirs in spring to avoid flooding. This would result in a reduction in hydropower generation and the economic value of that generation. At the same time, production of power by fossil fuels would have to increase to meet the same energy demands in California at a high cost and an increase in GHG emissions (Hanemann and McCann, 1993). Climate changes that reduce (increase) overall water availability or change the timing of that availability would adversely (positively) affect the productivity and production of hydroelectric facilities.

Nash and Gleick (1993) evaluated how equilibrium and transient climate scenarios would affect hydroelectricity production in the Colorado River system. Hydroelectricity production in the lower Colorado Basin was determined to be more sensitive to changes in runoff in the basin than any of the other variables studied, including salinity, reservoir levels, and deliveries of water to users. Under current operation laws and rules, Lake Mead has a relatively high minimum power pool and water deliveries are constrained to maintain some power-generating capacity. As a result, power is generated at a relatively constant level until critical reservoir levels are reached. At this point power generation ceases. A 10% increase in average runoff was estimated to increase basin hydroelectricity production by 11%. Decreases in runoff of only 10% were projected to decrease hydroelectricity production from the whole Colorado basin by 15% and from the lower basin by 36% because minimum power-pool levels are more frequently reached. An average drop in runoff of 20% resulted in a 57% decrease in hydroelectricity production in the whole basin and a 65% decline in hydroelectricity production in the lower basin. Table 4 shows the sensitivity of water supply

Page 32

variables including hydroelectricity production to changes in the natural flows of the Colorado under the current law of the river. No runs were made to explore the impacts on water deliveries or reservoir levels if operators try to maximize power production, but presumably hydropower production could be increased at the cost of a reduction in the reliability of water deliveries.

Table 4: Sensitivity of water-supply variables to climate change in the Colorado river basin (Nash and Gleick, 1993)

Change in natural flow (%) Change in actual flow (%) Change in storage (%) Change in power generation (%)

-20 -10 to -30 -61 -57

-10 -7 to -15 -30 -31

-5 -4 to -7 -14 -15

5 5 to 7 14 11

10 11 to 16 28 21

20 30 38 39

A more sophisticated study by Lettenmaier et al. (1999) looked at how climate change would affect a wide range of system characteristics for major watersheds, complex reservoir systems, in several parts of the United States. They conducted a broad assessment of the sensitivity of six major U.S. water resource systems to climate change and evaluated the performance of multiple-use systems. These studies applied a range of transient GCM scenarios and evaluated the effects on end users of water. Six systems were studied: two large river basins (the Columbia and Missouri), two moderate size basins (the Savannah and Apalachicola-Chattahoochee-Flint (ACF)), and two urban water-supply systems (Boston and Tacoma). For each system, several indicators were evaluated, including system reliability (defined as the percentage of time the system operates without failure), the system resiliency (ability of the system to recover from a failure), and the system vulnerability (average severity of failure). They evaluated the impacts of a range of climate change scenarios, including three transient scenarios and an equilibrium doubled-CO2 scenario. Their analysis concluded that power operations would be most sensitive to climate change in the Missouri River, where the climate scenarios would result in declines in the reliability of meeting monthly energy targets of as much as 15 to 35%. For the Columbia River basin, shifts in the seasonal hydrograph are critical, as are operating policies. In this region reliability of firm energy production showed progressive declines of as much as 5 to 15% over time as climate changes; more modest decreases were seen in the equilibrium doubled-CO2 scenario. For the Savannah River, two out of the three transient scenarios led to increases in hydroelectricity production; the third had slight declines. Results for the ACF basin were similar in direction to the Savannah basin, but smaller.While most of the scenarios were evaluated assuming current operating conditions, some alternative operational scenarios were evaluated. For example, the current conflicts in the

Page 33

Columbia basin over fisheries protection versus hydropower generation could lead to a reprioritization of operational rules. Another possibility is that hydropower generation might be constrained by recreational needs to maintain reservoir levels in summer. Both of these alternatives were evaluated under conditions of climate change, and the overall effects on hydropower were on the order of those effects for the most severe climate scenarios using current operating rules.

Georgakakos and Yao (2000) conducted a detailed hydropower assessment for the Apalachicola-Chattahoochee-Flint (ACF) river basin in the southeastern United States under historical and two climate change scenarios. The study is based on a decision-support system developed for water allocation negotiations among Georgia, Alabama, and Florida states. This assessment system is a detailed river-basin management model that represents all storage reservoirs, hydropower facilities, water-supply withdrawals (agricultural, municipal, and industrial), environmental flow requirements, recreational constraints, and navigational needs. Their model includes details of the basin’s hydropower facilities and optimizes peak and off-peak energy generation subject to all other water-use commitments and constraints. The study is based on three climate scenarios, and for water demands projected for the year 2050. These include the historical climate, and two potential futures generated by two different GCMs for 1994 to 2094. The climate change scenarios are generated by Canadian Center for Climate Modeling and Analysis (CCCMA) and the U.K. Hadley Meteorological Office (UKMO). Both models assume a 1% annual increase in atmospheric CO2. Both indicate increasing temperature trends, but the rainfall trends are inconsistent. Compared to the historical baseline, under the CCCMA Scenario, all basins exhibit less precipitation, ranging from - 15 to - 22%, an increase of evapotranspiration by 16 to 22%, a reduction of runoff of 28 to 48%, and smaller runoff coefficients. By contrast, under the UKMO Scenario, the basins experience an increase of precipitation (7-14%), evapotranspiration (8-11%), and runoff (7-21%), and higher runoff coefficients. The differences between the two climate scenarios indicate the uncertainties associated with such long-range climate predictions, and the need to consider them in water resources planning and management.The results indicate that under the Canadian scenario, the ACF river basin would shift toward substantively drier regimes and experience severe water shortages. Water-supply deficits would increase more than 50-fold in the basin upper part while reservoir levels would experience frequent and very severe draw downs. Water-level fluctuations of such magnitude would sharply diminish the ability of the lake to provide relief during droughts, generate dependable energy, and maintain its high recreational value. Under this scenario, the ACF system would also frequently fail to meet the low flow targets throughout the basin. These adverse effects are exacerbated if the reservoirs are operated according to the historical operational practices. Relative to the historical response, the dry CCCMA scenario resulted in a 33% reduction in total energy generation, a 14% reduction in peak energy generation, and a 35% reduction in off-peak energy generation. Under the UKMO scenario, which is considerably wetter, reservoir level fluctuations are comparable to those of the historical run, and no appreciable water supply deficits are expected to occur. Energy generation could increase by about 21% relative to the historical levels. They conclude their assessment by showing that the significant uncertainty associated with future climate necessitates flexible and adaptive water allocation agreements, management strategies, and institutional processes.

Finally, Chao (1999) evaluated ten different steady-state and transient climate change scenarios and modeled changes of hydropower generation in the Great Lakes compared with a base climate. Hydropower plants and their diversion works along the St. Mary’s and St.

Page 34

Lawrence rivers serve as water-level control structures for Lake Superior and Lake Ontario. The model also includes hydropower generated at Niagara. Treaties between the United States and Canada determine flow releases, but there are exceptions in the treaties when levels and flows fall outside treaty conditions. In all ten scenarios, hydropower generation decreased because of projected decreases in lake levels. On average, hydropower dropped 7 to 10%, though it decreased in some scenarios by as much as 20%.

2.2. Effects of climate change on hydrological systems and run-off

2.2.1. The hydroelectricity potential and runoff nexus

Literature that directly focuses on effects of climate change scenarios on gross hydropower potential and production of installed capacities remains very scarce, particularly when looking on aggregated (macro) regional and country studies. Facing such limitation, the more reliable assumption to anticipate, in first approximation, the impacts of climate change on hydroelectricity, would remain in the strong nexus between variations in runoff and relating changes in hydroelectric generation potential and/or production of installed capacity (Lehner et al, 2005 ; Alstom, 2009).

This assumption is made on the general relation: GP = m . g . h.,

where the gross hydropower potential (GP) is defined as the product of mass of runoff (m), gravitational acceleration (g) and elevation above sea level (h). With climate change, only the runoff variable (m) will observe potential changes, impacts on hydroelectricity generation would thus be encapsulated as this variation for a first approximation.

In that way, we focus here on studies that analyze the nexus between climate change and runoff, the main objective remain to describe the functional relationship between changes in global mean temperature due to climate change and change in runoff on a regional basis.

2.2.2. Overview of potential effects of climate change on regional runoffs

At first glance, rising global precipitation would seem to provide opportunities for increased use hydroelectricity. Unfortunately, such increases will not occur uniformly over time and space, and many regions are projected to experience significant reductions in precipitation. In addition, the temperature rise will lead to increased evaporation. The combination of changes in precipitation and evaporation will have profound effects on catchment soil moisture levels. Moreover, impacts on seasonal flows depend on regime types, dominated by rainfall and evaporative regime (winter max), and dominated by snowfall and snowmelt (spring max). In river basins that experience historical significant snow-fall, higher temperatures will tend to increase the proportion of wet precipitation. This may increase winter river flows, lead to an earlier spring thaw and reduce summer low flows (Gleick, 1986).Bates et al (2008) provide a summary of IPCC finding on water issues, mostly based on 4th

Assessment Report. They show that changes in runoff depend primarily on changes in the volume and timing of precipitation and, crucially, whether precipitation falls as snow or rain. Changes in evaporation also affect river flows. Studies are heavily focused towards Europe, North America and Australia, with a small number of studies from Asia. Virtually all studies use a catchment hydrological model driven by scenarios based on climate model simulations, and almost all are at the catchment scale. The few global-scale studies that have been

Page 35

conducted using both runoff simulated directly by climate and hydrological models show that runoff increases in high latitudes and the wet tropics, and decreases in mid-latitudes and some parts of the dry tropics. Figure 4 shows the change in annual runoff for 2090–2099 compared with 1980–1999, using the SRES A1B scenario. Runoff is notably reduced in southern Europe and increased in south-east Asia and in high latitudes, where there is consistency among models in the sign of change (although less in the magnitude of change). Flows in high-latitude rivers increase, while those from major rivers in the Middle East, Europe and Central America tend to decrease. The magnitude of change, however, varies between climate models and, in some regions such as southern Asia, runoff could either increase or decrease. A very robust finding is that warming would lead to changes in the seasonality of river flows where much winter precipitation currently falls as snow, with spring flows decreasing because of the reduced or earlier snowmelt, and winter flows increasing. This has been found in the European Alps, Scandinavia and around the Baltic, Russia, the Himalayas, and western, central and eastern North America. The effect is greatest at lower elevations, where snowfall is more marginal, and in many cases peak flows by the middle of the 21st century would occur at least a month earlier. In regions with little or no snowfall, changes in runoff are much more dependent on changes in rainfall than on changes in temperature. Most studies in such regions project an increase in the seasonality of flows, often with higher flows in the peak flow season and either lower flows during the low-flow season or extended dry periods. Many rivers draining glaciated regions, particularly in the Asian high mountain ranges and the South American Andes, are sustained by glacier melt during warm and dry periods. Retreat of these glaciers due to global warming would lead to increased river flows in the short term, but the contribution of glacier melt would gradually fall over the next few decades.

Figure 4: Large-scale relative changes in annual runoff for the period 2090–2099, relative to 1980–1999. Values represent the median of 12 models using the SRES A1B scenario. White areas are where less than 66% of the ensemble of 12 models agree on the sign of change, and hatched areas are where more than 90% of models agree on the sign of change. (Bates et al, 2008, p.30)

Page 36

More detailed regional insights and data are derived from Arnell (2003, 2004, 1999a). The study assess the implications of climate change for regional river runoff across the world, using six climate models used in the IPCC 3rd Assessment Report which have been driven by the SRES emissions scenarios. Streamflow is simulated at a 0.5° resolution using a macro-scale hydrological model, and summed to produce total runoff for almost 1 200 catchments (Arnell, 1998 ; see details in Arnell 2003, 1999). Table 5 shows the derived changes in global average temperature relative to historical average. The pattern of change in runoff is largely determined by simulated change in precipitation, offset by a general increase in evaporation.

Table 5: Increase in global average temperature relative to 1961-1990

Effects of climate change on annual average catchment runoff: Figure 5 shows changes in average annual catchment runoff by the 2050s. By the 2020s approximately a third of all catchments have a substantial increase in runoff, a third has a substantial decrease, and a third show no substantial change. By the 2050s the number with no substantial change reduces to between 20 and 30%, and it falls to between 10 and 30% by the 2080s. There is little difference in the pattern of change between different emissions scenarios, and only by the 2080s there is a clear gradation from A1F1 through A2 and B2 to B1. Figure 6 shows the degree of consistency in the direction of change in average annual runoff using the A2 emissions scenario. Areas where consistent decrease in runoff include much of Europe, North Africa and Middle East, central and southern Africa, North America, most of South America, and parts of Australia. Areas with consistent increases include high latitude North America and Siberia, eastern Africa and south and east Asia.

Page 37

Figure 5: Percentage change in average annual runoff, “2050s” compared with 1961-1990. HadCM3 model, 7 scenarios

Figure 6: Consistency in change in average annual runoff by the 2020s, 2050s and 2080s with A2 emissions scenarios. More than half of GCMs show significant increase or decrease

Change in variability and frequency of “drought” runoff: The inter-annual variability in runoff increases in most catchments due to climate change, even though the inter-annual variability in precipitation is not changed, because of the non-linear linkages between rainfall

Page 38

and runoff. The HadCM3 scenarios result in an increase in coefficient of variation (CV) of catchment annual runoff of around 15 % across much of Europe and western Russia, and around 25 % in the Amazon basin. CV decreases by up to 10 % in a few catchments in western and northern Africa and, under some scenarios, central North America. Changes in average catchment runoff, together with changes in the relative variability of runoff mean that the frequency of occurrence of “drought” river flows is likely to change in the future. The frequency of flow below the current 10-year return period minimum annual runoff increase by a factor of three in Europe, southern Africa and the Amazon basin, and of two across North America.

Figure 7: Change in “drought” runoff: percent change in 10-year return period annual runoff, and percentage of years that watershed annual runoff is below the current 10-year return period annual runoff.

Changes in flow timing: A change in climate may alter the timing of flows through the year, as well the magnitude of flows and the range between high and low flows. Across most of the world climate change does not alter the timing of flows through the year but, in the marginal zone between cool and mild climate, higher temperatures mean that peak streamflow moves from spring to winter as less winter precipitation falls as snow. Figure 8 shows the mean monthly runoff change for several regions for the 2050s. The two cells with maritime climates – Southern England and Italy – show little change in the timing of flows through the year, but an increase in the seasonal variation, particularly in the English cell. There is a substantial change in timing of flow in Belarus and the north east of USA, with large increase in winter runoff and the snow-melt-induced peak moving a month earlier. This is less apparent in the Great Plains, and the month of maximum runoff does not change in the west Russian cell. In these two cases, winter temperatures are so low that increasing temperatures do not result in significantly earlier snowmelt. The other cells show no clear change in the timing of maximum and minimum runoff.

Page 39

Figure 8: Average monthly runoff under current and 2050s climates (HadCM3-A1F1) for individual grid cells

Page 40

The report conducted by Warren et al. (2006) on the regional impacts of climate change - prepared for the Stern Review on the Economics of Climate Change - and particularly the chapter on water resources (Arnell, 2006) gives us more detailed data based on the same methodology and models than previously. Particularly, the figure 9 details graphically percent changes in runoff as a function of global mean temperature change by GCMs for each sub-region. Data were also resumes in the appendix of the report, where matrix of expected impacts of different levels of climate change are describe. In this way, the table 6 gives maximum, medium and minimum modelised changes in runoff for the different sub-regions consecutive of different levels of increase in global mean temperature.

Figure 9: Change in runoff as a function of variation in global mean temperature for each of the GCMs used (Warren et al, 2006)

Page 41

Page 42

Table 6: Maximum, medium and minimum percent change of different levels of climate change on runoff on a regional basis (Warren et al, 2006)

AFRICA 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

North Africa -24 -11 -5 -43 -25 -14 -57 -36 -22 -67 -42 -23 -74 -45 -21

West Africa -6 -2 4 -12 -4 9 -17 -5 13 -22 -7 18 -26 -8 22

South and East Africa -8 -1 5 -15 -4 11 -21 -4 16 -26 -7 20 -30 -8 22

ASIA 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

South Asia -1 4 7 -3 9 13 -6 12 18 -8 15 22 -12 18 27

East Asia -4 1 4 -8 4 7 -12 7 11 -15 10 15 -19 12 17

West Asia -15 -5 2 -26 -10 0 -33 -10 9 -36 -11 9 -36 -8 12

Central Asia 1 3 11 1 9 19 0 11 23 -3 13 22 -7 13 18

Australasia -2 1 3 -5 4 7 -7 6 12 -8 9 17 -10 11 22

AMERICA 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

North America -2 0 2 -5 1 4 -9 0 5 -13 -2 5 -17 -5 4

Caribbean -27 -4 0 -48 -10 1 -64 -15 1 -75 -18 2 -83 -20 3

Central America -23 -4 1 -44 -9 3 -60 -13 11 -71 -17 7 -77 -20 10

South America -15 -2 0 -27 -3 0 -38 -4 1 -47 -5 1 -53 -7 2

EUROPE 0 - 1°C 1 - 2°C 2 - 3°C 3 - 4°C 4 - 5°C

-8 -3 -1 -16 -7 -3 -23 -11 -6 -30 -14 -8 -35 -18 -10

2.3. Potential effects of climate change on anticipated hydropower investment

The increased use of renewable energy is critical to reducing GHG emissions in order to limit climate change. Hydropower is currently the major renewable source contributing to electricity supply, and its future contribution is anticipated to increase significantly. Particularly, in the context of CDM… (see % of hydro projects in CDM, and localization). However, the expansion of hydropower is dependent on the availability of the resource and the perceptions of those financing it. Global warming will alter the timing and magnitude of river flows, and thus affect the ability of hydropower stations to harness the resource, and may reduce production, implying from an investment point of view, lower revenues and poorer returns. Electricity industry liberalization implies that, increasingly, commercial considerations will drive investment decision-making. As such, investors will be concerned

Page 43

with processes, such as climatic change, that have the potential to alter investment performance.

2.3.1. Effects of climate change on attractiveness and viability of hydropower investments

Despite the several studies mentioned above, analyzing climate change and consecutive potential change in hydropower potential and production, very few works have been done to quantify the potential impact of climate change on perceived or anticipated financial performance of hydropower projects, and expected impacts on economic viability and related choice on hydropower investments. The analysis is thus extended here to examine how climate change would be taken into account by analyzing the potential changes in project-based risk, and further in hydro investment risk on a more global basis.A rising demand for electricity, likely increases in fossil-fuel prices and the need for GHG emission-free generation sources all appear to be trends in favor of increasing generation from alternative sources, such hydroelectricity. Indeed, hydroelectric production, currently supplying almost a fifth of global demand, is anticipated to increase threefold over the next century, mostly in developing countries. However, Harrison and Whittington (2003) show that the combination of two factors may constraint this trend: (i) Increased involvement of private capital may not favor hydropower given that hydropower capital costs are relatively high and payback periods longer than for fossil-fuelled plant and than might be preferred by private investors. Further, private investors generally expect a higher financial return than the public sector, traditionally the main source of funds for hydropower development. Despite high fossil-fuel costs, hydroelectricity will often be disadvantaged, and not be favored by short-term orientated investors. (ii) More importantly, however, is that many parts of the world are forecast to experience significant changes in climate. Studies have indicated that variations in river flows resulting from climate change will lead to changes in hydroelectric production. As with all generation methods, electricity sales revenue is the only way of servicing the capital debt. If reductions in runoff and output were to lead to reductions in revenue, this would adversely affect the return on investment and hence the perceived attractiveness of the plant. Energy production changes of the magnitude suggested in the literature will have a major impact on station revenue streams. For state-owned systems employing single energy tariffs, revenue will vary directly with production. For a given power station, if energy output falls, the result will be higher unit electricity costs, a lower return on investment and also longer payback periods.Therefore, the attractiveness of the scheme to potential investors would be lessened, and in the extreme case, potential schemes would not be pursued. If potential hydro schemes are abandoned or production from existing facilities is limited by runoff changes, then alternative power stations will have to be constructed to cover the deficit. These are likely to be fossil-fuelled, given that the technology and fuel are, in general, readily available and, that their construction periods are relatively short. The impact of this is that not only would this require additional capital to be used, but it would also result in additional GHG emissions, thus exacerbating climate change (Whittington and Gundry, 1998).If replacing fossil-fuelled generation electricity by hydropower is one solution to reduce the extent of climate change, simultaneous changes in climate may alter the available hydropower resource, threatening the financial viability of schemes. To illustrate this issue, the sensitivity analysis conducted by Harrison et al. that considers the impact of altered precipitation and temperature on river flows, energy production and financial performance of a planned hydro scheme in Sub-Saharan Africa is presented. Critical climate changes were identified in order

Page 44

to indicate the severity that could be tolerated before the project becomes financially non-viable. The study analyzes the sensitivity of station revenue streams and financial performance to changes in climate in a manner that is akin to standard sensitivity studies as used in capital investment analysis. The case study scheme is the 1600 MW Batoka Gorge project proposed for the Zambezi River. The feasibility study proposed a gravity arch dam with the scheme to operate as run-of-river and produce of 9100 GWh/y. The scheme was modeled using software developed by Harrison and Whittington (2002c), which consists of a series of serially-connected components (hydrological, reservoir, market and financial models) that allow the projection of river flow, energy production and financial performance based on climate scenarios. The Batoka scheme’s climate sensitivity analysis was assessed by altering historic precipitation and temperature levels by similar amounts to those indicated by GCMs. The changes in precipitation ranged from +20% (wet scenario) to –20% (dry scenario) and temperature is raised by up to 4°C.Hydrological and energy production sensitivity: The combined effect of a 20% increase in precipitation together with a 4°C rise in temperature is to increase river flows by just over 35%, while dry conditions scenario deliver a 39% decrease. The annual figures mask differences between changes in high flows and low flows. Under wet conditions there is an almost 40% rise in high flows but only a 16% rise in low flows. Energy production is constrained by the capacity of the turbines as well as the available storage. Turbine capacity restricts the station’s ability to take advantage of increased flows. Wet conditions produce a 10% increase in production, while dry conditions lead to a 25% decrease in production. Changes in performance are related to the seasonal changes in production. Although volumetrically greater changes in output occur during the high flow period, changing climate impacts proportionately more on low flows. Under wet conditions, production is raised by 7% and 18% for high and low flow periods, respectively, while dry conditions see output decrease by 23% and 30% on the same basis. The study also shows significant changes in the minimum production level, an important consideration in determining whether the electricity system is capable of meeting demand. The mean minimum monthly production level is a reasonably proxy for the firm power level of the plant, and under dry conditions this declines is about 27%. Overall, energy production was found to be sensitive to changes in precipitation with seasonal production and production variability related proportionally to the precipitation level. Such changes imply a major impact on the scheme’s financial performance.Revenue and financial sensitivity: In this study a flat rate (US$30/MWh, in real 1993 $US) is paid for all station output. Thus, changes in income directly follow the pattern of production and the changes affect financial performance similarly. The study has forecasted variation of net present value (NPV) with changes in climate parameters. Results show that accumulated changes in annual revenue means that NPV is very sensitive to changes in rainfall: NPV is reduced by over 250 % under dry conditions, while it doubles under wet conditions. Other financial measures reflect the changes in NPV, albeit with smaller percentage changes. Under wet conditions, internal rate of return (IRR) increases from 11 % to almost 12 %, while the discounted payback period (at 10% discount rate) reduces by just over 19 %. With dry conditions, IRR falls to 8 % and discounted payback extends to over thirty years, beyond the assumed project lifetime. Production costs, which are 1.52 $/kWh under current conditions, are lowered to 1.39 $/kWh, or raised to 2.01 $/kWh, under wet and dry conditions, respectively. The methodology used in this study is useful in identifying the severity of climate change required to render the project economically non-viable. Investment appraisal rules state that a project should only be accepted if it returns a positive NPV at the discount rate used. Here, a 10% real discount rate is used and the non-viability of the project can be identified where NPV is negative or falls by at least 100%. Investment profitability is positively correlated to precipitation and negatively to temperature. With no temperature rise,

Page 45

the project would remain viable with uniform decreases in precipitation of 11%. However, as temperature rises the tolerable reduction falls such that, the for a temperature rise of 4°C, a decrease in precipitation of just over 6% is required to remove profitability. Some GCMs project regional reductions in precipitation and temperature rise in excess of the critical combinations identified here, lead to the project becoming economically non-viable.A comparison of the climate change project sensitivity relative to other project parameters has been conducted. The following key parameters were selected: civil engineering costs, representing the main capital cost, with inaccurate estimation having a significant impact on project returns; build period, which impacts the amount of loan interest capitalized; and electricity sales prices. The effect of discount rate is also considered as it is critical to project worth. Each parameter was altered by ±20% of its original value. The NPV results from these simulations are shown in Fig. 2.11 and show that the sensitivity to climate change is of a similar magnitude to both the discount rate and sales price. This adds credibility to the view that investors should be concerned about the effects of this risk factor.

Figure 10: Variation of project NPV with climate and project parameter changes

2.3.2. Climate change and adaptation of management/design of hydropower investments

The previous section have assessed the potential impacts of climate change on hydropower investments and financial variables of projects, considering that the design of the hydropower structure has not integrate the expected or risk of change of climate parameters during the lifetime of the investment.Beyond, climate change effects would be taken in account in an anticipatory manner, directly in the design and conception of the project. The adaptation to climate change literature shows that long term infrastructure investments appear as one of the most urgent field for adaptation. Indeed, if adaptation is delayed, as climate change will become more visible and increase the difference between observed and design conditions, the investment performance will decrease. The difficulties is thus to design hydropower infrastructure in function of present climatic condition and with tacking into account that they would probably change, but at a rate or magnitude of change, and sometime with a direction of change that remain uncertain. This would be achieved principally by reducing the economic lifetime of the hydropower project or by increasing the flexibility of the infrastructure, i.e. by increasing the range of climatic conditions in the design of the project. In all case, adaptation come at cost, and climate change made hydropower as a more risky option for electricity production compare to

Page 46

other possibilities. Then, the impact on generation mix and choice would be captured toward a hypothesis of an option-value on hydropower projects.

References

Alstom Power Hydro, 2009, Personal Communication, [10/03/2009]

Arnell N.W, 2004, Climate change and global water resources: SRES emissions and socio-economic scenarios, Global Environmental Change, 14, p. 31-52

Arnell N.W, 2003, Effects of IPCC SRES emissions scenarios on river runoff: a global perspective, Hydrology and Earth System Sciences, 7(5), p. 619-641

Arnell N.W, 1999a, Climate change and global water resources, Global environmental change, 9(S1), p.31-49

Arnell N.W, 1999b, The effects of climate change on hydrological regimes in Europe: a continental perspective, Global Environmental Change, 9(S1), pp.5-23

Arnell N.W., Hudson D.A. , Jones R.G., 2003, Climate change scenarios from a regional climate model: Estimating change in runoff in southern Africa. Journal of Geophysical Research: Atmospheres, 108, 4519-[17pp].

Barnett,T., Malone R., Pennell W., Stammer D., Semtner B., Washington W., 2004, The effects of climate change on water resources in the west: introduction and overview, Climate Change, 62, pp. 1-11

Bates B.C., Kundzewicz Z.W., Wu S., Palutikof J.P. (Eds.), 2008, Climate Change and Water, Technical Paper of the Intergovernmental Panel on Climate Change, IPCC Secretariat, Geneva, 210 pp.

Chao P.T., 1999, Great Lakes water resources – Climate change impact analysis with transient GCM scenarios, Journal of the American Water Resources Association, 35, pp. 1499-1508.

Dettinger M.D., 2005, Changes in streamflow timing in the western recent decades, USGS Fact Sheet 2005-3018, March 2005.

DOE/NETL, 2007, Potential impacts of climate change on energy sector

Eurelectric, 1997, Study on the importance of harnessing the hydropower resources of the world, Hydro Power and other Renewable Energies Study Committee, EURELECTRIC, Brussels, 20 p.

Georgakakos and Yao, 2000, Climate change impacts on Southeastern U.S. Basins, Water Resources Research, Report 00-334, U.S. Geological Survey, 72 p.

Gleick P.H., 1994, Water and energy, Annual Review of Energy and the Environment, 19, pp. 267-299

Gleick P.H., 1986, Methods for evaluating the regional hydrologic impacts of global climatic changes , Journal of Hydrology, 88, pp. 97-116

Gleick P.H. Nash L., 1991, The Societal and Environmental Costs of the Continuing California Drought, Pacific Institute for Studies in Development, Environment, and Security, Oakland, California.

Hanemann, McCann, 1993

Harrison G.P., Whittington H.W., 2001, Impact of climate change on hydropower investment, Hydropower and the new millennium – Proceedings of the 4th international Conference, Hydropower ’01, Bergen, Norway, June 2001, pp. 257-261.

Harrison G.P., Whittington H.W., 2002a, Susceptibility of the Batoka Gorge hydroelectric scheme to climate change, Journal of Hydrology, 264(1-4), pp. 230-241

Harrison G.P., Whittington H.W., 2002b, Analysing climate change risk in hydropower development, 10 p.

Harrison G.P., Whittington H.W., 2002c, Vulnerability of hydropower projects to climate change, IEE Proc. Generation, Transmission & Distribution, 149(3), pp. 249-255

Harrison G.P., Whittington H.W., 2003, Climate change – a drying up of hydropower investment?, 8 p.

Harrison G.P., Whittington H.W., Gundry, S.W., 1998, Climate change impacts on hydroelectric power, Proc. 33rd Universities Power Engineering Conference (UPEC ‘98), Edinburgh, 8-10 September 1998, pp.391-394.

Harrison G.P., Whittington H.W., Wallace A.R., , Climate change impacts on financial risk in hydropower projects

Harrison G.P., Whittington H.W., Wallace A.R., , Sensitivity of hydropower performance to climate change

Lehner B., Czisch G., Vassolo S., 2005, The impact of global change on the hydropower potential of Europe: a model-based analysis, Energy Policy, 33, pp.839-855

Lettenmaier D.P., Wood A.W., Palmer R.N., Wood E.F., Stakhiv E.Z., 1999, Water Resources Implications Of Global Warming: A U.S. Regional Perspective, Climate Change, 43(3), pp. 537-579

Page 47

Miller B.A., Brock W.G., 1988, Sensitivity of the Tennessee Valley Authority Reservoir System to Global Climate Change, Report No. WR28-1-680-101, Tennessee Valley Authority Engineering Laboratory, Norris, Tennessee.

Milly P.C.D, Dunne K.A., Vecchia A.V., 2005, Global pattern of trends in streamflow and water availability in a changing climate, Nature, 438(7066)), p.347-350

Mimikou M.A., Baltas E.A., Varanaou E., Pantazis K., 2000, Regional impacts of climate change on water resources quantity and quality indicators, Journal of Hydrology, 234, p.95-109

Mimikou M.A., Baltas E.A., 1997, Climate change impacts on the reliability of hydroelectric energy production, Hydrological Sciences, 42(5), pp.661-678

Mimikou, M., Kouvopoulos, Y., Cavadias, G. and Vayianos, N., 1991, Regional hydrological effects of climate change, Journal of Hydrology, 123, pp. 119-146.

Nakicenovic et al., 1998

Nash L.L., Gleick P.H., 1993, The Colorado River Basin and Climatic Change: The Sensitivity of Streamflow and Water Supply to Variations in Temperature and Precipitation, US Environmental Protection Agency, Washington D.C.

Reibsame W.E., Strzepek K.M., Wescoat Jr. J.L., Perritt, R., Gaile G.L., Jacobs J., Leichenko R., Magadza C., Phien H., Urbiztondo B.J., Restrepo P., Rose W.R., Saleh M., Ti L.H., Tucci C., Yates D., 1995, Complex River Basins, In: Strzepek K.M. and Smith J.B. (eds), As Climate Changes - International Impacts and Implications, Cambridge University Press, pp. 57-91.

Sweeney J.L., 2002, The California Electricity Crisis. Pub. No. 503, Hoover Institution Press, Stanford, California.

USCCSP, 2006, Effects of climate change on energy production and use in the USA

Vicuna S., Leonardson R., Hanemann W., Dales L.L., Dracup J.A., 2008, Climate change impacts on high elevation hydropower generation in California’s Sierre Nevada: A case study in the upper American river, Climatic Change, 87, pp. S123-S137

Vicuña, S., R. Leonardson, J. A. Dracup, M. Hanemann, and L. Dale, 2006, Climate Change Impacts on High Elevation Hydropower Generation in California's Sierra Nevada: A Case Study in the Upper American River, Final white paper from California Climate Change Center, CEC-500-2005-199-SD,

Warren R., Arnell N., Nicholls R., Levy R., Price J., 2006, Understanding the regional impacts of climate change. Research Report Prepared for the Stern Review on the Economics of Climate Change, Working Paper 90, Tyndall Center for climate change research, 223 p.

Whittington H.W., Gundry S.W., 1998, Global climate change and hydroelectric resources, IEE Engineering Science and Education Journal, 7(1), pp. 29-34

Whittington H.W., Gundry S.W., , Global climate change and hydroelectric power

Wood A.W., Lettenmaier D.P., Palmer R.N., 1997, Assessing climate change implications for water resources planning, Climatic Change, 37, pp. 203-228.

World Bank, 2008, Estimating global climate change impacts on hydropower projects: Applications in India, Sri Lanka and Vietnam, Policy Research Working Paper 4344, 40 p.

Page 48

3. Assessment of changes in water regimes on the costs of cooling in thermal power production, either by fossil or nuclear fuels.

The issue of climate change impacts on thermoelectricity generation (from nuclear and fossil sources) has never been systematically or specifically assessed. Indeed this issue arises from the fact that thermoelectric production and efficiency are vulnerable to climate conditions particularly when effects of expected changes in temperatures and hydrology are linked to cooling systems capacity. This chapter relates thus to an emerging question in the context of climate change impacts assessment, where data and research efforts remain very scarce. Climate change could impacts the output and thermal efficiency of thermoelectric generation mostly via expected effects on cooling systems of these power plants. In this context we distinguish 3 types of effects of climate change that characterizing thoroughly the different issues. Thus, this chapter firstly yields a background on water use for thermoelectric generation. The three following parts focalize on the analysis of potential impacts of climate change on plants output and efficiency, namely the direct effects of ambient and cooling water temperature changes, the issues of water withdrawal and consumption for thermoelectric generation in the context of increased water stress and competing uses, and the impacts of climate change on output in the context of thermal discharge regulation. Finally, we analyze the economic, environmental and performance trade-offs, that arise from choices between the alternative cooling configurations in the context of climate change.

3.1. Background: Water use for thermoelectric generation

3.1.1. Supplying energy requires water

Water is used throughout the energy sector, including resource extraction, refining and processing, electric power generation, storage and transport. The energy sector also can impact water quality via waste streams, runoff from mining operations, produced water from oil and gas extraction, and air emissions that may affect downwind watersheds. Examples of interactions of thermal power plants with water quantities and quality, both large and small, are shown in Table 7.In this chapter we focus on water use for cooling in thermoelectric generation. Cooling systems are essential in the functioning of thermal power plant. In this section we detail first the different cooling technologies, implying different water use configurations, and we describe then in quantitative terms the water use of these plants both regarding power plant type and cooling systems, and sectoral uses

Table 7: Connections between the energy/thermoelectricity sector and water availability and quality

Energy Element Connection to Water Quantity Connection to Water Quality

Energy Extraction and Production

Page 49

Oil and Gas Exploration Water for drilling, completion, and fracturing Impact on shallow groundwater quality

Oil and Gas Production Large volume of produced, impaired water Produced water can impact surface and groundwater

Coal and Uranium Mining Mining operations can generate large quantities of water

Tailings and drainage can impact surface water and groundwater

Refining and Processing

Traditional Oil and Gas Refining Water needed to refine oil and gas End use can impact water quality

Electric Power Generation

Thermoelectric (fossil, biomass, nuclear)

Surface water and groundwater for cooling and scrubbing

Thermal and air emissions impact surface waters and ecology

Energy Transportation and Storage

Energy Pipelines Water for hydrostatic testing Wastewater requires treatment

Coal Slurry Pipelines Water for slurry transport, water not returned Final water is poor quality, requires treatment

Barge Transport of Energy River flows and stages impact fuel delivery Spills or accident can impact water quality

Oil and Gas Storage Caverns Slurry mining of caverns requires large quantities of water Slurry disposal impacts water quality and ecology

Source: SNL (2006)

3.1.2. Cooling technologies

In all steam-electric power plants, steam turbine exhaust must be condensed in order to maintain the required sub-atmospheric turbine exit pressure and to return the condensate to the boiler or the heat recovery steam generator. Cooling system alternatives include once-through cooling, recirculating wet systems (which include wet cooling towers and cooling ponds), dry cooling systems, and hybrid (wet/dry) systems. We present here briefly these different alternatives. In Once-through cooling systems, cooling water is withdrawn from a local natural water body source (i.e., ocean, lake, or river), passed through the tubes of a surface steam condenser and returned to the water body at a higher temperature. This was formerly the common form of cooling at power plants. Steam is condensed in a shell-and-tube surface condenser. Withdrawal rates are usually 400 to 600 gallons per minute (gpm) per megawatt (MW) of steam-electric generating capacity and the retuned water is typically 15°F to 20°F (8°C to 12°C) warmer than the source water from which it was withdrawn. Recirculating wet cooling systems are similar to once-through systems in that the steam is condensed in water-cooled shell-and-tube surface condensers, but different in that the heated cooling water is not returned to the environment. Instead, it is pumped to a cooling component, typically a mechanical draft wet cooling tower and then recirculated to the condenser. In the cooling tower a small fraction of recirculating water (typically 1 to 2%) is evaporated in order to cool the remainder. Once the system is filled, the only water withdrawn from the environment is make-up water sufficient to replace that lost to evaporation, blowdown, and drift. This amount is typically 10 to 15 gpm/MW of steam generating capacity.

Page 50

Dry cooling system may be categorized as direct or indirect. In direct systems, turbine exhaust steam is ducted directly to an air-cooled condenser. Heat rejection to the environment takes place in a single step in which steam is condensed in finned tube bundles, which are cooled by air blown across the exterior finned surfaces. Indirect systems have a separate condenser. The condenser may be either a surface condenser of the conventional shell-and-tube type or a so-called barometric condenser, in which the steam is condensed directly on a spray of cooling water. In either case, the water against which the steam is condensed is then circulated to an air-cooled heat exchanger for ultimate heat rejection to the atmosphere.Hybrid wet/dry systems employ a combination of both wet and dry cooling technologies. The two primary types of hybrid systems are water conservation and plume abatement designs. Hybrid systems intended for water conservation, on the one hand, are primarily dry systems with a small wet capacity to provide additional cooling during the hottest periods of the year to mitigate hot-day capacity losses associated with all-dry systems. Plume abatement towers, on the other hand, are essentially all-wet systems that employ a small amount of dry cooling to dry out the tower exhaust plume during those cold, high-humidity periods when the plumes is likely to be visible. Numerous design arrangements exist for hybrid systems.

3.1.3. Water use for thermoelectric generation

Thermoelectric water needs according to plant and cooling system configurations

Description of water use of thermoelectric generation might be conducted both with considering power plant types and cooling system configuration, and on a sectoral basis. Analyzes of cooling configurations shows that recirculating wet systems have lower water use requirements, but consumptive losses through direct evaporation can be relatively high on a percentage basis. In 2001, approximately 31% of thermoelectric generating units were equipped with wet cooling towers, representing approximately 38% of installed generating capacity in U.S. (DOE-NETL, 2005). Also, nuclear power plants show greater water needs than fossil-based power plants. Representative ranges, or typical values for each cooling system and power plant type, from various studies are reported in the following tables.

Table 8: Summary of cooling water needs (DOE-NETL, 2004)

Fuel Source Technology Withdrawal (gal/kWh) Consumption (gal/kWh)

FossilOnce-Through 37.7 0.1

Recirculating (Wet Tower) 1.2 1.1

NuclearOnce-Through 46.2 0.1

Recirculating (Wet Tower) 1.5 1.5

Page 51

Table 9: Cooling water withdrawal and consumption rates for common thermal power plant and cooling system types (EPRI, 2002)

Plant and cooling system type Water Withdrawal (gal/MWh) Typical Water Consumption (gal/MWh)

Fossil/biomass/waste-fueled steam, once through cooling

20 000 to 50 000 ~ 300

Fossil/biomass/waste-fueled steam, pond cooling

300 to 600 300 – 480

Fossil/biomass/waste-fueled steam, cooling towers

500 to 600 ~ 480

Nuclear steam, once through cooling 25 000 to 60 000 ~ 400

Nuclear steam, pond cooling 500 to 1 100 400 – 720

Nuclear steam, cooling towers 800 to 1 100 ~ 720

Natural gas/oil combined cycle, once through cooling

7 500 to 20 000 ~ 100

Natural gas/oil combined cycle, cooling towers

~230 ~ 180

Natural gas/oil combined cycle, dry cooling ~ 0 ~ 0

Coal/petroleum residuum-fueled combined cycle, cooling towers

~ 380* ~ 200

* includes gasification process water

Table 10: Cooling water withdrawal and consumption rates for common thermal power plant and cooling system types (DOE-NETL, 2008)

(a) National average withdrawal and consumption factors for model coal plantsModel Plant Withdrawal Factor

(gal/kWh)Consumption factor (gal/kWh)

Freshwater, Once-through, Subcritical, Wet FDG 27,113 0,138

Freshwater, Once-through, Subcritical, Dry FDG 27,088 0,113

Freshwater, Once-through, Subcritical, No FDG 27,046 0,071

Freshwater, Once-through, Supercritical, Wet FDG 22,611 0,124

Freshwater, Once-through, Supercritical, Dry FDG 22,590 0,103

Freshwater, Once-through, Supercritical, No FDG 22,551 0,064

Freshwater, recirculating, Subcritical, Wet FDG 0,531 0,462

Freshwater, recirculating, Subcritical, Dry FDG 0,506 0,437

Freshwater, recirculating, Subcritical, No FDG 0,463 0,394

Freshwater, recirculating, Supercritical, Wet FDG 0,669 0,518

Freshwater, recirculating, Supercritical, Dry FDG 0,648 0,496

Page 52

Freshwater, recirculating, Supercritical, No FDG 0,609 0,458

Freshwater, cooling pond, Subcritical, Wet FDG 17,927 0,804

Freshwater, cooling pond, Subcritical, Dry FDG 17,902 0,779

Freshwater, cooling pond, Subcritical, No FDG 17,859 0,737

Freshwater, cooling pond, Supercritical, Wet FDG 15,057 0,064

Freshwater, cooling pond, Supercritical, Dry FDG 15,035 0,042

Freshwater, cooling pond, Supercritical, No FDG 14,996 0,004

(b) National average withdrawal and consumption factors for model nuclear plantsModel Plant Withdrawal Factor (gal/kWh) Consumption factor (gal/kWh)

Freshwater, Once through 31,497 0,137

Freshwater, Recirculating 1,101 0,624

(c) National average withdrawal and consumption factors for model fossil non-coal plantsModel Plant Withdrawal Factor (gal/kWh) Consumption factor (gal/kWh)

Freshwater, Once through 22,74 0,09

Freshwater, Recirculating 0,25 0,16

Freshwater, Cooling pond 7,89 0,11

(d) National average withdrawal and consumption factors for model IGCC/NGCC plantsModel plant Withdrawal Factor (gal/kWh) Consumption factor (gal/kWh)

NGCC, Freshwater, Once through 9,01 0,02

NGCC, Freshwater, Recirculating 0,15 0,13

NGCC, Freshwater, Cooling pond 5,95 0,24

NGCC, Air Cooled 0,004 0,004

IGCC, Freshwater, Recirculating 0,226 0,173

Finally, we report data from Goosens and Bonnet (2001) for three nuclear reactor types and classical and expected fossil-fueled plants.

Table 11: Water consumption and withdrawal for three types of nuclear reactor (Gossens and Bonnet, 2001)

Expected industrial maturity

Thermal efficiency (%)

Once-through cooling Recirculating wet cooling

Consumption (l/kWh)

Withdrawal (l/kWh)

Consumption (l/kWh)

Withdrawal (l/kWh)

Page 53

REP En service 31 1.55 165 2.1 3

EPR 2000 36 1.33 142 1.8 2.6

RHR1 2015 47 1 108 1.38 2

REP : Réacteur à eau pressurisée, EPR : European Pressurized Reactor, RHR1 : Réacteur à haut rendement de première génération

Table 12: Water consumption and withdrawal for classical and expected thermal power plants (Gossens and Bonnet, 2001)

Thermal efficiency (%)

Once-through cooling Recirculating wet cooling

Consommation (l/kWh)

Withdrawal (l/kWh)

Consumption (l/kWh)

Withdrawal (l/kWh)

Conventional coal-fired plant 35 1.2 145 2.6 10 to 20

Centrale à charbon en lit fluidisé 35 0.8 145 2 10 to 20

Oil and gas plant (2000) 36 1.1 145 2.6 10 to 20

Oil and gas plant (2020) 40 0.9 125 2.2 8 to 17

Gas-fired combined cycle (2000) 55 0.5 67 1.2 5 to 10

Cycle combiné gaz (2020) 60 0.4 55 1 4 to 8

Power plants water needs comparing to sectoral withdrawal and consumption

According to USGS water use survey data, 346 billion gallons of freshwater per day (BGD) were used in the U.S. in 2000. Figure 11 presents the percentage of total U.S. freshwater withdrawal by sectors. Thermoelectric generation accounted for 39% (136 BGD) of all freshwater withdrawals in the nation in 2000, second only to irrigation. When discussing water and thermoelectric generation, it is important to distinguish between water use and water consumption. Water use represents the total water withdrawal from a source and water consumption represents the amount of that withdrawal that is not returned to the source. Although thermoelectric generation is the second largest user of water on a withdrawal basis, it was only responsible for about 3% of the total of 100 BGD freshwater consumed in 1995 compared to 81% for irrigation as shown in Figure 12 (DOE-NETL, 2005)

Figure 11: Estimated U.S freshwater withdrawal by sector, 2000, (Hutson et al, 2000)

Page 54

Figure 12: Estimated U.S freshwater consumption by sector, 1995, (Solley et al, 1998)

Vicaud (2008) show that for France, the share of electricity in national water withdrawal is particularly high, representing 57% of sectoral needs and more than 70% of sectoral withdrawal from surface water. This fact can be largely explains by the particularly low use of water by irrigation in France.

Table 13: Estimated France freshwater withdrawal by sectors, 2002, (Vicaud, 2008)

Withdrawal (Mm3) Drinking water Industry Irrigation Electricity

Surface Water 2200 (8%) 2117 (8%) 3284 (13%) 18508 (71%)

Ground Water 3746 (59%) 1458 (23%) 1107 (17%) 23 (0%)

Total 5966 (18%) 3575 (11%) 4391 (14%)

18531 (57%)

3.2. Direct effects of ambient and cooling water temperature changes on output and thermal efficiency of power plants

Direct effects of climate change on net power output and thermal efficiency have not been studied yet. However, climate parameters (and more generally environmental/ambient conditions) are an important factor of power plant capacity and thermal efficiency, and an essential parameter in the design of the installations. Particularly, observed statistical ambient and cooling water temperatures distribution (summer average, deviation/range, and 1% hours of maximum temperatures) constitutes a central aspect of design and performance of thermal power plant. Thus, deviations compared to standards imply variations in the output and firing rate of the power plant considered. In this context, literature on effects of short-term or seasonal ambient and water cooling temperature variations appears as an interesting starting point to analyze climate change impacts on power plants output and efficiency.

Page 55

3.2.1. Impacts of changes in ambient temperatures

Direct impact of increasing ambient temperature on output and efficiency of plant

Ganan et al (2005) show that the performance of nuclear power plant is strongly affected by weather conditions having experienced a power limitation due to vacuum losses in condenser during summer. USCCP (2007) argues that gas turbines in natural gas simple cycle, combined cycle, and coal based integrated gasification combined cycle applications are affected by local ambient conditions, largely ambient temperature that have an immediate impact on gas turbine performance measured in terms of heat rate and power output. In the same way, Chuang and Sue (2005) conclude that the power capability is significantly affected by the ambient temperature and condenser pressure in combined cycle power plant.Davcock et al (2004) analyze gas power plants and found that a 60°F increase in ambient temperature, as might be experienced daily in a desert environment, would have a 1-2 % point reduction in efficiency and a 20-25% reduction in power output of the plant. They show that this effect is nearly linear; so a 10°F increase in ambient temperature would produce as much as a 0.5 % point reduction in efficiency and a 3-4% reduction in power output in an existing gas turbine. Therefore, the impact of potential climate change on the fleet of existing turbines would be driven by the impact that small changes in overall performance would have on both the total capacity available at any time and the actual cost of electricity. Local ambient temperature conditions will normally vary by 10–20°F on a 24 hour cycle, and many temperate-zone areas have winter-summer swings in average ambient temperature of 25-35°F. Consequently, any long-term climate change that would impact ambient temperature is believed to be on a scale within the design envelope of currently deployed turbines. As noted earlier, both turbine power output and efficiency vary with ambient temperature deviation from the design point. The primary impacts of longer periods of off-design operation will be modestly but notably reduced capacity and reduced efficiency. Currently turbine-based power plants are deployed around the world in a wide variety of ambient conditions and applications, indicating that new installations can be designed to address long-term changes in operating conditions. In response to the range of operating temperatures and pressures to which gas turbines are being subjected, turbine designers have developed a host of tools for dealing with daily and local ambient conditions, including inlet guide vanes, inlet air fogging (essentially cooling and mass flow addition), inlet air filters and compressor blade washing techniques. Such tools could also be deployed to address changes in ambient conditions brought about by long term climate change.The analysis of Maulbetsh and Di Fillipo (2004) for California is particularly interesting in three ways. This study permits first to compare the plants capacities and efficiencies at design conditions for the four climatic stations1 and gives basis for “geographical analogues”. The plant output and heat rate in fact varies significantly from site to site. This is largely due to the effect of ambient temperature and site elevation on and gas turbine performance. If we put away mountain site because of influence of elevation, capital cost per capacity and heat rate are highly correlated with ambient summer temperature average taken for design condition. The coastal site, with lowest design temperatures has the highest design capacity, lowest

1 Four sites, representing different meteorology, were selected: desert (very hot, arid), central valley (hot, moderately humid), coastal

(cool, humid), and mountain (variable, elevated). Summer average temperatures using for meteorological design conditions are 96°F (30°C)

for desert site, 86°F (30°C) for valley site, 65°F (18°C) for coastal site, and 78°F (26°C) for mountain site. The 1 % dry-bulb maximum

temperatures using at design condition are 109°F (43°C) in desert station, 102°F (32°C) in central valley station, 79°F (26°C) in coastal

station and 103°F (39°C) in mountain station

Page 56

design heat rate, and the lowest normalized cost ($/kW). The desert and valley sites shows a decrease of nearly 5% in design net capacity comparing coastal site, and an increase of capital cost per capacity of 4.01 and 4.75% respectively. Heat rates are higher of 0.23% in central valley site, and of 5.9% in desert site compared to coastal site.

Table 14: Performance, cost and heat rate at design points of different climatic stations

Combined Cycle – Wet Cooling Combined Cycle – Dry Cooling

Design net capacity (MW)

Capital cost per

capacity ($/kW)Heat rate

(Btu/kWh)Design net

capacity (MW)Capital cost per

capacity ($/kW)Heat rate

(Btu/kWh)

Desert 457.8 427.3 6.896 445.5 479.5 6.795

Valley 457.8 430.3 6.588 458.0 488.4 6.686

Coast 481.8 410.8 6.573 486.3 456.5 6.596

Mountain 412.4 489.8 6.597 416.1 505.2 6.722

Secondly, in analyzing the effects of « hot days » on combined cycle power plant output for each of climatic stations studied and for two cooling systems alternative (wet recirculating and dry cooling), it gives a basis for addressing the effects of climate change and increased risk of heatwaves and “temporal analogue”. The “hot days” period is normally represented by the 1 % of warmest hours during summer, which also coincide with the times of national peak electricity demand and highest power price levels. Table 15 shows the difference between the design point performance and the performance at elevated temperature conditions for both the wet- and dry-cooled combined-cycle plants. For the combined-cycle plant with wet cooling, the fall-off in performance is modest, ranging from approximately 1% to 3.5%, depending on the site. For the combined-cycle plant equipped with dry cooling, the effect can be much greater, ranging from over 3% to over 9%. It should be noted that, for combined-cycle plants, the reduction in plant output between design point conditions and “hot day” conditions is attributable in part to the fall-off in gas turbine performance as well as to any limitations imposed by the cooling system capability. The design point specifications show that, in all but the desert case, the ambient dry bulb at design for the dry-cooled plant is lower than that at the design point for the wet-cooled case. Therefore, the difference in ambient temperature (and hence the reduction in gas turbine output) between the hot day and the design conditions is greater for the dry-cooled case than for the wet-cooled plant. This is reflected in the greater fall-off in plant output and might appear to bias the comparison unfairly in favor of wet-cooled plants. But the only appropriate comparison between plants with different cooling systems is between plants that have been optimized in their design choices.

Table 15: Hot day performance comparisons of power plants at different climatic stations

Combined Cycle – Wet Cooling Combined Cycle – Dry Cooling

Design Capacity (MW)

Hot Day Capacity (MW)

Percent Loss (%)

Design Capacity (MW)

Hot Day Capacity (MW) Percent Loss (%)

Desert 457.8 449.6 1.79 445.5 431.0 3.25

Page 57

Valley 457.8 453.6 0.92 458 440.9 3.73

Coast 481.8 465.2 3.45 486.3 441.8 9.15

Mountain 412.4 404.0 2.04 416.1 381.1 8.41

Third, the Maulbetsh and Di Fillipo’s study describes the functional relationship between ambient temperature and output of the plant in each site and cooling systems cases. Figure 13 and 14 illustrate the fall-off in plant output with increasing ambient dry-bulb temperature for plants types with wet cooling and dry cooling at all four sites. For a given climatic station, the relation between increase temperature and output is useful for temporal analogue and the relation appears linear. In each station, for wet cooling a 10°F increase results in a 6 000-7 000 kW decrease in output. For dry cooling, for each 10°F increase, a fall-out in output ranging 7 000 to 10 000 kW is observed depending on climatic station. Note that differences in output of the four climatic stations for each temperature levels can generate important information for geographical analogues in the climate change impacts analysis context.

Figure 13: Output vs. ambient temperature for wet cooled plants

Page 58

Figure 14: Output vs. ambient temperature for dry cooled plants

Indirect impacts of expected T° change on costs, output and efficiency following adaptive design of new power plant

The previous section shows the impacts of changes in ambient temperature on output and efficiency of existing power plant. But it should be noted that increase and uncertainty in future temperature might affect investment design and costs of projected future power plant because of changes in temperatures design point condition of plants and/or cooling system optimization choices. Thus, taking into account climate change risks into power plants design would impact output, efficiency and investment costs.Considering the long lifetime of power plant installations, designers of new power plants might integrate expected changes in temperatures due to climate change in order to offset impacts of temperature deviation on output and efficiency. This will result in higher ISO temperature conditions in the design point of power plant. In the instance of the dry-cooled plant, for example, the plant could have been designed at a higher design ambient temperature and equipped with a larger ACC. The result would be improved capacity during the hot day, reduced fall-off between design and hot day performance, but higher capital and operating costs.Moreover, the increased risks of heatwave has to be analyzed in a larger context, particularly with expected impacts and decrease of reliability of other electricity sources, like hydropower, and maximum needs and electricity cost in these periods. These risks would possibly change cooling systems optimization criteria. Instead of using an optimization criterion of minimum total annualized cost, one might wants choose optimization criterion of maximum performance in hot days. Thus if a very high value were assigned to meeting peak power demands on the hotter days and perform with climate change risks, a larger and more expensive cooling system would have been selected. While the total annualized cost would have been higher, the “hot day capacity reduction” and “climate change heatwave risk” would have been reduced or eliminated.

3.2.2. Impacts of changes in water cooling temperatures

The temperature of cooling water entering the condenser affects the performance of the turbine: the cooler the temperature, the better the performance, because the cooling water temperature affects the level of vacuum at the discharge of the steam turbine. As cooling

Page 59

water temperatures decrease, a higher vacuum can be produced and additional energy can be extracted. On an annual average, once-through cooling water has a lower temperature than recirculated water from a cooling tower (DOE-NETL, 2002). Note that change in water cooling temperature is highly correlated with changes in ambient temperature, but studied here separately.Durmayaz and Sogut (2006) analyze the influence of cooling water temperature on the efficiency of a pressurized-water reactor nuclear power plant. An iterative condenser heat balance model is developed to determine the functional relationship between the cooling water temperature and the condenser pressure, considering the fact that saturation condition exists in condenser and there is a finite amount of temperature difference between this saturation temperature and the cooling water exit temperature. In this study, a cooling water inlet temperature in the range of 10–30°C is selected. The hot side temperature difference is also taken as a parameter with the values of ∆Thot = 2; 4 and 6°C. The reference values for the design conditions in this study are presumed at 20°C for the cooling water inlet temperature and 4°C difference at the hot side of condenser. The paper shows that the change in cooling water inlet yields a marked decrease of 8.9% in net power output of the plant for the T cw;i

range of 10–30°C. For the variation of thermal efficiency with cooling water inlet temperature, it is observed that an increase from 20 to 30°C in temperature of the coolant extracted from environment yields a decrease from 35.96 to 34.78% in thermal efficiency of the pressurized-water reactor nuclear power plant considered. The main findings of this study is that the impact of 1°C increase of the coolant extracted from environment is predicted to yield a decrease of approximately 0.45% in the power output and 0.12% in the thermal efficiency of the pressurized reactor nuclear power plant. These results are consistent with the experimental findings of Chuang and Sue (2005).

Figure 15: Variation of net power output Wnet and thermal efficiency ηth with cooling water inlet temperature Tcw;I for ∆Thot = 2, 4 and 6°C (Durmayaz and Sogut, 2006).

Van Aart et al (2004) on the basis of KEMA (2004) highlight the functional relationship between changes in cooling water temperature and thermal efficiency of coal power plant (Supercritical boiler), gas power plant (Gas turbine topping), and combined cycle power plant, designed with an once-through cooling system. Their study shows the relative sensitivity of these different types of thermal power plant to temperature of the coolant extracted from environment. The combined cycle power plant proves to be the most sensitive to increase temperature of cooling water, and the relationship between efficiency and temperature

Page 60

appears to be almost linear. Conversely, super critical boiler efficiency seems to be the more robust to changes in water cooling temperature. In average, every 1°C increase in cooling water yields a decrease of efficiency of thermal power plant of 0.17% for coal power plants, 0.24% for gas plants and 0.27% for combined cycle power plants with once-through cooling system.

Figure 16: Efficiency loss due to higher cooling water temperatures (van Aart, 2004 ; KEMA, 2004)

-2.5%

-2.0%

-1.5%

-1.0%

-0.5%

0.0%

0 2.5 5 7.5 10

Temperature rise cooling water [K]

Effic

ienc

y lo

ss [%

]

Super critical boiler

Gas turbine topping

Combined cycle

3.3. Trends in water stress, competing uses in the context of climate change

Climate change impacts on electricity generation at fossil and nuclear power plants are likely to be similar. Beyond direct effect of ambient and cooling water temperature on output and efficiency of plants, another effect of climate change would arise from potential changes in water availability for cooling systems. Thermal power plants are vulnerable to climate change because of their high dependence to water resources for their cooling systems. Electricity generation requires a reliable, abundant, and predictable source of water. Changes in water following expected effects of climate change on local hydrology, and/or increased competition over the resource with commercial, residential or agricultural sectors, would reduce the water availability for thermoelectricity. In this context, in regions where trend in water stress and competition is increasing and may further be aggravated by climate change, freshwater availability appears as a critical limiting factor that would directly impacts power supply, development and sustainability of thermoelectric generation. The issue of increased water scarcity and competing use that may affect the availability for power plant appears to be an increased trend throughout many regions of the world. In this way, climate change would exacerbate this issue both in the long term with effects on average temperature and precipitation and related run-off and needs, and in the short term with anticipated increased risk of extreme events like drought. It is important to note that this issue would be distinguished according to cooling systems even if they are not completely independent. Once-through cooling technologies require large amount of water withdrawal that have to be available even if water is discharged upstream.

Page 61

Power plants water needs in this case essentially compete with environmental needs (in relation with thermal discharges, see section 4.), and upstream consumption uses by other sectors. Recirculating wet cooling systems, on the other hand, require far lower water, but in this case, withdrawals are consumptions that directly compete with other sectors. These different cooling configurations have to be taken in account when analyzing effects of climate change and trends in water scarcity on thermal power plants.A methodology supporting such an approach would couple regional projections on water demand from thermoelectric power plants with regional trends in water scarcity and sectoral competing uses that would be further exacerbating by climate change. Such an analyze would highlight vulnerable regions that will combine increased power plants water needs due to population and/or economic growth and increased water stress and competing uses due to trends in water needs from economic sectors and changes in water availability in the context of climate change. Weakness of data impedes comprehensive study of this aspect of climate change. Nevertheless, general and important elements of such analysis are given here as basis for characterizing regions at risk and further detailed study. In this section we first resume the methodology and results of two study for the U.S that analyze future regional water withdrawal and consumption of power plants that would further give basis for analyzing region at risk due to trend in water availability and competing use. We describe then the main regions at risk in the world ie. coupling major increase in forecasted thermoelectric generation due to increased energy needs, decrease in water availability due to climate change, and increase trend in sectoral water competition.

3.3.1. Water demand projections: The EPRI (2002) and DOE-NETL (2008) studies

We focus here on the assumptions and scenarios used to forecast water needs for thermoelectric generation in the U.S. EPRI (2002) and DOE-NETL (2008) studies objectives are to provide regional and national estimations of thermal power plants freshwater needs. EPRI (2002) focus on water consumption for power generation between 2000 and 2020. A “base case” and two alternative scenarios were employed to gauge sensitivity of water consumption projections to uncertainty in the ratio of power plant and cooling system types expected to be used in 2020. DOE-NETL (2008) analyzes water withdrawal and consumption between 2005 and 2030 under 5 underlying cases.The following 3 steps were used to estimate regional and national freshwater consumption for the power production sector: (a) Identify major water consuming power plant types and determine typical water withdrawal and consumption per unit of generation for each plant type ; (b) Determine current generation and estimate future generation by power plant and cooling system type ; (c) Multiply plant/cooling system–specific generation forecasts by the appropriate values for water withdrawal and consumption per unit of generation. We detail the methodology for the two constitutive components of step 2: (i) Power generation projections by plant and fuel type: The EPRI study uses two leading estimates of U.S. electric power production over the next 20 years: the DOE EIA Annual Energy Outlook 2000 (AEO2000) and EPRI’s “Energy-Environment Policy Integration and Coordination” (E-EPIC) study. The EIA AEO2000 projection serves as the “base case” and represents a “coal predominates” bounding scenario. EPRI’s E-EPIC scenario represents « current policy directions » with “major shift to gas”: The E-EPIC forecast predicts generators’ response to environmental restrictions likely to be imposed in regulations for SO2, NOX, and CO2 emissions. This scenario envisions massive premature retirement of coal-fired steam plants and a huge boom in the construction of natural gas combined-cycle plants. On

Page 62

the other hand, the DOE-NETL study uses a single scenario: the electricity capacity and generation forecasts provided by AEO 2008.(ii) Estimates of generation by plant type by cooling system type: The most difficult aspect of these studies was in estimating the fraction of generation for a given plant type within a given region attributable to the various cooling system types. EPRI report has developed two scenario: In the first (DOE EIA scenario + E-EPIC scenario), estimates had to be developed on the basis of available EPRI statistics on plant-by-plant generation and cooling system type and on the basis of trends observed in the industry with respect to permit requirements for condenser cooling systems. To gauge uncertainty with respect to cooling system types, an alternative scenario (DOE EIA data + “restrictive Clean Water Act 316(b)) considers the implication of an extreme potential rulemaking by the U.S. EPA on § 316(b) of the Clean Water Act (CWA). This “restrictive CWA 316(b)” scenario assumes that new plants must use cooling towers (or air-cooled condensers for combined-cycle plants where local permitting agencies require “dry” cooling), and that even existing plants with once-through or pond cooling systems must retrofit cooling towers.

Table 16: Method for estimating generation-weighted breakouts of cooling system types for current and future generation by plant type in the EPRI (2002) study

Scenario Coal steam plants Gas/Oil steam plants Nuclear steam plants Biomass/MSW steam plants

Combined Cycle plants

2000 Generation

Based on generation-weighted average of units in the ERAM database (EPRI) that produce more than 1 million MWh/yr

Based on generation-weighted average of units in the ERAM database (EPRI) that produce more than 1 million MWh/yr

Based on state-specific and plant-specific data from the Nuclear Regulatory Commision and the Nuclear Energy Institute

Assumed to be in equal proportion to cooling type breakouts for coal fired steam plants.

Region 13 based on California Energy Commission data; Region 8 assumed to be 67% cooling tower and 33% pond; other regions assumed to be 90% cooling tower and 10% saline, except in inland areas (where 100% cooling tower is assumed).

2020 Generation DOE EIA scenario and EPRI E-EPIC scenario

New units assumed to be 90% cooling tower and 10% saline, except in inland areas (where 100% cooling tower is assumed); existing unit breakouts assumed to be the same as for 2000.

Assumed to be in equal proportion to cooling type breakouts for 2000.

Assumed to be in equal proportion to cooling type breakouts for 2000.

Assumed to be in equal proportion to cooling type breakouts for coal fired steam plants.

New units assumed to be 80% cooling tower, 10% saline, and 10% dry, except in inland areas (where the 10% saline is allocated to either cooling towers, in non-arid areas, or to dry cooling in arid areas); existing unit breakouts assumed to be the same as for 2000.

2020 Generation DOE EIA scenario and CWA 316(b)

Same breakouts as the 2020 scenarios above, except that all non saline once-through and pond systems are assumed to be converted to cooling towers.

Same breakouts as the 2020 scenarios above, except that all non saline once-through and pond systems are assumed to be converted to cooling towers.

Same breakouts as the 2020 scenarios above, except that all non saline once-through and pond systems are assumed to be converted to cooling towers.

Same breakouts as the 2020 scenarios above, except that all non saline once-through and pond systems are assumed to be converted to cooling towers.

Same breakouts as the 2020 scenarios above, except that all non saline once-through and pond systems are assumed to be converted to cooling towers.

In the DOE-NETL study, future freshwater withdrawal and consumption requirements for the U.S. thermoelectric generation sector were estimated for five cases, (one reflecting status quo

Page 63

conditions, two reflecting varying levels of regulations regarding cooling water source, one incorporating dry cooling, and one reflecting regulatory pressures to convert existing once-through capacity to recirculating capacity), using AEO 2008 regional projections for capacity additions and retirements. In case 1, Additions and retirements are proportional to current water source and type of cooling system; according to Case 2, All additions use freshwater and wet recirculating cooling, while retirements are proportional to current water source and cooling system; in the case 3, 90% of additions use freshwater and wet recirculating cooling, and 10% of additions use saline water and once-through cooling, while retirements are proportional to current water source and cooling system. The Case 4 considers that 25% of additions use dry cooling and 75% of additions use freshwater and wet recirculating cooling. Retirements are proportional to current water source and cooling system; and finally, Case 5 suppose additions use freshwater and wet recirculating cooling, while retirements are proportional to current water source and cooling system. Five percent of existing freshwater once-through cooling capacity is retrofitted with wet recirculating cooling every five years starting in 2010. The five cases were selected to cover the range of possible design choices for new power plants including the source of water and type of cooling system. In addition, Case 5 assumes that 25% of existing power plants with a once-through cooling system are retrofit with a wet recirculating system. Table 17 presents the description and rationale for the five selected cases.

Table 17: Case description for the water needs analysis in DOE-NETL (2008) report

Case Description Rationale

Case 1: Additions and retirements proportional to current water source and type of cooling system.

Status quo scenario case. Assumes additions and retirements follow current trends.

Case 2: All additions use freshwater and wet recirculating cooling, while retirements are proportional to current water source and cooling system.

Regulatory-driven case. Assumes 316(b) and future regulations dictate the use of recirculating systems for all new capacity. Retirement decisions hinge on age and operational costs rather than water source and type of cooling system.

Case 3: 90% of additions use freshwater and wet recirculating cooling, and 10% of additions use saline water and once-through cooling, while retirements are proportional to current water source and cooling system.

Regulatory-light case. New additions favor the use of freshwater recirculating systems, but some saline capacity is permitted. Retirement decisions remain tied to age and operational costs, tracking current source withdrawals.

Case 4: 25% of additions use dry cooling and 75% of additions use freshwater and wet recirculating cooling. Retirements are proportional to current water source and cooling system.

Dry cooling case. Regulatory and public pressures result in significant market penetration of dry cooling technology. Retirement decisions remain tied to age and operational costs, tracking current source withdrawals.

Case 5: Additions use freshwater and wet recirculating cooling, while retirements are proportional to current water source and cooling system. 5% of existing freshwater once-through cooling capacity retrofitted with wet recirculating cooling every 5 years starting in 2010.

Conversion case. Same as Case 2, except regulatory and public pressures compel state agencies to dictate the conversion of a significant amount of existing freshwater once-through cooling systems to wet recirculating.

Moreover, climate change mitigation strategies might affects water needs for thermoelectric generation. Interestingly, the DOE-NETL (2008) analyzes the potential impacts of carbon capture and storage (CCS) on water demand. In fact, CCS technologies under development for coal-based power generation require large amounts of water. This analysis assumes aggressive carbon mitigation policies that would require all new and existing PC plants with scrubbers and IGCC plants to utilize carbon capture technologies by 2030. CCS technologies

Page 64

are applied in the year 2020. It is supposed that the generation mix would not change, thus provides an upper boundary of the estimated additional water usage for carbon capture. Water consumption and withdrawal factors were developed for the subcritical and supercritical plants. For the PC cases with carbon capture, the increase in water consumption, compared to a plant without carbon capture, is greatly influenced by the cooling water requirements of the CO2 capture process. The increased water use for the IGCC plants in largely due to the steam used in the water gas shift reaction. All additional cooling systems required for the retrofits and all new PC and IGCC capture ready plants are assumed to be recirculating systems. Carbon capture technologies require auxiliary power also termed “parasitic” load, which lowers the net exported power. This analysis assumes that all new additions include carbon capture technologies and that these new builds will meet the required capacity by accounting for their own parasitic load. The existing PC plants that will be retrofitted with carbon capture technologies will be de-rated due to the parasitic load. Net outputs from retrofitted PC plants are de-rated by approximately 30%.Four scenarios regarding the additional capacity needed to make up for the “parasitic” power loss of the carbon capture retrofits were applied to the 5 cases. Scenario 1 only accounts for the increased water requirements for the carbon capture technologies used for the retrofits and new builds and does not account for the 79.3 GW of reduced capacity due to the retrofits. For this analysis, it is assumed that the reduced capacity will be replaced with some other “non-thermoelectric” generation that does not require cooling water. This scenario is the lower estimate to serve as the lower boundary of the projections and as the initial step for the incremental water increase for scenarios 2 and 3 to build off of. Scenario 2 builds off of scenario 1 and assumes that the additional capacity needed to make up for the parasitic loss of the retrofits is supplemented by 79.3 GW of new IGCC plants with recirculating cooling and include carbon capture technologies. Scenario 3 is similar to scenario 2 except it assumes that the additional capacity needed to make up for the parasitic loss of the retrofits is supplemented by 79.3 GW of new supercritical PC power plants with recirculating cooling and include carbon capture technologies. Scenario 4 builds off of scenario 1 and assumes that the additional capacity needed to make up for the parasitic loss of the retrofits is supplemented by 79.3 GW of new nuclear plants with recirculating cooling.

3.3.2. Characterizing the main regions at risk

In analyzing the potential impacts of climate change on cooling capacities of thermoelectric power plants, the risk of increasing water stress, competing use and conflicts between sectors appears as an important feature when once-through cooling systems are used. This would be an important constraint on thermal power plants.Thus it would be important to focus on highly vulnerable regions that combine increased power plants water needs due to population and/or economic growth and increased water stress and competing uses due to trends in water needs from economic sectors and changes in water availability in the context of climate change as shown in most of IAM.Particularly, energy generation and water stress will increase notably in Southern, Western, North Africa, in Middle East, South of Europe, and in many regions of USA and decreases in stress in parts of Asia but increase in North China.

Page 65

3.4. Impacts of climate change in the context of thermal discharge regulation

One of the most important impacts of climate change on the output of thermoelectric power plant have to be understood in the context of environmental regulation on thermal discharge of plants. This issue arises from once-through cooling system context. Two important consequences can be highlighted here. The first concerns the increased risk of output fallen or power plant shutdown with the increased frequency and severity of heat waves. The second is more structural and results from trends in cooling system choice.

3.4.1. Heatwaves and output reduction impacts

Regulatory thermal discharge thresholds and climate change risksWater discharges of power plants rise river temperatures. Thus, regulatory thresholds have been fixed in order to prevent too high temperatures impacts on ecosystems. Electricity production decrease and power plant shutdown events resulting from exceeding these regulatory thresholds in thermal discharge are expected to increase with climate change. This issue relates to thermal power plant with once-through water cooling system. In fact, two types of regulatory thresholds concerning thermal discharge of once-through systems have to be considered: it is generally made up of (i) a threshold in water body temperature variation between upstream and downstream the plant, and (ii) an absolute threshold of temperature in the water body considered, that might prevent effects on river ecosystems.With climate change, an increase of frequency and intensity of heatwaves is expected, that will result in an increased frequency and duration of thermal discharge threshold exceedence risk. Particularly in developed countries, with high environmental regulatory constraints, output reduction and plant shutdown would thus be an important and growing impact of climate change. Impacts of recent events of heatwaves and/or drought constitute an important benchmark for anticipating future risks. The rationale is that even if it is impossible to prove that these events results from climate change, it shows nevertheless what we can expect from climate change. Effects of climate change for the next decades would be first experienced via increased frequency and intensity of heatwaves than effects of changes in average of temperatures. In the future, extreme heatwave events similar to that seen in 2003 in Europe are likely to become more frequent. Using a climate model simulation that follow an IPCC SRES A2 emissions scenario, Hadley Centre-Met Office (2004) predicts that more than half of all European summers are likely to be warmer than that of 2003 by the 2040s, and by the 2060s a 2003-type summer would be unusually cool. Short-term heatwaves in specific regions can threaten significant power supply disruptions. For example, the 2003 and 2006 heatwaves in Europe lead to decreased availability of cooling water for electricity generation. Extremely high temperatures in Europe during the summer of 2003 threatened the shut-down of nuclear power plants for lack of cooling water (Jowit et Espinoza, 2006) and again in July 2006, a heat spell across Europe forced several nuclear power plants to reduce generation or shut down to prevent additional impacts on wildlife populations that rely on adjacent rivers used for reactor cooling water. The Santa Maria de Garona reactor in Spain was shut down, more than one reactor in Germany reportedly reduced operation, and other units in Germany and France were granted special permits to discharge hot water into the rivers to avoid electricity shortages. 2007 drought in southeastern US has conduct several nuclear plants to reducing their output by up to 50% due to low river level in august (DOE-NETL, 2008). In a study of the impacts of climate change on river temperatures, Miller (1993) concluded that the Tennessee Valley Authority would be forced to reduce

Page 66

power generation and shut down fossil and nuclear plants more frequently to avoid violating temperature standards set for regional rivers. We can note here that considering the effects of climate change on environmental conditions, like changing temperature of river, might results in an adaptation of regulatory thresholds, particularly in maximum temperature of water body, in medium to long term. Thus, an approach would be to use geographical analogues to anticipate changes in regulatory thermal discharge thresholds following climate change.

Heatwaves and drought events impacts: the “2003 French experience”

We describe the French experience of 2003 heatwave and drought. The conjunction of heatwave and continuing drought since spring and a lack of wind have proved to be catastrophic for the whole of electricity production capacities. The energy production in France had never facing such problems than those posed by an outstanding climatic event like the 2003 heatwave. Thermal energy contributing for more than 80% of electricity needs, effects of this climatic event on these plants had thus concentrated a fundamental responsibility in difficulties experienced. Nevertheless, the problems of thermal electricity production have to be understood in the whole context of effects of heatwave and drought on both capacities and demand of electricity that depicts a scissors effect which had conduct to uneven difficulties to meet consumption needs, but above all had put in danger the overall stability of the grid.Because of heatwave, nuclear and fossil fuel power plants had faced high cooling difficulties. The unexpected intensity of heatwave experienced have resulted in extremely high, and never observed before, river temperature: several records had been broken in Seine, Garonne and Mozelle rivers. Thus, because of regulatory threshold on maximum temperature of river and thermal discharges, potential loss of thermal power plant capacity, that have reach 16 000 MW, had been identified during the august 18-24 week. During the august 4 to 24 period, a fall of 4% of nuclear energy production had been registered (Letard et al, 2004; DGEMP-DIDEME, 2004).Beyond problems of thermal power plants, electricity supplying difficulties during 2003 summer need to take in account the increase of electricity demand and reduction of production capacity of the other electricity sources. The increase in electricity needs might appear unexpected during summer, particularly with a heatwave event because of reduced economic activity, reduced lighting needs and near to zero heating. Generally, France summer electricity peak needs are about 46 000 MW, much lower of winter needs of about 75 000 MW. However, the heatwave have generated an increase of electricity consumption ranging from 5 to 10%. In fact, high temperatures have requiring to « produce more cooling » because of large call upon fridges, air-conditioners, fans and industrial cooling systems instruments. Following RTE, « for each degree upper 25°C, supplementary 250 to 300 MW are consumed in France. An increase of about 15°C, like in 2003 summer, thus increases electricity needs of about 4 000 MW. At the same time, production capacities have been reduced. Thermal electricity constitutes a major source of energy, but not the only one, particularly to meet « consumption peak ». However, the use of alternative energy sources was limited or even impossible this summer. Water power that represents the most important renewable energy contribution in France and mostly of 15% of electricity resources has not been called upon as usually because of extremely low levels of river flows. A deep decrease of hydroelectric production has been observed. The drought and consecutive low river flows generated in August the loss of 1000 MW of output of run-of-river installations, and mostly of 600 MW of

Page 67

mid-altitude reservoir. Wind energy has been totally shut-down because of lack of wind. In Germany, Netherland, Denmark and Spain, wind production has been also deeply affected. Facing the overall difficulties of electricity production, and more particularly the fall-off of thermal electricity, a massive call upon the European market of electricity have been necessary to meet the demand. EDF limited exportations when contractual commitments permitted it, and bought the maximum of available capacities on the market, about 2500 MW, at a price that have reached sometimes 1000€/MWh, thus 25 time more expensively than it has sold the electricity to final consumers. Secondly, an authorization has been given to thermal power plants to proceed to warmer discharges, while the use of this dispensation must be limited as much as possible. Very few plants have indeed used this special authorization. For two plants, their working was essential not to meet the demand, but above all to the stability of the grid. The shutdown of these plants would have led such a geographical imbalance between production and consumption places that might led to a collapse of electricity grid at regional or national scale, creating a "black out" like those that have undergone the North-East of the U.S. at the same time. Except from this, dispensations have been used only twice to meet supply-demand equilibrium, the august 14 and 15, by Bugey and Cattenom plants.

3.4.2. Trends in cooling systems choice and energy penalties potential impacts

In this regulatory context, thermal power plants with once-through cooling system show a strong vulnerability to climate change. To deal with increased risk of heatwave (and expected electricity supply and grid security impacts), new power plant would prefer wet recirculating or dry cooling and replace progressively once-through cooling. Structural impacts on output and efficiency of thermal power plant may thus result from trend in design of water cooling system to avoid decrease or power plant shutdown resulting from exceeding regulatory threshold. Moreover, independently of climate change (but amplified by it), trends in regulatory norms arising from increased competing use of water with environmental needs and increased recognition of fauna and flora protection issues yield significant trends and consequences for electricity generation of thermal power plants. Such a trend is particularly clear in the U.S. under the adopted §316(b) of the CWA.

Effects of potential retrofitting of existing plantsThe analyze of expected impacts of the CWA §316(b) in the U.S is interesting to show the energy penalty of retrofitting once-through cooling system into wet-recirculating or dry cooling. EPA adopted 316(b) regulations for new facilities (Phase I) in 2001. Under the final rule, most new facilities could be expected to install recirculating cooling systems, primarily wet cooling towers. The EPA signed proposed 316(b) regulations for existing facilities (Phase II) in 2002. The lead option in this proposal would allow most existing facilities to achieve compliance without requiring them to convert once-through cooling systems to recirculating systems. EPA is considering various options to determine best technology available. Among the options under consideration are wet-cooling and dry-cooling towers. Although neither the final new facility rule nor the proposed existing facility rule require dry cooling towers as the national best technology available, the environmental community and several States have supported the use of this technology as the most appropriate for addressing adverse environmental impacts. By switching a once-through cooling system to a cooling tower, less

Page 68

energy can be generated by the power plant from the same amount of fuel. This reduction in energy output is known as the energy penalty2. Veil et al. (1993) summarized literature values for the energy penalty associated with retrofitting once-through cooled plants with wet-cooling towers. The majority of the data points for energy penalty of fossil-fueled plants were clustered in a band of 1.5% to 2.5%. Results for nuclear plants show greater variability, ranging between 1% and 5.8%. The data points were not clearly clustered in a narrow range as for the fossil plants. They selected a range of 2 to 3% for the decrease in net electrical power that could be experienced if existing nuclear power plants retrofit from once-through to wet cooling.The DOE-NETL (2002) report quantifies the loss of net electric output from an existing coal-fired power plant that would result from a possible replacement from once-through cooling system to either a recirculating or a dry cooling tower for five locations. A 400 MW plant was selected as representative of the range of existing coal-fired plants. The results of the 1% high temperature modeling (peak season energy penalty analysis) show that conversion to a wet tower could cause energy penalties, i.e. a reduction of plant electricity production while burning the same amount of coal, ranging from 2.4% to 4%. Conversion to an indirect-dry tower, where possible, could cause energy penalties ranging from about 8.9% to 12.1% using 20°F for the approach (the difference between the inlet air dry-bulb temperature and the desired cold water temperature), and 12.7% to almost 15.9% using an approach of 40°F. The industry norm for indirect dry towers – a 40° approach -- was evaluated initially, but the resulting pressures for the steam turbines were found to result in unacceptable operating conditions during the one-percent highest temperature times of the year. The mostly likely way that a company could operate a retrofitted indirect-dry tower at a 40° approach would be to reduce the power output from the plant (load shedding) during the hottest times of the year. This power output reduction imparts an immediate energy penalty. On completion of the analysis it was determined that even if load shedding was attempted on all the 40° approach cases it would still be technically infeasible to operate the turbines safely during the summer months. To provide more information on dry tower energy penalties, a more conservative approach of 20° was subsequently modeled. Tables 18 and 19 demonstrate the effects on electric generating capacity during the one-percent highest temperature conditions if 10, 25, 50, or 100% of the existing once-through cooled power plants in the U.S. were required to retrofit.

Table 18: Wet cooling tower energy penalties and impact at one percent highest temperature conditions

Once- Wet, recirculating cooling tower retrofit penalty (%)

2 Energy penalty represents the loss of electricity generating capacity incurred when a cooling system is unable to perform at design

efficiency. The energy penalty is associated with insufficient cooling of the turbine exhaust steam and usually is manifested by an increase

in steam turbine back pressure. The penalty is expressed as “the percentage of plant output,” or “the percentage of additional energy that

would have to be used to generate the same amount of electricity.” The energy penalty also includes additional power needed for pumps

and fans in cooling tower systems.

Page 69

through cooling systems

required to retrofit (%)

Low value

2.4

Average value

3.0

High value

4.0

Energy penalty (MW)

% of total steam electric capacity

Energy penalty (MW)

% of total steam electric capacity

Energy penalty (MW)

% of total steam electric capacity

10 621 0.24 777 0.30 1 036 0.40

25 1 553 0.60 1 942 0.75 2 589 1.00

50 3 106 1.20 3 883 1.50 5 178 2.00

100 6 212 2.40 7 766 3.00 10 356 4.00

The annual energy penalty modeling (resulting of a monthly energy penalties, arithmetically averaged to generate an estimate of annual average penalty) show that conversion to a wet tower could cause energy penalties ranging from 0.8% to 1.5%. Conversion to an indirect-dry tower could cause energy penalties ranging from about 4.2% to 5.2% using 20° F for the approach, and 7.9% to almost 8.8% using an approach of 40°F. In order to compensate for the electricity lost as a result of the energy penalty, utilities would need to produce more electricity through burning additional fuel, resulting in additional CO2 emissions.

Table 19: Indirect-dry cooling tower energy penalties and impact at one percent highest temperature conditions

Once-through cooling systems

required to retrofit (%)

Indirect-dry (20°F approach) cooling tower retrofit penalty (%)

Low value

8.8

Average value

10.2

High value

13.1

Energy penalty (MW)

% of total steam electric capacity

Energy penalty (MW)

% of total steam electric capacity

Energy penalty (MW)

% of total steam electric capacity

10 2 278 0.88 2 641 1.02 3 392 1.31

25 5 696 2.20 6 602 2.55 8 479 3.28

50 11 392 4.40 13 204 5.10 16 958 6.55

100 22 784 8.80 26 408 10.20 33 917 13.10

Energy penalty relating to choice of dry or recirculating vs. once-through cooling for new power plants

Risks arising from increased heatwave events due to climate change might conduct power plant designers to prefer wet recirculating or dry cooling over traditionally once-through systems for new power plants in order to prevent impacts of increased probability of regulatory thermal discharge threshold exceedence. Such a trend in choice of cooling systems will result also in important energy penalties.Burns and Micheletti (2000) estimate the energy penalty values for a new generic 750-MW combined-cycle power plant using either a wet recirculating cooling system or a direct dry cooling system at sites in five different parts of the country. Then for both types of cooling

Page 70

systems, the maximum energy penalty occurs during the hottest times of the year when ambient wet-bulb and dry-bulb temperatures are greatest. This period normally is represented by 1% of the time during the four warmest months, which also happen to coincide with the times of national peak electricity demand. The modeling was initially done to simulate the performance and energy penalty in the hottest time of the year using temperature input values that are exceeded only 1% of the time between June through September at each location. These are the same temperature inputs commonly used by cooling tower designers to ensure that towers perform properly under most climatic conditions. The high temperature inputs correspond to the time of year when the highest power demands are observed and the needs for generating capacity are most critical due to the very high cost of buying replacement power on the spot market. For recirculating wet cooling, the estimated maximum energy penalty was less than 1% for any of the five sites. For direct dry cooling, the maximum penalty ranged from 11.6% to 18.1%, depending on site climatic conditions.

3.5. Technological adaptation and Cooling choices: Economic, environmental and performance tradeoffs

Thermal power plants are vulnerable to climate change due to the high dependency of their cooling systems to water availability, temperature, and environmental regulation on thermal discharge. Substitution of once-through cooling by recirculating wet cooling would inhibit risk of thermal discharge regulatory threshold exceedence, and replace high withdrawal by low consumptions. Beyond, replacement by dry cooling would permit to avoid all water risk relating to trends in water scarcity and competing use, and thermal discharge regulation. Although, saving water and reducing water dependency and vulnerability come at price, particularly for dry cooling, in the form of higher plant cost, reduced power production, increased fuel consumption as a result of lower plant efficiency, higher plant operating power requirements, and hence, higher operating costs—all resulting in a reduction in potential revenue from the power generation operation.Cooling system choice appears as the most important adaptation issue for thermal power plants facing climate change. We analyse here potential trade-offs in terms of investment costs, thermal performance and environmental effects that arise from cooling system choice. Table 20 resume advantages and disadvantages of different cooling systems, namely once-through cooling, wet recirculating cooling, dry cooling, and hybrid cooling systems. We have to note here that comparison between cooling configurations is not simple or direct because of the multidimensionality of tradeoff, and dependency to objective hierarchy.

Table 20: Summary of advantages and disadvantages of alternative cooling systems

Cooling configuration Advantages Disadvantages

Once-through cooling

- No water consumption

- Highest efficiency

- Lowest installation and operating costs

-No plume nor noise

- Highest withdrawal rates

- High thermal discharge

Recirculating wet cooling - Reduced withdrawal rates

- Low thermal discharge

- High efficiency

- Higher water consumptions

- Higher investment and operating costs

- chemical treatment discharges

Page 71

- emissions of air pollutants

- visual impacts of structure and plume

Dry cooling

- No water withdrawal

- No water consumption

- No thermal impact

- No plume

- lowest efficiency (particularly in hot days)

- visual and noise impact of structure

-Fan energy needs

- very high investment costs (x5) and operating costs

- limited capacity (~ 500 MWe)

- very high site space

Hybrid wet/dry cooling

- Low withdrawals

- Low water consumption

-Low thermal discharges

- moderate efficiency

- visual and noise impact of structure

- chemical treatment discharges

- Fan energy needs

- High investment costs

- high site space

Several studies have compared alternate cooling systems and analyzed multidimentional trade-offs that arises from choice between them. The Maulbetsh and DiFillipo (2006) report is based on comparison of wet recirculating and dry cooling for a 500 MW gas-fired combined-cycle plant in California. The purpose of this study is to estimate the value of water use at power plants at a variety of sites and using a variety of source waters representative of conditions in California. EPRI (2004) study is a more in depht analyze for understanding the tradeoffs between wet and dry cooling technologies. Systems comparisons are made under meteorological conditions of the entire U.S., and consideration is given to coal and nuclear steam plants in addition to gas-fired combined-cycle plants. More importantly the methodology used is more appropriate for the comparison between plants with different cooling systems because plants have been optimized in their design choices. Alternative cooling systems are configured and optimized for each site and then compared on the bases of water consumption, capital cost, effect on plant performance, operations and maintenance costs and other environmental effects. The motivation for this work stems from the increasing importance of water use and conservation as a power plant siting issue. While a variety of water-conserving cooling technologies exist which can significantly reduce the amount of water used by the plant, these savings typically come at a price in the form both of increased capital costs and of plant performance penalties including higher heat rate and reduced hot day output.

The purpose of the study of Maulbetsh and DiFillipo (2006) is to estimate the value of water use at power plants at a variety of sites and using a variety of source waters representative of conditions in California. The results of the analysis can be summarized in the following conclusions. For a 500 MW gas-fired, combined-cycle plant (typical of new plants in California) the use of dry cooling reduces the annual plant water requirements by approximately 2 000 to 2 500 acre-feet per year, depending on the climate at the plant location. The associated costs are: An increased plant capital cost of approximately $8 million to $27 million, or about 5% to 15% of the total plant cost; a potential reduction of energy production by about 13000–56000 MWh/y (1% to 2% of the total); a capacity reduction on hot days of 13 to 23 MW (4% to 6% of total); and a potential annual revenue reduction of about $1.5 to $3.0 million (1% to 2% of total). The cost of dry cooling can be

Page 72

expressed as the “effective cost” of water. This is defined as the additional cost of using dry cooling expressed on an annualized basis divided by the annual reduction in water requirement achieved through the use of dry cooling. It is important to understand that these costs and penalties are calculated for dry cooling systems which were sized using an optimization criterion of minimum total annualized cost based on current estimates of capital, fuel and electricity costs. As noted above, other optimization criteria could have been chosen and would have yielded different results.

The report of EPRI (2004) study alternative cooling systems for electric power generating plants with the particular objective of understanding the tradeoffs between wet and dry cooling technologies. The motivation for this work stems from the increasing importance of water use and conservation as a power plant siting issue. Alternative cooling systems are configured and optimized for each site and then compared on the bases of water consumption, capital cost, effect on plant performance, operations and maintenance costs and other environmental effects. The following paragraphs summarize the results and conclusions of the study in these specific areas.Capital cost and annualized costs comparison: Cooling system capital costs for a specified plant at a given site cannot be determined in the absence of a full consideration of performance issues and of the economic and business objectives of the project. To illustrate the point, note that an air-cooled condenser, sized for the steam cycle portion of a 500 MW combined-cycle plant, can have a capital cost for an erected unit ranging from $20.0 to $40.0 million depending on the size chosen. A corresponding range for a wet cooling system would be $4.5 to $6.5 million. A proper estimate of the capital costs must consider that the choice of a larger, higher capacity cooling system will result in higher capital costs, but will provide higher plant output and more efficient operation for the life of the plant. In order to be meaningful, comparisons should be made among optimized systems. An optimized system design is normally defined as one that minimizes the sum of all costs, including initial capital costs, operating and maintenance costs, plant heat rate and capacity penalties for the life of the plant. The capital and operating costs should include all equipment, labor and expendables costs for all plant elements influenced by the choice of cooling system, such as the cost of water and water supply, treatment and discharge/disposal facilities. The choice of the optimum design also depends on the relative importance assigned to present vs. future costs. Depending on the business plans and objectives, this might favor a “low first cost” design or a “minimum evaluated cost/30 year plant life” design. In this study, for a 500 MW combined-cycle plant, capital costs range from $21 to $26 million for dry systems and $5.7 to $6.5 million for wet systems. The capital cost ratios range from 4.5 at the hot arid site to approximately 3.5 for the other sites. Annualized costs for optimized wet and dry systems at each of the five sites range from $3.2 to $4.3 million for the dry systems and from $0.9 to $1.2 in the case of wet systems. Thus annualized costs ratios range from 4.5 at the hot arid site to 3.2 and 3.6 for the remaining sites. In the case of 350 MW coal-fired plants, capital costs are multiplied by 3.25 to 3.6 when dry cooling systems are chosen instead of wet systems. The ratios of annual costs are in this case about 3 to 3.75. Performance comparison: For optimized designs under nearly all conditions, wet cooling systems are not only the least expensive but result in the highest plant output and efficiency. The questions is how much more expensive are dry cooling systems and how great are the effects on plant output and efficiency and what is the cost of those effects. The performance costs are of three types: cooling system operating power requirements, increased plant heat rate due to a higher turbine backpressure, and a limited plant output during the hottest hours of the year.

Page 73

The power consumed by the cooling system pumps and fans represents energy that must be generated by the plant, but is not available for sale. As a result, the plant incurs a loss of potential revenue for the life of the plant. For wet systems, the required power depends on whether the cooling tower was designed for lowest first cost or for minimum evaluated cost. For the case studied, the wet cooling systems have the following range of power requirements: For a 500 MW combined cycle plant, power requirements are 1270 to 2000 kW for low first cost design and 900 to 1,270 kW for minimum evaluated cost. For a 350 MW coal-fired steam plant, energy needs are 2900 to 4600 kW for a low first cost design and 2000 to 2900 kW for minimum evaluated cost. For air-cooled condensers (dry systems) the fan power can be greater than the total pump and fan power for wet systems. For the cases calculated it ranges from 1500 to 3000 kW for the combined-cycle plants to 3400 to 6800 kW for the coal-fired steam plant.The plant performance penalties incurred as a result of higher backpressures—imposed by cooling system performance limitations—can be expressed in a number of ways. During much of the year, both the dry and the wet cooling systems can maintain the backpressure or below the design value of 2.5 in Hga. In the case of the wet system, if designed for 2.5 in Hga at the 1% wet bulb, the plant will actually perform slightly better than the design output for nearly the entire year for which the ambient wet bulb is below the design value. Dry systems operate for many hours of the year, however, at backpressures above design. As a result, the plant output, at constant firing rate, is less than design. For the case of the 500 MW combined-cycle plant at a hot, arid site, the lost output for the year amount to about 2% of the output that would have been obtained from the plant operating all-year at its design back- pressure. However, for the 1000 hottest ours of the year, the reduction in output ranges from nearly 25% on the hottest hour to about 8% at the coolest of the 1,000 hours. Water conservation : Historically, most power plants in the United States used once-through cooling. However, for plants built recently or being built now, the most common system is recirculating wet cooling with a mechanical draft wet cooling tower. These systems significantly reduce (by a factor of 20 to 50) the amount of water drawn into a plant compared to plants using once-through cooling, but nearly all the water withdrawn for cooling purposes is evaporated in the process. Water conserving systems such as dry cooling using air-cooled condensers or hybrid, wet/dry systems using parallel dry and wet condensing loops, can further reduce the water used for cooling. While plant cooling is the major water use, it is not the only one. Therefore, the choice of water-conserving cooling (wet or dry) will substantially reduce plant water requirements, but not eliminate them entirely. Using dry cooling will result in a large reduction in the amount of water used by a plant. Depending on the pant design and the water required for uses other than cooling, the dry cooled plant will save from 95% to 75% of the water used by a wet cooled plant. For the cooling alone, virtually all water consumed by recirculating wet cooling is saved by the use of dry cooling.

Reference

Burns J.M., Micheletti W.C., 2000, Comparison of Wet and Dry Cooling Systems for Combined Cycle Power Plants, prepared for Hunton & Williams, November 4.

Chuang C., Sue D., 2005, Performance effects of combined cycle power plant with variable condenser pressure and loading, Energy, 30, pp. 1793-1801

Davcock, C., DesJardins R., Fennell S., 2004, Generation cost forecasting using on-line thermodynamic models, In: Proceedings of Electric Power.

DGEMP-DIDEME, 2004, Notre système électrique à l’épreuve de la canicule, Lettre Energies et Matières Premières, 23, pp.

DOE/NETL, 2008, Water requirements for existing and emerging thermoelectric plant technologies, DOE/NETL-402/080108, 21 p.

Page 74

DOE/NETL, 2007, Potential Impacts of climate change on the energy sector, DOE/NETL-403/101807, 51p.

DOE/NETL, 2007b, Cost and Performance Comparison Baseline for Fossil Energy Power Plants, U.S. Department of Energy, National Energy Technology Laboratory

DOE/NETL, 2006, Carbon Dioxide Capture from Existing Coal-Fired Power Plants, U.S. Department of Energy, National Energy Technology Laboratory

DOE/NETL, 2005, Addressing the critical link between fossil energy and water, 39 p.

DOE/NETL, 2004, Estimating freshwater needs to meet electricity generating capacity forecasts, 12 p.

DOE/NETL, 2002, Energy penalty analysis of possible cooling water intake structure requirements on existing coal-fired power plants, 78 pp.

Durmayaz A., Sogut O.S., 2006, Influence of cooling water temperature on pressurized-water reactor nuclear-power plant, International Journal of Energy Research, 30, pp. 799-810.

EIA, 2008, Annual Energy Outlook 2008 with Projections to 2030, Energy Information Administration, http://www.eia.doe.gov/oiaf/aeo/index.html

EPRI, 2004, Comparison of alternate cooling technologies for U.S. power plants: EPRI Technical Report 1005358, Palo Alto, California, 270p.

EPRI, 2003, A survey of water use and sustainability in the United States with a focus on power generation, EPRI Technical Report 1005474, 86 p.

EPRI, 2002(a), Water and sustainability: U.S. water consumption for power production – The next half century (Volume 3), EPRI Topical Report 1006786, 57 p.

EPRI, 2002(b), Comparison of alternate cooling technologies for California power plants: Economic, Environmental, and other tradeoffs, 238 pp.

Hoffman J., Forbes S., Feeley T. (DOI-NETL), 2004, Estimating freshwater needs to meet 2025 electricity generating capacity forecasts, 12 p.

Ganan J., Rahman Al-Kassir A., Gonzalez J.F., Macias A., Diaz M.A., 2005, Influence of the cooling circulation water on the efficiency of a thermonuclear plant, Applied Thermal Engineering, 25, pp. 485–494

Létard V., Flandre H., Lepeltier S., 2004, La France et les Français face à la canicule : les leçons d’une crise, Rapport d’information du Sénat n° 195, 391 p.

Maulbetsch J.S., Di Fillipo M.N., 2006, Cost and value of water use at combined-cycle power plant, Report prepared for California Energy Commission Public Interest Research (PIER) Program, 134 pp.

Ponce Arrieta F.R., Silva Lora E.E, 2005, Influence of ambient temperature on combined cycle power plant performance, Applied energy, 80(3), 261-273

Smith B.T., Sale M.J., Bransterr M.L., King A.W., Coutant C.C.,, Potential effects of climate change in thermoelectric cooling systems, Poster presented at …

SNL, 2006, Energy demands on water resources, Report to the Congress on the interdependency of energy and water, U.S. Department of Energy, 80 p.

USCCSP, 2007, Effects of climate change on energy production and use in the United States, 108p.

Van Aart F. Kok W., Ploumen P., 2004, Energy efficiency in power plant, Présentation à la Conférence « Energy Efficiency in IPCC Installations », 21-22/10/2004, Vienne, Austria, 12 pp.

Veil J.A., VanKuiken J.C., Folga S., Gillette J.L., 1993, Impact on the Steam Electric Power Industry of Deleting Section 316(a) of the Clean Water Act: Energy and Environmental Impacts,” Argonne National Laboratory Report ANL/EAIS-5, January.

Vicaud A., 2008, Les besoins en eau de refroidissement des centrales thermiques de production d’électricité, La Houille Blanche, 6, pp. 34-40

Page 75

4. Assessment of impacts of climate change on energy consumption for water use.

Satisfying water needs requires energy for supply, purification, distribution, and treatment of water and wastewater. Impacts of climate change on energy requirement for water supplying may mainly arise from impacts of change on irrigation needs, and impacts of increased call in desalinization for meeting water needs, mainly drinking water but also irrigation or industrial, where water become more scarce.We study (i) technical coefficients of electricity requirements for water delivery and treatment, and (ii) expected impacts of climate change on energy consumption for satisfying water needs.

4.1. Technical coefficients of energy requirement for water delivery and treatment

4.1.1. Conventional waters

About 4% of U.S. power generation is used for water supply and treatment, which, is comparable to several other industrial sectors. Electricity represents approximately 75% of the cost of municipal water processing and distribution (SNL, 2006). Note that within regions, there can be substantial variation in energy requirements for water supply and treatment, depending upon the source, the distance water is conveyed, and the local topography. California, where 5% of electricity consumption is used for water supply and treatment, is an interesting case study in electrical consumption, and illustrates the cost of long-distance water conveyance.

EPRI (2002) StudyEPRI (2002) gives a very detailed study of present and projected energy requirement of water supply and treatment needs. Notably, electricity consumption for both supplying and wastewater treatment are distinguished according to sources, namely public vs. end-user and ground and surface water. Summary results of this study are reported in tables 21 to 23. Next sections detail assumptions and analyses that support these results.

Table 21: Summary of unit of electricity consumption for water supply and wastewater treatment in kWh/million gallons (and kWh/cubic meters)

Sector Surface Water Ground Water Wastewater

Domestic -NA- 700 (0.185) -NA-

Commercial 300 (0.079) 700 (0.185) 2500 (0.661)

Industrial 300 (0.079) 750 (0.198) 2500 (0.661)

Page 76

Mining 300 (0.079) 750 (0.198) 2500 (0.661)

Irrigation 300 (0.079) 700 (0.185) -NA-

Livestock 300 (0.079) 700 (0.185) -NA-

Power Generation 300 (0.079) 800 (0.211) -NA-

Public Supply 1406 (0.371) 1824 (0.482) -NA-

Publicy Owned Treatment Works (typical)

Trickling filter

Activated sludge

Advanced wastewater treatment

Advanced treatment with nitrification

955 (0.252)

1322 (0.349)

1541 (0.407)

1911 (0.505)

Table 22: Public vs. end-users supplied water by sectors in million gallons per day (and percent)

Sector Public Supply End-user Supply Total

Domestic 22 509 (87 %) 3 374 (13 %) 25 883

Commercial 6 630 (70 %) 2 895 (30 %) 9 524

Industrial 4 737 (19 %) 20 717 (81 %) 25 454

Mining - 2 754 (100 %) 2 754

Irrigation - 133 575 (100 %) 133 575

Livestock - 5 477 (100 %) 5 477

Power Generation 98 (1 %) 131 771 (99 %) 132 869

Table 23: Surface vs. ground water sources of self-supplied water by sectors

Sector Surface Water Ground Water

Domestic 31 (-) 3 343 (100 %)

Commercial 1 955 (66 %) 940 (34 %)

Industrial 16 642 (80 %) 4 076 (20 %)

Mining 1 693 (61 %) 1 061 (39 %)

Irrigation 84 557 (63 %) 49 018 (27 %)

Livestock 3 223 (59 %) 2 254 (41 %)

Page 77

Power Generation 131 208 (100 %) 563 (-)

▪ Electricity requirements for delivery of water by public supply agenciesThis section describes the methodology used to estimate and project electricity requirements for the delivery of freshwater by public water supply agencies derived from surface and groundwater.

- Surface water treatment process and unit electricity consumptionProcess: In a typical sequence of operations for surface water treatment, the following steps are followed. Raw water is first screened to remove gross debris and contaminants. The water is then pre-oxidized using chlorine or ozone treatment to kill any disease-carrying organisms and remove taste or odor causing substances. Alum and/or polymeric materials re-added to the water to aid in the flocculation and coagulation of finer particles. The flocculation step serves to agglomerate finer particles that can then be settled out or removed in the sedimentation and filtration steps. A second disinfection step kills any remaining disease causing organisms and leaves a disinfectant residue that is carried into the distribution system to prevent the growth of any organisms. The clear well storage allows contact time for disinfection and provides surge capacity for the distribution system to meet system demand. The treated water is then distributed to consumers by high pressure pumping. Sludges and other impurities removed from the fresh water are concentrated and disposed of.Electricity requirement: Along with the process sequence shown in figure 17 are daily electricity requirements for each process step. These figures are representative of a 10 million gallon per day (37 850 m3/day)) surface water treatment facility. Such a facility would have an estimated total electricity consumption of about 14 057 kWh per day, which is equivalent to a unit energy consumption of 1 406 kWh per million gallon (0.371 kWh/m3). Variations in unit electricity requirement with treatment plants size is not significant

Figure 17: Representative surface water treatment plant process (with typical daily electricity consumption for a 10 million gallon/day facility)

- Groundwater treatment process and unit electricity consumptionProcess: The process sequence for groundwater supply by public water supply agencies is much less severe than for surface water. The sequence consists of well pumping to the

Page 78

surface. The water is chlorinated for disinfection and removal of odor and taste. The treated water is then pumped directly to the distribution system or alternatively to above ground or ground level storage tanks before distribution.Electricity requirement: Unit electricity consumption for supply from groundwater is estimated at 1 824 kWh/million gallons (0.482 kWh/m3), some 30% greater than for surface water. This appears to be independent of the size of the pumping and treatment facility. The predominant consumer of electricity is pumping. About one-third of the electricity is used for well pumping, while the most of the balance is used for booster pumping into the distribution system. Less than 0.5 % of the electricity is used for chlorination of the water.

▪ Electricity requirements for end-users water supply Freshwater is supplied by public water supply agencies with distribution to end-users, and by end-users themselves. Here, the unit electricity estimates associated with the supply of water by the entities for their own consumption will be covered. Sectors covered here are domestic (residential), commercial, industrial and mining, irrigation and livestock, and thermal power generation.According to the U.S. Geological Survey (USGS), self-supplied water varied from 13 % for domestic sector to nearly 100 % for mining, irrigation, livestock and power generation sectors. Commercial and industrial sectors reports respectively 30 and 81 % of self-supplied water. The balance comes from public supply. Ground vs. surface in self-supplied water: domestic sector are summarized in Table 23. Unit electricity consumption for types of systems use by these sectors will vary with the depth of the well, the pressure and flow rate of the output water, and the efficiency of the pump system for ground water. For surface water, unit electricity consumption will vary with the distance between point of supply and point of use, the pressure and flow rate of the output water, and the efficiency of the pumping system. For the purpose of the analysis a unit electricity consumption of about 700 kWh per million gallons (0.185 kWh/m3) is assumed for ground water self-supplied water for domestic, commercial irrigation and livestock sectors. For industrial and mining sectors a 750 kWh per million gallons (0.198 kWh/m3) is assumed and a 800 kWh per MM gallons (0.211 kWh/m3) is assumed for power generation. These figures are based on the electricity requirements for municipal groundwater system well pumping (605 kWh/million gallon—0.161 kWh/m3), with allowance for the reduced scale of pumping and for the additional energy for distribution.: For the purpose of the analysis a unit electricity consumption of about 300 kWh/MM gallons (0.079 kWh/m3) is assumed for surface water for all the sectors considered. This figure is based on the unit electricity consumption for municipal surface water pumping of 278 kWh/MM gallons (0.073 kWh/m3), with an upward adjustment based on the reduced scale of pumping, the need for distribution pumping within the facility, and the energy requirements for treating the water prior to use.

▪ Electricity requirements for wastewater treatment by POTWS and private facilitiesThis section describes the methodology used to estimate and project electricity requirements for the treatment of wastewater by publicly owned treatment works (POTWs) and private facilities to end consumers in all sectors. There are many process sequences available for treatment of wastewater. Instead, four representative types of facilities will be used to characterize the larger population, with unit electricity consumption estimates for each of these types provided over a range of sizes. • Trickling Filter: In the typical process sequence for a trickling filter wastewater treatment plant, influent wastewater is screened to remove gross material carried in the stream. Finer particles are then removed with an aerated grit removal system. The wastewater is held in a settling vessel to remove other particulates before it is biologically treated in the trickling

Page 79

filter system. The trickling filter itself is a substrate over which the organic wastewater is passed. The trickling filter substrate supports the growth of bacteria that aerobically consume the organic material. A secondary settling step removes other particulate matter. The treated wastewater is then disinfected by chlorination before discharge. The remaining sludges may be further treated biologically to remove organic materials. A further anaerobic digestion step removes remaining organics, and the sludge is then dewatered mechanically and disposed of by incineration or by being sent to landfill.• Activated Sludge: As with the previous system, incoming wastewater to the activated sludge process is first screened to remove gross contaminants, and then passes through a grit removal system to remove smaller particulate matter. A primary settling chamber is used to remove smaller particulate and suspended matter and the effluent is then digested aerobically in an aeration tank. After sufficient residence time for digestion has passed, the wastewater stream is pumped to a secondary settling tank, for removal of digested material. After secondary settling, the treated wastewater is disinfected with chlorine and discharged. The sludge from primary settling is similarly aerobically digested, then pumped to a settling tank to separate the liquid from the solid stream. The solids are thickened and then anaerobically digested for removal of remaining organic materials. The waste sludge is then dewatered and disposed of in landfill or by incineration.• Advanced Wastewater Treatment: The advanced wastewater treatment process is similar to the activated sludge process, but includes additional treatment in the form of filtration prior to discharge of the biologically treated waste stream. These types of systems are more effective in removing nitrogen, phosphorus, and suspended solids by filtration. The front part of the process is similar to the activated sludge process. Incoming effluent is screened and grit is removed. After settling to remove suspended solids, the wastewater is aerobically digested in an activated sludge process. If nitrogen removal is required, bacteria specific for nitrification are used in this step. After, secondary settling chemicals are injected into the waste stream to aid in agglomeration of remaining solids, which are removed in the subsequent filtration step. After disinfection, the treated water is discharged. The sludges are thickened, anaerobically digested, dewatered and disposed of in landfill or by incineration• Advanced Wastewater Treatment with Nitrification

Unit electricity requirement: Unit electricity consumptions for the four processes are shown in Table 24, broken down by size of the treatment facility. As would be expected, the unit electricity consumption decreases with the size of the plant due to economies of scale. As also would be expected, unit electricity consumption is higher as the degree of treatment and complexity of the process increases – advanced wastewater treatment with nitrification is 3 times as energy intensive (due to additional pumping requirements) than the relatively simple trickling filter treatment.

Table 24: Unit electricity consumption for wastewater treatment by processes and plant sizes

Treatment plant size

Million gallon/day (m3/day)

Unit electricity consumption

kWh/million gallons (kWh/m3)

Trickling filter Activated sludge Advanced wastewater treatment

Advanced Wastewater treatment nitrification

1 MM gal/day

(3785 m3/d)1811 (0.479) 2236 (0.591) 2596 (0.686) 2951 (0.780)

Page 80

5 MM gal/day

(18925 m3/d)978 (0.258) 1369 (0.362) 1573 (0.416) 1926 (0.509)

10 MM gal/day

(37850 m3/d)852 (0.225) 1203 (0.318) 1408 (0.372) 1791 (0.473)

20 MM gal/day

(75700 m3/d)750 (0.198) 1114 (0.294) 1303 (0.344) 1676 (0.433)

50 MM gal/day

(189250 m3/d)687 (0.182) 1051 (0.278 1216 (0.321) 1588 (0.423)

100 MM gal/day

(378500 m3/d)673 (0.177) 1028 (0.272) 1188 (0.314) 1558 (0.412)

Given the smaller size and potentially higher loadings, the unit electricity consumption of private facilities will tend to be higher than for POTWs. A reasonable estimate of unit electricity consumption would be about 2,500 kWh/million gallons (0.661 kWh/m3).

▪ Issues related to trends in electricity use for supply and waste waterFactors that could increase unit electric consumption for public supply/treatment agencies include: The age of the water delivery system: as systems age friction in piping increases and efficiency of pumping systems decreases, resulting in an increase in electricity requirements for pumping. Implementation of voluntary or mandatory restrictions on water consumption (including application of home appliance and plumbing fixture water consumption standards): water conservation programs will should reduce the overall amount of electricity required, but may actually result in an increase in unit electricity consumption as economies of scale may be lost or systems operate at below optimum levels. Requirements for improved treatment: as standards and requirements for drinking water quality increase, more rigorous treatment will be required. Regardless of the type of enhanced treatment employed, more rigorous treatment will result in increased pumping energy requirements. The additional water pumping associated with advanced wastewater treatment results in 3 times the electricity use of a conventional trickling filter approach. In fact, this difference leads to the expectation of a 20% increase in electricity use by public supply agencies from 2000 to 2005; the projection for the next 45 years after that is only another 20%, since major treatment approach changeovers will have been completed in the first five year period. Factors that could decrease unit energy (electric) consumption for public supply/treatment agencies include: Economies of scale (a trend to larger systems from smaller systems will provide economies of scale of operation, resulting in reduced unit electricity consumption) and replacement of older equipment with more energy efficient pumps, drives, and water processing equipment.Conclusions about privately operated wastewater treatment works show that municipal wastewater treatment facilities are typically designed to handle domestic wastes, in terms of both volume and concentration of waste. Since discharges from these facilities are typically to surface water, it is likely that more aggressive wastewater treatment will be required over the next 20 years. This is likely to increase unit electricity consumption over the period by perhaps 5 to 10%.

Other studies relating to energy for water

Page 81

The report of Goosens and Bonnet (2001) describes matrix of water and energy interactions for three countries case study. In the case of France, they show that the supplying and treatment of water consume 19 TWh/year, representing 4.4% of national electricity consumption. Annual water withdrawal and consumption reach 40.5 Gm3, thus the production and treatment of one m3 of water represent a need of 0.47 kWh. For the U.S., water mobilization and treatment use 1.1% of national energy budget, but 6.3% of total final electricity consumption, by consuming 214 TWh/year. Water withdrawal and consumption are 625.8 Gm3/year in the U.S., thus 0.34 kWh/m3 of water supplied and treated are used. In the case of Saudi Arabia, 46 TWh/year of primary energy are dedicated to water supplying and treatment, representing 3.7% of energy consumed nationally. Annual water withdrawal and consumption are about 32.7 Gm3, so 1.41 kWhp are used for each m3 of water produced and treated. Renewable water resources are very scarce in Saudi Arabia (about 2.5 Gm3/y). Consequences of the agricultural policy result in 13 Gm3/y of fossil water withdrawal for irrigation. Important crops needs in terms of water quantities and depth of these withdrawals involve a high energy content of irrigation sector (more than 17 TWh of primary energy are used for irrigation, representing 70% of energy consumption of agricultural sector). Half of freshwater supply is provided by deep water treatment facilities, and the other half by desalting station. Desalinated water produced in 1998 amounted to more than 0.8 Gm3, and represented a primary energy consumption of about 20 TWhp (representing more than 9% of primary energy consumption of residential tertiary sector).

Table 25: Energy for water (Goossens et Bonnet, 2001)

Water use (Gm3) Energy needs by m3

France 40.5 0.47 kWh/m3

USA 625.8 0.34 kWh/m3

Saudi Arabia 32.7 1.41 kWhp/m3

They show that the production of each m3 of water supplied to final consumer requires several steps : pumping, efficiency of pumps are assumed to be about 75% ; filtration that necessitates 20 Wh/m3 ; desinfection pumps (30 Wh/m3) ; ozonation (60 Wh/m3) ; ultra filtration (518 Wh/m3) ; high pressure pump for distribution (250 Wh/m3) and distribution through the grid  (water losses range from 20% to 40% and sometime more). The results show that the energy requirement of supplying 1 m3 of drinking water range between 0.47 and 0.85 kWh for ground water sources, and 0.48 and 1.15 kWh for surface water.

Table 26: Energy consumption for freshwater production

Ground Water Surface Water

Water (m3)

Energy (kWh)Water (m3)

Energy (kWh)

Max Min Max Min

Pumping 1.3 0.468 0.14 1.3 0.094 0.047

Filtration 1.3 0.026 0.026 1.3 0.026 0.026

Page 82

Desinfection 1.3 0.004 0.004 1.3 0.004 0.004

Ozonation 1.3 0.029 0.029 1.3 0.029 0.078

Ultra filtration 1.3 0.673 0.673

Distribution: high pressure pump 1.3 0.328 0.328 1.3 0.328 0.328

Distribution: water losses 30 % 30 %

1 m3 of freshwater supplied to final consumer 1 0.854 0.472 1 1.153 0.482

Goossens et Bonnet (2003) analyze the energy implications of irrigation for various configurations. Results for France, India and Egypt resumed in the following table, show the variability of energy requirement for irrigation depending type of culture, localization, irrigation scheme type and efficiency, water resources used and energy types mobilized.

Table 27: Energy requirement for agriculture production following different irrigation configuration

Location Culture Irrigation technics

Water resource

type

Final energy

type

Water withdrawal Final energy

[m3/t] [m3/ha] [kWh/m3] [kWh/ha] [kWh/t]

Agen (France) Maiz Sprinkler Surface water Electricity 207 2 278 0.41 941 86

Jaïpur (India) Wheat Gravitational Superficial

groundwater Electricity 2 640 6 600 0.22 1 439 576

Nil Valley (Egypt) Wheat Gravitational Collective

channel Fuel oil 1 407 8 444 0.03 242 40

Darb El Arbaïn (South Egypt)

Wheat Gravitational Deep groundwater Fuel oil 2 857 10 000 1.14 11 374 3 250

In their report on the energy-irrigation nexus in South Asia, Shah et al (2003) show that South Asia’s groundwater economy differs in a unique ways from those of other intensive groundwater using countries. India is the biggest groundwater user in the world. In addition to India, Pakistan, Bangladesh, and Nepal constitute the biggest groundwater users countries in the world. Between them, they pump around 210 km3 of groundwater every year. In doing so, they use almost 20-21 million pump sets, of which approximately 13 million are electric and around 8 million are powered by diesel engines. They assume that an average electric tubewell (with a pumping efficiency of 25%) lifts water to an average head of 20-30 meters uses 0.5 kWh/m3 of water lifted, the total energy used in these countries for lifting 210 km3 of groundwater is about 68.6 billion kWhe per year.

In analyzing energy for water in Mediterranean countries, Thivet (2008) shows an average electricity consumption for water in 2000 estimated at 0.4 kWh/m3 in France and 1.5 kWh/m3 in Israel (where non conventional water are important source). At regional level, a unit electricity consumption of about 0.2 to 0.3 kWh/m3 of supplied and treated water is assumed for South and East Mediterranean Countries (SEMC), and 0.4 kWh/m3 for North

Page 83

Mediterranean Countries (NMC). The study estimates that actual needs of electricity for the supply and treatment of water (including pumping, drink water and waste water treatment, desalting and transfers) represent 5% and 10% of electricity demand in NMC and SEMC respectively. For 2025, unit electricity consumption of about 1 kWh/m3 for SEMC and 0.7 kWh/m3 for NMC are assumed.

4.1.2. Desalinated waters

Desalination technologies Desalting refers to a water treatment process that removes salts from water. A variety of desalting technologies has been developed over the years. They can be classified into thermal and membrane processes.

▪ Thermal ProcessesAbout half of the world’s desalted water is produced with heat to distill fresh water from sea water. The distillation process mimics the natural water cycle in that salt water is heated, producing water vapor that is in turn condensed to form fresh water.Multi-Stage Flash: In the MSF process, seawater is heated in a vessel called the brine heater. This is generally done by condensing steam on a bank of tubes that carry seawater which passes through the vessel. This heated seawater then flows into another vessel, called a stage, where the ambient pressure is lower, causing the water to immediately boil. The sudden introduction of the heated water into the chamber causes it to boil rapidly, almost exploding or flashing into steam. Generally, only a small percentage of this water is converted to steam, depending on the pressure maintained in this stage, since boiling will continue only until the water cools (furnishing the heat of vaporization) to the boiling point. The vapor steam generated by flashing is converted to fresh water by being condensed on tubes of heat exchangers that run through each stage. The tubes are cooled by the incoming feed water going to the brine heater. This, in turn, warms up the feed water so that the amount of thermal energy needed in the brine heater to raise the temperature of the seawater is reduced. Multi-stage flash plants have been built commercially since the 1950s. They are generally built in units of about 4000 to 57000 m3/d.

Figure 4.2: Diagram of Multi-Stage Flash

Multi Effect Distillation: MED, like MSF, takes place in a series of vessels and uses the principles of condensation and evaporation at reduced ambient pressure in the various effects.

Page 84

This permits the seawater feed to undergo boiling without the need to supply additional heat after the first effect. In general, an effect consists of a vessel, a heat exchanger, and devices for transporting the various fluids between the effects. Diverse designs have been or are being used for the heat exchanger area, such as vertical tubes with falling brine film or rising liquids, horizontal tubes with falling film, or plates with a falling brine film. By far the most common heat exchanger consists of horizontal tubes with a falling film. There are several methods of adding the feed water to the system. Adding feed water in equal portions to the various effects is the most common. The feed water is sprayed or otherwise distributed onto the surface of the evaporator surface (usually tubes) in a thin film to promote rapid boiling and evaporation after it has been preheated to the boiling temperature on the upper section. The surfaces, in the first effect, are heated by steam from steam turbines of the power plants or a boiler. The steam is then condensed on the colder heat transfer surface inside the effect to heat. The condensate is recycled to the boiler for reuse. The surfaces of all the other effects are heated by the steam produced in each preceding effect. The steam produced in the last effect is condensed in a separate heat exchanger called the final condenser, which is cooled by the incoming sea water, thus preheating the feed water. Only a portion of the seawater applied to the heat transfer surfaces is evaporated. The remaining feed water, of each effect, now concentrated and called brine, is often fed to the brine pool of the next effect, where some of it flashes into steam. This steam is also part of the heating process. All steam condensed inside the effects is the source of the fresh water product. MED plants are typically built in units of 2 000 to 20 000 m3/d.

Figure 18: Diagram of multi effect distillation

Mechanical Vapor Compression: The vapor compression (VC) distillation process is generally used in combination with other processes (like the MED) and by itself for small and medium-scale seawater desalting applications. The heat for evaporating the water comes from the compression of vapor rather than the direct exchange of heat from steam produced in a boiler. The plants that use this process are also designed to take advantage of the principle of reducing the boiling point temperature by reducing the pressure. Steam ejectors (thermal vapor compression) and mechanical compressors (mechanical vapor compression) are used in the compression cycle to run the process. The mechanical compressor is usually electrically or diesel driven, allowing the sole use of electrical or mechanical energy to produce water by distillation. VC units have been built in a variety of configurations to promote the exchange of

Page 85

heat to evaporate the seawater. The diagram illustrates a simplified method in which a mechanical compressor is used to generate the heat for evaporation. All steam is removed by a mechanical compressor from the last effect and introduced as heating steam into the first effect after compression where it condenses on the cold side of the heat transfer surface. Seawater is sprayed, or otherwise distributed on the other side of the heat transfer surface where it boils and partially evaporates, producing more vapor. In order to use low cost compressors, the pressure increase is limited, and therefore, most smaller plants only have one stage. In newer and larger plants, several stages are used. The mechanical VC units are produced in capacities ranging from a few liters up to 3000 m3/d. They generally have an energy consumption of about 7 to 12 kWh/m3. With the steam-jet type VC unit, also called a thermo-compressor, an ejector operated using 3 to 20 bar motive steam removes part of the water vapor (steam) from the vessel. In the ejector, the removed vapor is compressed to the necessary heating steam pressure to be introduced into the first effect.

Figure 19: Diagram of mechanical vapor compression

▪ Membrane ProcessesMembranes are used in two commercially important desalting processes: electrodialysis (ED) and reverse osmosis (RO). Each process uses the ability of the membranes to differentiate and selectively separate salts and water. However, membranes are used differently in each of these processes. ED is a voltage driven process and uses an electrical potential to move salts selectively through a membrane, leaving fresh water behind as product water. RO is a pressure-driven process, with the pressure used for separation by allowing fresh water to move through a membrane, leaving the salts behind.

Page 86

Figure 20: Diagram of membrane processes

Electrodialysis: ED was commercially introduced in the early 1960s. The development of ED provided a cost-effective way to desalt brackish water and spurred considerable interest in the whole field of using desalting technologies for producing potable water for municipal use. The dissolved ionic constituents in a saline solution are dispersed in water, effectively neutralizing their individual charges. When electrodes are connected to an outside source of direct current like a battery and placed in a container of saline water, electrical current is carried through the solution, with the ions tending to migrate to the electrode with the opposite charge. To desalinate water, individual membranes that will allow either cations or anions (but not both) to pass are placed between a pair of electrodes. These membranes are arranged alternately, with an anion-selective membrane followed by a cation-selective membrane. A spacer sheet that permits water to flow along the face of the membrane is placed between each pair of membranes. One spacer provides a channel that carries feed (and product) water, while the next carries brine. As the electrodes are charged and saline feed water flows along the product water spacer at right angles to the electrodes, the anions (such as sodium and calcium) in the water are attracted and diverted through the membrane towards the positive electrode. This dilutes the salt content of the water in the product water channel. The anions pass through the anion-selective membrane, but cannot pass any farther than the cation-selective membrane, which blocks their path and traps the anions in the brine stream. Similarly, cations (such as chloride or carbonate) under the influence of the negative electrode move in the opposite direction through the cation-selective membrane to the concentrate channel on the other side. Here, the cations are trapped because the next membrane is anion-selective and prevents further movement towards the electrode.

Figure 21: Components of an electrodialysis plant

Page 87

By this arrangement, concentrated and diluted solutions are created in the spaces between the alternating membranes. These spaces, bounded by two membranes (one anionic and the other cationic) are called cells. The cell pair consists of two cells, one from which the ions migrated (the dilute cell for the product water) and the other in which the ions concentrate (the concentrate cell for the brine stream). The basic ED unit consists of several hundred-cell pairs bound together with electrodes on the outside and is referred to as a membrane stack. Feed water passes simultaneously in parallel paths through all the cells to provide a continuous flow of desalted water and concentrate (or brine) from the stack. Depending on the design of the system, chemicals may be added to the streams in the stack to reduce the potential for scaling. An ED unit is made up of the following basic components: Pretreatment train, membrane stack, low-pressure circulating pump, power supply for direct current, post-treatment. The raw feed water must be pretreated to prevent materials that could harm the membranes or clog the narrow channels in the cells from entering the membrane stack. The feed water is circulated through the stack with a low pressure pump with enough power to overcome the resistance of the water as it passes through the narrow passages. A rectifier is used to transform alternating current to the direct current supplied to the electrodes on the outside of the membrane stacks. Post-treatment consists of stabilizing the water and preparing it for distribution. This post-treatment might consist of removing gases such as hydrogen sulfide and adjusting the pH.

Reverse Osmosis: In comparison to distillation and electrodialysis, RO is relatively new, with successful commercialization occurring in the early 1970s. RO is a membrane separation process in which the water from a pressurized saline solution is separated from the solutes (the dissolved material) by flowing through a membrane. No heating or phase change is necessary for this separation. The major energy required for desalting is for pressurizing the feed water. In practice, the saline feed water is pumped into a closed vessel where it is pressurized against the membrane. As a portion of the water passes through the membrane, the remaining feed water increases in salt content. At the same time, a portion of this feed water is discharged without passing through the membrane. An RO system is made up of the following basic components: Pretreatment, high-pressure pump, membrane assembly, post-treatment. Pretreatment is important in RO because the membrane surfaces must remain clean. Therefore, suspended solids must be removed and the water pretreated so that salt precipitation or microbial growth does not occur on the membranes. Usually, the pretreatment consists of fine filtration and the addition of acid or other chemicals to inhibit precipitation and the growth of microorganisms. The high-pressure pump supplies the pressure needed to enable the water to pass through the membrane and have the salts rejected. This pressure ranges from 15 to 25 bar for brackish water and from 54 to 80 bar for seawater. The membrane assembly consists of a pressure vessel and a membrane that permits the feed water to be pressurized against the membrane. The membrane must be able to withstand the entire pressure drop across it. The semi-permeable membranes vary in their ability to pass fresh water and reject the passage of salts. No membrane is perfect in its ability to reject salts, so a small amount of salts passes through the membrane and appears in the product water. RO membranes are made in a variety of configurations. Two of the most commercially successful are spiral-wound and hollow fiber. Both of these configurations are used to desalt both brackish and seawater. Post-treatment consists of stabilizing the water and preparing it for distribution. This post-treatment might consist of the removing gases such as hydrogen sulfide and adjusting the pH.

Page 88

Figure 22: Basic components of a reverse osmosis plant

Two developments have helped to reduce the operating cost of RO plants during the past decade: the development of more efficient membranes and the use of energy recovery devices. The membranes now have higher water flux, improved rejection of salts, lower prices, and longer service lives. It is common now to use energy recovery devices connected to the concentrate stream as it leaves the pressure vessel at about 1 to 4 bar less than the applied pressure from the high-pressure pump. These energy recovery devices are mechanical and generally consist of work or pressure exchangers, turbines, or pumps of some type that can convert the pressure difference to rotating or other types of energy that can be used to reduce the energy needs in the overall process. These can have a significant impact on the economics of operating large plants. They increase in value as the cost of energy increases. Now, energy usage in the range of 3 kWh/m3 for seawater RO plants has been reported. The other important event in the RO membrane area has been the use of membranes called nanofiltration (NF) that are more porous to the passage of dissolved solids.

Capacities, process and sectoral uses ▪ Capacities worldwide GWI (2006) indicated that the total capacity of installed desalination plants in operation worldwide was about 20 millions m3/d. This total capacity is an increase of about 70% from that reported in the previous edition of The Desalting ABC’s in 1990. Desalting equipments are now used in over 100 countries. According to the Inventory of Wangnick (1998), 10 countries have about 75% of all the capacity. IDA (2000) data shows that almost half of desalting capacity is used to desalt seawater in the Middle East and North Africa. Saudi Arabia ranks first in total capacity (24% of the world’s capacity), with most of it being made up of seawater desalting units that use the distillation process. USA ranks second in overall capacity, with about 16%. Most of the capacity in the USA consists of plants in which the RO process is used to treat brackish water. Europe accounts for 13% of world capacity, in which Spain and Italy rank fourth and tenth respectively in total capacities. Asia represents 11% of world desalting (dominated by Japan, China and India), Africa accounts for 5%, and Caribbean for 3%. South America and Australia account each for 1% of the total. The following figure shows installed capacities of countries representing more than 1% of world desalting capacities.In terms of sectoral use of the 7500 million m3 of desalinated water produced annually across the globe, the primary share goes to municipal use (64%), following by industry (25%), and power (5%). Agricultural use accounts only for 230 million m3, representing 3% of produced desalinated water.

Page 89

Figure 23: Countries with more than 1% of global desalination capacity (Wangnick/GWI, 2005)

▪ Capacity by processThe Wangnick/GWI (2005) Inventory indicates that the world’s installed capacity consists mainly of the multi-stage flash distillation and RO processes. These two processes make up about 86% of the total capacity, and shares almost equally. The remaining 14% is made up of the multiple effect, electro-dialysis, and vapor compression processes, while the minor processes amounted to less than 1%. Based on these data, the installed capacity of membrane and thermal processes is about equal. The Table 28 summarizes worldwide desalination capacity by process in 1998. From the inventory by Wangnick (2000), seawater and brackish water make up about 59% and 41%, respectively, of the total water sources for desalination.

Table 28: Summary of worldwide desalination capacity by process, 1998 (Wangnick, 2000)

Desalinating process % Capacity (106 m3/d) No. of plants

Multistage flash distillation 44.4 10.02 1 244

Reverse osmosis 39.1 8.83 7 851

Multiple-effect distillation 4.1 0.92 682

Electro-dialysis 5.6 1.27 1 470

Vapour compression distillation 4.3 0.97 903

Membrane softening 2.0 0.45 101

Page 90

Hybrid processes 0.2 0.05 62

Others 0.3 0.06 120

TOTAL 100 22.57 12 433

Since a portion of the older units, which generally were distillation units, are now retired, it is probable that the capacity of operating membrane units exceeds that of thermal. In fact, trends seem to be in favor of reverse osmosis. Between 1990 and 2005, membrane process has increased from 40% to 53% of world installed capacity. The following figure shows that even if MSF and RO share equally installed capacities, capacities added between 1988 and 1997 have favored notably RO. In the same way, Veolia research is oriented on RO, of which expected market share in 2020 are about 70% (20% for MED and 10% for the remainder processes) (Veolia, 2005). RO is particularly appealing because recent advances in membrane technology allow modular construction of desalinating facilities to meet small to large volume desalination needs (FAO, 2003).

Figure 24: Total capacity and capacity added between 1988 and 1997 by process (IDA, 2002)

On a geographical basis, thermal desalination processes remain to dominate the desalination market in the Gulf States. On the other hand, the RO process is dominant in the US, Spain, and Japan. Other countries like Italy and the Caribbean Islands have balanced production capacity among thermal and membrane desalination. For the next few decades, it is expected to have thermal desalination in the Gulf States; however, accumulated experience in design and operation seawater RO is resulting in adoption of larger RO plants in most of these countries (Al-Sahali and Ettouney, 2007).

Energy requirements, costs and trends in desalting water production ▪ Energy requirements for desalting water We report here the energy requirements for the production of 1 m3 of desalinated water by various desalting processes found in the literature. Note that results of the different reports analyzed here gave very different estimates. In fact, energy needs for desalting water vary with processes of desalination, but also with size of plants, and water types (brackish, seawater, salt concentration).The high-energy requirement is an essential feature of the desalination process. Hoffman (2004), reports an energy requirement of 4.7 – 5.7 kWh/m3 for RO, and 23–27 kWh/m3 for

Page 91

MSF. Following Al-Sahali and Ettouney (2007), RO needs 5 kWh/m3 of desalinated water, MSF accounted for 18 kWh/m3, MED needs 15 kWh/m3, and MVC requirements are about 10–14 kWh/m3. The IDA (2000) report assumes a 3 kWh/m3 for RO and 7-12 kWh/m3 for MVC. Table 29 describes some characteristics of desalination technologies and their corresponding energy requirements based on FAO data (FAO, 2003) and reported by Martinez Beltran et al (2006).

Table 29: Energy requirements of different desalination technology and plant capacity (FAO, 2003)

Desalination technology Salt concentration in product water TDS (ppm) Plant capacity (m3/d) Energy requirements

(kWh/m3)

Thermal distillation of seawater:

Multistage flash

Multiple-effect

Vapour compression

1-50

5 000 - 60 000

100 – 20 000

20 – 2 500

3.5

1.5

8 - 14

Reverse osmosis 200-500 100 - 100 000 4 - 7

Electro-dialysis - - 1

The Water Corporation (2000) reports other estimations of energy consumption for desalting water by using different technologies (Table 30). It makes a distinction between electrical energy consumption and thermal energy consumption.

Table 30: Energy use by various desalination processes (Water Corporation, 2000)

Process Electrical energy consumption (kWh/m3)

Thermal energy consumption (kWh/m3)

Total energy consumption (kWh/m3)

MSF 3.25 - 3.75 9.75 - 6.75 13 - 10.5

MED 2.5 - 2.9 6.5 - 4.5 9 - 7.4

METC 2.0 - 2.5 12 - 6.5 14 - 9

MVC 9.5 - 17 N/A 9.5 - 17

BWRO* 1.0 - 2.5 N/A 1.0 - 2.5

SWRO** 4.5 - 8.5 N/A 4.5 - 8.5

* Brackish Water Reverse Osmosis, ** Sea Water Reverse Osmosis

▪ Costs and trends of desalting water productionA summary of what is known about the current status and trends in desalination costs are presented in this section, followed by an analysis of the determinants of those costs. A review of the structure of desalination costs is important to identifying research areas with the greatest potential for reducing costs.

Page 92

Desalting costs composition: The primary elements of desalination costs are capital cost and annual running cost. The capital cost includes the purchase cost of major equipment, auxiliary equipment, land, construction, management overheads, contingency costs etc. The capital costs for seawater desalination plants have decreased over the years due to the ongoing development of processes, components and materials. Annual running costs consist of costs for energy, labor, chemicals, consumables and spare parts. A typical breakdown of running costs for thermal processes is that the ratio of energy, chemicals and labor equals 0.87:0.05:0.08 (IDA, 2000). The energy costs play a dominant role for thermal processes. Distillation costs will fluctuate more than RO with changing energy costs (Zhou and Tol, 2004)Reported desalination costs: The cost to treat seawater or brackish waters to produce potable water is a function of numerous variables, and the components of these costs are frequently difficult to ascertain precisely from the literature. Different project costs are also difficult to compare because virtually every desalination plant has its own unique design and site conditions and its own unique financing package. Reviews of published data on costs can be confusing because costs are rarely reported consistently and some cost parameters are not reported at all. Additionally, the underlying assumptions (e.g., project life, project size) may differ and sometimes remain unstated. For example, some cost data include distribution costs while others are for costs at the plant boundary. Miller (2003) summarizes costs reported in the published literature for a variety of desalination projects and notes that the numbers can only be used as a rough guide because they are not calculated on a consistent basis. Despite the limitations of proprietary data, there is a wealth of information available on the nature of desalination costs and on the ways in which those costs are determined.

Page 93

Table 31: Desalination costs for various technologies ($/m3) reported by Miller (2003) state-of-the-art

Membrane and thermal processes are both used widely in municipal-scale desalination plants worldwide and each technology has strengths and weaknesses and differing operating conditions under which one or the other may be economically optimal. Thermal desalination systems consume more energy than reverse osmosis (RO) systems and are more capital intensive. Nevertheless, thermal systems can use more diffuse or low-grade forms of energy (i.e., low-pressure steam) whereas membrane systems rely solely on electricity as an energy source. Global Water Intelligence (GWI, 2006) reports the capital costs of seawater desalination by multi-effect distillation and multistage flash distillation to be 1.5 to 2.0 times the capital costs of RO desalination systems, respectively. Additionally, GWI (2006) approximates the costs for the seawater desalination process by RO to be $0.61/m3 as compared to $0.72/m3 for MED and $0.89/m3 for MSF. The breakdown for these costs is shown in Table 32. These costs are based on a system scale of 100,000 m3/day; a nominal interest rate of 6 percent; $450 element cost; $0.05/kWh energy cost; assumed electricity use of 4.5, 4.0, and 1.25 kWh/m3 for RO, MSF, and MED, respectively; and a 20-year capital-payback period. The costs for seawater desalination by RO are slightly lower than costs reported from actual installations. Most likely this is due to the favorable interest and energy costs used in the analysis. Additionally, the calculated total costs for thermal technologies are likely exaggerated because offpeak electricity costs, cogeneration, or the use of low-grade or waste energy are not considered in this analysis. If low-cost, dispersed sources of energy are available or energy can be jointly used with other purposes, seawater desalination using thermal technologies becomes more cost effective. Leaving aside situations in which energy

Page 94

can be obtained cheaply, the capital and operating costs of thermal systems appear significantly higher than the best-available membrane technology.

Table 32: Comparative Total Cost Data for the Desalination Process for 100,000 m3 of Seawater by Reverse Osmosis, Multistage Flash Distillation, and Multi-Effect Distillation (GWI, 2006)

SW RO SW MSF SW MED

Annualized capital costs 0.15 0.29 0.22

Parts/maintenance 0.03 0.01 0.01

Chemicals 0.07 0.05 0.08

Labor 0.10 0.08 0.08

Membranes (life not specified) 0.03 0.00 0.00

Thermal energy 0.00 0.27* 0.27*

Electrical energy ($0.05 k/Wh) 0.23 0.19 0.06

Total ($/m3) 0.61 0.89 0.72

*The costs of thermal energy are likely exaggerated because offpeak electricity costs, cogeneration, or the use of waste energy are not considered in this analysis.

Determinants of costs and sensitivity analysis: The study of Zhou and Tol (2004) defines the main economic parameters used in estimation of desalination costs and calculates the unit costs of desalted water for five main processes based on simplified assumptions. They use multiple regression to estimate the trends of unit costs over time and analyze the significant factors that affect the cost of desalination. Costs of the MSF process: This study considers 442 desalting plants using MSF processes worldwide from year 1957 to 2001, with a total capacity of 12.6 million m3/d. The major consumers of MSF are in the Middle Eastern and North African (ME&NA) countries. Figure 25 illustrates the unit costs of all the desalting plants using the MSF process over the total cumulative installed capacity. The unit cost has been reduced substantially since the initial stage of MSF technology. The average unit cost has fallen from about 9.0 $/m3 in 1960 to about 1.0 $/m3 at present, which indicates that there has been a great improvement of MSF technology. The average annual reduction rate of unit costs has been about 5.3% in last 40 years. The study uses regression methods to estimate the unit costs of these desalting plants. The original data for the plant include the location, the year, the plant capacity and raw water quality. The calculated data include unit costs and the total cumulative installed capacity. The model for this process is specified in (1).

F(UNITC)=G(TIC,CAP,YEAR,ME&NA,SEA) (1)where UNITC is the average unit cost of desalting one cubic meter of water, TIC refers to the total cumulative installed capacity, which reflects the expansion of desalting plants over time. CAP is the capacity of a single plant. YEAR is the contract year of the plant. ME&NA is the regional dummy, and SEA is the raw water quality dummy. The model was estimated with OLS for two different equations, namely semi-log and double log. Since TIC and YEAR are correlated and non-stationary, Zhou and Tol (2004) estimate separate equations with either explanatory variable. Note that the two alternative regressions have a different interpretation. With YEAR as an explanatory variable, costs reductions are due to technological progress

Page 95

outside the water desalination industry. In contrast, with TIC as an explanatory variable, cost reductions are due to technological progress inside the water desalination industry through learning by doing.The regressions show that all the variables but ME&NA are statistically significant in unit cost estimation. As TIC represents the total installed capacity of all the desalting plants, the decline of the unit cost can be explained as a result of the technological development and gained experiences. According to the regression results, the unit cost will continue to decrease with the increasing cumulative capacity and over the time. The double log estimation with TIC suggests a total installed capacity elasticity of –0.35, that is, for every 1% extension of the total installed capacity, the unit costs decrease by 0.35%. For the year 2001 alone, the total contracted capacity has increased by about 8%. That would mean a decrease of unit cost by 2.8%. CAP also influences the unit cost of a plant, as the cost tends to be lower with the increase of plant capacity due to economies of scale. The study indicates an elasticity of –0.16 for the plant capacity, representing increasing returns to scale. It is thus suggested from this study that seawater desalting plants using the MSF process will be economically favorable to have a larger capacity. YEAR is significant, reflecting that the technology change outside the sector also plays an important role in the cost reduction over time.

Page 96

0.0

3.0

6.0

9.0

12.0

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Year

Uni

t cos

t ($/

m3)

Figure 25: Unit cost of desalinated water by MSF process depending on year of installation and cumulate installed capacity

Costs of the RO process: The RO process has become more popular during the past decades due to advancing technology and falling costs. The operating cost of RO plants has been reduced, thanks to two developments: (1) lower-cost, higher-flux, higher salt rejecting membranes that can efficiently operate at lower pressures and (2) the use of pressure recovery devices (Gleick, 2000). This study contains 2514 desalting plants using RO processes worldwide, with a total capacity of 12.7 million m3/d since the 1970’s.Figure 26 shows the unit costs of all desalting plants using RO processes over the total cumulative installed capacity. Raw water quality plays an important role in the costs of RO desalination. The average unit costs of RO processes have declined from 5.0 $/m3 in 1970 to less than 1.0 $/m3 today. Figure 26 also shows that the unit costs for seawater desalination are still above 1.0 $/m3 whilst the costs for desalting brackish-, river- and pure-water has been reduced to less than 0.6 $/m3 level. Note that recent tenders costs of large seawater RO indicate even lower costs. For instance, some field estimates suggest a cost of $0.55/m3 for a large RO project in Florida (Ettouney, 2002); more recent cost proposals such as for the Ashkelon desalination in Israel have included costs as low as US$0.52/m3 (Busch and Mickols, 2004).Essentially similar regressions to estimate the unit cost as for the MSF process have been done. The major consumers for RO are located quite dispersedly worldwide, therefore the

Page 97

0.0

1.0

2.0

3.0

4.0

5.0

6.0

1965 1970 1975 1980 1985 1990 1995 2000 2005

Year

1995

Uni

t cos

t($/m

3)regional dummies are excluded. Various raw water qualities such as brackish-, sea-, river-, pure-,wastewater are included. The model specification is in (2).

F(UNITC)=G(TIC,CAP,YEAR,SEA,BRACK,RIVERPURE) (2)where SEA, BRACK, and RIVERPURE refer to seawater, brackish water and river plus pure water dummies. The results show that all the variables are statistically significant. The negative coefficient values of TIC and CAP imply a lower unit cost with the increase of the total installed capacity and the plant capacity, which is similar to the estimation of MSF. The double-log regression results suggest a total installed capacity elasticity of –0.29. For the year 2001 alone, the total contracted capacity has increased by about 13%, which would mean a fall of unit cost by 3.77%. It also indicates an elasticity of –0.10 for the plant capacity, which is lower than for MSF.

Figure 26: Unit cost of desalinated water by RO process depending on year of installation and cumulate installed capacity

Page 98

4.2. Expected impacts of climate change on electricity consumption for water needs

Climate change would impact energy needs for water supplying and treatment in number of ways. On the demand side, major effects are expected to come from agriculture and impacts of climate change on irrigation needs, the other sectors demand would remain unchanged. On the supply side, climate change might impact the reliability of conventional water sources. In that sense another important effect of climate change on energy needs for supplying water would arise to expected increased call in desalination for meeting water needs, mainly drinking water but also irrigation or industrial, where water become more scarce.

4.2.1. Impacts of climate change on electricity requirement relating to change in irrigation needs

With respect to agriculture, considerable research has investigated the impacts of socio-economic development, climate change, and variability on global crop production. Yet a much smaller body of work has analyzed implications for irrigation water use, both regionally and globally. Impacts of climate change on irrigation water requirements may be large. A few new studies have further quantified the impacts of climate change on regional and global irrigation requirements, irrespective of the positive effects of elevated CO2 on crop water-use efficiency. Within this context, even fewer studies have specifically addressed future regional and global changes in irrigation water for agriculture.Döll and Siebert (2001) have developed a global irrigation model by integrating simplified agro-ecological and hydrological approaches. Döll (2002) used this framework to investigate global impacts of climate change and variability on agricultural water irrigation demand by comparing the impacts of current and future climate on irrigated cropland. She found that changes in precipitation, combined with increases in evaporative demands, but without any CO2 effects, increase the net crop irrigation requirements (i.e., net of transpiration losses) worldwide, with small relative changes in total, by about between +5 to +8 % by 2070 – depending on the general circulation model (GCM) projection – with larger regional signals, about +15%, in Southeast Asia and the Indian subcontinent. Fischer et al (2007), in a study that included positive CO2 effects on crop water-use efficiency, computed increases in global net irrigation requirements of 20% by 2080, with larger impacts in developing versus developing regions, due to both increased evaporative demands and longer growing seasons under climate change. Fischer et al. (2006) and Arnell et al. (2004) also projected increases in water stress (measured as the ratio of irrigation withdrawals to renewable water resources) in the Middle East and south-east Asia. Recent regional studies have likewise underlined critical climate change/water dynamics in key irrigated areas, such as northern Africa where irrigation requirements are expected to increase (Abou-Hadid et al, 2003) and China where decreased requirements are found (Tao et al, 2003). At the national scale, some integrative studies exist. In the USA, two modelling studies on adaptation of the agricultural sector to climate change (i.e., shifts between irrigated and rainfed production) foresee a decrease in both irrigated areas and withdrawals beyond 2030 under various climate scenarios (Reilly et al, 2003; Thomson et al, 2005). This is related to a declining yield gap between irrigated and rain-fed agriculture caused either by yield reductions of irrigated crops due to higher temperatures, or by yield increases of rain-fed crops due to higher precipitation. These studies did not take into account the increasing variability of daily precipitation and, as such, rain-fed yields are probably overestimated. In the case of Sri Lanka, the results of the study of De Silua et al (2007) suggests that, during the wet season, average rainfall would decrease by 17% (A2) and 9% (B2), with rains ending

Page 99

earlier, and potential evapotranspiration increasing by 3.5% (A2) and 3% (B2). Consequently, the average paddy irrigation water requirement would increase by 23% (A2) and 13% (B2).

We focus here on the methodology and results of Fisher et al (2007) to estimate the potential impacts of climate change on irrigation needs. This paper reports estimates of irrigation water requirements under current and future decades brought about by changes in both climate and socio-economic conditions. The methodology is based on the FAO–IIASA agro-ecological modeling framework (AEZ), employed in conjunction with IIASA's world food system model, or Basic Linked System (BLS). AEZ was used to assess net crop irrigation water requirements (WRQ), defined as the amount of water – in addition to available soil moisture from precipitation – that crop plants on irrigated land must receive to grow without water stress. Gross annual water withdrawals (AWW) for irrigation were then estimated via an irrigation efficiency parameter, an indirect proxy of irrigation water loss. A water scarcity index (WSI) was defined as the ratio of AWWs to internal renewable water resources (WRI). The paper focuses on the modified SRES A2r scenario. Climate change scenarios from HadCM3 and CSIRO GCMs were utilized. Projected climate changes for each decade, from 1990 to 2080, were computed relative to a baseline climate (1961–1990) at 0.5×0.5° grid, and used to generate future agronomic and water data. Two climate change scenarios were considered: SRES A2 climate projections were used as a proxy for the A2r unmitigated climate, while SRES B1 climate projections were employed as a proxy for climate change under the A2r mitigated scenario. Impacts of socio-economic development, no climate change: In the year 2000, world total irrigated area was nearly 18% of total cultivated land, with larger shares in developing countries, especially in Asia. By 2080, BLS projected global irrigated land of 393Mha, or 22% of global cultivated land. This corresponds to a +45% increase from 2000 levels. Of the additional irrigated land, the large majority is in developing countries (+56%), mainly in South Asia, Africa, and Latin America. For India and China irrigated land by 2080 represents 45% and 50%, respectively, of total cultivated land in these countries, an average increase of 28% compared to the year 2000. Total net irrigation water requirements, WRQ, increase proportionally with irrigated land. Specifically, global net irrigation requirements increase from 1350Gm3/year to 1960Gm3/year. Irrigation water requirements increase over 50% in developing regions and by about 16% in developed regions. The largest relative increases from 2000 to 2080 were computed for Africa, from 45 to 180Gm3/year (+300%) and Latin America, from 82 to 179Gm3/year (+119%). Developed regions were computed to add about 40Gm3/year in total, with North America (+23%) experiencing the largest increase. Impacts of socio-economic development, with climate change: Impacts of climate change on net irrigation water requirements, AWWs, and renewable water resources were analyzed using HADCM3 and the CSIRO GCMs. In general, in these simulations the higher temperatures and altered precipitation regimes impacted net irrigation water requirements in two distinct ways. First, by affecting crop evapotranspiration rates, and thus crop water demand; and second, by altering crop calendars and thus modifying the duration over which a crop could be grown and irrigated. Impacts of climate change on world aggregate net irrigation water requirements are significant. Total increases of about 395–410Gm3 water in 2080 were projected, similarly under both GCM scenarios (Table 33), i.e., a +20% increase over the net water requirements of 1960Gm3 water of reference case. Some important regional dynamics were also computed. First, in 2080, net irrigation requirements from climate change increase, in relative terms, significantly more in developed (+45% under Hadley, +36% under CSIRO) than in developing regions (+17%). Increases in net irrigation requirements are uniformly high in developed countries. In developing regions, largest increases were computed in East Asia (+35% under Hadley, +47% under CSIRO). The time

Page 100

evolution of net water requirements indicates a smooth transition (i.e., it followed the year 2000 regional patterns with gradual increases in each decade). Exceptions are the Indian subcontinent (in Hadley) and the Southeast Asian region (in CSIRO), for which small decreases in net irrigation water requirements up to 2040 are computed.Renewable water resources and security under climate change: We estimated changes in renewable fresh water resources as a function of changes in precipitation and potential evapotranspiration, based on a cross-country regression established under current climate conditions. Table 34 shows results for 2080, with global renewable water resources being reduced by −10% under Hadley, but slightly increased (+2%) under CSIRO, compared with the reference scenario. In particular, under the Hadley climate, significant reductions were computed for Europe (−19%), the Middle East (−20%), and most pronounced for Latin America (−42%), where rainfall volume under the A2r climate change decreases by −20%. At the same time, internal renewable water resources under Hadley increase in some regions, for instance in China (+14%) and the Indian subcontinent (+25%). These regional patterns of change are maintained under the CSIRO climate change, although the magnitudes of the projected changes are smaller and with fewer extremes – the largest deviation occurs for the Middle East region (−15%).

Table 33: Changes in projected net irrigation water requirement (Gm3) under climate change scenario A2r compared with the a2r reference scenario (no climate change), for Hadley and CSIRO climates

2000 2010 2020 2030 2040 2050 2060 2070 2080(a) Hadley climate change

World 0 36 76 113 154 196 264 335 409MDC 0 15 32 45 59 73 93 113 133LDC 0 21 45 68 95 124 171 222 276NAM 0 1 2 3 4 5 6 7 8 WEU 0 10 20 30 39 48 60 72 84PAO 0 6 11 15 20 25 32 41 49EEU+FSU 0 13 27 40 54 68 92 117 143AFR 0 8 18 28 41 55 79 105 132LAM 0 1 2 3 4 5 6 7 8MEA 0 7 14 22 29 37 45 53 61CPA 0 4 7 10 12 15 19 24 28SAS 0 1 1 2 2 3 4 5 7PAS 0 6 11 15 20 25 32 41 49

(b) CSIRO climate change

World 0 42 89 125 164 203 264 328 295MDC 0 12 25 33 42 50 68 87 107LDC 0 30 64 92 122 153 196 241 288NAM 0 7 15 18 22 25 33 40 48WEU 0 2 3 5 8 10 13 16 19PAO 0 0 0 1 1 1 2 4 5EEU+FSU 0 4 8 12 15 18 27 36 46

Page 101

AFR 0 1 2 3 4 6 10 14 19LAM 0 2 5 8 11 14 18 22 27MEA 0 3 6 10 14 19 25 32 39CPA 0 18 38 49 60 71 88 105 122SAS 0 6 12 20 29 38 47 56 65PAS 0 0 -1 -1 0 0 1 1 1

Table 34: Projected changes in renewable internal water resources (WRI) under climate change scenarios A2r and B2 in 2080 compared with the A2r reference scenario (no climate change)

Hadley CSIRO

A2r B2 A2r B2World -10.8 -6.0 1.5 2.0MDC -2.3 -0.1 0.0 0.9LDC -14.8 -8.8 2.2 2.5NAM -3.9 1.0 -4.2 -1.9WEU -19.4 -13.0 -5.2 -1.8PAO -1.7 -4.4 -2.8 -2.2EEU+FSU 7.1 5.7 7.8 6.2AFR -3.6 -3.9 -7.2 -3.4LAM -41.9 -28.2 -2.8 0.0MEA -20.3 -13.3 -14.6 -9.5CPA 13.8 13.6 4.9 3.2SAS 24.8 22.8 18.7 13.2PAS 5.3 6.7 15.7 10.2

4.2.2. Impacts of CC on electricity requirement due to increased call in desalination

The costs of water produced by desalination have dropped considerably over the years as a result of reductions in price of equipment, reductions in power consumption and advances in system design and operating experiences. As the conventional water supply tends to be more expensive due to over-exploitation of aquifers and increasing contaminated water resources, desalted water becomes a viable alternative water source. Desalination costs are competitive with the operation and maintenance costs of long-distance water transport system (Ettouney et al., 2002). As the previous section show, the use of desalination would increase sharply in the next century, independently of climate change. Moreover, climate change would impacts water resources availability and irrigation needs. This would result in an indirect increase call upon desalination for two main reasons. First of all, even if the use of desalinated water for agriculture remains generally too expensive, the development of desalination for municipal purposes would make conventional water available for the increasing crops needs. Moreover, risks posed by climate change reinforce the value of investments in desalinated water over conventional water in the sense of the seawater desalting secures the provision of freshwater by dissociate water availability from long term climate parameters and variability of precipitation.

ReferenceAbou-Hadid A.F., Mougou R., Mokssit A., Iglesias A., 2003, Assessment of Impacts, Adaptation, and Vulnerability to Climate Change in North Africa: Food Production and Water Resources. AIACC AF90 Semi-Annual Progress Report, 37 pp

Page 102

Al-Sahali M., Ettouney H., 2007, Developments in thermal desalination processes: Design, energy, and costing aspects, Desalination, 214, pp.227-240

Busch M., Mickols B, 2004, Economics of desalination – reducing costs by lowering energy use, Water & Wastewater International, 19(4)

De Silua C.S., Weatherhead E.K., Knox J.W., Rodriguez-Diaz J.A., 2007, Predicting the impacts of climate change—A case study of paddy irrigation water requirements in Sri Lanka,

Agricultural water Management, 93(1-2), p. 19-29

Döll P., 2002, Impact of climate change and variability on irrigation requirements: a global perspective, Climatic Change, 54, p. 269–293.

Döll P., Siebert S., 1999, A digital map of irrigated areas, Kassel World Water Series – Report No 1, Center for Environmental Systems Research, University of Kassel, 45 p.

EPRI, 2002, Water and sustainability: U.S. electricity consumption for water supply and treatment – The next half century (Volume 4), EPRI Topical Report 1006787, 93 p.

Ettouney H. M., 2002, Evaluating the economics of desalination, Chem. Eng. Prog., p. 32

FAO, 2003, Desalination of brackish waters and seawater, status in California and the USA, by K. Tanji, Draft report. Rome.

Fischer G., Tubiello F.N., van Velthuizen H., Wiberg D., 2006, Climate change impacts on irrigation water requirements: global and regional effects of mitigation, 1990–2080, Technological Forecasting Social Change, 74, pp. 1083-1107

Gleick P.H., 2000, The World’s Water 2000-2001, the biennial report on freshwater resources, Island Press, Washington, D.C., USA

Goossens X., Bonnet J.F., 2001, Etude de la matrice des interactions eau-énergie, Commissariat Général du Plan, 36 p.

Goosens X., Bonnet J.F., 2003, Analyse des implications énergétiques de l’irrigation, Actes du Séminaire CIID, septembre 2003, Montpellier, France, 32 p.

GWI (Global Water Intelligence). 2006, Desalination Markets 2007: A Global Forecast, Oxford, UK: Media Analyics Ltd

Hoffman A.R., 2004, The connection: Water and Energy Security

IDA, 2000, The ABCs of desalting, Second Edition, International Desalination Association, 32 p.

Martinez Beltran J., Koo-Oshima S., Steduto P., 2006, Introductory paper: Desalination of saline waters, In: Martinez Beltran J. and Koo-Oshima S., Water desalination for agricultural application, Proceedings of the FAO Expert Consultation on Water Desalination for Agricultural Applications, 26-27 April 2004, Rome, FAO Land and Water Discussion Paper 5, pp. 5-10

Mesa A.A., Gomez C.M., Azpitarte R.U., 1996, Energy saving and desalination of water, Desalination, 108, pp. 43-50

Miller J. E., 2003, Review of Water Resources and Desalination Technologies, Sandia National Laboratories, 49 pp.

Reilly J., et al, 2003, U.S. agriculture and climate change: new results, Climatic Change, 57, p. 43–69.

Semiat R, 2000, Desalination: present and future, Water International, 25(1), pp. 54–65.

Shah T., Scott C., Kishore A., Sharma A., 2003, Energy-irrigation nexus in South Asia - Improving groundwater conservation and power sector viability, Research Report 70, International Water Management Institute, 38 p.

SNL, 2006, Energy demands on water resources, Report to the Congress on the interdependency of energy and water, U.S. Department of Energy, 80 p.

Tao F., Yokozawa M., Hayashi Y., Lin E., 2003, Changes in agricultural water demands and soil moisture in China over the last half-century and their effects on agricultural production. Agri. Forest Meteorol., 118, p. 251–261.

Thivet G., 2008, Eau/Energie, Energie/Eau et changement climatique en Méditerranée, In: Plan Bleu, Changement climatique et Energie en Méditerranée, p. 530-552

Thomson A.M., Rosenberg N.J., Izaurralde R.C., Brown R.A., 2005, Climate change impacts for the conterminous USA: an integrated assessment Part 5. Irrigated agriculture and national grain crop production, Climatic Change, 69, p. 89-105.

Wangnick K., 2000, A global overview of water desalination technology and the perspectives

Wangnick/GWI, 2005, 2004 Worldwide Desalting Plants Inventory, Global Water Intelligence. Oxford, England

Water Corporation, 2000, Desalination-Creating New Water Sources, Water Corporation, Leederville, Australia

Zhou Y., Tol R.S.J., 2004, Evaluating the costs of desalination and water transport, Working paper FNU-41, 16 p.

Page 103

Page 104