[N1] Coverage of Report and General Notes

Most figures of global capacity, growth, and investment are not exact, but rather approximate to two significant digits at most (i.e., 630 but not 632; 1,300 but not 1,350, etc.). Sometimes only one-and-half significant digits may apply; for example, a number could be given as 15 rather than 10 or 20, but 17 would be too precise based on the data available and assumptions made.

This report generally covers those technologies with high technology maturity and either high or low levels of market maturity. These categories follow an analysis by Navigant Consulting, which groups renewable power generation technologies into three categories: 1.High technology maturity and high market maturity: small hydro, biomass direct combustion, landfill gas, geothermal, and on-shore wind (just emerging into high market maturity); 2.High technology maturity but low market maturity: biomass co-firing, crystalline silicon PV, waste-to-energy (combustion), anaerobic digester biogas, parabolic trough solar thermal power (just emerging into high technology maturity), and offshore wind (just emerging into high technology maturity); 3. Low technology maturity and low market maturity (technologies to watch): tidal barrage, thin-film PV, concentrating PV, biomass integrated gasification combined-cycle (BIG/GT), dish stirling, wave power, solar thermal power tower, biomass pyrolysis, tidal current OTEC, and nano solar cells.

This report does not cover policies and activities related to technology transfer, capacity building, carbon finance, and CDM projects. Hopefully subsequent editions, if published, could cover these topics.

For a general treatment of market, policies, and barriers to renewable energy, see IEA 2004b; EREC 2004; Beck & Martinot 2004; Komar 2004; Fulton et al. 2004; UNDP et al. 2000; Goldemberg & Johansson 2004; Johansson & Turkenburg 2004; Sawin & Flavin 2004; and Sawin 2004.


[N2] Primary Energy from Renewable Energy

Table N2 shows the relative energy contributions from new renewables, large hydro, and traditional rural biomass. The primary energy attributed to electricity supply is adjusted to reflect fossil fuel energy required to produce an equivalent about of electricity. This type of adjustment is made in some but not all published global energy statistics. The best example is BP’s annual Statistical Review of World Energy. In BP statistics, "the primary energy value of hydroelectricity generation has been derived by calculating the equivalent amount of fossil fuel required to generate the same volume of electricity in a thermal power station, assuming a conversion efficiency of 38% (the average for OECD thermal power generation)" (BP 2005). BP gives hydropower as 634 Mtoe in 2004, or 6.2% of global primary commercial energy. Other statistics not using this methodology will give hydropower as 2.4% of global primary commercial energy, so there will be significant discrepancies between numbers here and some other published numbers. In addition, this correction makes total primary energy higher, with BP’s number of 10,224 Mtoe commercial primary energy in 2004 higher than some other published figures.

Traditional biomass was given as 1,035 Mtoe for 1999 from World Resources 2002-2004, Table 8 (UNDP et al. 2002). Assuming 2% growth per year in traditional biomass use gives 1,140 Mtoe for 2004. This reflects population growth minus fuel switching minus more efficient use of resources. There are no definitive sources of information on traditional biomass use, and a fairly wide range of estimates can be found, reflecting the plausible range of assumptions, methodologies, and data quality. Traditional biomass fuels are commonly estimated in the literature at 9-10% of global primary energy (see Goldemberg & Johansson 2004; Kartha et al. 2004). The typical range in the literature for traditional biomass is 28-48 EJ. The WRI estimate of 1,035 Mtoe for 1999 is 43 EJ, which is at the higher end of the range. Goldemberg & Johansson 2004 give 950 Mtoe for 2001 (Figure 5), which is 40 EJ. Applying 2% growth from 2001 to 2004 would give 1,010 Mtoe in 2004, which is the figure assumed for purposes of this report. There is no consensus on how fast traditional biomass use is growing. Traditional biomass users should grow at the rate of growth of rural populations in developing countries, except for those countries where adoption of modern fuels in rural areas is becoming more widespread. Growth of biomass fuel use will be related, but not the same.

So total world primary energy in 2004 was 10,224 Mtoe (commercial) + 1,010 Mtoe (traditional) = 11,234 Mtoe. Renewables share of 1,876 Mtoe is 16.7%. (1 Mtoe = 41.9 PJ).

Electricity production from renewables in Table N2 is calculated from capacity figures in Table N2 by scaling energy production figures provided in Table 4 of Johansson & Turkenburg 2004, which gives 2001 figures of 2600 TWh large hydro from 690 GW, 43 TWh wind from 23 GWe, 170 TWh biomass electricity from 40 GWe, 730 TWh biomass heat from 210 GWth, 53 TWh geothermal from 8 GW, 55 TWh geothermal heat from 16 GWth, 57 TWh solar hot water from 95 million m2, 450 PJ ethanol from 19 billion liters/year, and 45 PJ from 1.2 billion liters/year. Thus, average capacity factors in 2004 are assumed similar to those implied by Johansson & Turkenburg for 2001.

Energy content of avoided fossil fuels for Table N2 assumes global average power generation efficiency from fossil fuels of 36% (BP’s Statistical Review of World Energy uses 38% as the average for OECD thermal power generation in their primary energy conversion, but developing countries will be less). Energy content of avoided fossil fuels assumed to be parity for biofuels and hot water/heating.

BP (2005) shows 17,450 TWh of electricity produced worldwide in 2004. Large hydro, at 2,800 TWh, is 16.0%. Renewables, at 540 TWh, are 3.1%. World electricity production in 1994 was 12,850 TWh and large hydro was 2,380 TWh, so the share of large hydro in 1994 was 18.5%.

IAEA (2005) gives electricity production from nuclear power at 2,619 TWh in 2004. The estimated 550 TWh from renewables (excluding large hydro) in 2004 (see Table N2) is 21% of this figure.

Table N2.

[N3] Added and Existing Capacities and Growth Rates

Table N3 presents installed capacities, added capacities, and growth rates of renewable energy. Growth rates are author’s estimates based on compilations of global installed capacity figures for all renewable technologies from 1995 to 2004. According to compiled figures, grid-connected solar PV grew from 190 MW in 1999 to 1,760 MW in 2004, and 630 MW were added in 2004 (adapted from Maycock 2003, 2004, 2005a). Off-grid solar grew from 990 MW to 2,200 MW (same). Wind power grew from 13.5 GW to 48 GW (GWEC 2005 and BTM Consult 2005). Ethanol grew from 18.8 billion liters to 31 billion liters (author’s spreadsheet based on Lichts 2005 and other data). Biodiesel grew from 0.7 billion liters/year to 2.3 billion liters/year (same). Geothermal power grew from 8.0 GW in 2000 to 8.9 GW in 2005 (Lund 2005a). Geothermal heat grew from 15.2 GWth in 2000 to 27.8 GWth in 2005 (same). The average growth rate for the five-year period 2000-2004 is calculated as the average compound rate for each of the five years, using end-1999 data and end-2004 data. The table is compiled from author’s database of country-by-country capacities and installations by year, including data from individual country statistics and submissions from report contributors, also AWEA 2005 ; EWEA 2005a; GWEC 2005; EREC 2004; Maycock 2004 and 2005a; Fulton 2004 plus updates; Lichts 2005; Weiss et al. 2005; ESTIF 2005; Johansson & Turkenburg 2004; Martinot et al. 2002 plus updates; Martinot 2004a; Karekezi et al. 2004; IEA 2004a; IEA 2004c; Graham 2001; TERI 2001; D’Sa & Murthy 2004; Goldemberg and Johansson 2004; World Geothermal Council 2005; and Lund 2005a and 2005b.

Table N3.
Notes:
(a) PV existing capacity is based on cumulative production since 1990, neglecting retirements.
(b) Number of homes for solar hot water collectors estimated based on 2.5 m2/home average for developing countries and 4 m2/home for developed countries, neglecting commercial use. Li (2002) suggests closer to 2 m2 in China, the largest market, so the actual number of homes is probably higher than the figures in the table.
(c) Total number of biomass cooking stoves is estimated based on assuming 4.4 persons per household and 2.4 billion people still using traditional biomass. Improved biomass cooking stoves based on Martinot et al. 2002 with updates from Karekezi et al. 2004, IEA 2002a, Graham 2001, TERI 2001, and D’Sa & Murthy 2004, but still reflect figures that are at least a few years old.
(d) Biomass power-generation capacity figures do not include electricity from municipal solid waste (MSW). Many sources include MSW in biomass figures, although there is no universally accepted definition. If MSW were to be included in the numbers in this table, biomass power generation might increase from 36 GW to 43-45 GW. OECD power generation from MSW was 6.7 GW in 2002 (IEA 2005a). Developing country numbers for MSW are difficult to estimate.
(e) Growth rates for biomass heating and large hydro are taken from Johansson & Turkenburg 2004 and reflect growth rates for the period 1997-2001. More recent worldwide growth rates are not available. The average annual capacity increase for all hydro in OECD countries was 1.2% from 1990-2002 (IEA 2004a).
(f) Geothermal heat figures include shallow geothermal energy and geothermal heat pumps.
(g) "---" means data not available or not reliable enough to state.
(h) Total installation of solar PV in 2004 was reported by Maycock (2005b) as 960 MW compared to total solar PV production of 1,100 MW.
(i) The "hot water/heating" category includes solar hot water, solar space heating, and solar cooling in residential, commercial, and industrial applications. The number of homes shown in the table assumes that a high proportion of installed capacity is for residential solar hot water systems. Active solar space heating is provided by a significant share of installations in some countries, although not in China, which is now two-thirds of the global market. Technically, this category is called "Solar Heating and Cooling" by the International Energy Agency, but this report uses the terminology "solar hot water/heating."
(j) Geothermal power capacity has grown by an average of 2.4% from 2000-2004. Geothermal heating capacity has grown by an average of 12.9% from 2000-2004 (World Geothermal Council 2005 and Lund 2005a.
(k) Solar hot water household estimation: 2.4 m2/system in China (70% of systems sold are small 2 m2 size) and 3.8 m2/system in rest of world. So 13.5 million in China equals 5.6 million homes, and 3.5 millon m2 elsewhere equals 0.9 million homes. 64 million m2 in China equals 26.7 million homes, and 46 million m2 elsewhere equals 12.1 million homes.
(l) SHW growth rate for 2004 is net, based on annual additions minus retirements.
(m) Solar PV for off-grid includes residential, commercial, signal, and communications, and consumer products. In 2004 globally, there were 70 MW used for consumer products, 80 MW used for signal and communications, and 180 MW used for residential and commercial off-grid applications (Maycock 2005a).
(n) Where 2004 data are not available, 2004 numbers are determined based on assumed growth rates from year(s) of last reported data and considering differing or conflicting data from multiple sources.
(o) Solar PV is separated into grid-connected and off-grid to reflect the different market characteristics of each application, such as costs relative to competing alternatives and types of policy support.
(p) Lund (2005) reports 1.7 million geothermal heat pumps with 56% of total geothermal heat capacity (27,600 GWth). But he notes the data are incomplete. Geothermal heat pumps grew by 24% per year from 2000-2005, a tripling of capacity in five years.


[N4] Electric Power Capacities

Table N4 presents installed electric power capacities. The table is based on author’s database compiled from individual country statistics and submissions from report contributors, also IEA 2003a, 2004b; IEA 2004c; EREC 2004; AWEA 2005; EWEA 2005; GWEC 2005; Maycock 2004 and 2005a; Johansson & Turkenburg 2004; Martinot et al. 2002 plus updates; Martinot 2004a. Many figures in the table are approximate, valid at best to two significant figures. These sources also provide information for much of the capacity discussion of Section 1.

Small hydro totals reflect reported small hydro, generally according to a definition of 10 MW, but higher in some countries such as China, which officially defines small hydro as less than 50 MW.

Municipal solid waste is commonly reported in biomass power generation statistics for OECD countries. However, municipal solid waste is not included in the biomass power generation capacity figures here because equivalent statistics from developing countries are not available and because municipal solid waste is not considered a form of renewable energy by some. There was 6.7 GW of municipal solid waste in OECD countries in 2002 (IEA 2004a), so including this figure increases world total biomass power capacity to 46 GW.

Table N4.
Notes:
(a) There is no international consensus on the definition of small hydropower (SHP). In China, it officially refers to capacities of up to 50 MW, in India up to 15 MW, and in Brazil up to 30 MW. In Europe, capacity of up to 10 MW total is becoming generally accepted by ESHA (European Small Hydropower Association) and the European Commission. Many published figures for small hydropower apply a definition of 10 MW maximum, which tends to exclude capacity from China, Brazil, and some other countries. Thus other published figures can be substantially smaller than the figures presented here, which represent data according to each country’s definition.
(b) Grid- connected solar PV exists in small quantities of a few MW in some other countries, primarily as small demonstration projects. Zero is given in the table because these numbers are much smaller than 0.1 GW, thus not significant enough to register.
(c) Comparison of "new" renewable power capacity to total electric power capacity does not provide a good comparison of actual energy produced. Capacity factors for conventional electric power generation are much higher than for most "new" renewable energy sources. So even though global "new" renewable capacity is roughly 4% of the world total capacity, electricity produced from renewables is about 2% of world total electricity production.
(d) These figures should not be compared with previous versions of this table or similar tables to get growth rates. Adjustments from previous versions are a combination of real growth plus adjustment due to improved data.


[N5] Large Hydropower Capacity and Growth Rate

IEA (2004c) shows OECD hydro was 393.8 GW in 1999 and increased to 407.9 GW in 2002, for a 1.2% annual growth rate for the three-year period 2000- 2002, or an average of 4.7 GW per year. China’s large hydro capacity has been increasing by 6-8 GW per year in recent years. (China installed 7.6 GW of large hydro capacity in 2004, according to Water Conservation Information Network (www.hwcc.gov.cn). China’s total hydro capacity went from 53 GW in 1999 to 105 GW in 2004, with 14 GW of the increase being small hydro. So large hydro increased by 38 GW, or 7.5 GW per year average during the five-year period 2000-2004.) Other developing countries probably represent another 3-5 GW per year, for total capacity additions of probably 14-16 GW per year. Thus, given the current installed large hydro capacity of 760 GW, the global average growth rate is on the order of 2%.

US EIA International Energy Annual 2003 (EIA 2005a) gives world total of 15,852 TWh of electric power generation in 2003, including 2,654 TWh from all hydro. Allowing for 3% annual growth in 2004 (2% for hydro) results in 16,328 TWh total and 2,707 TWh for all hydro in 2004. Subtracting 160 TWh of small hydro from this (assuming a third of small hydro doesn’t appear in global statistics), gives 2,540 TWh large hydro in 2004. EIA gives 2,461 TWh hydro in 1995 and 12,634 GWh total generation. Total hydro is thus 16.6% of global total for 2004 and 19.5% in 1995. Subtracting small hydro, large hydro alone is roughly 16% in 2004 and 19% in 1995.

Altinbilek et al. 2004 gives 730 GW and 2,650 GWh of hydro worldwide based on a 2003 source, so this number is presumed to be 2002 data. This is consistent with an IEA (2004b) figure of 2,676 TWh of hydro in 2002. Given the other sources, this number appears correct for large hydro, excluding all (or most) of small hydro. Allowing a 2% growth rate in 2003 and 2004 gives 760 GW in 2004.

Hydropower production statistics for 2004 from BP (2005).

There is a basic conflict between hydro statistics reported by the International Hydropower Association and World Energy Council, and those from the International Energy Agency. IHA and WEC statistics suggest total hydro worldwide was around 750 GW in 2004. The IEA shows hydro in OECD at 425 GW in 2002, which when added to reported small and large hydro in developing countries from several sources yields a total in the range of 800-820 GW allowing for modest growth since 2000 (most other data are for 1999-2000). It is believed that the former set of statistics misses some installed capacity due to reporting channels used. This report places more credibility in the later set of figures, with a total of 800 GW hydro, 740 GW large hydro, and 60 GW small hydro.


[N6] Wind, Geothermal, Biomass Power

Table N6 shows added and existing wind power. There is some variation of statistics depending on source, with data from the Global Wind Energy Council (2005) and BTM Consult (Cameron 2005) differing by about 200 MW world total added in 2004 and also in cumulative existing capacity (EWEA cites GWEC data of 47,317 MW total installed at end of 2004). Other sources include the AWEA (2005) and EWEA (2005a).

Offshore wind power 0.6 GW installed comes from New Energy Finance, www.newenergyfinance.com, as reported in RenewableEnergyAccess.com, "Blustery Conditions for European Wind Power New Energy Finance White Paper Outlines Difficulties in European Wind Power Market," 22 July 2005. www.newenergyfinance.com/NEF/HTML/Press/
Offshore-wind-funding.pdf and www.renewableenergyaccess.com/rea/news/
story?id=34645. (Note: China is also beginning to develop off-shore wind, with plans for the first wind farm off- shore of Shanghai in 2006.)

Information on biomass power and heat from IEA (2004b), Kartha et al. (2004), and submissions from report contributors. Also IEA 2005c.

Information on geothermal power and heat from Lund (2005a and 2005b). Information on biomass power generation is the most difficult to develop and generally relies on more informal data collection from in-country sources. In reporting on geothermal heating, Lund notes: "the world direct utilization of geothermal energy is difficult to determine; as, there are many diverse uses of the energy and these are sometimes small and located in remote areas. Finding someone, or even a group of people in a country who are knowledgeable on all the direct uses is difficult. In addition, even if the use can be determined, the flow rates and temperatures are usually not known or reported; thus, the capacity and energy use can only be estimated. This is especially true

of geothermal waters used for swimming pools, bathing and balneology."

Some of the biomass used for power generation around the world is urban and industrial residues, what the IEA calls "combustible renewables and waste." Urban residues, landfill gas (LFG), and digester gas from municipal water treatment and concentrated animal feeding operations (CAFOs) are currently very important and are becoming more so—they provide environmental services as well as generate energy. (This report excludes MSW from the biomass power generation statistics given, as comparable statistics for developing countries are not available and some contributors felt MSW belongs in a separate category and should not be mixed with "pure" biomass.)

Table N6.


[N7] Grid-Connected Solar PV

Table N7 shows grid-connected solar PV from the largest programs worldwide, which make up most of the global grid-connected solar PV. Sources: Maycock 2004 and 2005a; Jones 2005; Dobelmann 2003; California Energy Commission 2004; Navigant Consulting 2005; submissions from report contributors.

EU-15 grid- connected capacity was 316 MWp in 2002, including 258 MWp in Germany (EREC 2004). Thus, about 60 MWp existed in the EU outside of Germany in 2002. Czech Republic has 120 kWp grid-connected, Poland 47 kWp, and Romania 10 kWp (EREC 2004).

Table N7.
Notes:
(a) California reports total number of installations, which includes both residential and commercial, but the number of residential installations is assumed to be much higher than the number of commercial installations. The number of homes reported is consistent with an average of 4 kW/home and residential being more than half of total installed capacity in 2004.
(b) Assumption of 4 kW/home for new 2004 installations in Japan and Germany. Cumulative homes for 2003 estimated at 170,000 in Japan and 65,000 in Germany based on prior reports of homes and capacity.
(c) On-grid solar PV capacity in Europe was 480 MWp in 2003, of which 375 MW was in Germany. The Netherlands was the major contributor, with 44 MW in 2003. So additional on-grid capacity in Europe in 2004, besides Germany, was probably about 110 MW.
(d) Korea in 2005 announced a 100,000 rooftop program targeting 0.3 GW of solar PV by 2011.
(e) Thailand has had a small rooftop solar PV program. As of July 2004, 67 kWp were installed, subsidized by EPPO.
(f) Japan’s program was due to end in 2005. In 2004, Japan had 1,100 MWp of installed PV, 800 MWp for homes and 300 MWp for commercial and public buildings and other uses (not clear what fraction is grid-connected).


[N8] Solar Hot Water/Heating

Table N8a.
Note: This table excludes Barbados and other small island nations with population less than 500,000. Barbados has 277,000 inhabitants and at least 35,000 SWH systems. The indicator would be around 250 m2/1,000 inhabitants and this means Barbados would rank 5 of the top 10.
Source: Weiss et al. 2005; Li 2002 and 2005; ESTIF 2004 and 2005; Martinot 2004a; Karekezi & Kithyoma 2005; submissions from report contributors.

Table N8b.
Notes:
(a) Figures exclude passive (swimming pool) heating, which is considered a separate application from domestic hot water and space heating.
(b) Retirements are difficult to estimate for some countries, so all figures are approximate. The totals here reflect 2 million m2 of retirements in 2004, not including China.
(c) The International Energy Agency's Solar Heating and Cooling Program (IEA-SHC) recommended in December 2004 that SHW be reported in GWth (gigawatt thermies), with a standard conversion factor of 0.7 GWth per million m2.
(d) Additions for 2004 and existing 2004 for Turkey, Israel, United States, Australia, India, and Egypt are extrapolations based on actual 2003 installations. A 5% retirement rate of existing stock is assumed in the extrapolation. The resulting global total checks against estimates of 2004 by Weiss et al. 2005.
(e) Modeling retirements in Japan is a complicating factor in both Japanese and global totals, as retirements have been high relative to new installations for the past several years. Weiss et al. 2005 have a total about 4.5 million m2 higher than the figure used here for Japan in 2003, but the lower number used here is based on another model of retirements by Japanese researchers consulted for this report (also see the reference: Solar System Development Association website, www.ssda.or.jp/index.php). The global total of 110 million m2 (77 GWth) would be 115 million m2 (80 GWth) using the higher number for Japan.
(f) About 1.5 million is estimated to be installed in Africa, primarily in South Africa, Egypt, and Niger (Karekezi & Kithyoma 2005).
(g) Solar hot water numbers in a given year must account for both additions and retirements. Retirements are modelled and estimated by various organizations in different ways, and so figures are not always compatible, particularly for countries with long-standing markets in which many systems are now reaching the end of their service life. In particular, there is a large discrepancy as to how to account for retirements in Japan, leading to a large divergence between figures published by the IEA (Weiss et al. 2005), which give 12.4 million m2 in 2004, and those provided by other Japanese sources, which give 7.7 million m2 in 2004. The lower figure is used in this report.
Sources: Weiss et al. 2005; Li 2002 and 2005; ESTIF 2004 and 2005; Martinot 2004a; EurObserv’ER 2005b; Karekezi & Kithyoma 2005; submissions from report contributors.

The solar thermal industry in Europe will install 1.2 GWth of capacity during 2005 according to the latest statistics from the European Solar Thermal Industry Federation. See story at ReFocus, at www.sparksdata.co.uk/refocus/fp_showdoc.asp
?docid=
83735293&accnum=1&topics=


[N9] Ethanol and Biodiesel

Table N9.
Notes:
(a) Ethanol figures do not include production of ETBE in Europe, which was about 0.7 billion liters in 2004.
(b) Finland plans to build a biodiesel production plant of 170,000 tons/year capacity by 2007, which would put it in fourth place in Europe behind Germany, France, and Italy.
(c) Fulton et al. 2004 gives Germany 2002 biodiesel capacity as 750,000 liters/year and sales as 550,000 liters/year. Production was 550,000 tons in 2002; 720,000 tons in 2003; and 1 million tons in 2004 from EurObserv’ER 2005a.
(e) Germany added 0.3 billion liters/year biodiesel production capacity in 2004, and 0.1 billion l/yr for ethanol.
(f) Ethanol in the United States, 2005 figures, from presentation by Brian Jennings, Executive Vice President, American Coalition for Ethanol (Jennings 2005). Jennings gives 3.4 billion gallons produced in 2004, or 13 billion liters. Also same from the Renewable Fuels Association ( www.ethanolrfa.org/pr050223.html), an increase of 21 percent from 2.8 billion gallons (10.6 billion liters) in 2003.
Sources: Adapted from Fulton et al. 2004; Lichts 2005; EurObserv’ER 2005a; US Renewables Fuels Association (www.ethanolrfa.org); IEA 2004d; and submissions by report contributors.

Australia Ethanol Limited gives 70 million liters/year produced in Australia (presumed current), and Fulton et al. (2004) gives 40 million in 2002.

In Spain, there are currently two ethanol production facilities, one in Cartagena, with capacity of 100 million liters, and the other in Teixeiro, with capacity of 126 million liters (IEA 2005c)

Other countries in Europe have also decided to go into biodiesel production. Spain started up its biggest biodiesel production unit (250,000 tons) last May in the region of Cartagena. The company, called Biodiesel Production, is part of the German group Sauter and has invested 50 million euros in this project. A first 100-ton biodiesel production unit will also be put into service in Portugal next August. The Ibersol company, a subsidiary of the German food group Nutas, is responsible for this 25 million euro investment. Other units are also under construction or in project stage in the United Kingdom and Finland.

In Canada, there are currently more than 1,000 retail locations selling ethanol-blended gasoline in six provinces. Approximately 7 percent of gasoline sold in Canada is currently blended with ethanol. Ethanol production is expected to grow to 1.4 billion liters to meet the Government of Canada's target of 35 percent of Canadian gasoline containing 10 percent ethanol by 2010. This target means that ethanol production will have to increase from production of 200 million liters per year (2004) to 1.4 billion liters per year. To reach that target the federal government, through Natural Resources Canada, has implemented an Ethanol Expansion Program (EEP) that provides funding for construction of new ethanol plants or plant expansions. Under the first round of EEP CDN, $72 million in contributions has been allocated to six projects across Canada, and in the second round an additional CDN$46 million have recently been allocated. In addition to EEP the federal government provides an exemption on its gasoline excise tax of $0.10 per liter of ethanol. At the provincial level, Manitoba provides the greatest exemption of the provinces at $0.25 per liter of ethanol produced and consumed in the province, British Columbia $0.11 /liter (when a plant is built in BC), Alberta $0.09 /liter (no restriction on ethanol source), Saskatchewan $0.15 /liter (ethanol must be produced/consumed in SK), Manitoba $0.25 /liter (ethanol must be produced/consumed in MB), Ontario $0.147 /liter (no restriction on ethanol source), Quebec $0.198 /liter (when plant is built in QC). (www.nrcan- rncan.gc.ca/media/newsreleases/
2005/200550a_e.htm and other sources).

This report generally compares ethanol and gasoline based on equivalent energy content rather than volumetric equivalents. It may be that some of the comparisons mistakenly are based on volumetric equivalents, since source material sometimes isn’t clear. The energy content of ethanol is only 70% or so of gasoline on a volumetric basis.

Liquid fuels from biomass have major impacts on land use, farm policy (which in turn bears indirectly on the poor agricultural countries in the developing world), and food pricing. Corn farmers in the U.S. appreciate the fact that in 2003 the substitution of 1.5% of gasoline on an energy basis consumed 14% of the corn crop. In 2005, due to demand for ethanol there was a savage spike in sugar prices. In Brazil, ethanol production fluctuates with sugar prices; when sugar prices are low more ethanol is produced, and when high less ethanol is produced. Fulton et al. (2004) covers the food and land issues.


[N10] Ethanol in Brazil

Total ethanol consumption by cars in Brazil was 12.5 billion liters in 2004, 5.22 as hydrated, used in neat ethanol and flex-fuel cars, and 7.22 as anhydrous, blended to gasoline. Total gasoline for road use (essentially cars, since almost no truck uses gasoline) in 2004 was 15.8 billion liters. Thus, on a volume basis, gasoline represents 15.8 billion liters in a total volume of 28.3 billions liters of liquid fuels for cars. Ethanol share is 44.2%. Production of ethanol in 2004 was 16.0 billion liters , which surpasses gasoline production of 15.8 billion liters. From the 16.0 billion, 2.52 billion was exported and 1.02 billion used for other purpose than fuel. For the year 2005 it is expected there will be an increase in ethanol consumption and a decline in gasoline, but even so gasoline will be responsible for more than 50%.


[N11] Renewable Energy Cost Comparisons

Three sources of recent information are the IEA reports Renewables for Power Generation (IEA 2003a), Renewable Energy Market and Policy Trends in IEA Countries (IEA 2004b), and Biofuels for Transport (IEA 2004d).

Sources for Table 2 include: IEA 2003a; IEA 2004b; OECD and IEA 2005; ICCEPT 2002; Fulton et al. 2004; Johansson & Turkenburg 2004; and submissions from report contributors.

Ethanol from cellulose shows great promise for future cost-competitiveness. Canada and Sweden are leading research and demonstration. Canada has helped to fund construction of the first commercial-scale cellulosic ethanol production plant, which converts wheat straw into ethanol using an advanced enzymatic hydrolysis process. Such plants may eventually become common, and will allow ethanol to be produced from almost any type of biomass, including agricultural and forestry wastes and high-yielding dedicated energy crops such as poplar trees and switchgrass. The province of Ontario plans to provide additional recognition for ethanol produced from cellulosic feedstocks (e.g., wood, straw) in its proposed ethanol regulation.

Technology cost estimates and projections for renewable power generation technologies, made by the International Energy Agency and Imperial College of London, are shown in Tables N11a and N11b. Compared to the costs of historical coal and natural gas generation costs (typically 2-4 cents/kWh, although recent natural gas price rises are increasing costs in some countries), hydro, geothermal, and some forms of biomass power generation are already competitive with good resources and sites. Wind power costs are approaching competitive levels, and are expected to achieve those levels sometime by 2010. Solar PV costs are still substantially higher, although compared to retail residential electricity rates in some countries with substantially above-average rates (i.e., 20-30 cents/kWh), the costs of solar PV should likewise become competitive before 2010, particularly in sunny (high insolation) climates.

Geothermal costs for Table 2 are those for new plants at new sites. Costs will vary higher and lower depending on whether they are for currently operating plants, expansion plants on existing fields, or new plants at new sites.

Table 2 states that wind-generated electricity fell from about 46 cents/kWh in 1980 (in the U.S.; 2003$) to 4-5 cents/kWh at good sites today. DOE document DOE/GO-102005-2115, April 2005, p. 4 says "…dramatic reductions in cost – from $.0.80 (current dollars) per kWh to about $0.04/kWh for utility-scale turbines…." Also, the statement in Table 2, "how to make the machines bigger is still the number one technological issue in the turbine industry," oversimplifies the technical challenges facing the wind industry.

Table N11a.


[N12] Global Investment in Renewable Energy

Investment figure of $30 billion/year developed from database of installed capacity by technology for the period 1995-2004, as used for Martinot 2004a, along with submissions from report contributors, using global average capacity costs (installed costs, including balance of plant for solar PV). Further details of cost estimates taken from the literature and explanations of cost assumptions used for those papers are available at www.martinot.info/markets.htm.

Typical investment costs for 2004 were estimated as follows:
  SHW in China: $150/m2
  SHW elsewhere: $800/m2
  Wind: $1,200/kW
  Solar PV (installed): $7,000/kW
  Geothermal heat: $500/kWth
  Geothermal power: $1,600/kW
  Biomass heat: $200/kWth
  Biomass power: $2,000/kW
  Small hydro in China: $900/kW
  Small hydro elsewhere: $1,300/kW
  Large hydro in China: $1,400/kW
  Large hydro elsewhere: $2,000/kW


Table N11b.
Wind power costs from previous years might justify a figure than $1,200/kW, but in 2004 wind power costs rose, some said to more typically $1,300/kW, due to higher steel prices from high global demand for steel. Canada reported $1,500/kW in 2004 (according to a private communication with the Canadian Wind Energy Association). Solar PV prices also increased in 2004. Solar PV prices in 2004 in California were reported at $9,000/kWp installed. Canada solar PV prices in 2004 were reported at $8,000/kWp. However, the assumption of $7,000/kWp was left unchanged from 2003.

Solar hot water costs in China for 2002 were reported by Li (2005). Over 70% of solar hot water heaters were sold in 2002 at prices less than 1,500 RMB ($180) and the lowest-cost heaters typically comprise 2 m2 of collector area. This would imply a cost of $90/m2. A further 26% of products are sold between RMB 2,200-3,000 ($270-360), probably implying costs of $100-120/m2. High-end systems, still a small market share, sell for $300/m2. The China SHW industry in 2000 had 6 million m2 production and $750 million revenue, or an average of $125/m2 in revenue. This has probably increased since 2000 as larger and more expensive systems capture more of the market. Another expert source gives 1,000-1,500 RMB/m2 as typical costs, or $120-180/m2. An average cost of $150/m2 is assumed for solar hot water collectors in China, for purposes of calculating global investment figures. This is still much lower than estimated costs in Europe and other developed countries.

Small hydropower costs in China are reported from one Chinese source as 3,000-6,000 RMB/kW, or $370-740/kW. This is significantly lower than small hydro costs elsewhere. But others have questioned such low figures, so $900/kW is used.

Cost data from a variety of sources, including Johansson & Turkenburg 2004, Turkenburg et al. 2000, EC 2002a, IEA 2004b, IEA 2003a, and ICCEPT 2002. EC CORDIS cost data from Section 1.9 on geothermal energy (12/20/02), Section 1.10 on photovoltaics (12/23/02), Section 1.11 on small hydropower (12/20/02), Section 1.12 on solar heating and cooling (12/20/02), Section 1.15 on wind energy (12/23/02) and Section 1.3 on CHP microturbines (12/18/02).

Investment of $4-5 billion for capital expenditures in 2004 by the solar PV industry is estimated by Michael Rogol, MIT, and CLSA Asia-Pacific (personal communication). See also CLSA Asia-Pacific Markets (2004). Some of this investment will not immediately translate into increased production in 2005 due to time required to get some capacity up-and-running (e.g. silicon production capacity takes 18-24 months or longer to reach full production) and due to constraints on silicon availability (e.g. significant portion of Chinese ingot growth capacity is idle). Rogol also estimates the figure will be $5-7 billion for 2005.

Comparisons with global investment in power generation are rough estimates based on 2.5-3% average growth in power generation worldwide and personal communications with experts. Some experts believe the total may be much higher than $150 billion, perhaps closer to $400 billion for the entire power sector, including transmission and distribution and fossil fuel supply chains. Comparisons of renewables power generation investment with global power generation investment exclude transmission and distribution investment and fossil fuel supply chains, which might mean the comparison is too favorable to renewable energy.


[N13] Private Financing and Venture Capital

Venture capital investment from Makower et al. (2005) and Liebreich & Aydinoglu (2005). CLSA Asia-Pacific Markets projections from CLSA Asia-Pacific Markets (2004). An updated version was available in mid-2005.

New Energy Finance, Ltd. (2005) analyzed 201 venture capital investment rounds from 2001 to 2004, covering total estimated investment of $2.2 billion, including about $1.2 billion in efficiency, fuel cells, and hydrogen. Investment increased from $414 million in 2003 to $958 million in 2004, although it is not clear how much of the increase was for renewable energy.


[N14] Public Financing

EIB total financing for renewables was reported by EIB as € 91 million in 2000, € 180 million in 2001, €682 million in 2002, € 414 million in 2003, and €469 million in 2004. The average for 2002-2004 is € 520 million. Converting to USD at an average exchange rate of $1.20 yields $630 million. EIB is a public sector institution in the sense that it is owned by the EU Member States. However, it raises its resources on capital markets. It only has access to "public money"—funds that come from government budgets—in the case of its financing operations under the Cotonou Agreement's Investment Facility in the African, Carribbean and Pacific (ACP) Countries. The Investment Facility resources in fact come from the European Development Fund financed by the EU Member States. Source: personal communication with EIB, 2005.

For information on EIB renewable energy lending between 1999 and 2003, see: www.eib.org/Attachments/thematic/
renewable_energy_en.pdf

All exchange rate conversions done using € 1 = $1.20, the rate as of July 2005, and are thus conversions into current 2005 dollars rather than 2002, 2003, or 2004 dollars.


[N15] Multilateral and Bilateral Financing for Developing Countries

From 1990-2004, the World Bank Group committed $1.8 billion to new renewables, which along with co-financing of $450 million from the Global Environment Facility, resulted in $2.3 billion World Bank/GEF combined financing for new renewables. The World Bank also committed $3.9 billion to large hydro (>10 MW) during this period (World Bank 2005, Table 1). Thus, average World Bank Group financing for new renewables has historically been about $120 million per year (excluding GEF financing). This average has remained in recent years. During the three-year period 2002-2004, the World Bank Group committed an average of $113 million per year to new renewables ($338 million committed to new renewables by IBRD, MIGA, IFC, IDA, and carbon finance in 2002-2004 per Table 3, Annex 2). Associated with those commitments was GEF co-financing averaging $43 million per year during the three-year period 2002-2004. The World Bank Group also committed an average of $166 million per year to large hydro during the three-year period 2002-2004 (no GEF co-financing involved). Thus total World Bank/GEF financing for all renewables during the three-year period 2002-2004 averaged $320 million per year. (Note: "World Bank Group commitment" as used in World Bank 2005 includes allocations by the GEF. This report separates the two agencies and reports on their commitments separately.)

World Bank and GEF projects often include non-renewables components, or are blended with energy efficiency components, making it difficult to analytically separate out the renewable energy finance from other finance. Reported figures by these agencies are subject to such analytical uncertainties, and it is possible that non-renewables finance from a few projects is included in reported renewables totals.

GEF-reported financing figures for renewable energy include fees paid to the GEF implementing agencies. If such fees are excluded, GEF financing would average closer to $90 million per year for the three-year period 2002-2004 rather than $100 million per year. Some discrepancies may exist with other reported figures because this report totals by calendar year, while the GEF totals by fiscal year.

From 1999 to 2002, OECD DAC overseas development assistance averaged about $130 million/year for non-hydro renewables and about $400 million/year for hydro (OECD DAC, cited in Saghir 2005; OECD DAC 2005). Total official development assistance (ODA) for hydro averaged more than $420 million per year during the five-year period 1999-2003. Donor statistics are from OECD DAC (2005) and include all forms of reported donor assistance to developing countries.

Table N15.
Financing amounts based on e-mail queries and interviews with agency officials and a variety of unpublished sources. The $500 million public financing for developing countries only includes public funds from projects—grants, loans, and other financing from governments, international agencies, or other public sources. These are often called "budgetary funds." Figures do not include private financing tied to projects, often called "private financing" or "market funds."

Source for OECD Agreement on Officially Support Export Credits: OECD 2005. Sources for future multilateral commitments: email inquires and interviews with development agency officials; OECD 2005; submissions by report contributors.

In 2004, KfW approved about € 151 million for renewable energy, of which € 81.6 million were "budget funds" and € 69.3 million were "market funds." The budget funds are considered public-source investment and the market funds are considered private-source investment. Source: KfW, personal communication. Use mid-2005 exchange rate of € 1 = $1.20 for conversions into dollar equivalent.


[N15b] Bonn Action Programme in International Context

Source for the content analysis of the Action Programme is Fritsche & Kristensen 2005.

There are no global estimates for CO2 emissions reductions from renewables in the literature, so a rough estimation was made for power generation. Analysis of global CO2 emissions is approximate and does not include rural energy technologies like solar home systems and biogas digesters (which are orders of magnitude lower than the other numbers here).

Power generation avoided CO2 emissions calculated at 0.6 billion tons CO2/year for new renewables, excluding biofuels and heating, and 3.6 billion tons/year for large hydro (based on 720 GW). Assumptions for power generation: (a) Large hydro replaces baseload power, i.e. coal. (b) Small shares of gas-CC are offset by similar shares of lignite. (c) Small hydro is same as large hydro. (d) Wind replaces intermediate load, i.e. 50% from coal and 50% from gas-CC in OECD, and 50% from coal and 50% oil-fired GT in developing countries. (e) Biomass replaces 50% baseload and 50% intermediate load. Same assumptions on mix for all countries. (f) Geothermal replaces 100% baseload. (g) Solar PV replaces 100% peak load from 50% gas-CC and 50% oil-fired GT. (h) Solar-thermal replaces 50% intermediate load and 50% peak load. (i) Ocean tidal replaces 100% baseload. Emissions factors (CO2 eq in g/kWhel): 1,040 for coal in developing countries; 1,050 for coal in OECD; 451 for gas-CC; and 1,141 for oil-GT. Capacity factors: large hydro 68%, small hydro 57%, wind 23%, biomass 51%, geothermal 74%, solar-PV 11%, solar-thermal 23%, and ocean tidal 68%.

Solar hot water was probably around 25-30 million tons avoided CO2/year in 2004. Weiss et al. (2004) give 15 million tons CO2/year from all SHW, excluding unglazed, in 2001, with 70 million m2 installed. Installed increased by 60% by 2004, to 110 million m2. China reported 13 million tons CO2 from solar hot water in 2003, with 52 million m2 installed.

Geothermal heat supply is about two-thirds of solar hot water on a thermal output basis, and thus might be 20 million tons/year. Biomass heating is about 70% more than biomass power generation on an equivalent energy basis, and since much biomass is combined heat and power, the same fossil fuels would be displaced for both. Addition analysis for hot water/heating and gives about 0.2 billion tons CO2/year total.

Biofuels probably add another 100-120 million tons/year. Rossillo-Calle & Cortez (1998) estimated 46 million tons CO2/year avoided from Brazil biomass in 1998-1999, when production was 15 billion liters, about the same as today. The global biofuels market is now more than twice as large as Brazil.


[N16] R&D Spending and Subsidies

The IEA RD&D database for all IEA countries (IEA 2005d) gives $352 million, $364 million, and $356 million for solar RD&D for the years 1999-2001 (using data based on exchange rates rather than PPP). Total of all solar, wind, ocean, biomass, small hydro, and geothermal for these three years is $2,165 million, for an average of $720 million per year. Of this number, about $250 million was accounted for by the United States, and another $130 million by Japan, with the remaining $340 million by European countries. RD&D on large hydro for all IEA countries averaged $10 million per year. All numbers are slightly lower if PPP is used rather than exchange rates. There is a large discrepancy in reported RD&D for the U.S. in 1999 by the IEA, which gives $280 million, and the U.S. Energy Information Administration (1999), which gives $327 million.

Estimates of global subsidies for fossil fuels and nuclear power taken from UNEP & IEA (2002). Also, Johansson and Turkenburg2004 say "at present, subsidies to conventional energy are on the order of $250 billion per year" (p.29). Earthtrack (earthtrack.net) has a comprehensive set of references on subsidy policies and estimates.

Goldberg (2000) gives U.S. federal subsidy estimates for the period 1943-1999 (cumulative) of $5.7 billion (1999 dollars) for wind, solar, and solar thermal power. Another $1.6 billion is estimated for subsidies to hydropower during the same period. One source cited (EIA 1999) gives $1.1 billion subsidies for renewables in 1999 alone, including hydropower. This represents federal on-budget, for direct payments, tax expenditures, and research and development. It includes $725 million for ethanol excise tax exemption, $327 million for R&D, $15 million on income tax exemptions, and $4 million on direct expenditures. Ritschel & Smestad (2003) cite $135 million per year in California public benefit fund support for renewables in the late 1990s. They also quote $9 billion for global subsidies to renewable energy and energy efficiency, compared to $150 billion for fossil fuels and $16 billion for nuclear power, citing van Beers & de Moore (2001). In the United States, public benefit funds in more than a dozen states are spending $300 million per year on renewables (Martinot et al. 2005).

The OECD defines subsidies as: "any measure that keeps prices for consumers below market levels, or for producers above market levels or that reduces costs for consumers and producers." EEA (2004) notes that energy subsidy definitions that refer only to a direct cash payment to an energy producer or consumer ignore a range of other indirect support mechanisms, including tax measures, and the effects of trade restrictions and other government interventions (such as purchase obligations and price controls) on prices received by producers and paid by consumers.

EEA (2004): Off-budget subsidies are typically transfers to energy producers and consumers that do not appear on national accounts as government expenditure. They may include tax exemptions, credits, deferrals, rebates and other forms of preferential tax treatment. They also may include market access restrictions, regulatory support mechanisms, border measures, external costs, preferential planning consent and access to natural resources. Quantifying off-budget subsidies is complex, in some cases impossible. It often requires that the benefit be calculated on the basis of differential treatment between competing fuels, or between the energy sector and other areas of the economy.

EEA (2004): Taxation policy is a key mechanism for off-budget support in energy markets. A fuel may be exempted from certain taxes, or enjoy lower rates of value added tax (VAT) and excise duty in relation to other fuels or to the wider economy. Tax exemptions, rebates and incentives for investments in the energy sector and for the installation of energy related materials and equipment may allow industry and consumers to offset their costs. Accelerated tax depreciation may also be permitted, allowing energy-related equipment to be amortised (have the costs written off) more quickly, thereby lowering effective tax rates in the early years of an investment.

EEA (2004): Regulatory support mechanisms make up the other most significant area of off-budget support for the energy sector. These mechanisms most commonly take the form of price guarantees and demand quotas for specific energy sources. They are introduced to support environmental, economic, employment or energy security policy objectives. Some of these mechanisms, such as feed-in tariffs or competitive tenders can be described as ‘supply push’ mechanisms, in that they stimulate production. Others, such as purchase obligations are ‘demand pull’ mechanisms in that they create an artificial demand to which the market responds. EC (2004) estimated energy subsidies in the EU. It noted that "Various attempts have been made to quantify the type and amount of aid provided to energy industries. There is no comprehensive official record of historical and ongoing energy subsidies in the EU." With various caveats and analytical notes, that report provides indicative estimates of € 0.6 billion in on-budget subsidies and more than € 4.7 billion in off-budget subsidies for renewable energy in 2001.

A Greenpeace-commissioned report in the late 1990s, titled "Energy Subsidies in Europe," cited $1.5 billion in direct subsidies for renewable energy (Greenpeace 1997). Jennings (2005) gives $1.7 billion in ethanol fuel subsidies (excise tax exemptions) in 2004 (roughly 3.4 billion gallons times 51 cents/gallon). One report contributor well versed with energy subsidies thought the subsidy numbers used for this report were too low. Some factors that might cause the numbers to be too low: (1) State and provincial subsidies are quite important with renewables. Sub-national subsidies are most relevant with oil, gas, and certain renewables (through the portfolio standards, but also many direct subsidies to ethanol). (2) As ethanol absorbs a higher percentage of total corn production, it's pro-rated share of corn subsidies rise as well. The ethanol share was 9.7% of corn production in 2003. Between 1995 and 2002, the Environmental Working Group tallied subsidies to corn at $34.6 billion, or $4.33 billion per year. The ethanol share of this in 2003 would have been $420 million, making it the second largest subsidy to the fuel. Pass-through of irrigation subsidies to corn would be additional, but I've not seen it estimated. It's important not to forget about these ancillary subsidies to key feedstocks, be they corn or uranium. (3) Tax-exempt debt used for energy purposes are often ignored in many public accountings of subsidization. Sometimes they pick up tax-exempt private activity bonds, but if the facility is municipally-owned the subsidies are often lumped in with all tax-exempt debt issued by states. Tax-exempt debt is used for WTE plants and landfills (affecting the cost of landfill-gas-to-energy), and perhaps for other projects classed as renewable energy as well. (4) Large scale hydro continues to receive large and varied subsidies associated with the government ownership that they often entail. Low market interest rates tend to reduce the value of some of these subsidies, since historically they had very long term bonds at fixed low interest rates. Such contracts deviate less from market conditions during low interest rate periods. For this reason, dam financing subsidies to hydro may be lower than in the past, though other forms of support still exist. It is not clear if some of the subsidy numbers include large hydro or not.

Global subsidy estimates are highly uncertain. If they are done by aggregating the various existing studies, they generally suffer from large inaccuracies associated with double-counting and non-systematic valuation methods. Often, very large but more complicated value transfers are missing entirely from at least a portion of the studies. This may include incomplete evaluation of tax breaks and loan guarantees; and exclusion of programs of are of large benefit to particular fuels, but not solely targeted to them. Shifting of accident or cleanup liability to the public sector is also commonly missing. If they are generated using price-gap methods for multiple countries (the gap between the domestic price and the world price for a fuel), they will pick up only the portion of subsidies that affect domestic prices, totally missing the support that leaks to other factors of production. It is possible that many of these problems underlie what seems a low global value for nuclear subsidies of $16 billion per year. That is roughly what some estimated in the U.S. alone during the early 1990s, and accident liability caps outside of the U.S. are even more generous to producers than Price-Anderson is inside. Thus, the real value of nuclear subsidies is most likely much higher. Investment incentives, sovereign guarantees or guaranteed purchase contracts, accident liability caps, public responsibility for waste management, losses on uranium enrichment, and support for uranium mining are all common subsidies to the sector. Most likely many of these are missing from the $16 billion figure. It's also useful to be clear about separating fusion and fission subsidies, as the former is pretty much basic research while the latter is a market-distorting subsidy—even if supporting new reactor designs.

For the fossil fuels, a check to see if estimates include any allowance regarding research on externalities (such as climate change) or energy security (such as securing key infrastructure or shipping; or oil stockpiling) would be warranted. These are big-ticket items generally ignored in most subsidy studies.


[N17] Market Capitalization and Top 60 Publicly-Traded Companies

The following companies represent a preliminary list of companies that meet the following criteria: (1) publicly traded stock, and (2) more then US$40 million in market capitalization attributable to renewable energy. This list is provisional and may inadvertently exclude stocks that meet these criteria. Market capitalization attributable to renewable energy is a rough estimate. For "pure play" renewable energy stocks (stocks that have bulk of earnings from renewables), market capitalization is assumed to be 100% attributable to renewable energy. For companies engaged in renewable energy as a minority of earnings, we have made rough estimate of earnings from renewable energy, divided this by total earnings and multiplied this percentage by total market capitalization to derive a rough estimate of renewable energy market capitalization. In cases where this was not possible due to information being either confidential or not available, we made an outside-in estimate of renewable energy capacity, revenue and operating profit. We then took the ratio of renewable energy operating profit by the company's total operating profit, then multiplied this ratio by the total market capitalization. Categories of renewable energy included in this list include bio fuels/biomass, geothermal, hydro, solar, wave and wind energy. Sources include: Bloomberg, MarketWatch.com, CLSA Asia-Pacific Markets, InvestGreen.com, Investext, Reuters, and company data. List compiled by John Michael Buethe (Georgetown University) and CLSA Asia-Pacific Markets.

Acciona (Spain), Alliant Energy (USA), Automation Tooling Systems (Canada), Bharat Heavy Electricals (India), Boralex (Canada), BP (UK), Brascan (Canada), British Energy (UK), Calpine (USA), Carmanah Technologies (Canada), Conergy (Germany), Corning (USA), Cypress Semiconductor (USA), Daystar (USA), E.On Energie (Germany), Endesa (Spain), ENEL (Italy), Energy Developments (Australia), Enersis (Chile), Eni (Italy), Evergreen Solar (USA), Florida Power & Light Energy (USA), Gamesa Energia (Spain), General Electric/GE Wind (USA), Geodynamics (Australia), Greentech Energy Systems (USA), Ishikawajima-Harima Heavy Industries (Japan), Japan Wind Development (Japan), Kaneka SolarTech (Japan), Kyocera (Japan), Marubeni (Japan), Mitsubishi Electric (Japan), Mitsubishi Heavy Industries (Japan), Nordex Energy (Germany), Novera Energy (Australia), Omron (Japan), Ormat Technologies (USA), Pacific Hydro (Australia), Pfleiderer (Germany), Repower Systems (Germany), RWE (Germany), SAG Solarstrom (Germany), Sanyo (Japan), Scottish Power (UK), Sekisui Chemical (Japan), Sharp (Japan), Shell (UK), Solar Integrated Technologies (UK), Solar-Fabrik (Germany), Solarparc (Germany), SolarWorld (Germany), Solon (Germany), Spire (USA), Sunways AG Photovoltaic Technology (Germany), Talisman Energy (Canada), Tokuyama (Japan), TransCanada (Canada), TXU (USA), Vestas (Denmark), XCEL Energy (USA).

In addition to these companies with publicly-traded stock, there are many other companies involved in renewable energy, such as private unlisted companies and public utilities, that are not traded on stock exchanges. There were no clear criteria or data available to include these companies in an expanded list for this version of the report. Prominent examples of such companies include Iberdrola of Spain, Nuon and Essent of the Netherlands, Electricité de France, Hydro Quebec of Canada, Hydro Tasmania of Australia, Norsk Hydro and SN Power of Norway, and Enercon of Germany. It also excludes project developers that may not have large capital bases but still are major players in the renewables industry. Examples include Zilkha Renewables of the United States (owned by Goldman Sachs), Clipper Windpower and AES of the United States (which just bought Seawest), Eurus of Japan, and many others. There is also the issue of renewable energy value chains and what part of the value chain constitutes a renewable energy business—such as PV silicon wafer manufacturers, manufacturing equipment suppliers, and wind turbine blade manufacturers like LM Glasfibre of Denmark. Future versions of the status report could attempt to create a more comprehensive list.


[N18] Wind Power Industry and Costs

Wind technologies fall into two distinct types: large turbines, designed to supply electricity to the grid, typically 1-3 MW rated capacity with blade diameters of 60-100 meters, and small turbines rated from around 3 kW up to around 100 kW. As wind technology has matured, large wind turbines have become increasingly standardized. All are now broadly similar three bladed designs. However, the potential for innovation has not been exhausted. There is scope for cost reductions through site optimization and innovations in blade and generator design and in grid connection using power electronics. Offshore wind power is still in its infancy and large potential cost reductions exist.

Typical wind turbines produced today are in the 1-3 MW scale, although the 600 kW scale is still common in India and China. European manufacturers have introduced new wind-turbines in the 5 MW range, and achieved an evolution of cost per kW of installed capacity from 1,650 Euro/kW in 1986 to about 850 Euro/kW in 2004. At present little offshore wind capacity is installed anywhere in the world. As with onshore developments during the 1990s, Europe is the lead, with all the world’s operating offshore capacity and ambitious plans for future development in the 2006-2007 timeframe. The first large-scale offshore wind farm (160 MW) was completed in 2002 in Denmark.

Wind technology costs have declined 12-18% for each doubling of global capacity, with costs of wind-generated electricity falling from about 46 cents/kWh in 1980 (in the US; 2003$) to 4-5 cents/kWh at good sites today. Technology development and cost reduction have been driven primarily by feed-in policies in just a few countries: Germany, Denmark, and Spain. The German Wind Energy Association (BWE) estimated that the costs of wind power in Germany fell in real terms by 55% between 1991 and 2004.

How to make the machines bigger is still the number-one technological issue in the turbine industry, with the current philosophy being that the larger the turbine, the greater its cost effectiveness. The average size of turbines installed increased by only around 3% to 1.25 MW in 2004, with the three-blade, three-stage gear box design remaining the most popular. Some progress is being made in producing a single-geared generator, with German company Enercon being the only one to commercially produce them at present. 5 MW turbines remained the largest available but so far only three prototype units have been installed worldwide. (Cameron 2005).

During 2003-2004, there were six competitively-bid wind projects in China and Canada , totaling almost 2,000 MW, that show winning-bid prices from 4.1-4.8 eurocents/kWh, considerably lower than most present feed-in tariffs (see Table N31). However, competitive bidding in new markets may not reflect commercially viable prices if aspiring market entrants underbid to gain market entry or mis-bid due to insufficient experience.

Wind power markets remain fragmented by country. That is, the wind market is not yet a global market but really a collection of national markets, each growing fairly independently. Wind power has become a mainstream commercial investment in about 8-10 primary countries (including Denmark, Germany, India, Italy, Netherlands, Spain, the United Kingdom, and the United States) (Figure 6). Several countries are now taking their first steps to develop large-scale commercial markets, including Russia and other transition countries of Europe, China, South Africa, Brazil, and Mexico. In the case of China, most wind power investments historically have been donor or government driven, but a shift to private investors has been underway in recent years. Several other countries are at the stage of demonstrating wind farm installations, looking to develop commercial markets in the future.

The global market for small-scale wind turbines has been growing rapidly in recent years. Small-scale wind turbines (typically 100-1,000 W) provide power for homes and remote locations. The largest installed base of small-scale turbines is an estimated 230,000 in Inner Mongolia in China, for household use. Sales of small wind turbines were estimated to be 13,000 in 2005, totaling 14 MW (an average of 1 kW per turbine), bringing total small wind capacity to 30 MW. Manufacturers are aiming to reduce hardware costs by 20 percent to $1,700 per installed kW by 2010; and the average size of small wind turbines has doubled from 500 W in 1990 to 1 kW in 2004.


[N19] Solar PV Costs, Industry, and Production Capacity Expansion

The three main types of solar PV in commercial production are single-crystal, polycrystalline, and thin film. Japanese single-crystal solar cell technology has seen its module conversion efficiency improve from 6% in 1963 to over 17% today. The average efficiency of polycrystalline silicon cells is approaching 15%, and of thin film 10-12%. Still under development are the super-thin flexible cell, which has attained 38% efficiency, and the condensed type, which has attained 28.5%.

Since 1976, costs have dropped about 20% for each doubling of installed PV capacity, or about 5%/year. (Module prices have fallen from $30/W in 1975 to close to $3/W today. Costs rose slightly in 2004 due to high demand (which outpaced supply) and the rising cost of silicon. Rooftop PV systems currently cost around $6,000-$9,000 per kW installed.

The potential for further cost reductions as markets expand is appreciable. The technologies are small-scale and modular, and the scale economies of batch production and new manufacturing techniques have been barely exploited. In addition, conversion efficiencies of PV modules have seen continuous improvement through the use of new materials and cell designs. One of the issues for the future of PV is whether and how fast crystalline silicon can be replaced by high-volume, low-cost thin-film production.

Global solar PV module prices reached a low of $2.60/Wp in 2002/2003 (Sharp), but have since rebounded to average of about $3.25/Wp in 2004. But grid-connected installed prices remained flat (about $5.50/AC-watt in Japan and $6.50-8.00/AC-watt in the U.S.). One reason for module price increases is the rising cost of silicon due to high demand (coupled with the industry’s traditional reliance on computer-industry scrap silicon). Another reason is simply high demand relative to existing production. In China, solar PV module prices declined from an average of $5/Wp in 2000 to $3.50/Wp in 2003, but rose again to $4/Wp in 2004 due to raw material shortages and increased demand relative to supply. The high prices in 2004 were spurring many new manufacturers to get into the solar PV business, as profits were also high.

The PV industry celebrated its first gigawatt of global installed capacity in 1999. Five years later, by the end of 2004, this capacity had quadrupled to more than 4 GW. Solar PV market growth has very much been influenced by the grid-connected rooftop programs in Japan, Germany, and the U.S. state of California since the mid-1990s. Indeed, without these programs, the solar PV industry would likely be several years behind where it is today.

Investment in solar PV production capacity is growing in both capacity and plant scale. World solar PV production grew from 740 MW in 2003 to 1,150 MW in 2004. In 2004, U.S. solar PV production increased 39% even as its share of global production fell to 11%. Japanese production topped 600 MW. German production was up 66%, representing 60% of total European production. Production expansion continued aggressively around the world in 2004 (Table N19).

China and other developing countries have emerged as major solar PV manufacturers. As of 2004, China had 70 MW of cell production capacity and 100 MW of module production capacity, compared to the world total module production capacity of 1,150 MW. Chinese module production capacity doubled during 2004, from 50 MW in 2003. (China’s domestic PV market was 20 MW in 2004, so most production is exported.) Production capacity could double again in 2005, as the Nanjing PV-Tech Co. launched construction of China’s largest PV cell production facility, with 100 MW capacity, in early 2005. The Nanjing plant is scheduled to be finished by the end of 2005. Also, Chinese Electrical Equipment Group Ltd. plans to invest in new solar cell production capacity of 600 MW by 2008.

Other developing countries are also emerging as solar PV manufacturers. India’s primary solar PV producer is Tata BP solar, which expanded production capacity from 8 MW in 2001 to 38 MW in 2004. Central Electronics, Bharat Heavy Electrical, and WEBEL Solar are other leading solar cell/module manufacturers in India. In the Philippines, Sun Power doubled its production capacity to 50 MW in 2004. In Thailand in 2004, Solartron PLC, a solar-cell module assembler, announced plans to develop the country's first commercial solar cell manufacturing facility, with annual capacity of 20 MW, to start production in 2007.

Future plans for production expansion by the major solar PV manufacturers, as well as major new entrants, are also impressive. Announced plans by major manufacturers for 2005 included at least 400 MW increase in production capacity and several hundred megawatts further capacity in the 2006-08 period (Table N19).

Table N19.

[N20] Biomass

Cost reductions have been achieved in the area of small- to medium-scale steam turbines for biomass-based co-generation (mainly from woody residues) in Germany and Finland, and for "new" smaller-scale co-generation technologies like ORC and stirling engines (mainly Austria and Germany). Currently, plants of this type are estimated to deliver energy at a cost between $0.07/kWh (a CHP scheme) and $0.12/kWh (electricity only). Engineering assessment suggests that capital costs could be reduced by half through replication and economies of scale once the plants enter early commercial application. Much lower costs could be achieved in co-firing applications, where suitable quantities of biomass can be supplied to existing coal plants for example.

The largest potential for cost reduction lies with gasification technologies. Costs of advanced biomass gasifiers are dropping to 10-12 cents/kWh for megawatt-scale gasifiers. Small-scale gasification of biomass still lacks development, but from RT&D in the area of biofuels (BtL schemes), positive impacts are expected to medium- to large-sized gasification and, hence, for efficient biomass-based electricity generation using gas turbines and combined cycles. China and Europe are both leaders in small-scale gasification technology.

Rural biomass pelleting for heat and power. The most prominent development in Europe is the rapid introduction of pellet heating systems, mainly in Finland and Sweden, and to a smaller extent in Austria, Germany, and the UK. Cost reductions per unit of installed kWth could be achieved by some 10%, and logistics to deliver pelletized fuels to customers improved significantly. In developing countries, rural use of biomass for power generation and heating could be on the verge of wide-scale commercial use because of deployment of pelleting and briqueting technologies. These technologies improve portability, reliability, and range of feedstocks. (E.g. Project in Bangalore to palletize agricultural waste and gasify it and a mobile pelletizing process technologies being developed in China.)


[N21] Geothermal

Geothermal energy has been used for electricity generation and heat for about 100 years. Electricity generation from geothermal sources can take place at various temperatures, starting from below 100 °C ("Binary" power plants, ORC or Kalina-cycle) to high-temperature steam plants with more than 300 °C steam temperature. The distribution of power plant types in terms of installed power is the following: Natural steam 29%, single flash 37%, double flash 25%, binary 8%, and back-pressure 1%. For heat production, hydro-thermal resources are commonly used for district heating, and CHP plants.

Natural steam or hydrothermal resources are easiest to exploit, typically located at depths of 1-4 km and containing steam or liquid hot water. Molten rocks (magma systems) may also be accessed in the future at greater depths (up to 7 km) as can hot dry/wet rocks at 4-8 km, depending on the temperature gradient. The hot dry/wet rocks concept, more generally called "enhanced geothermal systems," has been proven successfully in a European test facility. Hot dry/wet rock resources are much more abundant, and are in principle available everywhere just by drilling sufficiently deep to produce rock temperature useful for heat extraction.

Geothermal heat pumps, also called ground source heat pumps (GSHP), are increasingly being used for building heating and cooling. Ground couplings include borehole heat exchangers (vertical loops), groundwater wells, horizontal loops in the soil, and similar techniques.

The main technical challenges being addressed for reducing costs and opening up new resources include cheaper driller techniques (drilling typically accounts for half of the capital costs), remote detection of producing zones during exploration, well-stimulation measures or ‘heat mining’ to extract the heat more extensively and efficiently, and better power conversion technology.


[N22] Biofuels

Ethanol is the most common biofuel, accounting for more than 90% of the total usage. Ethanol is most frequently used in low-concentration blends with petroleum gasoline. In North America and parts of Europe, blends of 5-10% (E5 and E10) are common, and selected filling stations in a few major metropolitan areas sell E85 for "flexible fuel" vehicles that can run on either gasoline or ethanol. The warm climate of Brazil also makes feasible the use of E95, and an increasing number of vehicles capable of using that fuel are being sold. ETBE, a mixture of ethanol and isobutylene (petrochemical), is used in low-concentration gasoline blends up to about 8-10% in fuels in parts of Europe, particularly France and Spain. (ETBE is "25% renewable" on a carbon atom basis and some question whether it should be considered a renewable fuel.)

In the U.S., construction of 12 new ethanol plants was completed in 2004, bringing the total to more than 80 plants. Also in 2004, construction of 16 new plants was started. More and more states are requiring that use of MTBE as a gasoline oxygenator be discontinued, due to its toxicity and contamination of drinking water, and ethanol is being used as a substitute. Consequently, by 2004, over 30% of all gasoline sold in the U.S. was being blended with ethanol as a substitute oxygenator (Renewable Fuels Association 2005).

There were more than 300 sugar mills/distilleries producing ethanol, served by a plantation area of 5.4 million hectares. In early 2005, 39 new distillers were licensed. As production increases, some even expect that ethanol exports could reach 6 billion liters/year by 2010. Several larger bioethanol plants will begin production in 2005 in Germany and the United States. Projections for the global market are for 60-75 billion liters/year by 2010.

Ethanol prices in Brazil have steadily fallen. Prices (in 2002 US$) fell from $11/GJ in 1980 to $5/GJ in 2002, and since 1999 have been equal to or below the equivalent Rotterdam gasoline price (Goldemberg et al. 2004).

Ethanol is now very competitive with gasoline. Cost reductions have been driven by Brazil and U.S. policies and also improvements in production efficiencies with additional investments and technology advances.

Ethanol from cellulose shows great promise for the future. Canada has led research in this field, and has helped to fund construction of the first commercial-scale cellulosic ethanol production plant, which converts wheat straw into ethanol using an advanced enzymatic hydrolysis process. Such plants may eventually become common, and will allow ethanol to be produced from almost any type of biomass, including agricultural and forestry wastes and high-yielding dedicated energy crops such as poplar trees and switchgrass.

International biofuels trade has expanded rapidly during the past few years. World ethanol trade volume hit a record level in 2004, reaching nearly 4.9 billion liters, compared with 3.7 billion liters in 2003. Brazil is by far the biggest exporter, accounting for about half of international shipments of ethanol during 2004. Japan and the U.S. were the largest importers, with India close behind. However, Brazilian ethanol prices during 2004 were near historic lows, fuelling trade, and higher ethanol prices likely during 2005 could slow or even reverse this trend, at least in the short term. There was also considerable biofuels trade (of both ethanol and biodiesel) within the EU (between various member countries), and growth in intra-EU trade appears likely to continue with the 10 new members beginning to play an active role.

Biodiesel was not produced in significant quantities anywhere in the world prior to 1996. By 2004, biodiesel markets had developed in seven primary countries (Austria, Belgium, France, Germany, Italy, Indonesia, and Malaysia). Germany has been the biggest biodiesel producer, with about 2 billion liters capacity on line or under construction. France, Italy, and the UK are the next largest producers.

A biodiesel market is emerging in the U.S., with currently between 20 and 25 biodiesel production sites, with an estimated production capacity over 150 million gallons per year. An additional 100 million gallons of annual capacity is under construction or has been announced. Sales of biodiesel exceeded 30 million gallons in 2004, and are expected to more than double in 2005 due to tax incentives. A recent example of expansion is a 15-million-gallon-per-year biodiesel production plant planned for Missouri by Mid-America Biofuels. The plant will use the soybean oil from nearly 10 million bushels of soybeans grown in the state, representing approximately 7 percent of Missouri's average annual harvest.

India has been examining for quite some time the supply of ethanol-blended petrol in the country. In order to ascertain financial and operational aspects of blending 5% ethanol with petrol, the government had launched three pilot projects in different states during 2001 and these pilot projects were supplying 5% ethanol-doped-petrol only to the retail outlets under their respective supply areas. The Society for Indian Automobile Manufacturers (SIAM) has confirmed the acceptance for use of 5% ethanol-blended petrol in vehicles. State governments of major sugar producing states and representatives of sugar/distillery industries have confirmed availability/capacity to produce ethanol. An expert group established by the government recommended blending of ethanol with petrol at supply locations (terminals/depots) of oil companies. In 2003, the government resolved that 5% ethanol-blended petrol would be supplied in the nine states and four union territories. For biodiesel, a national program aims to produce enough oil seeds for the production of biodiesel in sufficient quantities to enable its blending with diesel to the extent of 20%. Pilot projects and analyses of feed-stock collection and plantations were ongoing.


[N23] Concentrating Solar Thermal Power

In Europe, research and development for concentrating SEGS was significantly increased in 2003 and 2004. New designs using Fresnel reflectors are being proposed, promising 20% cost reductions as compared to the standard parabolic trough and tower concepts. Performance of trough receiver tubes continues to increase, thermal storage continues to be developed for trough systems, and advanced stirling dishes are under test at some laboratories.


[N24] Jobs from Renewable Energy

We conducted a literature review of analytical factors for jobs-per-existing-capacity and jobs-per-unit of produced capacity (Table N24c). We then totalled the jobs based on existing installed capacity in 2004 and new manufactured/installed capacity in 2004 (Table N24a). In general, employment impacts of renewable energy development are difficult to measure in a precise way, especially if total employment figures—including both direct and indirect jobs—are to be estimated. A proper approach would be to build input-output analysis models, an analytic tool that macroeconomists use to derive employment multipliers with which to predict the number of jobs (direct and indirect) created by sales increases from a given sector or industry. The simplified alternative adopted here is to use analytical approaches to define employment coefficients, generally based on (a) information on labor time needed for a unit of power (i.e. person-years per MW), or (b) data on expenditure necessary to support a full-time job annually (person-years/USD invested).

Table N24a.


Table N24b.
Additional Explanatory Notes:

Methodological premise. Employment impacts of renewable energy development are difficult to measure in a precise way, especially if total employment figures—including both direct and indirect jobs—are to be estimated. A proper approach would be to build Input-Output analysis models (see note-f below), an analytic tool that macroeconomists use to derive employment multipliers with which to predict the number of jobs (direct and indirect) created by sales increases from a given sector or industry. A simplified alternative is to use analytical approaches to define employment coefficients, generally based on (a) information on labor time needed for a unit of power (i.e. person-years per MW), or (b) data on expenditure necessary to support a full-time job annually (person-years/USD invested).

Table N24c summarizes some of the most relevant employment coefficients developed by analysts. The following points summarize additional explanatory elements on the employment impact parameters and estimates presented:

(a) Most of the studies in the literature focus on direct jobs that is, employment generated within the renewable energy industry chain, usually disaggregated in the following categories: manufacturing, construction and installation, operation and maintenance, and fuel collection. They therefore do not count the indirect jobs, that is, those jobs created in the economy by multiplier effects in the renewable energy sectors.
(b) There are different ways to build employment impact indicators. Many studies report on employment in the manufacturing and installation segment in terms of person-years per MW, that is the amount of labor time required to manufacture equipment (or build a power plant) equivalent to MW of power. In Tables N24b and N24c, this indicator has been selected to offer the picture of how many full-time employees were working in renewable energy manufacturing and installation in 2004. For this reason, whenever possible, other employment coefficients from the literature were adapted to person-years values. The indicator Jobs per MW is used in Table N24c with regards to the O&M and fuel collection segments of labor, it refers to permanent employment, that is the number of laborers needed continuously to support the ongoing operation of a power plant with a maximum output of one MW.
(c) Generally the employment created is measured against the power capacity installed (MWp), as it is in this report, but an alternative may be to consider as common denominator the average power capacity (MWa), the power capacity de-rated for taking into account the capacity factor of each energy technology. This way an indicator that standardizes the actual energy outputs is obtained and values referring to employment impacts of different RE technologies can be compared.
(d) Table N24a reports the range of values of estimated employment obtained by using the lowest and the highest employment coefficients of Table N24c for each technology. While for solar hot water heaters there are not many employment studies and parameters available, it should be noted that the Chinese industry is representative of the largest production (72% of global production in 2004). Therefore the choice was to use Chinese industry data to derive employment coefficients and adjust them to account for lower labor intensity for the non Chinese production figures. As for biofuels, the employment parameter (Table N24c) and the estimate figure (Table N24a) refer to total direct employment in the relevant agriculture and industrial sectors, thus it is presented separately from the other employment estimates.
(e) All figures estimating the labor requirement of renewable energy presented in Table N24c have been developed in the OECD countries, except for solar heating and biofuels. It can be recognized that in a developing country context the same processes and markets can be more labor intensive per MW, thus leading in a probable underestimation of global employment when applied to global renewable energy capacity figures in Table N24a.
(f) For further reference, see MITRE Project (EC 2002b) for a good example of this method applied to the growth scenarios of renewables across technologies and within EU 15 member states: starting from SAFIRE model of market penetration for the different RE technologies, an input-output model named RIOT (Renewables Enhanced Input Output Tables) was used to calculate production functions representing the value of inputs (including employment) needed from the different sectors of the economy to obtain a unit of energy from different energy sources (both conventional and renewables). These parameters were then used to model net employment impacts (including the substitution of conventional energy sector jobs) in the scenarios at 2010 and 2020.

Table N24c.
Individual jobs estimates:

The China solar hot water industry employed 200,000 people in 2002, with a market size of 40 million installed and 12 million produced annually (Li 2005). The top eight manufacturers are Himin, Tsinghua Yang AGuang, Linuo Paradigma, Tianpu, Hua Yang, Mei Da, Sunpu, and Five Star. Considering growth in the market and installed base, by 2004 there may have been at least 250,000 employed.

Europe wind power jobs from Global Wind Energy Council. Nepal biogas industry from Nepal Biogas Support Programme. Other jobs estimates from report contributors. Europe small hydro and solar PV jobs from EREC 2004.

Sources for job estimation parameters and methods: EC 2002b; ECOTEC 2002; GAC 2005; Goldemberg 2004; Heavner & Churchill 2002; Kammen et al. 2004; Pembina Institute 2004; Schwer & Riddel 2004; and US DOE 1997.


[N25] Policy Targets

Sources for Table 3 and Figure 11 are: IEA, OECD, and JREC policy databases (IEA 2005a and 2005b); DSIRE database (DSIRE 2005); Li 2002 and 2005; Sawin and Flavin 2004; Thailand DEDE 2004; South Africa Department of Minerals and Energy 2003; and many other submissions from report contributors.

Some of these targets are not legally binding within the countries concerned, but are rather indicative or planning targets. Some targets may include capacity or energy from large hydropower.

China’s targets are from the draft renewable energy development plan being prepared by NDRC. The plan has not yet been approved by the government. The Chinese renewable energy law from February 2005 requires NDRC to publish the renewable energy development plan, including targets, by January 2006. Targets also include 140 million m2 of solar hot water by 2010, 270 million m2 of solar hot water by 2020, 20 GW of wind by 2020, and 20 GW of biomass by 2020, and 12.5% of total electric power capacity by 2020 (which would be an anticipated 125 GW out of 1,000 GW). China’s target of 10% of total installed electricity from renewable energy, excluding large hydro, would mean 60 GW of renewables out of 600 GW total power capacity. In relation to the target of 5% total primary energy by 2010, China today stands at approximately 3.3-3.5% of total primary energy from renewables (excluding large hydropower).

In 2004, Korea established a goal of 1.3 GW of grid-connected solar PV by 2011. This follows a previously announced target of 100,000 solar PV homes by 2011, an expected 300 MW.

Korea’s target of 7% electricity by 2011 includes large hydropower. Excluding large hydropower, the target becomes 5.6%.

Japan also has targets of 4.8 GW from solar PV and 3 GW from wind. Although these targets remain "on the books," they have been eclipsed by the RPS policy of 1.35% and are no longer regarded as primary.

EU data also from EC 2004a and 2004b, which provide the best overview of EU policy targets..

Note: The percentage contributions of RES-E are based on the national production of RES-E divided by the gross national electricity consumption. For the EU15, the reference year is 1997. For the EU10 (Czech Republic, Estonia, Cyprus, Latvia, Lithuania, Hungary, Malta, Poland, Slovenia and Slovakia), the reference year is based on 1999-2000 data.

Philippines: The Renewable Energy Policy Framework (REPF) aims to double the capacity of renewable energy resources by instituting favorable policies and incentive packages for industry participants with the following objectives in mind: (1) Increase renewable energy-based capacity by 100 percent by 2013, with 425 MW expected to be supplied by wind power. The Philippines has over 70,000 MW of potential wind energy, with estimates of realizable wind power ranging from 20-30,000 MW. (2) Become the top geothermal energy producer in the world. Currently, the Philippines is the second largest geothermal power in terms of generating capacity, having generated 9,822 GWh from geothermal energy in 2003, displacing around 16.9 MMBFOE. It is projected that geothermal installed capacity will increase from the current 2,146 MW to 2,206 MW by 2014, equal to 14,403 GWh generation and 23.41 MMBFOE. The country is estimated to have 4,790 MW of potential geothermal reserves. (3) Become the largest wind-power producer in Southeast Asia with a wind energy investment kit focusing on the development of 16 wind power areas, beginning with a 25 MW wind farm—which went online this year—and another 40 MW wind farm in Ilocos Norte. (4) Become the solar-manufacturing hub of Southeast Asia through the establishment of a local industry in the manufacture of affordable solar energy systems. A US$300 million solar wafer fabrication plant was inaugurated in April 2004 to manufacture high-efficiency PV cells with an anticipated initial production equivalent of 25 MW, increasing to 150 MW within the next five years. At full capacity, the plant can supply 6% of the world's total market for the PV industry. The manufacturing plant aims to distribute 30% of its production to the local market, thereby significantly decreasing the cost of local solar panels. (5) Push for the development of all viable mini- and micro-hydropower plants through various cost-efficient foreign loans. (6) Install 130-250 MW of biomass, solar, and ocean capacity; and (7) Partner with Congress for the passage of the Renewable Energy Bill that seeks to institutionalize the guidelines, procedures, and incentives for renewable energy development.

Table N25.

[N26] Power Generation Promotion Policies

Sources for Table 4: IEA, OECD, and JREC databases (IEA 2005a and 2005b); IEA 2004b; Sawin & Flavin 2004; Wahnschafft & Soltau 2004; Johansson & Turkenburg 2004; Martinot et al. 2005; Beck & Martinot 2004; Osafo & Martinot 2003; Thailand DEDE 2004; Tumiwa 2005; Rousseff 2005; Austrian Energy Agency 2005; Stenzil et al. 2003; EWEA 2005c; EAEF 2005; EEA 2004; ECN Renewable Energy Policy Info website (and Vries et al. 2003) (www.renewable-energy-policy.info); country references noted in country data section; submissions from report contributors. IEA 2004b in particular contains a wealth of historical and current information on IEA country policies. EU data also from EC 2004a and 2004b.

Notes for Table 4:
(a) Entries with an asterisk (*) mean that some states/provinces within these countries have state/province-level policies but there is no national-level policy. See separate table for RPS policies by state/province. In the case of Inida, however, the Electricity Act of 2003 mandates state-level policies, and states are developing different combinations of policies, including feed-in tariffs and RPS. Even though this could not be considered a "national feed-in law," the mandate is having a similar effect.
(b) Japan’s net metering is voluntary by utilities and features separate buy/sell transactions, although the selling price is typically the same as the purchase price. Japan’s feed-in tariffs are also voluntary by utilities, and some utilities have switching to annual caps with bidding.
(c) Spain’s feed-in tariff system incorporates both fixed total prices and price premiums added to variable-cost components of electricity tariffs.
(d) Some policies listed may not be active or may not have associated implementing regulations developed. It is very difficult to separate active, inactive, and "not yet implemented" policies without extremely detailed data gathering. So the table reflects enacted policies, and the information it portrays should be considered as "notional" rather than "definitive."
(e) Mexico has an atypical form of net metering that allows intermittent self-generators access to the grid for surplus self-generation, to be used at other times of the day, subject to certain limits based on local utility marginal costs. Mexico also allows wheeling costs to be based on average plant capacity factor.
(f) Norway had a type of feed-in policy (added premium) for wind power, but this was discontinued in 2003.


[N27] Feed-in Laws

Sources for Table 7: IEA OECD Policies database (IEA 2005a); IEA 2004b; Sawin & Flavin 2004; other sources from Table 10; REAccess 5/10/05 for United States, Washington State; REAccess 5/16/05 for Turkey; Austrian Energy Agency 2005; ECN Renewable Energy Policy Info website (www.renewable-energy-policy.info); country references noted in country data section; submissions from report contributors.

Italy adopted CIP6/92 from 1992 to 1995. Denmark, Spain, and Portugal all had forms of feed-in policies earlier than those shown in Figure 12, but the dates in Figure 12 reflect the modern versions of the laws that are credited with the major market impacts which have taken place. Other countries also had earlier pre-cursor feed-in policies that might be considered the original legislative enactment.

Notes for Table 7
(a) Tariffs can vary depending on size of plant, region of plant, whether onshore or offshore in the case of wind, year of commissioning of plant, season of operation in which the tariff is paid (summer vs. winter), and/or year of plant’s operational life in which the tariff is paid. Some tariffs decline substantially or become invalid after a certain year of plant operation, and this varies widely by country. Ranges given reflect typical prices considering these factors, for Germany in 2004 and for other countries in 2002-2004.
(b) Germany’s feed-in law has undergone continuous updating, reflecting changing conditions, objectives, and technology characteristics and costs, first in 1994, and then in 1998, 2000, and 2004.
(c) Denmark’s price figures are from the old pricing system before feed-in tariff was suspended in 2003. (d) "---" means law does not cover that technology.
(e) Some tariffs have upper limits to plant size. Czech Republic and Slovenia limit small hydro to 10 MW.
Latvia limits small hydro to 2MW. Indonesia limits all plants to 1 MW.
(f) Spain’s feed-in tariff system incorporates both fixed total prices and price premiums added to variable-cost components of electricity tariffs.
(g) In India, national feed-in tariffs (common guidelines to all states for a minimum buy-back rate of Rs. 2.25/kWh in order to bring uniformity) were declared by MNES in 1993. However, two states, Gujarat and Tamil Nadu, were offering attractive buy-back rates even earlier in order to attract private sector investment in wind (MNES annual reports for 1991-1994). Similarly, Maharastra and Tamil Nadu had promotional policies for bagasse-based cogeneration. Tamil Nadu had evolved a scheme in 1988 (TNEB-Tamil Nadu Electricity Board Notification dated 12 December 1988) called "Power feed scheme" permitting co-generators and private-sector power producers of 2 MW capacity and greater to sell surplus power to the grid. It covered co-generation units, mini- and micro-hydro, wind farms, and diesel/gas turbines. The power purchase rate for this scheme in 1990-91 was Rs. 1.00 per unit subject to yearly review. MSEB (Maharashtra State Electricity Board), on the other hand, offered Rs. 1.20 per unit with periodic revisions. (Source for both the above is Winrock International & IDEA 1993.)
(h) India’s Electricity Act of 2003 mandates national targets by 2012 and provides guidelines for fixing RPS and feed-in tariffs for each state.
(i) PURPA was first enacted in the U.S. in 1978 and actively implemented by many states during the 1980s. By the 1990s, fewer states still had active PURPA implementation, although currently several states still implement PURPA as a feed-in tariff for small projects; examples of this exist in Idaho, Minnesota, and Oregon.
(j) Some countries have feed-in tariffs that apply only to solar PV.
(k) Turkey Adopts National Feed-in Law for Renewables, news item at REAccess.com, 16 May 2005, at www.renewableenergyaccess.com/rea/news/story?id=29822
(l) Slovakia: Feed-in-Tariffs for Green Electricity 2006 issued. In June 2005, the Slovak Regulator has issued the feed-in-tariffs for Electricity from Renewable Energy Sources and CHP for the year 2006. This latest decree brings about considerably higher tariffs, as compared to the current regulation. For example, the tariff for electricity from newly installed wind power plants put into operation after January 1st, 2005, is fixed with 2,800 Slovak Crowns per MWh (about 72 Euro). These tariffs are set by the Regulatory Office for one year. A complete table with the tariffs is now online on enerCEE: www.energyagency.at/enercee/sk/supplybycarrier.htm#res


[N28] Renewables Portfolio Standards

RPS information comes from DSIRE database; Martinot et al. 2005; IEA 2004b; Pollution Probe 2004; Linden et al. 2005; ECN Renewable Energy Policy Info website (www.renewable-energy-policy.info); submissions from report contributors.

Some RPS targets include large hydro, for example in Wisconsin, Maine, New Jersey, Texas, Hawaii, Maryland, New York, Pennsylvania, District of Columbia, and British Columbia, while other targets restrict renewables to a certain maximum size, with the maximum usually falling between 1-30 MW.

A 2005 study by Global Energy Decisions estimated that state RPS laws currently existing in the United States would require an additional 52 GW of renewable energy by 2020, which would more than double existing U.S. renewables capacity.

Table N28a.
Canada: According to Pollution Probe (2004), there are 10 Canadian provinces with RPS or planning targets for renewable energy. Pollution Probe identifies the Nova Scotia and Ontario policies as RPS policies, while the others are planning targets. Other sources from early 2004 state that no RPS policies yet existed in Canada. News reports confirm Nova Scotia passed energy legislation in November 2004 with the RPS. Ontario enacted its RPS in its 2004 Electricity Restructuring Act. British Columbia has introduced a voluntary RPS targeting 10% of new generation from renewable sources (www.energyroundtable.org/energy_opp.php). Alberta’s target is similarly voluntary. "Prince Edward Island introduced an RPS of 15% by 2010, 100% by 2015." PEI’s Renewable Energy Act was enacted in December 2004. Hydro Quebec has issued an RFP to procure 1,000 MW of new wind power over 10 years.

Table N28b.

[N29] Rooftop Solar PV Policies

Table N29.

[N30] Other Power Generation Promotion Policies

See Martinot et al. (2005) for further details and full references on U.S. public benefit funds (available at www.resource-solutions.org).

Net metering policies from Martinot et al. (2005), plus IEA and JREC policy databases (IEA 2005a and 2005b) and submissions from report contributors.


[N31] Public Competitive Bidding and Other Regulatory Measures

Many broad policies for power sector reform/restructuring also affect renewable energy in significant ways, beyond the administrative measures specifically targeting renewable energy. Such policies are beyond the scope of this report, but good discussion can be found in Beck & Martinot (2004).

Table N31.

[N32] Solar Hot Water Policies

More information on China can be found in Li (2005).

For more information about solar hot water policies in Spain, see: Instituto para la Diversificación y Ahorro de la Energía (Institute for Energy Diversification and Saving), at www.idae.es and Comision Nacional de la Energia (National Energy Commission), www.cne.es and ww.energias-renovables.com

For specialized news group on renewables in Spain, see:
www.energias-renovables.com/paginas/ Contenidosecciones.asp?Id=5993 and www.energias-renovables.com/paginas/ Contenidosecciones.asp?ID=5202&Tipo=& Nombre=Solar%20t%C3%83%C2%A9rmica

Agència d’Energia de Barcelona (Barcelona Energy Agency), at www.barcelonaenergia.com

For Barcelona Solar Ordinance, see www.barcelonaenergia.com/cas/
observatorio/ost/ost.htm


[N33] Biofuels Policies

Table N33.
Note: As part of Thailand’s national 8% of energy target by 2011, biomass transport fuels are targeted at 1570 ktoe/year, which could be achieved by 3 million liters/day of ethanol and 2.4 million liters/day of biodiesel. But it is still unclear what the actual blending mandates will be. Sources: Submissions from report contributors. Some of the information is inadequately verified.

In Canada, the province of Ontario announced in 2004 that it intends to require that all gasoline sold there must contain an average of 5% ethanol by 2007. The province of Saskatchewan enacted an ethanol fuel act in 2002 that creates the legal framework to mandate ethanol blending with gasoline and is planning to move in that direction in 2005; the province of Manitoba is also considering enacting a policy to support ethanol blending.


[N34] Green Power Purchasing and Utility Green Pricing

Recent data on green power customers are not readily available. Most recent data show 600,000 green power customers in Germany (almost double from 2002) and almost 3 million in the Netherlands. According to some sources, Netherlands as of the end of 2003 was 2.2 million. UK and the Switzerland are almost the same number in 2004 as of the end of 2002, they were 45,000 and 46,000 for each. http://www.greenprices.com gives roughly 4 million green power customers total in Europe. Individual county numbers for Europe totaled together give a slightly smaller number, perhaps 3.7 or 3.8 million.

Bird et al. (2002) gives these totals of green power consumers for 2002: Australia: 60,000; Canada: 6,000; Finland: 8,000 in 2001; Germany: 325,000 (including 250,000 large hydro); Japan: 38,000; Netherlands: 775,000; Sweden: 9,000 GWh; Switzerland: 46,000; and United Kingdom: 50,000. Australia government (2004) gives 70,000 green power consumers.

Sources for green power include: Bird et al. 2002, Bird & Swezey 2004, Martinot et al. 2005, and submissions from report contributors.

An important distinction to make in considering numbers of green power customers is what percentage of these purchases are for new renewables and thus are serving to expand the deployment of renewable power generation. Many of the European purchases are for existing large hydro at prices on par with conventional energy, while the U.S. EPA Green Power Partnership has strict eligibility criteria for new renewables content (minimum 50% new).

See FOE (2004), which says that only "retired" ROCs in the UK are really comparable to U.S. voluntary products; most Green Power buyers in the UK are merely subsidizing the utility's need to buy some renewables. The Shanghai electricity comes from a 3.4 MW wind farm in Fengxian District, with another 20 MW of wind power capacity coming on line in mid-2005 in two other wind farms. The first round of green electricity purchases by these 12 enterprises is equal to 50% of the power output from these 3 wind farms. (News release from the Shanghai Energy Conservation Supervision Center, 12 June 2005.)

The consumer’s cooperative union in Japan that initiated green power in 1999 was the Seikatsu Club Hokkaido (SCH). Together with a regional utility, SCH established a fund to support the development of new wind projects in the region. Under the program, SCH collects electricity bills instead of the utility, and the members who joined the program can make contributions by adding 5% to their electricity bills. SCH also established the Hokkaido Green Fund (HGF) for contributions from non-members. In turn, the Hokkaido Green Fund established Hokkaido Civic Wind Co. to allow members to purchase shares of wind projects in return for dividends from the sale of electricity from the wind turbines. Thus was built the first "citizen-owned" wind turbine in 2001. By early 2005, the Hokkaido Civic Wind Co. had invested in 7 MW of wind capacity. After this program, HGF and the Institute for Sustainable Energy Policies established the Japan Green Fund Co. to allow further citizen investments in renewable energy. By 2005, the Japan Green Fund had constructed five wind turbines. And by early 2005, there were 1,300 members of HGF’s green pricing program.


[N35] Municipal Policies

Table N35a.
Notes:
(a) "X’ indicates significant activity in the given category.
(b) Categories are defined as follows: "RE goals" means targets or goals set for the future share of energy from renewable energy; "CO2 goals" means future CO2 emissions targets set, usually on a city-wide or per-capita basis; "SHW" means policies and/or incentives for solar hot water enacted; "Solar PV" means policies and/or incentives for solar power enacted; "Planning" means overall urban planning approaches considering future energy consumption and sources; "Demos" means specific projects or one-time demonstrations subsidized by public funds; and "Other" means other policies or programs.
Sources: International Solar Cities Initiative, www.solarcities.or.kr, and www.martinot.info/solarcities.htm, December 2004, with updates from DSIRE database and submissions from report contributors. Barcelona energy improvement plan at www.barcelonaenergia.com.

Table N35b.
Note: Austin’s target includes energy efficiency improvements. Sources: International Solar Cities Initiative, www.solarcities.or.kr; www.martinot.info/solarcities.htm, December 2004; DSIRE database.

Table N35c.
Notes:
(a) Calgary: GHG reduction goal is 6% reduction from 1990 levels for corporate emissions, and 6% reduction from 1990 levels for community emissions.
(b) Sudbury: GHG reduction goal is 574,800 tons of GHGs per year (77% through energy, 10% through transportation, 13% through solid waste). This translates into a target of more than a 30% reduction below 1990 levels.
(c) Toronto: GHG reduction goal is 20% from 1990 levels for corporate emissions, 6% for community emissions.
Sources: International Solar Cities Initiative, www.solarcities.or.kr; www.martinot.info/solarcities.htm, December 2004; DSIRE database; submissions by report contributors. Vancouver CO2 reduction goal from http://vancouver.ca/sustainability/ coolvancouver/backgrounder.htm; Toronto CO2 reduction goal from www.city.toronto.on.ca/taf

(San Francisco, CA, Refocus Weekly, 15 June 2005) Politicians from 50 of the largest cities in the world have signed a treaty to source 10% of their city’s peak electric load from renewable energies. The non-binding ‘Urban Environmental Accord’ was signed at the United Nations World Environment Day conference in San Francisco. The accord lists 21 specific actions, topped by an action item to "adopt and implement a policy to increase the use of renewable energy to meet 10% of the city’s peak electric load within seven years." The mayors agreed to adopt municipal plans to reduce GHG emissions by 25% by 2030, including a system for accounting and auditing greenhouse gas emissions. Signatories include Jakarta, Delhi, Istanbul, London, Seattle, Melbourne, Kampala, Zurich, Dhaka, Moscow, Rio de Janeiro, Copenhagen and Islamabad. Available at www.wed2005.org/pdfs/Accords_v5.25.pdf? PHPSESSID=d3f44c0bb102b22541fbf9f35b268650 "Green Cities Declaration" (see PDF file)


[N36] Rural Energy and Development Assistance

For basic references and sources on rural energy, see World Bank 1996, UNDP et al. 2000, and Goldemberg & Johansson 2004.

For information on the World Bank’s renewable energy strategies, see:

• World Bank Renewable Energy Action Plan, described in World Bank’s RE/EE Annual Report, at
http://siteresources.worldbank.org/INTENERGY/ Resources/335544-1111615897422/ Annual_Report_Final.pdf
• World Bank, "Fuel for Thought: Environmental Strategy for the Energy Sector." (2000 strategy paper), at
http://www-wds.worldbank.org/servlet/WDSServlet ?pcont=details&eid=000094946_0008040539585
• "The Strategy of the World Bank in Financing Renewable Energy Projects in South Asia," at www.worldenergy.org/wec-geis/publications/ reports/renewable/annexes/annex_2.asp#strategy

For information about ASTAE, see www.worldbank.org/astae.

For Global Environment Facility-related information, see:

• GEF project briefs and documents, at www.gefweb.org.
• Other GEF monitoring and evaluation reports, at: http://thegef.org/MonitoringandEvaluation/ METhemesTopics/METClimateChange/ metclimatechange.html
• GEF, Office of Monitoring and Evaluation. 2004. Climate Change Program Study. Washington, DC, at http://thegef.org/MonitoringandEvaluation/ METhemesTopics/METClimateChange/ 2004_ClimateChange.pdf

For information about UNEP, see:

• Rural Energy Enterprise Development Programme, at www.uneptie.org/energy/projects/REED/ REED_index.htm, www.b-reed.org, and www.c-reed.org
• UNEP Sustainable Energy Finance Initiative, at www.sefi.unep.org
• UNEP Activities on Renewable Energy, at www.uneptie.org/energy/act/re

For information on UNIDO see: UNIDO initiative on rural energy for productive use, at www.unido.org/doc/24839 (lists UNIDO projects by technology type)

For information on African Development Bank, see "Renewable Energy Summary," at www.afdb.org/en/what_s_new/events/s_minaire_sur_l_ nergie_olienne_octobre_2004/adb_intervention_in_ renewable_energy

The Asian Development Bank (ADB) is currently developing a renewable energy operational and strategic action plan to promote renewable energy by building a pipeline of feasible renewable energy projects. The ADB established a Renewable Energy, Energy Efficiency and Climate Change (REACH) Program (www.adb.org/reach), which supports capacity building, institutional development, and project development activities in the area of energy efficiency and renewables, in 15 DMCs of Asia. It is expected that these technical assistance interventions will lead to increased lending in the area of renewable energy and energy efficiency.


[N37] Rural Biomass Use

Further references on rural biomass use include Kartha and Larson 2000; Kartha et al. 2004; Bailis et al. 2005; Karekezi & Kithyoma 2005; and Elauria et al. 2002.

All data on biomass consumption and rural household energy is from Bailis et al. 2005. Information on the health impact of traditional biomass use is from Ezzati & Kammen 2002.

Biomass energy is used extensively as fuel in the Philippines, particularly in the residential and industrial sectors. The types of fuel used in the country are: wood fuel, wood wastes, and other agricultural residues such as sugar cane bagasse, coconut husk and shell, rice-hull, and industrial and animal wastes. The residential sector accounted for about 70% of biomass use, with cooking as the major end-use. The shares of various biomass fuels consumed in the residential sector are 77 % wood fuel, about 19% agricultural residues, 4% charcoal, and 0.4 % animal manure in the form of biogas. Biomass consumption in the industrial sector is mainly for steam and power generation, which consumed about 84% of the total consumption of the sector while baking and commercial cooking used about 1%. The remaining 15% is used in commercial applications such as fish- and crop-drying, ceramic processing, food manufacturing, metal works, and brick-making. Applications of biomass energy systems are dominated by ovens/kilns/furnaces and biomass dryers, roughly 15,000 of each in 1997, along with about 5,000 cook stoves and on the order of hundreds of biomass-fired boilers and biogas systems, and a few dozen gasifiers (Elaur