43099 v 2 Annex 1 Detailed Technology Descriptions and Cost Assumptions ANNEX 1: DETAILED TECHNOLOGY DESCRIPTIONS AND COST ASSUMPTIONS Solar Photovoltaic Technologies SPV systems utilize semiconductor-based materials which directly convert solar energy into electricity. These semiconductors, called solar cells, produce an electrical charge when exposed to sunlight. Solar cells are assembled together to produce solar modules. A group of solar modules connected together to produce the desired power is called a solar array. The first SPV cell was developed in 1950. Very expensive at first, early applications of photovoltaic power systems were mainly for space programs. Terrestrial applications of SPV started the in late 70s and were primarily for powering small, portable gadgets like calculators and watches. By the 80s, a number of large-scale but still niche markets for SPV systems had emerged, mostly for remote power needs such as lighting, telecommunications and pumping. In spite of its high cost, SPV systems have steadily gained power generation market share due to their ability to produce electricity with no moving parts, no fuel requirements, zero emissions, no noise and no need for grid connection. The modular nature of SPV, which allows systems to be configured to produce power from W (s) to MW (s), gives it a unique advantage over other technologies. An SPV system typically consists of an array of solar cells, power conditioning and/or controlling device such as inverter or regulator, an electricity storage device such as battery (except in grid applications), and support structure and cabling connecting the power system to either the load or the grid. A typical SPV system arrangement is shown in Figure A1.1. Figure A1.1: Typical SPV System Arrangement Array of PV Modules Power Conditioner (invertor, control Energy-efficient Lighting and protection) Power Storage (battery) Television Radio Source: DOE/EPRI. 71 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Technology Description and Power Applications SPV systems can be classified according to three principal applications: · Stand-alone solar devices purpose-built for a particular end use, such as solar HF radios, solar home lighting systems, or solar coolers. These dedicated SPV systems can either be configured to include some energy storage capacity or directly power electrical or mechanical loads, such as pumping or refrigeration; · Stand-alone solar power plants, basically small power plants designed to provide electricity from a centralized SPV power plant to a small locality like village or a building; and · Grid-connected SPV power plants, which are equivalent to any other generator supplying power to the electricity grid. The SPV module is the most important component of a PV system comprising 40-50 percent of the total system cost. As such, research and development programs have focused both on cost reduction and efficiency improvement of the solar modules. SPV cell technologies can be classified according to the materials and technology used in their manufacture. The major categories of commercial interest are: · Silicon-based SPV cells, which are the most common solar cells in commercial use. Included in this family of solar cells are crystalline silicon solar cells (both single crystalline and poly-crystalline), which account for more than 90 percent of the world's solar cell production. A well-made crystalline silicon solar cell has a theoretical PV conversion efficiency of up to 20 percent; · Amorphous silicon cells, also called thin film solar cells, which are cheaper to produce and require fewer materials as compared to the crystalline silicon cells. However, these cells have lower efficiency ­ typically 5-10 percent, and tend to lose up to one-third of their efficiency levels in the first year of use. Because they can be produced as thin film of semiconductor material on a glass or plastic substrate they offer a wide variety of designs and configurations, and have found application in integrated roofing/SPV arrays; and · Compound semiconductors, which are thin film multi junction cells manufactured using other photosensitive composite solid state materials such as Cadmium/Telluride (Cd/Te) and Copper Indium Gallium Diselenide (CIGD). This is an emerging but promising technology with high efficiency levels and light weight. 72 ANNEX 1: DETAILED TECHNOLOGY DESCRIPTIONS AND COST ASSUMPTIONS Table A1.1 summarizes the characteristics of the major solar cell categories. Table A1.1: Characteristics of Solar Cells Technology Market Share Efficiency Range Cost Range Life Remarks Silicon Single Crystal Cells >90% 12-20% 3- 4 US$/Wp >20 years Mature Technology Silicon Multi Crystal Cells 6-7% 9-12% 3-4 US$/Wp > 15 years Mature Technology Amorphous Silicon Cell Technology 3-5% 5-10% 4-5 US$/Wp >10 years Degradation of Efficiency in First Few Months. Compound Semiconductors CIGSC <1% 7.5% (13.5% at NA Commercially Available laboratory level) NA (maximum 16% at laboratory level,) (1) d/Te <1% Source: Renewable Energy Information Network. Note: NA= Not applicable. Technical, Environmental and Economic Assessment For the SPV assessment we have chosen several common configurations of solar systems used in India (Table A1.2). Table A1.2: SPV System Configurations and Design Assumptions Description SPV Systems SPV Mini-grid Large Grid-connected Power Plants SPV Power Plant Module Capacity 50 Wp 300 Wp 25 kW 5 MW Life Span Modules 20 Years 20 Years 25 Years 25 Years Life Span Batteries 5 Years 5 Years 5 Years NA Capacity Factor 20% 20% 20% 20% Note: NA = Not applicable. Our analysis assumes a capacity factor of 20 percent, based on 4.8 hrs/day average power generation at peak level. Solar modules are rated at design operating conditions of 250C ambient temperature and solar insolation of 1,000 W/m2. In practice and under typical weather conditions, an average solar module on an annual basis will generate peak power for about four-five hours a day, equivalent to a 20 percent capacity factor. This assumes that solar modules are deployed to face south (in Northern latitudes) and are 73 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES inclined at an angle equal to latitude to achieve maximum solar energy collection throughout the year. The environmental impact of SPV technology is nil at the point of use. Modules produce electricity silently and do not emit any harmful gases during operation. Silicon, the basic PV material used for most common solar cells, is environmentally benign. However, disposal of used batteries in environmentally safe way is important. Table A1.3 gives the capital costs for different sized SPV systems. Table A1.3: SPV 2005 Capital Costs (US$/kW) Solar-PV System Capacity 50 W 300 W 25 kW 5 MW Equipment 6,780 6,780 4,930 4,640 Civil 0 0 980 980 Engineering 0 0 200 200 Erection 0 0 700 560 Process Contingency 700 700 700 680 Total 7,480 7,480 7,510 7,060 Based on the assumed capacity factor and the life of the SPV plant, the capital cost was annualized and the total generation cost was estimated using the formulations provided in Section 2. The generation costs for the year 2004 are given in Table A1.4. Variable O&M costs include cost of battery replacement after five years for small systems (up to 25 kW) plus replacement of electronics components for larger (25 kW and 5 MW) systems. Table A1.4: SPV 2005 System Generating Costs (USą/kWh) SPV System Capacity 50 W 300 W 25 kW 5 MW Levelized Capital Cost 45.59 45.59 42.93 40.36 Fixed O&M Cost 3.00 2.50 1.50 0.97 Variable O&M Cost 12.00 8.00 7.00 0.24 Fuel Cost 0.00 0.00 0.00 0.00 Total 61.59 56.09 51.43 41.57 74 ANNEX 1: DETAILED TECHNOLOGY DESCRIPTIONS AND COST ASSUMPTIONS Future SPV Costs SPV module costs are currently about 50 to 60 percent of the total system costs. We note that the cost of SPV modules on a per-Wp basis has fallen from US$100 in 1970 to US$5 in 1998.26 SPV module costs continue to fall, and this drop in SPV module costs are influenced by technology advancement and growing production volume.27 Future costs will be driven by market growth and technology advancements, both of which can be forecast. Japan, one of the major markets for SPV and a major manufacturer of SPV modules, is forecasting production cost reductions from „100/Wp today to „75/Wp by 2010 and „50/Wp by 2030. The SPV industry in Europe and the United States is targeting costs of US$1.5-2.00/Wp within 10 years, based on technological improvements as well as a growth in production volumes of 20-30 percent (Table A1.5). Europe and the United States is targeting costs of US$1.5-2.00/Wp within 10 years, based on technological improvements as well as a growth in production volumes of 20-30 percent (Table A1.5). Table A1.5: Projected SPV Module Costs Cost Europe United States Japan India SPV Module 5.71/Wp US$5.12/Wp „100/Wp Rs 150/Wp Costs 2004 Target Cost 1.5-2/Wp US$1.5-2/Wp „75/Wp Rs 126/Wp*(@US$2.75/Wp) in 2010 Expected Cost 0.5/Wp NA „50/Wp(Note- Rs 92/Wp* in 2015 2030 projection) (@US$ 2/Wp) Sources: http://www.solarbuzz.com/ModulePrices.htm; http://www.solarbuzz.com/ModulePrices.htm NEDO (Japan); TERI (India). Note: NA = Not applicable. We have based SPV capital cost projections for the year 2010 and 2015 on the forecasts shown in Table A1.5. Our projection assumes that, as in the past, balance of system (BOS) costs will come down due to improvements in the technology of electronics components and batteries, as well as increase in production volume. Thus, we assume that BOS costs 26The challenges of cold climates PV in Canada's North, Renewable Energy World, July 1998, pp 36-39. 27SPV sales have increased from 200 MW in 1999 to 427 MW in 2002 and to above 900 MW in 2004. 75 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES will follow the same international trends as module costs. Installation and O&M costs are not likely to change significantly, they are assumed to be constant when calculating future system capital, installation and operational costs. The results of our projection, including uncertainty bands, are provided in Table A1.6. Table A1.6: SPV System Capital Costs Projections (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 50 W 6,430 7,480 8,540 5,120 6,500 7,610 4,160 5,780 6,950 300 W 6,430 7,480 8,540 5,120 6,500 7,610 4,160 5,780 6,950 25 kW 6,710 7,510 8,320 5,630 6,590 7,380 4,800 5,860 6,640 5 MW 6,310 7,060 7,810 5,280 6,190 6,930 4,500 5,500 6,230 Uncertainty Analysis An uncertainty analysis was carried out to estimate the range over which the generation cost could vary as a result of uncertainty in costs and capacity factor. Most variables were allowed to vary over a ±20 percent range. Projected SPV generation costs for the years 2010 and 2015 resulting from the uncertainty analysis are shown in Table A1.7. The dependence of the generation cost on uncertainty of different parameters is shown with tornado charts given in Annex 4. Table A1.7: Uncertainty Analysis of SPV Generation Costs (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 50 W 51.8 61.6 75.1 44.9 55.6 67.7 39.4 51.2 62.8 300 W 46.4 56.1 69.5 39.6 50.1 62.1 34.2 45.7 57.0 25 kW 43.1 51.4 63.0 37.7 46.2 56.6 33.6 42.0 51.3 5 MW 33.7 41.6 52.6 28.9 36.6 46.3 25.0 32.7 41.4 76 Annex 2 Wind Electric Power Systems ANNEX 2: WIND ELECTRIC POWER SYSTEMS A wind power generator converts the kinetic energy of the wind into electric power through rotor blades connected to a generator. Horizontal axis wind turbines are almost exclusively used for commercial power generation, although some vertical axis wind turbine designs have been developed. The mechanism to capture the energy and then transmit and convert it into electrical power involves several stages, components and controls. Wind turbines can be broadly classified into two types according to capacity ­ small wind turbines (up to 100 kW) and large wind turbines. Small wind turbines are used for grid, off-grid and mini-grid applications, while large wind turbines are used almost exclusively for interconnected grid power supply. Figure A2.1 depicts both a horizontal wind turbine and a typical large-scale wind farm arrangement. Figure A2.1: Wind Turbine Schematics Rotor Pad-mounted Blade Transformer Gear box Acces s Roads Generator Nacelle Cover (inside Nacelle: ­ Brake Fenced Wind Rotor ­ Yaw Drive Plant Boundary Diameter ­ Electronic Controls and Sensors) To Utility T&D Turbine Wind Plant System Controller Wind Substation Yaw Gears/ Bearings Wind Plant Collection Tower Lines Wind Plant Control Lines Foundation Wind Plant Horizontal Axis Operations Center Wind Farm Control Wind Turbine System/SCADA Wind Farm Schematic Source: DOE/EPRI. Wind Turbine Technology Description Major components of horizontal axis wind turbine include the rotor blades, generator aerodynamic power regulation, yaw mechanism and the tower. The rotor blade is critical, as it captures the wind energy and converts it into the torque required to spin the generator. One measure of an aerodynamically efficient blade design is the weight/swept area ratio; this parameter can be used to compare efficiency across machines of similar design and capacity. Blade lengths increase with the size of the wind turbines, as longer lengths result in more energy capture. Longer blades require higher strength and lower mass, leading to common use of composite materials including carbon epoxy and fiber-reinforced plastic. 79 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Kinetic energy captured by the rotor blades is transferred to the generator through the transmission shaft. The shaft is coupled directly or via a gearbox mechanism to the armature of either an asynchronous (induction) or synchronous generator. A wind turbine with an induction generator comes with gearboxes, which convert the cut-in to cut-out speed variations to one, two or three speeds of the generator. In an induction generator the generator revolutions increase or decrease with the wind speed. For example, a two-speed generator has 4 poles at 1,500 (RPM) and 6 poles at 1,000 RPM. Wind turbines configured with synchronous generators have continuous speed variation according to the speed of the wind. Synchronous machines have no gearbox and can be connected to the grid at almost any wind speed. Synchronous machines provide great operational flexibility and good power quality, but are expensive because of the need for power electronics. Both asynchronous and synchronous machines can operate over a significant range of wind speeds. Wind turbine technology continues to evolve, with the doubly-fed induction generator (DFIG) direct drive (DD) synchronous machines under development. The DFIG incorporates most of the benefits of the variable speed drive system and has the advantage of minimal losses because of the fact that only a third of the power passes through the converter. DD synchronous machines have multi pole design for a wide speed range. Power electronics facilitates such wide speed ranges. All these generator developments rely on power electronics to control power quality. The cost of power electronics is falling, resulting in reduction of capital cost of the variable speed drives and thus lower generation costs for electricity produced by wind. The other major improvement is the increasing size and performance of wind turbines. From machines of just 25 kW 20 years ago, the commercial range sold today is from 600 up to 2,500 kW. In 2003 the average capacity of new turbines installed in Germany was 1,390 kW. With development of larger individual turbines, the required capacity of a wind farm can be met with fewer individual turbines, which has beneficial effects on both investment and O&M costs. Aerodynamic power regulation is a common feature of modern wind turbines allowing control of output power by mechanical adjustment of the rotational speed, especially at higher wind speeds. In a pitch-controlled wind turbine, the turbine's electronic controller checks the power output of the turbine several times per second. When the power output becomes too high, it sends a signal to the blade pitch mechanism, which immediately pitches (turns) the rotor blades slightly out of the wind. Conversely, the blades are turned back into the wind whenever the wind drops again. Stall, or passive control through the blade design itself, requiring no moving parts. The profile of the rotor blade is aerodynamically designed to ensure that the moment the wind speed becomes too high; it creates turbulence on the side of the rotor blade, which is not facing the wind. Although power regulation through stall control avoids complex control systems, it represents a very complex aerodynamic design problem, including avoiding the problem of stall-induced 80 ANNEX 2: WIND ELECTRIC POWER SYSTEMS vibrations in the structure of the turbine. Finally, an active stall control mechanism is being used in larger (1 MW and above) wind turbines. At low wind speeds, the machines will usually be programed to pitch their blades much like a pitch-controlled machine. However, when the machine reaches its rated power and the generator is about to be overloaded, the machine will pitch its blades in the opposite direction from what a pitch-controlled machine does. This is similar to normal stall power control, except that the whole blade can be rotated backwards (in the opposite direction as is the case with pitch control) by a few (3-5) degrees at the nominal speed range in order to give better rotor control. In other words, it will increase the angle of attack of the rotor blades in order to make the blades go into a deeper stall, thus wasting the excess energy in the wind. The result is known as the "deep stall" effect, which leads to the power curve bending sharply to a horizontal output line at nominal power and keeping this constant value for all wind speeds between nominal and cut-out. The wind tower is another critical wind turbine component, as it must provide the structural frame necessary to accommodate the external forces due both to the wind and the motions of the various components of a wind turbine. The tower must be designed to withstand vibrations as well as static and dynamic loads. The most important consideration in tower design is to avoid natural frequencies near rotor frequencies. The two most common tower designs are lattice and tubular. A lattice tower is cheaper compared to the tubular tower and, being usually a bolted structure, is easier to transport. However, tubular towers have several advantages over lattice towers. Not only is a tubular tower stiffer than a lattice tower, thus better able to withstand vibrations, it also avoids the many bolted connections of a lattice tower that require frequent checking and tightening. Moreover, tubular tower allow full internal access to the nacelle. As wind turbines increase in size and height, tower design is becoming critical. Only recently the conventional wisdom was that traditional towers taller than 65 m presented significant logistical problems and result in high costs. However, hub heights of 100 m or more for commercial wind turbines are becoming more frequent (GE's 2.3 MW turbine has a hub height of 100 m), and efforts are under way to develop innovative construction materials and erection concepts to allow these tall turbine structures to be erected without adverse cost impact. A final mechanical design feature is yaw control. The yaw control continuously orients the rotor in the wind direction. Large wind turbines mostly have active yaw control, in which the yaw bearing includes gear teeth around its circumference. A pinion gear on the yaw drive engages with those teeth, so that it can be driven in any direction. The yaw drive normally consists of electric motors, speed reduction gears and a pinion gear. This is controlled by 81 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES an automatic yaw control system with its wind direction sensor usually mounted on the nacelle of the wind turbine. Wind turbine technology is being continuously improved worldwide, resulting in better performance, more effective land utilization, and greater grid integration. Technology development in the form of larger size wind turbines, larger blades, improved power electronics and taller towers is noteworthy, resulting in dramatic improvement. Averaging 25 kW just 20 years ago, the commercial range sold today is typically from 600 up to 2,500 kW. Small Wind Turbines Small wind turbines are mostly used for charging batteries or supplying electrical loads in DC (12 or 24 V), bus-based off-grid power systems. However, when used in conjunction with a suitable DC-AC inverter and a battery bank, the turbine can also deliver power to a mini-grid. A particularly attractive configuration is small wind turbines in the 5 kW generating AC power for village-scale mini-grids. As with larger wind turbines, almost all small wind turbines are horizontal axis machines with the same basic components as their larger brethren. The major components of a typical horizontal axis small wind turbine include: · A simple alternator which converts the rotational energy of the rotor into three-phase AC electricity. The alternator utilizes permanent magnets and has an inverted configuration in that the outside housing (magnet) rotates, while the internal windings and central shaft are stationary; · Turbine blades and a rotor system, usually comprising three fiberglass blades; · A simple lattice tower and tail assembly, the latter composed of a tail boom and the tail fin which keeps the rotor aligned into the wind at wind speeds below the limiting, or cut-out, wind speed. At wind speed exceeding cut-out the tail turns the rotor away from the wind to limit its speed; and · A power controller unit which serves as the central connection point for the electrical portion of the system and regulates the charging and discharging of the battery bank and incorporates protection features including load dumping and turbine protection. 82 ANNEX 2: WIND ELECTRIC POWER SYSTEMS Wind Turbine Economic and Environmental Assessment The key design and performance assumptions regarding wind turbines with output capacities from 0.3 kW to 100,000 kW are shown in Table A2.1. We selected an average capacity factor of 30 percent across the board, even though capacity factors are highly dependent on wind speeds at a given location and can vary from 20 percent to 40 percent. The uncertainty analysis performed will accommodate a broader rage of capacity factor. Table A2.1: Wind Turbine Design Assumptions Capacity 300 W 100 kW 10 MW 100 MW Capacity Factor (%) 25 25 30 30 Life Span (year) 20 20 20 20 Annual Gross Generated Electricity (MWh) 0.657 219 26,280 262,800 As with most other RE systems, the direct environmental impact in terms of air or water emissions is nil. There are other environmental impacts including noise, bird mortality and aesthetic/visual impact. All of these impacts are highly location-specific and considerable mitigation is possible with the careful design of wind turbines and their deployment. The magnitude of costs associated with these impacts or their mitigation will differ greatly from region to region, and, therefore, we have elected not to attempt to quantify them in the economic assessment. Table A2.2 shows the capital costs for different size of wind power projects. Table A2.2: Wind Turbine Capital Costs in 2005 (US$/kW) Items 300 W 100 kW 10 MW 100 MW Equipment 3,390 2,050 1,090 940 Civil 770 260 70 60 Engineering 50 50 40 40 Erection 660 160 100 80 Process Contingency 500 260 140 120 Total 5,370 2,780 1,440 1,240 83 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A2.3 shows the levelized generation costs given the performance parameters of Table A2.1 and considering average O&M costs for wind power projects. Table A2.3: Wind Turbine Generating Costs in 2005 (USą/kWh) Items 300 W 100 kW 10 MW 100 MW Levelized Capital Cost 26.18 13.55 5.85 5.04 Fixed O&M Cost 3.49 2.08 0.66 0.53 Variable O&M Cost 4.90 4.08 0.26 0.22 Fuel Cost 0.00 0.00 0.00 0.00 Total 34.57 19.71 6.77 5.79 For small wind turbines the periodic cost of battery replacement was distributed (assuming five-year average battery life) over system life span and included in the variable costs. Future Wind Turbine Costs The costs of wind generators have been coming down over the years, as shown in Figure A2.2. Most analysts expect this trend to continue in future, with reductions of as much as 36 percent in capital costs by 2020 forecast by the EWEA (Figure A2.3). Figure A2.2: Wind Power Project Cost Trends 2,500 2,000 0.75 6 9.9 5.6 1.32 41.4 1,500 1.5 23.1 1.65 21.6 33.6 1 15.6 11 US$kW1,000 40.2 13.2 1.3 1.2 40.8 46.5 15 21 40.5 500 13.2 5.16 0 1995 1997 1999 2001 2003 Completion Year Source: Asia Alternative Energy Programme (ASTAE). 84 ANNEX 2: WIND ELECTRIC POWER SYSTEMS Figure A2.3: Wind Power Cost Projections 900 800 700 (€/kW) 600 Cost 500 Project 400 300 2000 2005 2010 2015 2020 2025 Year Source: European Wind Energy Association. EPRI also had made cost projections for the capital cost of wind power. As per the EPRI projections, the costs for a 10 MW plant would be about US$1,080/kW in 2010 and US$980/kW in 2015 in terms of US$1,999. In case of a 100 MW plant, the costs projections are about US$850/kW in 2010, and US$750/kW in 2015 in US$1,999 terms.28 We note, however, that the costs in many countries are lower than the EPRI costs. For example, in India, the costs are about US$1,000/kW, while the costs in Germany, Denmark and Spain are about 900 to 1200/kW in 2002.29 Thus, in our forecast of future wind turbine costs, we have elected to use the EWEA cost projections as a lower bound and use the EPRI cost projections as an upper bound.30 Uncertainty Analysis Uncertainty analysis was performed to place bounds on both the inherent uncertainty stemming from a stochastic resource such as wind as well as the more familiar uncertainties as regards forecast capital and other costs. The variation of the wind resource and, thus, wind turbine capacity factor from site to site can be generally captured by using the Weibull 28Renewable Energy Technical Assessment Guide ­ TAG-RE: 2004, EPRI, 2004. 29Wind Energy ­ The Facts, Vol. 2: Costs and Prices, European Wind Energy Association, 2003. 30We do this mathematically by using the GDP deflator to change the projection in 1999 dollar terms to 2004 dollar terms. 85 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES distribution. Since wind energy generation is a function of the wind speed variation as well as the power curve of the wind turbine, the capacity factor varies over time for a given location and for a specific time from location to location. In the present analysis, the range of location-to-location variation of the capacity factor is used for the uncertainty analysis and is captured by letting the capacity factor range from 20 percent to 40 percent, with 30 percent as an average value. The uncertainty in projected capital costs, described above and shown in Table A2.4, is included along with an assumed variability in O&M costs of ±20 percent. Table A2.5 shows the results of our uncertainty analysis for wind power generation costs. Table A2.4: Present and Projected Wind Turbine Capital Costs (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 4,820 5,370 5,930 4,160 4,850 5,430 3,700 4,450 5,050 100 kW 2,460 2,780 3,100 2,090 2,500 2,850 1,830 2,300 2,650 10 MW 1,270 1,440 1,610 1,040 1,260 1,440 870 1,120 1,300 100 MW 1,090 1,240 1,390 890 1,080 1,230 750 960 1,110 Table A2.5: Present and Projected Wind Turbine Generation Costs (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 30.1 34.6 40.4 27.3 32.0 37.3 25.2 30.1 35.1 100 kW 17.2 19.7 22.9 15.6 18.3 21.3 14.4 17.4 20.2 10 MW 5.8 6.8 8.0 5.0 6.0 7.1 4.3 5.5 6.5 100 MW 5.0 5.8 6.8 4.2 5.1 6.1 3.7 4.7 5.5 86 Annex 3 SPV-wind Hybrid Power Systems ANNEX 3: SPV-WIND HYBRID POWER SYSTEMS Another promising approach to meeting rural energy needs at the village level is PV-wind hybrid systems using small wind turbines. Such a hybrid configuration is a viable alternative to expensive engine-generator sites for serving isolated mini-grids. The hybrid design approach also takes advantage of the differential availability of the solar resource and the wind resource, allowing each renewable resource to supplement the other, increasing the overall capacity factor.31 PV-wind hybrid systems consist of the following components: · One or more wind turbines (common capacity ranges from 5 to 100 kW); · PV modules (capacity varies depending on load requirement and the nature of the control unit); · Control unit (commonly known as inverter-cum-controller); · Storage system (typically battery banks); · Consumer load; · Additional controllable or dump load; and · Additional provision for connecting diesel generating sets. The actual systems vary widely and depend on conditions specific to individual sites. The hybrid system architecture mainly depends on the nature of the inverter-cum-controller. The two most common system types are: · A small AC mini-grid with DC-coupled components. Originally, this technology was created in order to provide AC power from DC sources and to use both DC and AC sources to charge batteries. Multiple AC generators are coupled on the AC side, and a suitable control strategy for generation and power delivery using a bidirectional inverter is implemented. The inverter can receive power from DC and AC generators and also works as a battery charger. The common power range is from 0.5 to 5 kW and DC voltage is 12, 24, 48 or 60 V. The system layout is shown in Figure A3.1; and · Modular AC-coupled systems. Larger loads (3 to 100 kW) call for more traditional AC-coupled systems with all of the flexibility inherent to a more conventional grid arrangement, but still incorporating battery storage and an optional DC bus (Figure A3.2). This arrangement requires coupling of all generators and consumers on the AC side. Since these kinds of decentralized systems are grid compatible in their power characteristics, they can be deployed so that broader interconnection to other mini-grids 31Numerous studies, including SWERA (Solar-Wind Energy Resource Assessment, UNDP), have observed this reverse coincidence of solar insolation and high wind speeds for many parts of the developing world. 89 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Figure A3.1: Mixed DC- and AC-coupled PV-wind Hybrid Power System Wind Generator PV-module Genset G Loads, 120/240 V 50/60 Hz Bidirectional Inverter Optional DC-Bus (0-20 m) AC-Bus (0-500) Battery Source: DOE/EPRI. Figure A3.2: Pure AC PV-wind Hybrid Power System PV-module Wind Genset Other AC PV-module Generator System or Utility G Loads, 120/240 V 50/60 Hz Optional DC-Bus (0-20 m) AC-Bus (0-500) Battery Battery Source: DOE/EPRI. 90 ANNEX 3: SPV-WIND HYBRID POWER SYSTEMS or the national grid is possible in future. Such a structure allows maximum electrification flexibility in initially supplying rural villages with the power for basic needs and, subsequently, scaling up the rural power available through progressive interconnection. Solar-wind hybrid systems have been installed for a variety of applications around the world. Successful deployments include island mini-grids, remote facilities and small buildings. Typical applications include water pumping, communications and hospitals. Economic assessment For the economic assessment, we assume a system life of 20 years and a capacity factor of 30 percent. We note that the capital costs of hybrid systems are highly dependent on the system configuration and the individual capacities of the SPV and wind energy systems. We have set typical costs for two size ranges ­ 300 W and 100 kW ­ as shown in Table A3.1. These capital costs are calculated based on Indian small PV-wind hybrid systems' product data.32 Table A3.1: PV-wind Hybrid Power System 2005 Capital Costs (US$/kW) Items 300 W 100 kW Equipment 4,930 3,680 Civil 460 640 Engineering 30 130 Erection 390 450 Process Contingency 630 520 Total 6,440 5,420 Table A3.2 shows the results of PV-wind hybrid system generating costs calculated in line with the methodology described in Annex 2. Total O&M cost is assumed to be 2.5 percent of capital cost and is then divided into fixed and variable portions. Variable O&M cost also includes battery replacement aspect as per the SPV system. 32See M/s. Auroville Wind Systems, particularly the 1.5 kW and 5 kW wind turbines with 130 Wp and 450 Wp of SPV modules. 91 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A3.2: PV-wind Hybrid Power System 2005 Generating Costs (USą/kWh) Items 300 W (CF 25%) 100 kW (CF 30%) Levelized Capital Cost 31.40 22.02 Fixed O&M Cost 3.48 2.07 Variable O&M Cost 6.90 6.40 Fuel Cost 0.00 0.00 Total 41.78 30.49 The PV-wind hybrid systems have a niche market in remote areas far from economical grid extension. The costs of these hybrid systems are projected to be reduced consistent with the cost projections for the individual SPV and wind energy systems. Uncertainty Analysis As with the individual SPV and wind technologies, the key uncertainties affecting delivered generation costs revolve around expected capacity factor and capital cost variability. Since the hybrid systems combine two resources, the range over which capacity factor can vary will be smaller than with the individual technologies. We assume a capacity factor in the range from 25 percent to 40 percent, with 30 percent as probable value. We carry forward the uncertainties in projected capital costs, shown in Table A3.3, and assume a ± 20 percent variation in O&M costs in order to estimate the band of generation cost estimates in the years 2010 and 2015 shown in Table A3.4. Table A3.3: PV-wind Hybrid Power System Projected Capital Costs (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 5,670 6,440 7,210 4,650 5,630 6,440 3,880 5,000 5,800 100 kW 4,830 5,420 6,020 4,030 4,750 5,340 3,420 4,220 4,800 92 ANNEX 3: SPV-WIND HYBRID POWER SYSTEMS Table A3.4: PV-wind Hybrid Power System Projected Generating Costs (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 36.1 41.8 48.9 31.6 37.8 44.5 28.1 34.8 40.9 100 kW 26.8 30.5 34.8 23.8 27.8 31.7 21.4 25.6 29.1 93 Annex 4 Solar-thermal Electric Power Systems ANNEX 4: SOLAR-THERMAL ELECTRIC POWER SYSTEMS Solar-thermal power generation technologies comprise several technically viable options for concentrating and collecting solar energy in densities sufficient to power a heat engine. These include parabolic dish collectors, parabolic trough collectors and central receivers. Only the parabolic trough configuration has found commercial application. Although several large solar thermal electric projects are in the planning stages, and other options are in the research and development stage, the amount of installed solar thermal electric capacity around the world is negligible compared with SPV or wind turbines. Only the parabolic trough-based solar-thermal electric system is considered for the present study. Technology Description The parabolic trough concentrator is essentially a trough lined with reflective material. The concentrators track the sun with a single-axis mechanical tracking system oriented east to west. The trough focuses the solar insolation on a receiver located along its focal line. A collector field consists of large number of concentrators sufficient to generate the required amount of thermal energy. A heat transfer fluid (or thermic fluid), typically high temperature oil, is circulated via pipes to the concentrators and the heated fluid is then pumped to a central power block, where it exchanges its heat to generate steam (Figure A4.1). The power block consists of steam turbine and generator, turbine and Figure A4.1: Solar-thermal Electric Power Plant Schematic Sunlight: 2.7 MWh/m2/yr System Boundary Substation Solar Field Solar Steam Turbine HTF Heater Superheater (optional) Boiler Fuel Condenser Thermal Fuel Energy (optional) Steam Generator Solar Preheater Deaerator Low-pressure Preheater Solar Reheater Expansion Vessel Source: DOE/EPRI. 97 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES generator auxiliaries, feed-water and condensate system. A variant of this technology is the direct solar steam (DSS) concentrator, which eliminates the heat transfer loop by generating steam directly at the concentrator. A solar thermal electric power plant can also have thermal storage, which improves the capacity factor but increases the cost. While both options are analyzed here, the present trend is to use the solar thermal plant without thermal storage in large, grid-connected applications. Economic Assessment The design and performance assumptions for solar thermal electric power projects are listed in Table A4.1. We assessed two configurations (with and without storage) but only one size range ­ 30 MW ­ which is typical of several projects under development in Spain and the MENA region.33 The capacity factor for solar thermal power projects is dependent on the availability of solar resource, especially in the case of plants without storage. A capacity factor of 20 percent was used for analysis of plants without thermal storage and 54 percent was used for analysis of plants with thermal storage.34 Table A4.1: Solar-thermal Electric Power System Design Assumptions Capacity 30 MW (without thermal storage) 30 MW (with thermal storage) Capacity Factor (%) 20 50 Life Span (year) 30 30 Gross Generated Electricity (GWh/year) 52 131 Table A4.2 provides a capital cost breakdown based on NREL data for solar thermal power projects with and without thermal storage, exclusive of land costs. 33See, for example, Project Information Document (PID) ­ Arab Republic of Egypt Solar Thermal Power Project. Report No. AB662 and Solar Thermal Power 2020: Exploiting the Heat from the Sun to Combat Climate Change, Greenpeace 2004. 34Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance Forecasts, NREL, NREL/SR-550-34440, October 2003. 98 ANNEX 4: SOLAR-THERMAL ELECTRIC POWER SYSTEMS Table A4.2: Solar-thermal Electric Power System 2005 Capital Costs (US$/kW) Items 30 MW (without thermal storage) 30 MW (with thermal storage) Equipment 890 1,920 Civil 200 400 Engineering 550 920 Erection 600 1,150 Process Contingency 240 460 Total 2,480 4,850 Harmful emissions and pollution impacts of solar thermal power generation are nil. Water requirements, mainly for the cooling towers, is an issue, as most potential sites for solar thermal power generation are in arid or desert areas. The generating cost (Table A4.3) is estimated using the capital costs in Table A4.2 and based on the performance parameters mentioned in Table A4.1. O&M costs are taken from NREL data. Table A4.3: Solar-thermal Electric Power 2005 Generating Costs (USą/kWh) Items 30 MW (without thermal storage) 30 MW (with thermal storage) Levelized Capital Cost 13.65 10.68 Fixed O&M Cost 3.01 1.82 Variable O&M Cost 0.75 0.45 Fuel Cost 0.00 0.00 Total 17.41 12.95 Future System Cost Projections The cost assessment report by NREL forecasts the possible cost reductions in the solar thermal power generation based on an analysis of technology improvement projections and scale-up. The projected reduction (15 percent by 2010 for the nonstorage configuration and 33 percent by 2015 for the storage case) is a result of lower solar collector system and mirror costs as well as cheaper storage costs due to technological improvements and economies of scale. These cost projections are shown in Table A4.4 and are taken forward into the uncertainty analysis. 99 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A4.4: Solar-thermal Electric Power Capital Costs Projections (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 30 MW 2,290 2,480 2,680 1,990 2,200 2,380 1,770 1,960 2,120 (without storage) 30 MW 4,450 4,850 5,240 3,880 4,300 4,660 3,430 3,820 4,140 (with storage) Uncertainty Analysis Solar thermal power plant capacity factor varies according to location; however, locating these large expensive plants in areas of high solar radiation will minimize any uncertainty associated with capacity factor. For our uncertainty analysis, we will allow the capacity factor to vary between 18 and 25 percent with 20 percent as the probable value for plants without storage and no variation in case of the plants with storage. Our uncertainty analysis for estimations of generation cost further assumes the capital cost variability shown in Table A4.4 and an assumed ±20 percent variation in operating costs. The results are shown in Table A4.5. Table A4.5: Solar-thermal Electric Power Generating Costs Projections (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 30 MW 14.9 17.4 21.0 13.5 15.9 19.0 12.4 14.5 17.3 (without storage) 30 MW 11.7 12.9 14.3 10.5 11.7 12.9 9.6 10.7 11.7 (with storage) 100 Annex 5 Geothermal Power Systems ANNEX 5: GEOTHERMAL POWER SYSTEMS Geothermal energy arises from the heat deep within the earth. Worldwide, the most accessible geothermal resources are found along the boundaries of the continental plates, in the most geologically active portions of the earth. Two primary types of geothermal resources are being commercially developed ­ naturally-occurring hydrothermal resources and engineered geothermal systems. Hydrothermal reservoirs consist of hot water and steam found in relatively shallow reservoirs, ranging from a few hundred to as much as 3,000 m in depth. Hydrothermal resources are the current focus of geothermal development because they are relatively inexpensive to exploit. A hydrothermal resource is inherently permeable, which means that fluids can flow from one part of the reservoir to another, and can also flow into and from wells that penetrate the reservoir. In hydrothermal resources, water descends to considerable depth in the crust where it is heated. The heated water then rises until it becomes either trapped beneath impermeable strata, forming a bounded reservoir, or reaches the surface as a hot spring or steam vent. The rising water brings heat from the deeper parts of the earth to locations relatively near the surface. The second type of geothermal resource is "engineered geothermal systems (EGS)," sometimes referred to as "Hot Dry Rocks (HDR)." These resources are found relatively deep in masses of rock that contain little or no steam, and are not very permeable. They exist in geothermal gradients, where the vertical temperature profile changes are greater than average (>50°C/km). A commercially attractive EGS would involve prospecting for hot rocks at depths of 4,000 m or more. To exploit the EGS resource, a permeable reservoir must be created by hydraulic fracturing, and water must be pumped through the fractures to extract heat from the rock. Most of the EGS/HDR projects to date have been essentially experimental; but there is future commercial potential. Commercial exploitation of geothermal systems in developing economies is constrained by two factors: · Geothermal exploration, as with most resource extraction ventures, is inherently risky. Geothermal power systems are difficult to plan because what lies beneath the ground is only poorly understood at the onset of development. It may take significant work to prove that in a particular field, and many exploration efforts have failed altogether. The exception is areas with many hydrothermal manifestations (for example, geysers, mud pots), such as The Geysers in the United States and a number of fields in Indonesia and Central America; and · Both exploration and development require substantial specialized technical capacity that is not usually available in developing countries unless there has been focused local 103 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES capacity-building or an influx of specialists and creation of local teams. Countries where such teams have been successful or are emerging include the Philippines, Mexico, Indonesia, Kenya and El Salvador. Technology Description For developing country applications, we assume that geothermal systems will be available in small sizes suitable for mini-grid applications and a larger size suitable for grid-electric applications: · For mini-grid applications, 200 kW binary hydrothermal; and · For grid applications, a 20 MW binary hydrothermal, and a 50 MW flash hydrothermal. Figure A5.1 provides a schematic for a binary hydrothermal electric power system of indeterminate size. Figure A5.2 provides a schematic for a flash hydrothermal unit. Figure A5.1: Binary Hydrothermal Electric Power System Schematic System Boundary Generator Interconnect Electricity Vapor HP Turbine Waste Heat Vapor Air-cooled Condenser Primary Heat Exchanger Liquid Working Fan Ambient Air Fluid Liquid Pump Brine Cooled Brine Injection Pump (Downhold Production Pumps) Production Wells Injection Wells Hot Fluid Geothermal Reservoir Cooled Fluid 104 ANNEX 5: GEOTHERMAL POWER SYSTEMS Figure A5.2: Flash Hydrothermal Electric Power System System Boundary Generator Interconnect Electricity Steam HP Turbine Steam LP Turbine Cooling Waste Heat and Tower Water Vapor HP Flash Condenser Tank Cooling Water G Liquid Hot Well Pump e o A LP Flash c Tank Gas Ejectors Noncondensible F i Gases l Excess d u Condensate Spent i Brine d Acid Brine Injection Pump Tank Production Wells Injection Wells Hot Fluid Geothermal Reservoir Cooled Fluid Source: DOE/EPRI. Environmental and Economic Assessment Table A5.1 provides the basic design and performance assumptions we associate with the binary hydrothermal and flash hydrothermal electric power project shown in Figures A5.1 and A5.2. Table A5.1: Basic Characteristics of Geothermal Electric Power Plants Binary Binary Flash Hydrothermal Hydrothermal Hydrothermal Plants Capacity 200 kW 20 MW 50 MW Capacity Factor (%) 70 90 90 Geothermal Reservoir Temperatures 125-170°C 125-170°C >170°C Life Span (year)* 20 30 30 Net Generated Electricity (MWh/year) 1,230 158,000 394,200 * Although the plant life span is 20-30 years, wells will be depleted and new wells will be drilled much before that time. An allowance for this additional drilling is included in the generating cost estimates. Large geothermal plants can generally operate as base-loaded facilities with capacity factors comparable to or higher than conventional generation (90 percent CF). Binary plants in mini-grid applications will have lower capacity factors (30-70 percent), due mainly to limitations in local demand. We consider only the high capacity factors for small binary 105 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES systems, as they will be the most cost-effective. The viability of the geothermal resource is dictated by local geological conditions. For this report, we assume that hot water resources can be categorized as being either high temperature (>170°C) or moderate temperature (<170°C and >125°C). Because they operate in a closed-loop mode, binary plants have no appreciable emissions, except for very slight leakages of hydrocarbon working fluids. Some emissions of H2S are possible (no more than 0.015 kg/MWh), but H2S removal equipment can easily eliminate any problem. CO2 emissions are small enough to make geothermal power a low CO2 emitter relative to fossil fuel plants. Table A5.2 shows the conventional breakdown of geothermal capital costs into the standard cost components used in this study. Table A5.2: Geothermal Electric Power Plant 2005 Capital Costs (US$/kW) Items 200 kW Binary Plant 20 MW Binary Plant 50 MW Flash Plant Equipment 4,350 1,560 955 Civil 750 200 125 Engineering 450 310 180 Erection 1,670 2,030 1,250 Total 7,220 4,100 2,510 Table A5.3 shows a breakdown in the capital cost estimates organized by the sequence of development activities, for example, exploration costs (to discover first productive well), confirmation costs (additional drilling to convince lenders that the site has commercial capability, main wells costs (remaining wells drilled during construction phase) and remaining costs associated with construction of the power plant itself. Table A5.3: Geothermal Capital Costs by Development Phase (US$/kW) Items 200 kW Binary Plant 20 MW Binary Plant 50 MW Flash Plant Exploration 300 320 240 Confirmation 400 470 370 Main Wells 800 710 540 Power Plant 4,250 2,120 1,080 Other 1,450 480 280 Total 7,200 4,100 2,510 106 ANNEX 5: GEOTHERMAL POWER SYSTEMS For the 200 kW binary projects, we set the contingency cost quite high, because very few projects of this size have been built. It is likely that the risk associated with such small projects would be unattractive for commercial firms, and thus a public sector entity would be the most likely implementing agency for such systems. Table A5.4 shows the results of converting capital cost into generating cost, in line with Annex 2. O&M costs are stated as fixed costs here because the truly variable costs, for example, lubricants, are very low. Most of the O&M is in labor for the power plant. O&M for binary systems includes replacement of downhole production pumps at three to four year intervals. Table A5.4: Geothermal Power Plant 2005 Generation Costs (USą/kWh) Items 200 kW Binary Plant 20 MW Binary Plant 50 MW Flash Levelized Capital Cost 12.57 5.02 3.07 Fixed O&M Cost 2.00 1.30 0.90 Variable O&M Cost 1.00 0.40 0.30 Total 15.57 6.72 4.27 Future Price of Geothermal Electric Power Plants It is difficult to predict future prices for geothermal power systems. There have been long-term trends (since 1980) of price declines, of about 20 percent per decade for power plants, and 10 percent per decade for geothermal production and injection wells (relative to petroleum wells). Recently, variations in oil prices have been so large that they obscure any useful projections in cost reductions of geothermal exploration or development. In fact, the recent increases in oil prices have driven up the apparent cost of geothermal wells in the United States in the past year. We assume a flat cost trajectory for this technology, as shown in Table A5.5. Table A5.5: Geothermal Power Plant Capital Costs Projections (US$/kW) 2005 2010 2015 200 kW Binary Plant 7,220 6,580 6,410 20 MW Binary Plant 4,100 3,830 3,730 50 MW Flash Plant 2,510 2,350 2,290 107 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Many industry analysts contend that geothermal R&D and improved economies of scale due to large-scale deployment can help the industry resume the downward trends seen since 1980. There may also be opportunities to locate binary systems in areas with shallow reservoirs, where the costs of drilling and well maintenance may be lower. The section on uncertainty analysis attempts to reflect this improvement potential through the quantification of a "minimum" capital cost. For the purpose of uncertainty analysis below, we draw from the EPRI work on RE to establish a range of expected capital cost reductions (generally, -20 percent and +10 percent) over the study period. Uncertainty Analysis Future Price of Geothermal Electric Power Plants The cost of geothermal power plants can be quite variable, depending on the specific resource that is being used. This fact is reflected in the range of capital costs presented in Table A5.6. Table A5.6: Geothermal Power Plant Capital Costs Uncertainty Range (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 200 kW 6,480 7,220 7,950 5,760 6,580 7,360 5,450 6,410 7,300 Binary 20 MW 3,690 4,100 4,500 3,400 3,830 4,240 3,270 3,730 4,170 Binary 50 MW 2,260 2,510 2,750 2,090 2,350 2,600 2,010 2,290 2,560 Flash Table A5.7 shows projected ranges in levelized generating cost given the capital cost ranges presented in Table A5.6, and the O&M costs presented in Table A5.4. Table A5.7: Geothermal Power Plant Projected Generating Costs (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 200 kW 14.2 15.6 16.9 13.0 14.5 15.9 12.5 14.2 15.7 Binary 20 MW 6.2 6.7 7.3 5.8 6.4 6.9 5.7 6.3 6.8 Binary 50 MW 3.9 4.3 4.6 3.7 4.1 4.4 3.6 4.0 4.4 Flash 108 Annex 6 Biomass Gasifier Power Systems ANNEX 6: BIOMASS GASIFIER POWER SYSTEMS Biomass gasification is the process through which solid biomass material is subjected to partial combustion in the presence of a limited supply of air. The ultimate product is a combustible gas mixture known as "producer gas." The combustion of biomass takes place in a closed vessel, normally cylindrical in shape, called a "gasifier." Producer gas typically contains N (50-54 percent), CO2 (9-11 percent), CH4 (2-3 percent), CO (20-22 percent) and H (12-15 percent). Producer gas has relatively low thermal value, ranging from 1,000- 1,100 kcal/m3 (5,500-MJ/m3) depending upon the type of biomass used. Gasification of biomass takes place in four distinct stages: drying, pyrolysis, oxidation/ combustion and reduction. Biomass is fed at the top of the hopper. As the gasifier is ignited in the oxidation zone, the combustion takes place and the temperature rises (900-1,200°C). As the dried biomass moves down, it is subjected to strong heating (200-600°C) in the pyrolysis zone. The biomass starts losing the volatiles at above 200°C and, continues until it reaches the oxidation zone. Once the temperature reaches 400°C, the structure of wood or other organic solids breaks down due to exothermic reactions, and water vapor, methanol, acetic acid and tars are evolved. This process is called pyrolysis. These products of pyrolysis are drawn toward the oxidation zone, where a calculated quantity of air is supplied and the combustion (similar to normal stove/furnace) takes place. A portion of pyrolysis gases and char burns here which raises the temperature to 900-1,200°C in the oxidation zone. Partial oxidation of biomass by gasifying agents (air or O2) takes place in the oxidation zone producing high temperature gases (CO2), also containing products of combustion, cracked and uncracked pyrolysis products, and water vapor (steam) which pass through the reduction zone consisting of a packed bed of charcoal. This charcoal is initially supplied from external sources, and, later, the char produced in the pyrolysis zone is simultaneously supplied. The reactions in the reduction zone are endothermic and temperature sensitive (600-900°C). The principal chemical reactions taking place in a gasifier are shown in Table A6.1. Table A6.1: Principle Chemical Reactions in a Gasifier Plant Reaction-type Reaction Enthalpy (kJ/mol) Devolatilization C+Heat = CH4 + Condensable Hydrocarbons + Char Steam-carbon C+H2O + Heat = CO+H2 131.4 Reverse Boudouard C + CO2 + Heat = 2CO 172.6 Oxidation C + O2 = Heat -393.8 Hydro Gasification C+ 2H2 = CH4 + Heat -74.9 Water Gas Shift H2O + CO = H2 + CO2 + Heat -41.2 Methanation 3H2 + CO = CH4 + H2O + Heat 4 H2 + -206.3 CO2 = CH4 + 2H2O + Heat -165.1 111 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES In the above reactions, devolatilization takes place in the pyrolysis zone, oxidation in the oxidation zone and all other reactions in the reduction zone. The low thermal value (about 10-15 percent of natural gas) of producer gas is mainly due to diluting effect of nitrogen (N) present in the combustion air. Since N is inert, it passes through the gasifier without entering into any major chemical reactions. An efficient gasifier produces a clean gas over a range of flow rates of gas. If all the above-mentioned processes take place efficiently, the energy content of the producer gas would contain about 70-78 percent of the energy content of the biomass entering the gasifier. The gasification process is influenced by two parameters ­ properties of the biomass and the gasifier design. Biomass properties such as energy content, density, moisture content, volatile matter, fixed carbon, ash content and also size and geometry of biomass affect the gasification process. The design of the oxidation zone is the most important, as the completion of each reaction depends on the residence time of biomass in the oxidation and reduction zones. Figure A6.1 shows the schematic of a gasifier-based power generation system. Figure A6.1: Biomass Gasifier Power System Schematic Gasifier Air Filter Heat Venturi Exchanger Cyclone Scrubber Paper Sand Filter Bed Mist Filter Cyclone Separator Engine with Alternator Wire Mesh Filter Source: DOE/EPRI. Biomass Gasifier Technology Assessment There are three main types of gasifiers ­ down draft, updraft and cross draft. In the case of down draft gasifiers, the flow of gases and solids occurs through a descending packed bed. The gases produced here contain the least amount of tar and PM. Downdraft gasification is fairly simple, reliable and proven for certain fuels. In case of updraft gasifiers, the gases 112 ANNEX 6: BIOMASS GASIFIER POWER SYSTEMS and solids have counter-current flow and the product gas contains a high level of tar and organic condensable. In the cross draft gasifier, solid fuel moves down and the airflow moves horizontally. This has an advantage in traction applications. But the product gas is, however, high in tars and requires cleaning. Other kinds of gasification technology include fluidized bed gasifiers and pyrolyzers. In a fluidized bed gasifier, the air is blown through a bed of solid particles at a sufficient velocity to keep them in a state of suspension. The bed is initially heated up and then the feedstock is introduced at the bottom of the reactor when the temperature of the reactor is quite high. The fuel material gets mixed up with the bed material and until its temperature is equal to the bed temperature. At this point the fuel undergoes fast pyrolysis reactions and evolves the desired gaseous products. Ash particles along with the gas stream are taken over the top of the gasifier and are removed from the gas stream, and the clean gas is then taken to engine for power generation. Economic and Environmental Assessment Table A6.2 gives details of the design and performance parameters we will assume for the economic assessment of biomass gasifier technology. Table A6.2: Biomass Gasifier System Design Assumptions Capacity 100 kW 20 MW Fuel Wood/Wood Waste/Agro Waste Wood/Wood Waste/Agro Waste Calorific Value of Fuel 4,000 kcal/kg 4,000 kcal/kg Capacity Factor 80% 80% Producer Gas Calorific Value 1,000-1,200 kcal/Nm3 1,000-1,200 kcal/Nm3 Life Span of System 20 Years 20 Years Specific Fuel Consumption 1.6 kg/kWh 1.5 kg/kWh Biomass gasifier projects are considered to be Greenhouse gases (GHG)-neutral, as there is sequestration of GHGs due to the growth of biomass feedstock ­ provided that the biomass used is harvested in a sustainable way. Environmental impacts associated with combustion of the biomass gas are assumed to be constrained by emissions control regulation, consistent with the World Bank standards. 113 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A6.3 shows the capital costs associated with biomass gasifier-based power plants of two representative sizes ­ 100 kW for mini-grids and 20 MW for large-scale grid-connected applications. Table A6.3: Biomass Gasifier Power System 2005 Capital Costs (US$/kW) Capacity 100 kW 20 MW Equipment Cost 2,490 1,740 Civil Cost 120 100 Engineering 70 40 Erection Cost 70 50 Process Contingency 130 100 Total Capital Cost 2,880 2,030 Fuel cost is the most important parameter in estimating the generation costs of any biomass-based power generation technology. The cost of biomass depends on many parameters, including project location, type of biomass feedstock, quantity required and present and future alternative use. Biomass fuel costs can vary widely; in this study we use a range from US$11.1/ton (US$0.64/GJ) to US$33.3/ton (US$1.98/GJ), with US$16.6/ton (US$0.99/GJ) as a probable value. Based on the design and performance parameters given in Table A6.2, the total generating cost can be estimated inclusive of O&M costs. Table A6.4 shows the results. Table A6.4: Biomass Gasifier Power System 2005 Generating Costs (USą/kWh) Capacity 100 kW 20 MW Capital 4.39 3.09 Fixed O&M Cost 0.34 0.25 Variable Cost 1.57 1.18 Fuel Cost 2.66 2.50 Total 8.96 7.02 114 ANNEX 6: BIOMASS GASIFIER POWER SYSTEMS Future Price and Uncertainty Analysis The future cost of these systems will likely be less than at present, as biomass gasification has considerable potential for technology improvement and economies of mass production. We assume that improvements in the areas of low tar-producing two-state gasifiers and improved cleaning and cooling equipment will yield an 8 percent reduction in capital costs by 2010 (Table A6.5). The range over which projected biomass gasifier generation costs can vary are primarily a result of uncertainty in future cost projections plus variations in fuel costs. We carried out an uncertainty analysis to estimate the range over which the generation costs could vary due to these variable parameters and the projected generating cost bands are provided in Table A6.6. Table A6.5: Biomass Gasifier Power System Capital Costs Projections (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Gasifier 2,490 2,880 3,260 2,090 2,560 2,980 1,870 2,430 2,900 100 kW Gasifier 1,760 2,030 2,300 1,480 1,810 2,100 1,320 1,710 2,040 20 MW Table A6.6: Biomass Gasifier Power Generating Costs Projections (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Gasifier 8.2 9.0 9.7 7.6 8.5 9.4 7.3 8.3 9.5 100 kW Gasifier 6.4 7.0 7.6 6.0 6.7 7.5 5.8 6.5 7.5 20 MW 115 Annex 7 Biomass-steam Power Systems ANNEX 7: BIOMASS-STEAM POWER SYSTEMS Biomass combustion technologies convert biomass fuels into several forms of useful energy including hot air, steam or power generation. Biomass-based power generation technologies can be classified as direct firing, gasification and pyrolysis. This section will cover the direct-fired biomass combustion-based electricity generation (see Figure A7.1). Technology Description A pile burner combustion boiler consists of cells, each with an upper and lower combustion chamber. Biomass burns on a grate in lower chamber, releasing volatile gases which then burn in the upper chamber. Current biomass combustor designs utilize high efficiency boilers and stationary or traveling grate combustors with automatic feeders that distribute the fuel onto a grate to burn. In stationary grate design, ashes fall into a pit for collection, whereas in traveling grate type the grate moves and drops the ash into a hopper. Figure A7.1: Biomass-steam Electric Power System Schematic Flue Gas Boiler Biomass Storage Steam Turbine Generator Preparation and Processing Air Water Pump FBC are the most advanced biomass combustors. In a FBC, the biomass fuel is in a small granular form (for example, rice husk) and is mixed and burned in a hot bed of sand. Injection of air into the bed creates turbulence, which distributes and suspends the fuel while increasing the heat transfer and allowing for combustion below the temperature normally resulting in NOx emissions. Combustors designed to handle high ash fuels and agricultural biomass residue have special features which handle slagging and fouling problems due to K, sodium (NA) and silica (SiO2) found in agricultural residues. 119 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Economic and Environmental Assessment The design and performance parameters assumed for biomass-steam power projects are given in Table A7.1. Note that only one size ­ large, grid-connected ­ is assessed. Such a large power system has a high capacity factor, assuming continuous availability of the biomass feedstock, comparable to that of a conventional central station power plant. Table A7.1: Biomass-steam Electric Power System Design Assumptions Biomass-steam Capacity 50 MW Capacity Factor (%) 80 Fuel Wood/Wood Waste/Agro Waste Calorific Value of Fuel 4,000 kcal/kg Specific Fuel Consumption 1.5 kg/kWh Life Span (year) 20 Gross Generated Electricity (GWh/year) 350 The biomass steam projects are considered to be GHG-neutral, as there is sequestration of CO2 due to the biomass cultivation, provided that the biomass used is harvested in a sustainable way. Table A7.2 gives the capital cost breakdown for a biomass steam power plant. Table A7.2: Biomass-steam Electric Power Plant 2005 Capital Costs (US$/kW) Items Cost Equipment 1,290 Civil 170 Engineering 90 Erection 70 Process Contingency 80 Total 1,700 120 ANNEX 7: BIOMASS-STEAM POWER SYSTEMS Based on the capacity factor and the life of the plant, the capital cost is annualized and the generating cost is estimated in Table A7.3. Table A7.3: Biomass-steam Electric Power Plant 2005 Generating Costs (USą/kWh) Capital 2.59 Fixed O&M 0.45 Variable O&M 0.41 Fuel 2.50 Total 5.95 Future Cost Projections and Uncertainty Analysis The future costs for biomass-steam generation projects are expected to drop as a result of increased market penetration and technology standardization. Cost reductions of about 10 percent by the year 2010 are expected and are reflected in Table A7.4. Table A7.4: Biomass-steam Electric Power Plant Projected Capital Costs (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Biomass-steam 1,500 1,700 1,910 1,310 1,550 1,770 1,240 1,520 1,780 50 MW The uncertainty analysis for generating cost was carried out using the range of present and future costs, as shown in Table A7.4. However, the key uncertainty in estimating the generation costs of any biomass-based power generation technology is the fuel cost. The cost of biomass depends on a large number of parameters including project location, type of biomass feedstock, quantity required and present and future alternative use. Biomass fuel costs can vary widely; in this study we use a range from US$11.1/ton (US$0.64/GJ) to US$33.3/ton (US$1.98/GJ), with US$16.6/ton (US$0.99/GJ) as probable value. An O&M cost variation of 20 percent was also assumed. Based on the cost projections, the generation cost for biomass steam power plant was estimated and shown in Table A7.5. The effect of variation in different cost components in the generation cost is shown in the tornado charts in Annex 4. 121 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A7.5: Biomass-steam Electric Power Projected Generating Costs (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Biomass-steam 5.4 6.0 6.5 5.2 5.7 6.4 5.1 5.7 6.6 50 MW 122 Annex 8 Municipal Waste-to-power System Using Anaerobic Digestion ANNEX 8: MUNICIPAL WASTE-TO-POWER SYSTEM USING ANAEROBIC DIGESTION MSW contains significant portions of organic materials that produce a variety of gaseous products when dumped, compacted and covered in landfills. Anaerobic bacteria thrive in the oxygen(O)-free environment, resulting in the decomposition of the organic materials and the production of primarily CO2 and CH4. CO2 is likely to leach out of the landfill because it is soluble in water. CH4, on the other hand, which is less soluble in water and lighter than air, is likely to migrate out of the landfill. Landfill gas energy facilities capture CH4 (the principal component of natural gas) and combust it for energy. Figure A8.1 shows a schematic diagram of a landfill-based municipal waste-to-energy operation. Figure A8.1: Municipal Waste-to-power System Schematic MSW Landfill Site CH4-CO2 Gas Capture Pipelines LPG LPG Flare Stack Blower Gas Treatment Gas Equipment Holder Self-consumption LPG Self-consumption CH4-CO2 Supplied to G Supplied to Landfill Thermal Gas Engine Thermal Electric Landfill Electric Energy Demand Energy Power Demand Cogeneration System Source: The Ministry of Environment, Government of Japan. Technology Description The biogas comprises CH4, CO2, H and traces of H2S. The biogas yield and the CH4 concentration depend on the composition of the waste and the efficiency of the chemical and collection processes. The biogas produced is either used for thermal applications, such replacing fossil fuels in a boiler, or as a replacement for liquefied petroleum gas (LPG) for cooking. The biogas after treatment can also be used in gas engines to generate electric power. 125 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Environmental and Economic Assessment We assume the design and performance parameters listed in Table A8.1 in the economic assessment. Table A8.1: Municipal Waste-to-power System Design Assumptions Capacity 5 MW Capacity Factor (%) 80 Fuel-type Municipal Solid Waste Life Span (year) 20 Gross Generated Electricity (GWh/year) 35 Since the gas (mainly CH4) derived from the waste is used for power generation, the emissions will be below the prescribed standards. Waste-to-energy projects result in net GHG emission reductions, since CH4 emissions that might otherwise emanate from landfill sites are avoided. Table A8.2 gives the capital cost breakdown for a typical MSW plant of indeterminate size. Table A8.2: Municipal Waste-to-power System 2005 Capital Costs (US$/kW) Items Cost Equipment 1,500 Civil 900 Engineering 90 Erection 600 Contingency 160 Total 3,250 Using the assumed capacity factor and plant life span, we annualized the capital cost and add O&M costs to produce the estimate of generating cost shown in Table A8.3. Note that there is no fuel cost, as we assume the feedstock MSW will be provided free of charge. However, provision for royalties to an assumed municipal corporation from the sale of electricity and manure is included under variable costs. 126 ANNEX 8: MUNICIPAL WASTE-TO-POWER SYSTEM USING ANAEROBIC DIGESTION Table A.8.3: Municipal Waste-to-power System 2005 Generating Costs (USą/kWh) Capital 4.95 Fix O&M 0.11 Variable O&M 0.43 Fuel 1.00 Total 6.49 Future Cost Projections and Uncertainty Analysis There will be a decrease in future of the capital cost as well as generating costs of waste-to-power systems. We assume these trends will result in a decrease in equipment cost of 15 percent by 2015. The uncertainty analysis for the generation cost was carried out using the range of expected capital and O&M, as shown in Table A8.4. Table A8.4: Municipal Waste-to-power System Projected Capital Costs (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max MSW 2,960 3,250 3,540 2,660 2,980 3,270 2,480 2,830 3,130 Based on the capital cost projections, the generating cost for MSW plant was estimated and shown in Table A8.5. The effect of uncertainty in different cost components on the generation cost is shown in the tornado charts given in Annex 4. Table A8.5: Municipal Waste-to-power Projected Generating Costs (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max MSW 6.0 6.5 7.0 5.6 6.1 6.6 5.3 5.9 6.4 127 Annex 9 Biogas Power Systems ANNEX 9: BIOGAS POWER SYSTEMS Biogas generation is a chemical process whereby organic matter is decomposed. Slurry of cow dung and other similar feedstock is retained in the biogas plant for a period of time called the hydraulic retention time (HRT) of the plant. When organic matter like animal dung, human excreta, leafy plant materials, and so on, and so forth, are digested anaerobically (in the absence of O), a highly combustible mixture of gases comprising 60 percent CH4 and 37 percent CO2 with traces of SO2 and 3 percent H is produced. A batch of 25 kg of cow dung digested anaerobically for 40 days produces 1 m3 of biogas with a calorific value of 5,125 kcal/m3. The remaining slurry coming out of the plant is rich in manure value and useful for farming purposes. Technology Description Biogas plants are designed in two distinct configurations ­ the floating drum-type and the fixed dome-type. The floating drum plant (Figure A9.1) consists of a masonry digester and a metallic dome, which functions as a gas holder. The plant operates at a constant gas pressure throughout, that is, the gas produced is delivered at the point of use at a predetermined pressure. The gas holder acts as the lid of the digester. When gas is produced in the digester, it exerts upward pressure on the metal dome which moves up along the central guide pipe fitted in a frame, which is fixed in the masonry. Once this gas is taken out through the pipeline, the gas holder moves down and rests on a ledge constructed in the digester. Thus, a constant pressure is maintained in the system at all times. There is always sufficient slurry liquid in the annulus to act as a seal, preventing the biogas from escaping through the bottom of the gas holder. Figure A9.1: Floating Drum Biogas Plant View Outlet Inlet Tank Tank Gas Outlet Filling Guide Plate Frame Frange 131 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES In the fixed dome plant (Figure A9.2), the digester and the gas holder (or the gas storage chamber) form part of an integrated brick masonry structure. The digester is made of a shallow well having a dome shaped roof. The inlet and outlet tanks are connected with the digester through large chutes (inlet and outlet displacement chambers). The gas pipe is fitted on the crown of the dome and there is an opening on the outer wall of the outlet displacement chamber for the discharge of spent mass (digester slurry). The output of the biogas plant can be used for cooking or any other thermal application. For this assessment we consider the biogas plant output to be power generation. Environmental and Economic Assessment The design and performance assumptions for the biogas-based power generation are given in Table A9.1. We assume a biogas system sized to provide sufficient power for a 60 kW engine. We assume a capacity factor of 80 percent, which is achieved by properly sizing the plant and ensuring sufficient feedstock into the biogas system. Figure A9.2: Fixed Dome Biogas Plant View Mixing Tank Dome Roof Gas Outlet Pipe Inlet Outlet Displacement Displacement Chamber Chamber Gas Storage Chamber Inlet Outlet Chute Chute Fermentation Chamber Table A9.1: Biogas Power System Design Assumptions Capacity 60 kW Capacity Factor (%) 80 Life Span (year) 20 Gross Generated Electricity 0.42 GWh 132 ANNEX 9: BIOGAS POWER SYSTEMS The biogas is mainly CH4 and, thus, when combusted, will generate CO2 emissions. However, the use of cow dung as an input means the CH4 which would have been produced from the cow dung is replaced with CO2, which has only a fraction of the GHG impact as the captured and combusted CH4. Table A9.2 shows the capital costs assumed for the biogas power generation project. Table A9.2: Biogas Power System 2005 Capital Costs (US$/kW) Items 60 kW Equipment 1,180 Civil 690 Engineering 70 Erection 430 Contingency 120 Total 2,490 Table A9.3 shows the generating cost based on the capital costs of Table A9.2 and the design and performance parameters in Table A9.1. Table A9.3: Biogas Power System 2005 Generating Costs (USą/kWh) Items 60 kW Levelized Capital Cost 3.79 Fixed O&M Cost 0.34 Variable O&M Cost 1.54 Fuel Cost 1.10 Total 6.77 133 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Future Cost Projections and Uncertainty Analysis Biogas technology is very simple, uses local resources and has been in commercial operation for a long time.35 Thus, it is expected that the costs would not change over time (as the capital costs projects are in 2004 US$), as shown in Table A9.4. Table A9.4: Biogas Power System Capital Costs Projections (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Biogas 2,260 2,490 2,790 2,080 2,330 2,570 2,000 2,280 2,540 60 kW An uncertainty analysis for future biogas power system generation cost was carried out using the range of likely variation in future costs, mainly the equipment costs and an assumed ±20 percent variation in O&M cost. The uncertainly analysis results are shown in Table A9.5. Table A9.5: Biogas Power System Generating Costs Projections (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Biogas 6.3 6.8 7.2 6.0 6.5 7.1 5.9 6.5 7.1 60 kW 35For example, the Indian biogas program started in 1973. 134 Annex 10 Micro- and Pico-hydroelectric Power Systems ANNEX 10: MICRO- AND PICO-HYDROELECTRIC POWER SYSTEMS Micro-hydro and pico-hydro power projects are usually RoR schemes which operate by diverting part or all of the available water flow by constructing civil works, for example, an intake weir, fore bay and penstock (note: pico-hydro units do not have a penstock). Water flows through the civil works into a turbine, which drives a generator producing electricity. The water flows back into the river through additional civil works (the tail race). The RoR schemes require no water catchments or storage, and thus have minimal environmental impacts. The main drawback of RoR hydro projects are seasonal variation in flow, which make it difficult to balance load and power output on an annual basis. Micro- and pico-hydro systems can be built locally at low cost, and their simplicity gives rise to better long-term reliability. They can provide a source of cheap, independent and continuous power, without degrading the environment. Figure A10.1 shows a typical micro-hydro configuration. Figure A10.1: Typical Micro-hydroelectric Power Scheme Intake Water Penstock Transmission Lines Transformer Tailrace Power House Source: http://www.microhydropower.net/. Technology Description A micro-hydroelectric power project comprises two principle components: civil works and electro-mechanical equipment. 137 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES The civil works include: · The weir, a simple construction that provides a regulated discharge to the feeder channel; · The feeder channel, constructed of concrete with desilting tanks along its length; · The fore bay, an open concrete or steel tank designed to maintain a balance in the power output by providing a steady design head for the project; and · The penstock, simply a steel, concrete or PVC pipe sized to provide a steady and laminar water flow into the turbine. The electro-mechanical works include: · A turbine sized according to the design head and water flow available, typically a Pelton or Turgo design for high-head applications and a Kaplan or Francis design for low-head applications; · A generator, usually a synchronous design for larger micro-hydro sites and self-excited induction design for low-power and pico-hydro applications; and · A governor, usually an electronic load governor or electronic load controller, depending on whether the turbine and generator operate on full or varying load conditions. A pico-hydroelectric power plant is much smaller than a micro-hydro (for example, 1 kW or 300 W), and incorporates all of the electro-mechanical elements into one portable device. A pico-hydro device is easy to install: A 300 W-class pico-hydroelectric can be installed by the purchaser because of the low (1-2 m) required waterhead, whereas, a 1 kW pico- hydroelectric requires a small amount of construction work because of the higher (5-6 m) required waterhead but provides a longer and more sturdy product life span. They are typically installed on the river or stream embankment and can be removed during flood or low flow periods. The power output is sufficient for a single house or small business. Earlier, pico-hydro devices were not equipped with any voltage or load control, which was a drawback as it produced lighting flicker and reduced appliance life. Newer pico-hydro machines come with embedded power electronics to regulate voltage and balance loads. Economic Assessment Table A10.1 gives the details on the design and performance assumptions used to assess micro- and pico-hydroelectric power projects. We selected three design points ­ a micro-hydro scheme of 100 kW and two pico-hydro schemes of 1 kW and 300 W respectively. There is a very large variation in the capacity factor depending upon the site conditions, which will be taken into account in the uncertainly analysis. In the case of off-grid and mini-grid applications demand requirements are also a limiting factor. Most of these projects 138 ANNEX 10: MICRO- AND PICO-HYDROELECTRIC POWER SYSTEMS work on full load, single point operation but for a limited period of time each day, so we assume an average capacity factor of 30 percent. Table A10.1: Micro/Pico-hydroelectric Power Plant Design Assumptions Capacity 300 W 1 kW 100 kW Capacity Factor (%) 30 30 30 Source River/Tributary River/Tributary River/Tributary Life Span (year) 5 15 30 Gross Generated Electricity (kWh/year) 788.4 2,628 26,280 The cost estimations shown in Table A10.2 are drawn from numerous sources, principally Vietnam and the Philippines. Table A10.2: Micro/Pico-hydroelectric Power Plant 2005 Capital Costs (US$/kW) Items/Models 300 W 1 kW 100 kW Equipment 1,560 1,960 1,400 Civil ­ 570 810 Engineering ­ ­ 190 Erection ­ 140 200 Total 1,560 2,670 2,600 Note: "­" means no cost needed. Table A10.3 shows the generation costs for micro/pico-hydro power calculated as per the methodology described in Section 2. Table A10.3: Micro/Pico-hydroelectric Power 2005 Generating Costs (USą/kWh) Items/Models 300 W 1 kW 100 kW Levelized Capital Cost 14.24 12.19 9.54 Fixed O&M Cost 0.00 0.00 1.05 Variable O&M Cost 0.90 0.54 0.42 Fuel Cost 0.00 0.00 0.00 Total 15.14 12.73 11.01 139 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Future Cost and Uncertainty Analysis There has been very little variation in the equipment cost of micro- and pico-hydroelectric equipment. We, therefore, assume that the capital costs for pico/mini-hydro technology will remain constant over the study period. An uncertainty analysis was carried out to estimate the range over which the generation cost could vary as a result of uncertainty in costs as well as variability in the capacity factor. The capacity factor will vary widely depending upon the availability of hydro resource and the quality of the sizing and design process. We assume well-designed and well-sited schemes that would have lower capacity factor variability, 25 percent to 35 percent, with 30 percent as probable capacity factor. We allowed capital costs and O&M costs to vary across the range ±20 percent (Table A10.4). Table A10.4: Micro/Pico-hydroelectric Power Capital Costs Projections (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 1,320 1,560 1,800 1,190 1,485 1,770 1,110 1,470 1,810 1 kW 2,360 2,680 3,000 2,190 2,575 2,950 2,090 2,550 2,990 100 kW 2,350 2,600 2,860 2,180 2,470 2,750 2,110 2,450 2,780 The generation costs estimated based on the cost projections in Table A10.4 and the design parameters in Table A10.1 are shown in Table A10.5. The sensitivity of generation cost to parametric variation in the form of tornado charts is given in Annex 4. Table A10.5: Micro/Pico-hydroelectric Power Generating Costs Projections (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 12.4 15.1 18.4 11.4 14.5 18.0 10.8 14.3 18.2 1 kW 10.7 12.7 15.2 10.1 12.3 14.8 9.7 12.1 14.9 100 kW 9.6 11.0 12.8 9.1 10.5 12.3 8.9 10.5 12.3 140 Annex 11 Mini-hydroelectric Power Systems ANNEX 11: MINI-HYDROELECTRIC POWER SYSTEMS As with micro/pico-hydro, mini-hydroelectric power schemes are usually "RoR" designs which operate by diverting the stream or river flow via civil works. A mini-hydro scheme is based on the same basic design principles and comprises the same major civil and electro-mechanical components as a micro/pico-hydro scheme. These projects do not require dams or catchments, which is preferable from an environmental point of view. Mini-hydro technology is well established around the world, and has found favor with private investors. The systems are simple enough to be built locally at low cost and have simple O&M requirements, which gives rise to better long-term reliability. These systems are highly bankable and provide a source of cheap, independent and continuous power, without degrading the environment. Larger mini-hydro projects are envisaged for grid-connected applications, while smaller mini-hydro projects are suitable for mini-grids. Technology Description A mini-hydroelectric power project comprises two principle components: · Civil works; and · Electro-mechanical equipment. The civil works include: · The weir, a simple construction that provides a regulated discharge to the feeder channel; · The feeder channel, constructed of concrete with desilting tanks along its length; · The fore bay, an open concrete or steel tank designed to maintain a balance in the power output by providing a steady design head for the project; and · The penstock, simply a steel, concrete or PVC pipe sized to provide a steady and laminar water flow to the turbine. The electro-mechanical works include: · A turbine sized according to the design head and water flow available, typically a Pelton or Turgo design for high-head applications and a Kaplan or Francis design for low-head applications; · A generator, usually a synchronous design for larger micro-hydro sites and self-excited induction design for low-power and pico-hydro applications; and · A governor, usually an electronic load governor or electronic load controller, depending on whether the turbine and generator operate on full or varying load conditions. 143 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Economic Assessment We selected a representative mini-hydroelectric power plant of 5 MW for the economic assessment. Table A11.1 gives the design and performance assumptions. A properly-sited, well-designed mini-hydro project should have a capacity factor of 45 percent on average.36 Table A11.1: Mini-hydroelectric Power Plant Design Assumptions Capacity 5 MW Capacity Factor (%) 45 Source River/Tributary Auxiliary Power Ratio (%) 1 Life Span (year) 30 Gross Generated Electricity (GWh/year) 19.71 The capital cost of mini-hydro projects is very site-specific, and can range between US$1,400/kW and US$2,200/kW. The probable capital cost is US$1,800/kW. Table A11.2 shows a breakdown of the probable capital cost for a 5 MW mini-hydro power project. Table A11.2: Mini-hydroelectric Power Plant 2005 Capital Costs (US$/kW) Capacity 5 MW Equipment 990 Civil 1,010 Engineering 200 Erection 170 Total 2,370 Following the methodology described in Section 2, we can estimate the generation costs on a levelized basis (Table A11.3). 36Based on several sources: (i) inputs from Alternate Hydro Energy Centre (AHEC), Roorkee; (ii) Small Hydro Power: China's Practice ­ Prof Tong Jiandong, Director General, IN-SHP; and (iii) Blue AGE Report, 2004 ­ A strategic study for the development of Small Hydro Power in the European Union, published by European ESHA. 144 ANNEX 11: MINI-HYDROELECTRIC POWER SYSTEMS Table A11.3: Mini-hydroelectric Power Plant 2005 Generating Costs (USą/kWh) Items/Models 5 MW Levelized Capital Cost 5.86 Fixed O&M Cost 0.74 Variable O&M Cost 0.35 Fuel Cost 0.00 Total 6.95 Future Cost and Uncertainty Analysis The actual equipment cost of the technologies described above has not changed over the past five years; therefore, we assume mini-hydro equipment costs will remain constant over the study period. An uncertainty analysis was carried out to estimate the range over which the generation cost could vary as a result of uncertainty in costs as well as variations in capacity factor. The capacity factor would vary depending upon the availability of hydro resource and reliability of the electro-mechanical works. Depending upon the location, the capacity factor for mini-hydro plants vary in the range from 35 percent to 55 percent, with 45 percent as probable capacity factor. Assuming a ±10-15 percent variation in projected capital costs (Table A11.4) range together with O&M costs varied ±20 percent we can carry out our uncertainty analysis, the results of which are shown in Table A11.5. Table A11.4: Mini-hydroelectric Power Plant Capital Costs Projections (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 5 MW 2,140 2,370 2,600 2,030 2,280 2,520 1,970 2,250 2,520 Table A11.5: Mini-hydroelectric Power Generating Costs Projections (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 5 MW 5.9 6.9 8.3 5.7 6.7 8.1 5.6 6.6 8.0 145 Annex 12 Large-hydroelectric Power and Pumped Storage Systems ANNEX 12: LARGE-HYDROELECTRIC POWER AND PUMPED STORAGE SYSTEMS Unlike mini-, micro-, and pico-hydro schemes, large hydroelectric projects typically include dams and catchments for water storage in order to assure a very high capacity factor consistent with the very high construction costs of these facilities. The characteristics and costs of large hydroelectric power plants are greatly influenced by natural site conditions. Technology Description The distinguishing characteristic of large hydroelectric and large pumped storage projects is the dam design, which generally falls into three categories ­ gravity concrete dams, fill dams and arch concrete dams: · In a gravity concrete dam, the structure supports external force using the weight of concrete. Structurally this is a simple system with broad applicability to topographic conditions and excellent earthquake resistance; · A fill dam consists of accumulated rock and soil as the main structural material. It can be built on sites where the foundation is poor, and can accommodate flexibility in design depending on the soil and stone materials available; and · An arch-type concrete dam utilizes the geometric form of the dam to economize on the amount on concrete required. It is generally restricted to narrow valleys. The intake system determines the amount of pressure head and the way in which water flows to the hydroelectric turbines. There are two types of intake systems, dam-type and dam-conduit type: · A dam-type intake system obtains its head by the rise in the reservoir water surface level. The hydroelectric power plants are installed directly under the dam, which allows effective use of water and no need for a feed channel; and · A dam-conduit type stores the water in a high dam and water is introduced to the hydroelectric power plant via a feed channel (Figure A12.1). There are three types of power generation systems ­ reservoir, pondage and pumped storage: · The reservoir power generation system employs a reservoir such as an artificial dam or a natural lake. The water storage provided by the reservoir allows water level adjustment in accordance with seasonal flux in water inflow and power output; · A pondage-type power generation system uses a regulating pond capable of adjusting for daily or weekly flux; and · A pumped storage power generation scheme is a specialized scheme in which several power plants are used to optimize the power output in accordance with diurnal variation in system load. In this scheme the hydroelectric power plant acts both as a generator and a pump, allowing water in a lower reservoir to be pumped up to the upper reservoir during the low-load overnight period, and then generating electricity during peak load periods. 149 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Figure A12.1: Conduit-type Intake System for a Large Hydroelectric Power Plant Dam and Spillway Intake Tower Pipeline Penstock Tunnel Pipeline Surge Tank Power House Surge Tank Intake Tower Head H.W. Water Elevation Penstock Rock Pipeline Tunnel Tail Water Economic Assessment We will assess two cases ­ a 100 MW conventional hydroelectric facility and a 150 MW pumped storage hydroelectric facility. Design characteristics and performance parameters for the two cases are shown in Table A12.1. Table A12.1: Large-hydroelectric Power Plant Design Assumptions Items Conventional Large-hydroelectric Pumped Storage Hydroelectric Capacity 100 MW 150 MW Capacity Factor 50% 10% Dam-type Gravity Concrete Gravity Concrete Turbine-type Francis Francis Reversible Pump Turbine Power Generation System Pondage Pumped Storage Auxiliary Power Ratio37 0.3% 1.3% Life Span (year) 40 40 37Auxiliary power electricity in a hydro power plant is used for drainage system, cooling system, hydraulic system, switchboard system, motors, air-conditioning, lighting and so on, and so forth. Auxiliary power electricity ratio (= auxiliary power electricity/generating electricity) of the electric power used for these is an average of 0.5 percent or less in large hydro-type. 150 ANNEX 12: LARGE-HYDROELECTRIC POWER AND PUMPED STORAGE SYSTEMS The capital cost of hydroelectric power plants comprises civil costs (dam, reservoir, channel, power plant house, and so on, and so forth), electric costs (water turbine, generator, substation, and so on, and so forth), and other. The capital costs of large hydro power plants is dominated by the civil works. Table A12.2 shows the estimated capital costs for the two large hydroelectric power cases assessed here. Table A12.2: Large-hydroelectric Power Plant 2005 Capital Costs (US$/kW) Items Large-hydro Pumped Storage Hydro Equipment 560 810 Civil 1,180 1,760 Engineering 200 300 Erection 200 300 Total 2,140 3,170 The generating cost of a hydro power plant (Table A12.3) is calculated by levelizing the capital costs and adding additional O&M components, per the method described in Section 2. The costs of large hydroelectric power plants are not expected to decrease in future, and are assumed constant over the study life as shown in Table A12.4. Table A12.3: Large-hydroelectric Power Plant 2005 Generating Costs (USą/kWh) Items Large-hydro Pumped Storage Hydro Levelized Capital Cost 4.56 34.08 Fixed O&M Cost 0.50 0.32 Variable O&M Cost 0.32 0.33 Total 5.38 34.73 Table A12.4: Large-hydroelectric Power Plant Capital Costs Projections (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Large-hydro 1,930 2,140 2,350 1,860 2,080 2,290 1,830 2,060 2,280 Pumped 2,860 3,170 3,480 2,760 3,080 3,400 2,710 3,050 3,380 Storage Hydro 151 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Uncertainty Analysis An uncertainty analysis was carried out assuming that all cost data as well as capacity factor is variable within a ±20 percent range.38 The analysis results are shown in Table A12.5 below. Table A12.5: Large-hydroelectric Power Generating Costs Projections (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Large-hydro 4.6 5.4 6.3 4.5 5.2 6.2 4.5 5.2 6.2 Pumped 31.4 34.7 38.1 30.3 33.8 37.2 29.9 33.4 36.9 Storage Hydro Environmental Impact Environmental preservation is a key element in developing a hydro power plant and often dictates many details of construction and operation. It is necessary to investigate, predict and evaluate the potential environmental impact, both during construction and operation, and to take sufficient safeguard measures to prevent adverse environmental and social impacts including sediment transport and erosion, relocation of populations, impact on rare and endangered species, loss of livelihood and passage of migratory fish species in hydro power plant. 38Except civil costs, which are allowed to vary ±30 percent, and the capacity factor of large-hydro, which is constrained to only vary ±10 percent. 152 Annex 13 Diesel/Gasoline Engine-generator Power Systems ANNEX 13: DIESEL/GASOLINE ENGINE-GENERATOR POWER SYSTEMS Diesel and gasoline engines (both characterized as internal combustion [IC] engines) can accommodate power generation needs over a wide size range, from several hundred watts to 20 MW. Features including low initial cost, modularity, ease of installation and reliability have led to their extensive use in both industrial and developing countries. A typical configuration is an engine/generator set, where gasoline and diesel engines basically indistinguishable from their counterparts in transportation vehicles are deployed in a stationary application. However, in many developing countries, slower speed diesel engines burning heavier and more polluting oils (for example, residual oil or mazout) are used. Technology Description A gasoline engine generator is lightweight, portable and easy to install and operate ­ all important characteristics for off-grid electrification. However, as shown in Table A13.1, it is not as efficient as a diesel generator, and the fuel costs are somewhat higher. A diesel generator includes the core of the diesel engine (prime mover), a generator and some auxiliary equipment, such as fuel-feed equipment, air intake and exhaust equipment, cooling equipment, lubricating equipment and starting equipment (Figure A13.1). A diesel generator has an efficiency of 35-45 percent, and can use a range of low-cost fuels, including light oil, heavy oil, residual oil and even palm or coconut oil, in addition to diesel. However, since the diesel equipment is heavier than a gasoline engine generator, it is mostly deployed in stationary applications. A diesel engine also has a wide capacity range, from 2 kW to 20 MW. Table A13.1: Characteristics of Gasoline and Diesel Generators Gasoline Generator Diesel Generator Thermal Efficiency (% LHV) <27 30-45 Generating Capacity <5 kW 2 kW-20,000 kW Fuel-type Gasoline Light Oil, Fuel ­ A, B, C Residual Oil In this section, we will consider four typical size diesel engines (300 W, 1 kW, 100 kW and 5 MW), which has seen a great number of installations for rural electrification in many countries including the Philippines and Indonesia. 155 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Figure A13.1: Diesel-electric Power Plant Schematic Air Starting Unit Fuel Tank Air Receiver Fuel Tank Air Compressor Radiator Diesel Engine Stack Generator P Cooling Water Pump P PM-filter Silencer Lubricating Oil De-SOx Pump De-Nox Environmental and Economic Assessment We have chosen four "typical diesel plants" to assess their economic effectiveness: a 300 W and a 1 kW gasoline engine generator, and a 100 kW and a 5 MW diesel engine generator. The type of engine and fuel reflect available commercial products. The design and operating parameters for each case are shown in Table A13.2. Table A13.2: Gasoline and Diesel Power System Design Assumptions 300 W (Off-grid) 1 kW (Off-grid) 100 kW (Mini-grid) 5 MW (Grid) Capacity Factor (%) 30 30 80 80/10 Engine-type Gasoline Gasoline Diesel Diesel Fuel-type Gasoline Gasoline Light Oil Residual Oil Thermal Efficiency (LHV, %) 13 16 38 43 Life Span (year) 10 10 20 20 Generated Electricity (GWh/year) 0.0008 0.003 0.7 35.0/4.4 As Table A13.2 indicates, the smaller engines are assigned a capacity factor of 30 percent. The larger engines are assigned a capacity factor of 80 percent, based on 14 hours/day of 100 percent rated output and 10 hours/day of 50 percent rated output. The 5 MW diesel plants are also considered as peaking (with 10 percent capacity factor) in grid-connected applications. 156 ANNEX 13: DIESEL/GASOLINE ENGINE-GENERATOR POWER SYSTEMS Small-sized gasoline generators are assumed to have a 10-year life span reflecting frequent start-up/shut-downs, as well as the low maintenance common in most applications. The larger diesel units are assigned an operating life of 20 years. Emissions from IC engines are shown in Table A13.3 assuming fuel properties typically used in India. Emission control equipment costs are included in the capital cost for the two diesel generator cases. Table A13.3: Air Emission Characteristics of Gasoline and Diesel Power Systems Emission Standard Typical Emissions Gasoline Engine Diesel Engine 300 W 1 kW 100 kW 5 MW PM 50 mg/Nm3 Zero Zero 80-120 100-200 SOx 2,000 mg/Nm3 Very Small Very Small 1,800-2,000 4,400-4,700 (<500 MW:0.2tpd/MW) NOx Oil: 460 1,000-1,40039 1,600-2,000 CO2 g-CO2/net-kWh 1,500-1,900 650 Emissions control equipment is required Table A13.4 shows the capital cost40 of gasoline and diesel engine generators. Note that 300 W and 1 kW engines are portable, so only the equipment cost is included. Table A13.4: Gasoline and Diesel Power System 2005 Capital Costs (US$/kW) Items 300 W 1 kW 100 kW 5 MW Equipment 890 680 600 510 Civil ­ ­ 10 30 Engineering ­ ­ 10 30 Erection ­ ­ 20 30 Total 890 680s 640 600 Note: "­" means no cost needed. 39The two smallest gasoline engine generators emit NOx beyond the World Bank's standard. However, since it is not realistic to add removal equipment to these small generators in order to follow a guideline strictly, cost for De-NOx equipment is not included. 40 The follow-up study on the effective use of captive power in Java-Bali Region, Japan International Cooperation Agency (JICA), November 2004. 157 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A13.5 shows the levelized generating costs, in line with the methodology described in Chapter 2. No fixed O&M cost is included for the small, portable gasoline engines. Table A13.5: Gasoline and Diesel Power System 2005 Generating Costs (USą/kWh) Items 300 W 1 kW 100 kW 5 MW CF=30% CF=30% CF=80% CF=80% CF=10% Levelized Capital Cost 5.01 3.83 0.98 0.91 7.31 Fixed O&M Cost ­ ­ 2.00 1.00 3.00 Variable O&M Cost 5.00 3.00 3.00 2.50 2.50 Fuel Cost 54.62 44.38 14.04 4.84 4.84 Total 64.63 51.21 20.02 9.25 17.65 Note: "­" means no cost needed. Future Cost and Uncertainty Analysis As is the case with all power generation options, the costs of power plants are site-specific; they also vary from country to country and from manufacturer to manufacturer. Table A13.6 and Table A13.7 provide the projected range of capital and generating costs at present, and in the future. Table A13.6: Gasoline and Diesel Power System Projected Capital Costs (US$/kW) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 750 890 1,030 650 810 970 600 800 980 1 kW 570 680 790 500 625 750 470 620 770 100 kW 550 640 730 480 595 700 460 590 720 5 MW 520 600 680 460 555 650 440 550 660 158 ANNEX 13: DIESEL/GASOLINE ENGINE-GENERATOR POWER SYSTEMS Table A13.7: Gasoline/Diesel Power System Projected Generating Costs (USą/kWh) Capacity 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 W 59.0 64.6 72.5 52.4 59.7 71.8 52.5 60.2 75.0 1 kW 46.7 51.2 57.6 41.4 47.3 57.1 41.5 47.7 59.7 100 kW 18.1 20.0 23.1 16.6 19.0 23.3 16.7 19.2 24.3 5 MW (Base) 8.3 9.3 10.8 7.6 8.7 10.8 7.6 8.8 11.3 5 MW (Peak) 16.2 17.7 19.6 15.0 16.7 19.1 14.9 16.7 19.6 159 Annex 14 Combustion Turbine Power Systems ANNEX 14: COMBUSTION TURBINE POWER SYSTEMS Oil and Gas CT and CCGT power plants are considered together. The common element of these plants is the use of the gas turbine, most commonly burning natural gas but in some cases distillate or heavy oil. Open cycle plants utilize only a gas turbine and are used for peaking operation. CCGT power plants utilize both a gas turbine and a steam turbine, and are used for intermediate and base load operation. Depending on the size and dispatching duty, industrial (large frame) or aero-derivative gas turbines may be used. Most of the large power generation applications are industrial large frame turbines; smaller plants (less than 100 MW) use aero-derivatives. However, there is not a clear separating line between the two. The advanced gas turbine designs available today are largely due to 50 years of development of aero-derivative jet engines for military applications and commercial aviation. Given the aircraft designer's need for engine minimum weight, maximum thrust, high reliability, long life and compactness, it follows that the cutting-edge gas turbine developments in materials, metallurgy and thermodynamic designs have occurred in the aircraft engine designs, with subsequent transfer to land and sea gas turbine applications. However, the stationary power gas turbine designers have a particular interest in larger unit sizes and higher efficiency. The largest commonly used gas turbines are the so-called "F" class technology, with an output range of 200-300 MW, an open cycle efficiency of 34-39 percent, and a weight of several hundred tons. Generally speaking, the industrial or frame type gas turbine tend to be a larger, more rugged, slightly less efficient power source, better suited to base-load operation, particularly if arranged in a combined-cycle block on large systems. Today, the largest aero-derivative gas turbine has an output range of 40 MW, with a 40 percent simple cycle efficiency and a weight of several tons. A CT has many features desirable for power generation, including quick start up (within 10 minutes), capacity rating modularity (1-10 MW), small physical footprint, and low capital cost. Gas turbines demand higher quality fuels (light oil or gas containing no impurities) than diesel generators, and have considerably higher O&M requirements. A gas turbine (or turbines) combined with a steam turbine can form a combined cycle configuration in which the overall thermal efficiency is improved by utilizing the gas turbine exhaust heat energy. The combined cycle comes in a wide variety of forms, but the study focuses on the technical and cost characteristics of a typical, newly built 300 MW CCGT power plant. Larger plants (up to 500-700 MW) are also available. The prominent feature of the system is its high efficiency, realized by combining a high temperature (1.300°C) gas turbine with two or more middle- and bottom-cycles using the 300°C and 600°C waste heat 163 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES out of the combustion turbine. This approach boosts the overall thermal efficiency from 36 percent to 51 percent lower heating value (LHV). The combined cycle can be either single shaft or multishaft design, depending on the number of combustion turbines aligned with the steam turbine. The type of design is determined according to whether the power plant is designed to operate on a partial load or a base load basis. More advanced Class "G" and "H" gas turbines have been developed and are commercially available with the combined cycle efficiency reaching up to 60 percent. However, since the operational experience is limited, these types were not considered in this study. Technical Description A single shaft CCGT consists of gas turbine, steam turbine and generator commonly coupled on the same shaft (Figure A14.1). In the case of multishafts (for example, 2-7 shafts) configuration, each shaft can be shut down separately, and the plant has better part-load performance. This multishaft configuration is well suited for load following, and is adopted as the basis in this report for assessing the CCGT technology. Figure A14.1: Combined Cycle Gas Turbine Power Plant Single Shaft Multishaft GT: Gas Turbine ST: Steam Turbine G: Generator HRSG: Heat Recovery Steam Gas Boiler In a multishaft combined cycle configuration, waste heat from two or more gas turbines is collected via a dedicated waste heat recovery boiler to produce steam, which turns the steam turbine generator. When the capacity of the steam turbine becomes larger, the thermal efficiency improves over its single shaft counterpart, making it a competitive candidate for base load operation. However, a multiple train single shaft configuration has an advantage of operational flexibility. The combined cycle can be constructed in phases, with only the gas turbine installations at first for basic power supply, and expanded afterwards, by adding one or more bottoming cycles to complete an integral combined cycle power plant (Figure A14.2). 164 ANNEX 14: COMBUSTION TURBINE POWER SYSTEMS Figure A14.2: Simple Cycle and Combined Cycle Gas Turbine Layouts Environmental and Economic Assessment Table A14.1 presents the assumed design parameters and performance characteristics used in economic assessment of CT and CCGT power systems. For the CT, we assume only a 10 percent capacity factor, reflecting a typical peak load application. For the CCGT, we assume a combination of base load operations (100 percent capacity factor for 14 hours per day) and load following (50 percent capacity factor for 10 hours per day). Because the combustion turbine is used primarily during peak times, we assume the lower cost 1,100°C turbine instead of the more efficient super-high temperature design assumed for the CCGT case. All other design parameters are derived based on typical Japanese CT and CCGT operations. Table A14.1: CT and CCGT Power Plant Design Assumptions Combustion Turbine Combined Cycle Capacity 150 MW 300 MW Capacity Factor (%) 10 80 Combustion Turbine Inlet Temperature (°C) 1,100 1,300 Steam Turbine Inlet Temperature (°C) ­ 538/538/260 Fuel-type Gas (light oil) Gas (light oil) Thermal Efficiency (LHV, %) 34 51 Auxiliary Power Ratio (%) 1 2 Life Span (year) 25 25 Gross Generated Electricity (GWh/year) 131 2,102 Net Generated Electricity (GWh/year) 130 2,060 Note: "­" means no cost needed. 165 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Assuming typical fuel properties found in India originally, we can estimate the emissions of the CT and CCGT units (Table A14.2). We assume all environmental impacts are less than the World Bank guidelines and, therefore, do not include the costs for emission control equipment (such as SCR for NOx control) in the capital costs. Table A14.2: Air Emission Characteristics of Gas Turbine Power Plants Emission Standard Result Combustion Turbine Combined Cycle Gas Oil Gas Oil PM 50 mg/Nm3 NA Very Small NA Very Small SOx 2,000 mg/Nm3 NA Very Small NA Very Small (<500 MW:0.2tpd/MW) NOx Gas Turbine for Gas: 100-120 160-200 100-120 150-180 125 mg/Nm3; Oil: 460 CO2 g-CO2/net-kWh 600 780 400 520 Note: NA = Not applicable. Table A14.3 shows today's capital cost associated with oil/gas combustion turbine and combined cycle power plants. Table A14.3: Gas Turbine Power Plant 2005 Capital Costs (US$/kW) Items Combustion Turbine Combined Cycle Equipment 370 480 Civil 45 50 Engineering 30 50 Erection 45 70 Contingency 0 0 Total 490 650 Table A14.4 shows the result of levelized generation cost calculations, using the methodology described in Annex 2. 166 ANNEX 14: COMBUSTION TURBINE POWER SYSTEMS Table A14.4: Gas Turbine Power Plant 2005 Generating Costs (USą/kWh) Items Combustion Turbine (CF=10%) Combined Cycle (CF=80%) Natural Gas Light Oil Natural Gas Light Oil Levelized Capital Cost 5.66 0.95 Fixed O&M Cost 0.30 0.10 Variable O&M Cost 1.00 0.40 Fuel Cost 6.12 15.81 4.12 10.65 Total 13.08 22.77 5.57 12.10 Future Cost and Uncertainty Analysis The capital costs of CT and combined cycle power plants are decreasing as a result of both mass production and technological development. In this study, we assume that capital cost decreases 7 percent from 2004 to 2015. The uncertainty analysis assumes that all cost data varies ±20 percent. The uncertainty analysis results are shown in Table A14.5 and Table A14.6. Table A14.5: Gas Turbine Power Plant Capital Costs Projections (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Combustion 430 490 550 360 430 490 340 420 490 Turbine Combined 570 650 720 490 580 660 450 560 650 Cycle Table A14.6: Gas Turbine Power Plant Generating Costs Projections (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Combustion 11.9 13.1 14.7 10.4 11.8 14.0 10.2 11.8 14.5 Turbine (gas) Combined 4.94 5.57 6.55 4.26 5.10 6.47 4.21 5.14 6.85 Cycle (gas) 167 Annex 15 Coal-steam Electric Power Systems ANNEX 15: COAL-STEAM ELECTRIC POWER SYSTEMS PC plant is a term used for power plants which burn PC in a boiler to produce steam that is then used to generate electricity. PC plants are widely used throughout the world, in both developed and developing countries. Figure A15.1 provides a typical schematic of such a plant equipped with post-combustion De-NOx (selective catalytic reduction ­ SCR), particulate controls (electrostatic precipitator ­ ESP) and De-SOx (flue gas desulfurization ­ FGD). SCR and FGD may not be needed depending on the coal characteristics and the environmental requirements applicable to the specific power plant site. However, more and more of the pulverized coal plants are being equipped with such environmental controls even for low-sulfur and low-NOx producing coals. Also, the gas-to-gas heater may not be needed in all power plant sites. Figure A15.1: Pulverized Coal-steam Electric Power Plant Schematic Technology Description PC plants involve: · Grinding (pulverization) of coal; · Combustion of coal in a boiler, producing steam at high temperature and pressure; · Steam expansion into a turbine, which drives a generator producing electricity; and · Treatment of combustion products (flue gas) as required before they are released into the environment through the stack (chimney). While there are many variations in the design of the specific components of the PC plant, the overall concept is the same. Variations may include: 171 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES · Boiler design, for example, front wall-fired vs. opposed wall-fired vs. tangentially-fired vs. roof-fired, all indicating how the burners are arranged in the boiler. Other alternative arrangements include cyclones and turbo, grate, cell or wet-bottom firing methods; · NOx emissions control. Primary control is usually accomplished through low NOx burners and over fire air, but, further NOx reduction may be needed using Selective Catalytic Reduction (SCR) or Selective Non-Catalytic Reduction (SNCR) or gas reburning; and · Control of particulates, accomplished through dry Electrostatic Precipitator (ESP), wet ESP or bag filters (baghouses). The most important design feature of the PC plant relates to the steam conditions (pressure and temperature) entering the steam turbine. PC plants, designed to have steam conditions below the critical point of water (about 22.1 MPa-abs), are referred to as "SubCritical" PC plants, while plants designed above this critical point are referred to as "SC." Typical design conditions for SubCritical plants are: 16.7 MPa/538°C/538oC. SC PC plants can be designed over a spectrum of operating conditions above the critical point. However, for simplification, and based on the industry experience, often the terms "SC" and "USC" are used: · "SC" plants are designed usually at an operating pressure above the critical point (>22.1 MPa), but steam temperatures at or below 565°C. Typical design conditions are: 24.2 MPa/565°C/565°C; and · "USC" plants are designed above these conditions. Table A15.1 shows typical design conditions of recent SC plants operating in Europe. Increased steam conditions are important because they increase the plant efficiency. Figure A15.2 shows how efficiency improves with higher temperatures and pressures. The relative difference in plant heat rate (inverse of efficiency) between a basic SubCritical unit with steam conditions of 16.7 MPa/538°C/538°C and a SC unit operating at 24.2 MPa/ 538°C/565°C is about 4 percent. If steam conditions in the SC plant can be increased to 31 MPa/600°C/600°C/600°C (note: a second reheat step has been added), the heat rate advantage over a conventional SubCritical unit reaches about 8 percent. Further development of advanced materials is the key to even higher steam conditions and major development projects are in progress, particularly in Denmark, Germany, Japan and the United States. Plants with pressure up to 35 MPa, and steam temperatures up to 650°C (1,200°F), are foreseen in a decade, giving an efficiency approaching 50 percent. 172 ANNEX 15: COAL-STEAM ELECTRIC POWER SYSTEMS Table A15.1: European SuperCritical Pulverized Coal Power Plants Power Plant Fuel Output MW Steam Conditions Start-up Date MPa/°C/°C/°C Denmark: Skaerbaek Coal 400 29/582/580/580 1997 Nordiyland Coal 400 29/582/580/580 1998 Avdoere Oil, Biomass 530 30/580/600 2000 Germany: Schopau A,B Lignite 450 28.5/545/560 1995-96 Schwarze Pumpe A,B Lignite 800 26.8/545/560 1997-98 Boxberg Q,R Lignite 818 26.8/545/583 1999-2000 Lippendorf R,S Lignite 900 26.8/554/583 1999-2000 Bexbach II Coal 750 25/575/595 1999 Niederausem K Lignite 1,000 26.5/576/599 2002 Source: The World Bank Technical Paper 011, May 2001. This efficiency improvement represents proportional reduction of all pollutants (particulates, SO2, NOx, mercury [Hg] and CO2, among others) per unit of generated electricity. Figure A15.2: Heat Rate Improvements from SuperCritical Steam Conditions 8 Single Reheat (%) 7 593/621 °C 6 593/593 °C 565/593 °C 5 565/565 °C Improvement 4 538/565 °C Rate 538/538 °C 3 Heat 2 1 0 150 200 250 300 350 Rated Main Steam Pressure (bar) Figure on curve are main and reheat steam temperatures (°C) Source: The World Bank Technical Paper 011, May 2001. 173 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Both SubCritical and SC plants are commercially available worldwide. Subcritical plants are used in all countries; SC are less widespread, but there are more than 600 plants in operation in countries such as China, East and West European countries, India, Japan, Republic of Korea and the United States, some operating since the 70s. Individual units of over 1,000 MWe are in operation, but most new plants are in the 500-700 M We range. Environmental and Economic Assessment With regard to environmental performance, there are many technologies developed to reduce all "criteria pollutants" (particulates, SO2 and NOx) by more than 90 percent (nearly 100 percent with regard to particulates and SO2). Some of these technologies have resulted in emission levels comparable to natural gas power plants (except for CO2 emissions). Table A15.2 presents typical emissions for a 300 MW SubCritical steam electric power plant burning Australian coal. If lower emissions are required, there are many environmental control options to be employed to achieve them. Table A15.2: Air Emissions from a 300 MW Pulverized Coal-steam Electric Power Plant Emission Standard for Coal Result Reduction Equipment (The World Bank, 1998) Boiler Exhaust Stack Exhaust SOx 2,000 mg/Nm3 1,700 mg/Nm3 Not Required (<500 MW:0.2 tpd/MW) (33 tpd) NOx 750 mg/Nm3 500 mg/Nm3 Not Required PM 50 mg/Nm3 20,000 mg/Nm3 50 mg/Nm3 Required CO2 None 880 g-CO2/kWh NA Note: NA = Not applicable. Table A15.3 shows design parameters and operating characteristics for typical steam-electric power plants of 300 and 500 MW size. 174 ANNEX 15: COAL-STEAM ELECTRIC POWER SYSTEMS Table A15.3: Pulverized Coal-steam Electric Power Plant Design Assumptions Capacity 300 MW 500 MW 500 MW 500 MW SubCr SubCr SuperCr USC Capacity Factor (%) 80 80 80 80 Steam Turbine Inlet 16.7 MPa/ 16.7 MPa/ 24.2 MPa/565°C/ 31 MPa/ Pressure and Temperature 538/538 538/538 565°C 600°C/600°C Fuel-type Coal (Australia) Coal (Australia) Coal (Australia) Coal (Australia) Gross Plant Efficiency (LHV, %) 40.9 41.5 43.6 46.8 Auxiliary Power Ratio (%) 6 5 5 5 Life Span (year) 30 30 30 30 Capital Costs (US$/kW) 1,020 980 1,010 1,090 The capital costs shown in the previous Table have been developed assuming no FGD and SCR. In the absence of specific data for Tamil Nadu, India, international prices were used.41 More specifically, the capital costs for USC are the average from the following sources after US$170/kW were taken out for FGD and SCR, which are not needed to meet the local regulations or the World Bank guidelines: The breakdown of the capital costs is shown in Table A15.4. A clarification should be made on process contingency category. Project contingency (typically 15 percent of the capital costs) is already included in the above cost estimates. Process contingency reflects additional uncertainty with technologies which have not been used widely or with coals representative in developing countries. Five percent process contingency has been assigned to USC technology which has yet to be used in developing countries. 41See: Booras, G. (EPRI) "Pulverized Coal and IGCC Plant Cost and Performance Estimates," Gasification Technologies 2004, Washington, D.C., October 3-6, 2004; Bechtel Power: "Incremental Cost of CO2 Reduction in Power Plants," presented at the ASME Turbo Expo, 2002; Florida Municipal Power Authority: "Development of High Efficiency, Environmentally Advanced Public Power Coal-fired Generation," presented at the PowerGen International Conference, Las Vegas, Nevada, December 2003; and EPRI: "Gasification Process Selection ­ Trade Offs and Ironies," presented at the Gasification Technologies Conference ­ 2004. 175 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A15.4: Pulverized Coal-steam Electric Power Plant Capital Costs Breakdown Equipment 60-70% Civil 9-12% Engineering 9-11% Erection 9-12% Process Contingency 0-10% Total 100% The generating cost estimates are shown in Table A15.5. Table A15.5: Pulverized Coal-steam Electric Power 2005 Generating Costs (USą/kWh) 300 MW 500 MW 500 MW 500 MW SubCr SubCr SuperCr USC Levelized Capital Cost 1.76 1.67 1.73 1.84 Fixed O&M Cost 0.38 0.38 0.38 0.38 Variable O&M Cost 0.36 0.36 0.36 0.36 Fuel Cost 1.97 1.92 1.83 1.70 Total 4.47 4.33 4.29 4.29 Future Price and Uncertainty Analysis The total capital costs and generation costs for the options being considered are shown in Table A15.6 and Table A15.7. Table A15.6: Pulverized Coal-steam Electric Power Capital Costs Projections (US$/kW) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 MW 1,080 1,190 1,310 960 1,080 1,220 910 1,060 1,200 SubCr 500 MW 1,030 1,140 1,250 910 1,030 1,150 870 1,010 1,140 SubCr 500 MW 1,070 1,180 1,290 950 1,070 1,200 900 1,050 1,190 SuperCr 500 MW 1,150 1,260 1,370 1,020 1,140 1,250 960 1,100 1,230 USC 176 ANNEX 15: COAL-STEAM ELECTRIC POWER SYSTEMS Table A15.7: Pulverized Coal-steam Electric Power Generating Costs Projections (USą/kWh) 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 300 MW 4.18 4.47 4.95 3.91 4.20 4.76 3.86 4.20 4.84 SubCr 500 MW 4.05 4.33 4.79 3.77 4.07 4.62 3.74 4.06 4.69 SubCr 500 MW 4.02 4.29 4.74 3.74 4.04 4.56 3.72 4.03 4.63 SuperCr 500 MW 4.02 4.29 4.71 3.74 4.02 4.51 3.69 3.99 4.55 USC 177 Annex 16 Coal-IGCC Power Systems ANNEX 16: COAL-IGCC POWER SYSTEMS As IGCC power plant in its simplest form is a process where coal is gasified with either O or air, and the resulting synthesis gas, consisting of H and CO, is cooled, cleaned and fired in a gas turbine. The hot exhaust from the gas turbine passes through a HRSG where it produces steam that drives a turbine. Power is produced from both the gas and steam turbine generators. By removing the emissions-forming constituents from the synthetic gas prior to combustion in the gas turbine, an IGCC power plant can meet very stringent emission standards. There are many variations on this basic IGCC scheme, especially in the degree of integration. It is the general consensus among IGCC plant designers today that the preferred design is one in which the Air Separation Unit (ASU) derives part of its air supply from the gas turbine compressor and part from a separate air compressor. Technology Description Three major types of gasification systems in use today are: moving bed; fluidized bed; and entrained flow. All three systems use pressurized gasification (20 to 40 bars), which is preferable to avoid auxiliary power losses for synthetic gas compression. Most gasification processes currently in use or planned for IGCC applications are O-blown, which provides potential advantages if sequestration of CO2 emissions is a possibility.42 In the coal-fueled IGCC power plant design, the hot syngas leaving the gasifier goes to a residence vessel to allow further reaction. It is then cooled in the High Temperature Heat Recovery (HTHR) section before almost all of the particulates are removed by a hot gas cyclone. The remaining particulates and water soluble impurities are removed simultaneously by wet scrubbing with water. The particulates are concentrated and recovered from the wash water by a filter system before being recycled to the gasifier for further reaction. Filtered water is recycled to the wet scrubber or is sent to the sour water stripper. Figure A16.1 provides a typical configuration for a coal-fired IGCC power plant such as that considered in this study. Most of the large components of an IGCC plant (such as the cryogenic cold box for the ASU, the gasifier, the syngas coolers, the gas turbine and the HRSG sections) can be shop-fabricated 42See various presentations from the Gasification Technologies Council. 181 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES and transported to a site. The construction/installation time is estimated to be about the same (three years) as for a comparably sized conventional coal power plant. Figure A16.1: Coal-IGCC Power System Schematic Air Separation Unit Sulfur Recovery Coal Feed Preparation Gasification Unit Gas Cooling Acid Gas Removal Air Gas Turbine HRSG Steam Turbine IGCC provides several environmental benefits over conventional units. Since gasification operates in a low-O environment (unlike conventional coal plants, which is O-rich for combustion), the sulfur in the fuel converts to H2S, instead of SO2. The H2S can be more easily captured and removed than SO2. Removal rates of 99 percent and higher are common using technologies proven in the petrochemical industry. IGCC units can also be configured to operate at very low NOx emissions without the need for Selective Catalytic Reduction (SCR). Two main techniques are used to lower the flame temperature for NOxcontrol in IGCC systems. One saturates the syngas with hot water while the other uses N from ASU as a diluting agent in the combustor. Application of both methods in an optimized combination has been found to provide a significant reduction in NOx formation. NOx emissions typically fall in the 15-20 parts per million (ppm) range, which is well below any existing emissions standard. The basic IGCC concept was first successfully demonstrated at commercial scale at the pioneer Cool Water Project in Southern California from 1984 to 1989. There are currently two commercial sized, coal-based IGCC plants in the United States, and two in Europe. The two projects in the United States were supported initially under the DOE's Clean Coal Technology demonstration program, but are now operating commercially without DOE support. 182 ANNEX 16: COAL-IGCC POWER SYSTEMS Environmental and Economic Assessment Table A16.1 provides the design parameters and operating characteristics assumed for the 300 MW coal-fired IGCC power plant assessed here. Table A16.1: Coal-IGCC Power System Design Assumptions Capacity 300 MW 500 MW Capacity Factor (%) 80 Life Span (year) 30 Fuel-type Coal (Australia) Gasifier-type Coal Slurry Entrained Bed Oxygen Purity 95% Auxiliary Power Ratio (%) 11 10 Gross Thermal Efficiency (LHV, %) 47 48 Gross Generated Electricity (GWh/year) 2,102 3,504 Net Generated Electricity (GWh/year) 1,870 3,154 Assuming coal properties typical of Illinois # 6 coals, the emission characteristics of a 300 MW IGCC are shown in Table A16.2. IGCC power plants are capable of removing 99 percent of S in the fuel as elemental S; hence S emissions are extremely low. The high pressure and low temperature of combustion sharply reduces NOx formation. Table A16.2: The World Bank Air Emission Standards and IGCC Emissions Emission Standard for Coal IGCC Plant Emissions SOx 2,000 mg/Nm3 (<500 MW:0.2 tpd/MW) > 0.30 gm/kWh NOx 750 mg/Nm3 > 0.30 gm/kWh PM 50 mg/Nm3 Negligible CO2 None 700-750 gm/kWh Indicative capital costs for the IGCC plant considered are as shown in Table A16.3, while conversion to levelized generation costs using the method described in Annex 2 yields the results shown in Table A16.4. 183 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A16.3: Coal-IGCC Power Plant 2005 Capital Costs (US$/kW) 300 MW 500 MW Equipment & Material 1,010 940 Engineering 150 140 Civil 150 140 Construction 100 100 Process Contingency 200 180 Total Plant Cost 1,610 1,500 Table A16.4: Coal-IGCC Power Plant 2005 Generating Costs (USą/kWh) 300 MW 500 MW Levelized Capital Cost 2.49 2.29 Fixed O&M 0.90 0.90 Variable O&M 0.21 0.21 Fuel 1.79 1.73 Total COE 5.39 5.14 Future Cost and Uncertainty Analysis The cost of coal-based IGCC power plants probably will not change over the next five years until the first generation commercial units are commissioned. Improvements in design with respect to advanced gas turbines and hot gas clean-up systems may be expected over the next 10 years. The results of operating experience accumulated in these plants and the confidence gained in the utility industry overall may bring down the cost of these plants by about 10 percent over the next 10 years. In this assessment, we assume that all cost data is variable ±30 percent, yielding the Monte Carlo simulation analysis results shown in Table A16.5. 184 ANNEX 16: COAL-IGCC POWER SYSTEMS Table A16.5: Coal-IGCC Capital and Generating Costs Projections 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Capital Cost 300 MW 1,450 1,610 1,770 1,200 1,390 1,550 1,070 1,280 1,440 (US$/kW) 500 MW 1,350 1,500 1,650 1,130 1,300 1,450 1,000 1,190 1,340 Generating Cost 300 MW 5.05 5.39 5.90 4.58 4.95 5.52 4.40 4.81 5.43 (USą/kWh) 500 MW 4.81 5.14 5.62 4.38 4.74 5.28 4.21 4.60 5.19 185 Annex 17 Coal-fired AFBC Power Systems ANNEX 17: COAL-FIRED AFBC POWER SYSTEMS AFBC is a combustion process in which limestone is injected into the combustion zone to capture the S in the coal. The CaSO4 by-product formed from the combination of SO2 and the CaO in the limestone) is captured in the particulate control devices (electrostatic precipitator or bag filter) and disposed along with the fly ash. Technology Description There are two types of fluidized bed designs, the bubbling AFBC and the circulating AFBC. The difference is in the velocity of the gas inside the boiler and the amount of recycled material. Bubbling AFBC has lower velocity; hence less amount of material escapes the top of the boiler. Circulating AFBC has higher velocity and much higher amount of recycled material relative to the incoming coal flow. Bubbling AFBC is used mostly in smaller plants (10-50 MWe) that burn biomass and municipal wastes. Circulating AFBC, also known as circulating fluidized bed (CFB), is used for utility applications, especially in plants larger than 100 MWe. We focus on circulating AFBC in this report. AFBC boilers (Figure A17.1) are very similar to conventional PC boilers. The majority of boiler components are similar, and hence manufacturing of the furnace and the back-pass can be done in existing manufacturing facilities. In addition, an AFBC boiler utilizes the Rankine steam cycle with steam temperatures and pressures similar to PC boilers. AFBC boilers can be designed for either SubCritical or SC conditions. Most AFBC boilers, utilized so far, are of the SubCritical type, mainly because the technology has been utilized in sizes up to 350 MWe, where SubCritical operation is more cost-effective. As the technology is scaled up (above 400-500 MWe), the SC design may be used depending on site-specific requirements (for example, cost of fuel and environmental requirements). The difference of AFBC relative to PC boilers stems from lower operating temperatures and the injection of limestone in the furnace to capture SO2 emissions. Typical maximum furnace temperature in an AFBC boiler is in the 820-870°C (1,500-1,600°F) range, while conventional PCs operate at 1,200-1,500°C (2,200-2,700°F). Low combustion temperature limits the formation of NOX, and is also the optimum temperature range for in situ capture of SO2. The injected limestone is converted to lime, a portion of which reacts with SO2 to form CaSO4, a dry solid which is removed in the particulate collection equipment. A cyclone is located between the furnace and the convection pass to capture unreacted lime and 189 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES limestone present in the flue gases exiting the furnace. The solids collected in the cyclone are recirculated to the furnace to improve the overall limestone utilization. Limestone injection can remove up to 90-95+ percent of S in the coal, eliminating the need for FGD downstream of the boiler. AFBCs have NOx emissions 60-70 percent less than conventional PCs with low NOx burners. AFBC boilers can efficiently burn low reactivity and low-grade fuels, which may not be burned in conventional PCs. Such fuels include anthracite, coal cleaning wastes, and industrial and municipal wastes. High-ash fuels, such as lignite, are particularly suitable for AFBC technology. Figure A17.1: AFBC Process Schematic Gas Convection Pass Hot Cyclone Coal Limestone Combustor Solids Recycle Flue Gas Secondary Air Heat Exchanger (optional) Source: The World Bank.43 Environmental and Economic Assessment Consistent with the methodology followed in this study, and especially the assumptions made for the large power plants, AFBC power plant economics were developed for an indicative design located in India. 43"The Current State of Atmospheric Fluidized-bed Combustion Technology," Washington, DC: The World Bank, Technical Paper #107, Fall 1989. 190 ANNEX 17: COAL-FIRED AFBC POWER SYSTEMS The design assumptions are as follows: · Gross output: 300 MW; · SubCritical steam cycle with steam conditions: 16.7 MPa/538°C/538°C (2,400psi/ 1,000oF/1,000oF); · Gross thermal efficiency: 41% (LHV); · Auxiliary power ratio: 7%; · Plant life: 30 years; · CF: 80%; · Onsite coal storage: 30 days at 100% load and utilization factor; · Start-up fuel: oil; and · Ash transferred through a pneumatic system to adjacent disposal pond. The emission results for the indicative coal-fired AFBC design are compared with the World Bank's coal-fired power plant standards in Table A17.1. Table A17.1: AFBC Emission Results and the World Bank Standards The World Bank Emission Standards for Coal Emissions Calculated for a Coal-fired AFBC Design Located in India SOx 2000 mg/Nm3 (<500 MW: 0.2 tpd/MW) 940 mg/Nm3 44 NOx 750 mg/Nm3 250 mg/Nm3 45 PM 50 mg/Nm3 Under 50 mg/Nm3 46 CO2 ­ 940 g-CO2/Year Note: "­" means no cost needed. The capital costs of an AFBC plant are affected by many site-specific factors, such as coal properties, environmental regulations, sourcing of the key components, and geophysical characteristics of the construction site. Table A17.2 provides a sample of the relevant capital costs available for various locations. 44Indian coal contains CaO in the ash and can capture SO2 without adding limestone. If the S in the coal is relatively low and/or the environmental standards are not very strict, limestone may not be required. 45Lower than 100 mg/Nm3 (typically 30-50 mg/Nm3) is possible with the addition of SNCR (Selective Non-Catalytic Reduction) system in the AFBC boiler. 46Depends on ESP or fabric filter design; in some developing countries higher particulates (for example, 100 or 150 mg/ Nm3) may be allowed. In this case, the capital costs may be slightly lower (for example, US$10-15/kW). 191 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A17.2: Indicative AFBC Installations and Capital Costs Estimates Location Size (MW) Capital Costs Source (US$/kW) Elbistan, Turkey 250 1,100 The World Bank, Turkey EER Report/ Task 2 Generic, China 300 721 The World Bank/ESMAP Paper 01147 Jacksonville, United States 2x300 1,050 Coal Age Magazine, November 2002 Generic, Europe 150 1,27348 Eurostat (Les Echos Group), 200349 Generic, United States 200 1,304 Alstom (2003)50 Generic, United States 664 1,038 Alstom (2003)51 (SuperCritical) Average 1,081 Based on these actual projects, we provide the breakdown of coal-fired AFBC costs shown in Table A17.3. Table A17.3: Coal-fired AFBC Power Plant 2005 Capital Costs (US$/kW) Items 300 MW 500 MW Equipment 730 680 Civil 120 120 Engineering 110 110 Erection 120 110 Process Contingency 100 100 Total52 1,180 1,120 47ESMAP, "Technology Assessment of China Clean Coal Technologies: Electric Power Production," 2001. 48Note: The publication provides the costs in Euros; considering that US$1 was equal to €0.85 to 1.10 during 2003, we assume that US$1 equal €1.0. 49Source: World Energy Council, "Performance of Generating Plant 2004," Section 3. 50Marion, J., Bozzuto, C., Nsakala, N., Liljedahl, G., "Evaluation of Advanced Coal Combustion & Gasification Power Plants with Greenhouse Gas Emission Control," Topical Phase-I, DOE-NETL Report under Cooperative Agreement No. DE-FC26- 01NT41146, prepared by Alstom Power Inc., May 15, 2003. 51Source: Palkes, M., Waryasz, R., "Economics and Feasibility of Rankine Cycle Improvements for Coal Fired Power Plants," Final DOE-NETL Report under Cooperative Agreement No. DE-FCP-01NT41222, prepared by Alstom Power Inc., 52Total Capital Requirement (TCR) is "overnight costs" not including interest during construction. 192 ANNEX 17: COAL-FIRED AFBC POWER SYSTEMS Typical O&M values for a coal-fired AFBC plant are provided in Table A17.4, while typical generating costs are shown in Table A17.5. Table A17.4: Coal-fired AFBC Power Plant 2005 O&M Costs (USą/kWh) Items 300 MW 500 MW Fixed O&M Cost 0.50 0.50 Variable O&M Cost 0.34 0.34 Total O&M 0.84 0.84 Table A17.5: Coal-fired AFBC Power Plant 2005 Generating Costs (USą/kWh) Items 300 MW 500 MW Levelized Capital Cost 1.75 1.64 O&M Cost 0.84 0.84 Fuel Cost 1.52 1.49 Generating Cost 4.11 3.97 Technology Status and Development Trends The technology is considered commercially available up to 350 MW, as demonstrated by hundreds of such boilers operating throughout the world (for example, Australia, China, Czech Republic, Finland, France, Germany, India, Japan, Poland, Korea, Sweden, Thailand and the United States). In 1996, EPRI estimated that there are approximately 300 AFBC units (larger than 22 tons/hr each) in operation worldwide. Since then (1996), the number of AFBC operating units has increased above 600 units. Experience from these units has confirmed performance and emissions targets, high reliability and ability to burn a variety of low quality fuels.53 AFBC plants are being built worldwide, and are especially well suited for solid fuels difficult to burn in a PC boiler (anthracite, lignite, brown coal and coal wastes). AFBC plants can 53Palkes, M., Waryasz, R., "Economics and Feasibility of Rankine Cycle Improvements for Coal Fired Power Plants," Final DOE-NETL Report under Cooperative Agreement No. DE-FCP-01NT41222, prepared by Alstom Power Inc., February 2004. 193 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES also utilize industrial and MSWs, petroleum coke and other combustible industrial waste as supplemental fuels. AFBC technology is expected to be used widely in the future, mainly in new power plant applications. Costs are expected to decline, especially in developing countries such as China and India. Specific capital cost reductions are envisioned through: · Scale up of the technology to 500-600 MW level; this has a potential reduction of US$200-300/kW comparing the 500-600 MW plant to the 300 MW plant; and · Further improvement of plant design resulting in 5 percent reduction of capital costs every five years for the nominal 300 MW plant, resulting in capital costs of: US$1,000/kW in 2010, and US$950/kW in 2015.54 Uncertainty Analysis The analysis results using Monte Carlo simulation are shown in Table A17.6. Table A17.6: Coal-fired AFBC Power Plant Projected Capital and Generating Costs 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Capital 300 MW 1,060 1,180 1,300 940 1,070 1,210 880 1,040 1,180 Cost (US$/kW) 500 MW 1,010 1,120 1,230 900 1,020 1,140 840 990 1,120 Generating 300 MW 3.88 4.11 4.56 3.72 3.98 4.55 3.67 3.96 4.55 Cost (USą/kWh) 500 MW 3.75 3.97 4.40 3.61 3.81 4.42 3.58 3.83 4.71 54All data in June 2004 US$. 194 Annex 18 Oil-fired Steam-electric Power Systems ANNEX 18: OIL-FIRED STEAM-ELECTRIC POWER SYSTEMS Oil-fired steam power plants have been used around the world for many years and they are particularly common in countries with access to cheap oil (mainly oil-producing regions such as the Middle East) and countries without access to other energy sources (for example, Italy and Japan). However, after the two oil crises of the 70s, oil is used less and less for power generation mainly due to the high prices, but also the development of new, more efficient technologies. Nevertheless, oil continues to play some role in many countries. Technology Description The oil-fired power plant consists of a boiler, in which the oil is burned and water is heated to superheated (high temperature and pressure) steam; the steam in turn expands in a steam turbine which turns a generator to produce electricity. A schematic of an oil-fired steam-electric power plant is shown in Figure A18.1. With the exception of the fuel being burned, the system configuration is very similar to PC power plants. As in these plants, oil-fired plants could be designed for SC or SubCritical steam conditions. SubCritical is the most common, but SC plants have been used in countries such as Italy and Japan. Figure A18.1: Oil-fired Steam-electric Power Plant Steam Turbine Stack Generator Steam Boiler De-NOx Air Electrostatic System Preheater Precipitator Fuel Tank Fuel Pump Environmental and Economic Assessment Typical design and operating parameters for oil-fired plants are shown in Table A18.1. 197 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A18.1: Oil-fired Steam-electric Power Plant Design Assumptions Capacity 300 MW Capacity Factor (%) 80 Steam Turbine Inlet Pressure and Temperature 16.7 MPa /538/538 Fuel-type Residual Oil Gross Thermal Efficiency (LHV, %) 41 Auxiliary Power Ratio (%) 5 Life Span (year) 30 Gross Generated Electricity (GWh/year) 2,102 Net Generated Electricity (GWh/year) 1,997 A capacity factor of 80 percent is assumed, based on 14-hour operation at 100 percent (full load) output and 10-hour operation at 50 percent rated output per day. Residual oil with properties typically found in India is used.55 Emissions from a 300 MW oil-fired plant (SOx, NOx, PM and CO2) are shown in Table A18.2. For the oil quality assumed, the SOx and NOx emissions are below the World Bank's emission standards; therefore, only ESP is included in the capital cost. However, for higher S oil, SO2 emissions may require control either through treatment of the oil (before combustion) or through flue gas desulfurization, even though the latter is not common due to unfavorable economics. The most common is to use low-S oil. NOx emissions could be a problem too, but in most cases properly designed burners (combustion system) could control NOx emissions to meet the World Bank Environmental Guidelines and emission standards of most countries. For countries with very tight standards, SCR may be needed, in which case special consideration needs to be made to potential impacts from metals in the oil (especially vanadium) on the effectiveness of the SCR catalyst. 551.2% S content. 198 ANNEX 18: OIL-FIRED STEAM-ELECTRIC POWER SYSTEMS Table A18.2: Oil-fired Steam-electric Power Plant Air Emissions Emission Standard for Oil Emissions Emission Control Boiler Exhaust Stack Exhaust Equipment SOx 2,000 mg/Nm3 1,500 mg/Nm3 Same Not Required (<500 MW:0.2 tpd/MW) (33 tpd) NOx 460 mg/Nm3 200 mg/Nm3 Same Not Required PM 50 mg/Nm3 300 mg/Nm3 50 mg/Nm3 Required CO2 None 670 g-CO2/kWh Same NA Note: NA = Not applicable. Table A18.3 shows typical capital cost for oil-fired steam plants,56 while Table A18.4 shows the generation costs using the methodology described in Section 2. Table A18.3: Oil-fired Steam-electric Power Plant 2005 Capital Costs (US$/kW) Equipment 600 Civil 100 Engineering 80 Erection 100 Total 880 Table A18.4: Oil-fired Steam-electric Power 2005 Generating Costs (USą/kWh) Levelized Capital Cost 1.27 Fixed O&M Cost 0.35 Variable O&M Cost 0.30 Fuel Cost (levelized fuel cost is as US$5.8/GJ) 5.32 Total 7.24 56Preliminary Study on the Optimal Electric Power Development in Sumatra, Japan International Cooperation Agency (JICA), January 2003. 199 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Future Cost and Uncertainty Analysis Considering the uncertainty associated with the cost estimates (mainly due to site-specific considerations) capital and generation costs may vary (Table A18.5). The same Table shows a decline in the capital costs over time, even though it is not substantial due to the fact that the technology is mature, and is not expected to develop further. Table A18.5: Oil-fired Steam-electric Power Plant Projected Capital and Generating Costs 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Capital Cost 780 880980 700 810 920 670 800 920 (US$/kW) Generating Cost 6.21 7.249.00 5.50 6.70 9.08 5.49 6.78 9.63 (USą/kWh) 200 Annex 19 Microturbine Power Systems ANNEX 19: MICROTURBINE POWER SYSTEMS Microturbines are 25 kW to 250 kW turbine engines that run on natural gas, gasoline, diesel or alcohol. Derived from aircraft auxiliary power systems and automotive designs, microturbines have one or two shafts that operate at speeds of up to 120,000 RPM for single shaft engines and 40,000 RPM for duel shaft engines. Microturbines are a relatively new technology and are only now being sold commercially. They have capital cost of US$500 to US$1,000/kW and electrical efficiencies of 20 to 30 percent. Their main advantage is their small size and relatively low NOx emissions. Main markets for this power generation technology include light industrial and commercial facilities that often pay higher price for electricity. The modest heat output can also be used for low-pressure steam or hot water requirements. According to trial calculation of EPRI, generating cost is reduced 40 percent by 100 percent cogeneration system. Technology Description Figure A19.1 shows the schematic of microturbine burning natural gas. Note that the basic layout is that of a Brayton cycle machine, identical to a larger scale simple cycle or closed cycle gas turbine plant. Figure A19.1: Gas-fired Microturbine Power System Heat Exchanger Exhaust Fuel Combustor Compressor Gas Turbine Generator Air Environmental and Economic Assessment Table A19.1 provides assumed design parameters and operating characteristics for a gas-fired microturbine. 203 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A19.1: Microturbine Power Plant Design Assumptions Capacity 150 kW Capacity Factor (%) 80 Gas Turbine Inlet Temperature 950 degree Operate Speeds 90,000 RPM Fuel-type Natural Gas Thermal Efficiency (LHV, %) 30 Auxiliary Power Ratio (%) 0 Life Span (year) 20 Generated Electricity (MWh/year) 1,051 Source: The Institute of Applied Energy (Japan). The environmental impacts of microturbines are extremely low ­ just 30-60 mg/Nm3 for NOx and 670 g­CO2/net-kWh. Table A19.2 provides estimated capital costs of a gas-fired microturbine. Table A19.2: Microturbine Power System 2005 Capital Costs (US$/kW) Equipment 830 Civil 10 Engineering 10 Erection 20 Process Contingency 90 Total 960 Table A19.3 provides the results of the generation cost calculations, in line with the methodology described in Annex 2. 204 ANNEX 19: MICROTURBINE POWER SYSTEMS Table A19.3: Microturbine Power Plant 2005 Generating Costs (USą/kWh) Levelized Capital Cost 1.46 Fixed O&M Cost 1.00 Variable O&M Cost 2.50 Fuel Cost 26.86 Total 31.82 Future Cost and Uncertainty Analysis The two main American microturbine manufacturers have announced target prices corresponding to their long-term plans for technology development and manufacturing scale-up. These forecasts are roughly half the current as-delivered cost (Table A19.4). We assume that the target price will be reached in 2025, a cost reduction trajectory equivalent to a decline of US$20 per year over the study period. Table A19.4: Microturbine Power System Target Price Maker US$/kW Elliott (United States) 400 Capstone (United States) 500 Source: The Institute of Applied Energy (Japan). The cost of power plants changes with conditions such as maker, location, fuel price and so on. In this section, it is assumed that all costs have ± 20 percent variability around the probable values. This uncertainty assumption together with the capital cost projections yields the projected capital and generating costs shown in Table A19.5. Table A19.5: Microturbine Power Plant Projected Capital and Generating Costs 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max Capital Cost 830 960 1,090 620 780 910 500 680 810 (US$/kW) Generating Cost 30.4 31.8 33.9 28.8 30.7 33.5 28.5 30.7 34.2 (USą/kWh) 205 Annex 20 Fuel Cells ANNEX 20: FUEL CELLS Fuel cells produce direct current electricity through an electrochemical process. Reactants, most typically H and air, are continuously fed to the fuel cell reactor, and power is generated as long these reactants are supplied (Figure A20.1). A detailed description of the fuel cell technology status and applications is provided in the Fuel Cell Handbook.57 Figure A20.1: Operating Principles of a Fuel Cell 2e- Load Fuel In Electrolyte Oxidant In H2 œO2 Positive Ion or H2O Negative Ion H2O Depleated Fuel and Depleated Oxidant and Product Gases Out Product Gases Out Anode Cathode Source: Fuel Cell Handbook, October 2000. Technology Description Operation of complete, self-contained, natural gas-fueled small (less than 12 MW) power plants has been demonstrated using four different fuel cell technologies. They are: PEFC, PAFC, MCFC, and SOFC. Over 200 PAFC have been sold worldwide since the early 90s, when 200 kW PAFC units were commercially offered by IFC. These systems were installed at natural gas-fueled facilities and are currently in operation. Lower capacity units operate at atmospheric pressure while an 11 MW system that went into operation at the Tokyo Power Company's Geothermal Station in 1991, operates at eight atmospheres. MCFC units rated at 300 kW are also considered ready for commercialization. 57Fuel Cell Handbook, Fifth Edition, U.S. DOE Office of Fossil Energy's National Energy Technology Laboratory, October 2000. 209 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES PEFC and PAFC operate at low temperatures, less than 260°C (500oF), while MCFC and SOFC operate at high temperatures, 650-1,010°C (1,200-1,850oF). Operating pressures also vary from atmospheric pressures to about eight atmospheres depending on the fuel cell type and size. Pressurization generally improves fuel cell efficiency,58 but increases parasitic load and capital cost. It could also lead to operational difficulties such as corrosion, seal deterioration and reformer catalyst deactivation. Most fuel cells require a device to convert natural gas or other fuels to a H-rich gas stream. This device is known as a fuel processor or reformer. Fuel cell system performance is also sensitive to a number of contaminants. In particular, PEFC is sensitive to CO, S and ammonia (NH3); PAFC to CO and S; MCFC to S and hydrogen chloride (HCl); and SOFC to S. Fuel cell system design must reduce these contaminants to levels that are acceptable to fuel cell manufacturers. Environmental and Economic Assessment We assume the design parameters and operating characteristics for fuel cells as shown in Table A20.1. Table A20.1: Fuel Cell Power System Design Assumptions 200 kW Fuel Cell 5 MW Fuel Cell Capacity 200 kW 5 MW Capacity Factor (%) 80 80 Fuel-type Natural Gas Natural Gas Electrical Efficiency (LHV, %)59 50 50 Auxiliary Power Ratio (%) 1 1 Life Span (year) 20 20 Gross Generated Electricity (MWh/year) 1,402 35,040 Net Generated Electricity (MWh/year) 1,388 34,690 58Sy A. Ali and Robert R. Mortiz, The Hybrid Cycle: Integration of Turbomachinery with a Fuel Cell, ASME, 1999. 59Operating fuel cells as a CHP plant can increase fuel cell plant efficiency to 70 percent. 210 ANNEX 20: FUEL CELLS Fuel cells have essentially negligible air emissions characteristics, as shown in Table A20.2. Table A20.2: Fuel Cell Power System Air Emissions Emission Standard Fuel Cell Gas PM 50 mg/Nm3 ­ SOx 2,000 mg/Nm3(<500 MW:0.2 tpd/MW) ­ NOx Gas: 320 mg/Nm3; Oil: 460 1.4-3 Note: "­" means no cost needed. Fuel cells do generate CO2 emissions at a level comparable to direct combustion of gas (Table A20.3). Table A20.3: Fuel Cell Power System Carbon Dioxide Emissions 200 kW Fuel Cell 5 MW Fuel Cell (CF=80%) (CF=80%) Gas Gas g-CO2/kWh 370-465 370-465 10^3 Ton/Year 0.52-0.65 13-16 Table A20.4 shows the estimated capital cost of a 200 kW and 5 MW fuel cells. Table A20.4: Fuel Cell Power System 2005 Capital Costs (US$/kW) Items 200 kW Fuel Cell 5 MW Fuel Cell Equipment 3,100 3,095 Civil 0 5 Engineering 0 0 Erection 20 10 Process Contingency 520 520 Total 3,640 3,630 211 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A20.5 shows the results of converting the capital cost into per kWh cost, assuming a 20-year service life and using the methodology described in Annex 2. Table A20.5: Fuel Cell Power System 2005 Generating Costs (USą/kWh) Items 200 kW Fuel Cell 5 MW Fuel Cell Natural Gas Natural Gas Levelized Capital Cost 5.60 5.59 Fixed O&M Cost 0.10 0.10 Variable O&M Cost 4.50 4.50 Fuel Cost 16.28 4.18 Total 26.48 14.37 Future Cost and Uncertainty Analysis The actual equipment cost for fuel cells is expected to decrease in the future due to technological improvements and reduced manufacturing costs. Cost projections reflecting these decreases are given in Table A20.6. Table A20.6: Fuel Cell Power System Projected Capital and Generating Costs 2005 2010 2015 200 kW Fuel Cell Total Installed Cost (US$/kW) 3,640 2,820 2,100 Total Generating Costs (USą/kWh) 26.5 24.7 23.7 5 MW Fuel Cell Total Installed Cost (US$/kW) 3,630 2,820 2,100 Total Generating Costs (USą/kWh) 14.4 12.7 11.7 The cost of power plants often changes with conditions such as maker, location, fuel price and so on. In this section, we assume that all costs are variable within a ±20 percent range, with the results shown in Table A20.7 and Table A20.8. 212 ANNEX 20: FUEL CELLS Table A20.7: Uncertainty in Fuel Cell Capital Costs Projections 2005 2010 20151 Min Probable Max Min Probable Max Min Probable Max 200 kW 3,150 3,640 4,120 2,190 2,820 3,260 1,470 2,100 2,450 Fuel Cell 5 MW 3,150 3,630 4,110 2,180 2,820 3,260 1,470 2,100 2,450 Fuel Cell Table A20.8: Uncertainty in Fuel Cell Generating Costs Projections 2005 2010 2015 Min Probable Max Min Probable Max Min Probable Max 200 kW 25.2 26.5 28.2 22.8 24.7 26.6 21.5 23.7 25.8 Fuel Cell 5 MW 13.2 14.4 15.8 11.0 12.7 14.4 9.6 11.7 13.4 Fuel Cell 213 Annex 21 Description of Economic Assessment Methodology ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY Assessment results for generation technologies vary according to the operating environment. During an August 2004 inception meeting, the study team suggested values for key operating assumptions, including average unit size, life span, output and capacity factor. Consultation with the World Bank Task Managers yielded the operating parameter assumptions and ranges specified in Table A21.1, which were then used in the assessment process. Table A21.1: Power Generation Technology Configurations and Design Assumptions Generating-types Life Span (Year) Off-grid Mini-grid Grid-connected Base Load Peak Capacity CF Capacity CF Capacity CF Capacity CF (%) (%) (%) (%) Solar-PV 20 50 W, 300 W 20 25 25kW 20 5 MW 20 Wind 20 300W 25 100kW 25 10 MW 30 100 MW PV-wind Hybrids 20 300W 25 100kW 30 Solar Thermal With Storage 30 30 MW 50 Solar Thermal Without Storage 30 30 MW 20 Geothermal Binary 20 200kW 70 Geothermal Binary 30 20 MW 90 Geothermal Flash 30 50 MW 90 Biomass Gasifier 20 100kW 80 20 MW 80 Biomass Steam 20 50 MW 80 MSW/Landfill Gas 20 5 MW 80 Biogas 20 60kW 80 Pico/Micro-hydro 5 300W 30 15 1 kW 30 30 100kW 30 Mini-hydro 30 5 MW 45 Large-hydro 40 100 MW 50 Pumped Storage Hydro 40 150 MW 10 Diesel/Gasoline 10 300 W, 30 Generator 20 1 kW 100kW 80 5 MW 80 5 MW 10 Microturbines 20 150kW 80 Fuel Cells 20 200kW 80 5 MW 80 Oil/Gas Combined Turbines 25 150 MW 10 Oil/Gas Combined Cycle 25 300 MW 80 Coal Steam SubCritical 30 300 MW 80 Sub, SC, USC 30 500 MW 80 Coal IGCC 30 300 MW 80 30 500 MW 80 Coal AFB 30 300 MW 80 30 500 MW 80 Oil Steam 30 300 MW 80 217 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Assessment results will also vary widely according to the values assumed for key economic parameters. Following the World Bank guidance contained in the study's terms of reference, we used a discount rate60 set at 10 percent/year. We performed and expressed all economic analysis in constant June 2004 US dollars. Economic cost equivalent to international competitive price of machines, materials and fuel are used. Transport costs are included and shown separately, and only labor expenses are assumed to differ between regions. Cost Formulations for Generation The generating cost of each resource is simply the sum of capital cost and operating cost, expressed on a levelized basis. This formulation (Equation 1) reflects an explicitly economic analysis, as opposed to a financial analysis. Generating Cost = Capital Cost + Operating Cost (Equation 1) Capital cost is calculated on a unit basis using Equation 2. Costs which do not directly contribute to power generation, such as land, roads, offices, and so on, and so forth, are not included in the calculation. Unit Capital Cost (US$/kW) = (Equipment Cost including Engineering + Civil Cost + Construction Cost + Process Contingency) ś Generation Capacity (kW) (Equation 2) Capital cost can be expressed in levelized terms through Equation 3 below: ( Cn ($) Levelized Capital Cost ($/ kWh) = 1+ r)n ( En (kWh) 1+ r)n (Equation 3) Where r is the discount rate, n is the life span, Cn is the capital cost incurred in the nth year and En is the net electricity supplied in the nth year. 60Used for calculating levelized cost. 218 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY Operating cost can be calculated using Equation 4 below, Operating Cost (US$/kWh) = {Fixed O&M Cost (US$/yr) +Variable O&M Cost (US$/yr)+ Levelized Fuel Cost (US$/yr)}ś Net Electricity (kWh/yr) (Equation 4) Where: Fixed O&M Cost (US$/yr) = Operating Labor, General and Administrative, Insurance, other Variable O&M Cost (US$/yr) = Maintenance Labor and Material, Supplies and Consumables, Water and Water Treatment, other Levelized Fuel Cost (US$/yr) = Levelized Heat Unit Price (US$/J) x Gross Heat Consumption (J/kWh)ŚGross Electricity (kWh/yr) and: Net Electricity (kWh/yr) = Gross Electricity (kWh/yr) ­ Auxiliary Electricity (kWh/yr) Cost Formulations for Distribution Distribution cost (in US$/kWh) is calculated by Equation 5 below: Distribution Cost = Levelized Capital Cost + O&M Cost + Cost of Losses (Equation 5) Where: 1­R Levelized Capital Cost (US$/year) = Capital Cost (US$) x 1­Rn 219 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Levelized Capital Cost (USą/kWh) = Capital Cost (US$) x 1­R /(Annual Generated 1­Rn Electricity (kWh) ­ Annual Distribution Losses (kWh)) x 100 R = 1 / (1+r); r = Discount Rate (= 0.1); n = Life Time (assumed = 20 years) Capital Cost = Materials Cost (MC) + Labor Cost = Poles MC + Wires MC + Transformers MC + Other MCs + Labor Cost Distribution Losses (kWh) = Generated Electricity (kWh) x Distribution Loss Rate O&M Cost (US$/yr) = Capital Cost (US$) x O&M Annual Cost Rate O&M Annual Cost Rate (USą/kWh) = O&M Cost (US$/year) / (Annual Generated Electricity ­ Annual Distribution Losses) x 100 Loss Cost (USą/kWh) = (Generating Cost [USą/kWh] x Annual Distribution Losses [kWh])/ (Annual Generated Electricity [kWh] ­ Annual Distribution Losses [kWh]) The unit capital cost for distribution (in US$/kW) is calculated per Equation 6 below: Unit Distribution Capital Cost = Capital Cost/(Rated Output of Power Station (kW)- Distribution Losses (kW)) (Equation 6) Cost Formulations for Transmission Transmission cost (in US$/kWh) and unit transmission cost (US$/kW) is calculated in the same way as distribution costs, per Equations 7 and 8 below: Transmission Costs = Levelized Capital Cost + OM Cost + Loss Cost (Equation 7) Unit Capital Transmission Cost = Capital Cost/(Rated Output of Power Station (kW)- Transmission Losses (kW)) (Equation 8) 220 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY Transmission capital cost is calculated as a function of the distance from the generation area to the grid connecting point. Transmission losses are based on the I-squared losses of a representative transmission line, both as shown below: Transmission Capital Cost = Transmission Capital Cost /km x Distance (Line km) = Materials Cost (MC)/km + Labor Cost/km = Poles or Steel tower MC/km + Wires MC/km + Other MCs/km + Labor Cost/km Transmission Losses (kW/km) = 3I2r / 1000 n = (rP2/V2) / (1000 n) Transmission Losses (kWh/ km -year) = (3I 2 r / 1000 n) x 8,760 C = Transmission Losses (kW/km) x 8,760 C Where: I = Current of line at Rated Capacity of Generation (A) r = Resistance (/km) P = Rated Capacity of Generation (kW) V = Nominal Voltage (kV) C = Capacity Factor P = 3 x IV Power Factor = 1.0 n = "The number of circuits" x "the number of bundles" Cost Formulations for Distribution India is selected as the baseline country as per the overall methodology. Average distribution capital costs over normal terrain in India are shown in Table A21.2 and the component breakdown of capital cost for an 11kV line is shown in Table A21.3. Table A21.2: Average Capital Costs of Distribution (per km) Item Average Capital Cost Specifications High-voltage Line 5,000 (US$/km) 33 kV-11 kV Low-voltage Line 3,500 (US$/km) 230 V Transformer 3,500 (US$/unit) 50 kVA ,311kV/400/230 V Source: Interviews with Indian electric power companies conduced by TERI, November 2004. 221 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Table A21.3: Proportion of Capital Costs by Component of a 11 kV Line Item Specifications Proportion of Capital Cost (%) Poles 8 m, Concrete 13 Materials Wires 3.1 km 30mm2 ACSR 39 Other Materials Insulator, Arms, and so on, and so forth 27 Labor 21 Source: Reducing the Cost of Grid Extension for Rural Electrification, NRECA, 2000. Distribution capital costs are levelized as per the methodology described above, and O&M cost calculated as 2 percent of the initial capital cost annually. Both can be expressed on a per-circuit-km basis (Table A21.4). Table A21.4: Levelized Capital Costs and O&M Costs (per km) Item Levelized Capital Cost O&M Cost High-voltage Line 535 (US$/km-year) 100 (US$/km-year) Low-voltage Line 375 (US$/km-year) 70 (US$/km-year) Transformer 375 (US$/unit-year) 70 (US$/unit-year) The capital and levelized costs of distribution including the costs of losses and O&M are shown in Table A21.5. A value of 12 percent is used for the distribution loss percentage.61 Table A21.5: Capital and Variable Costs for Power Delivery, by Power Generation Technology Mini-grid Generating-types Rated CF USą/kWh US$/kW Output (%) 2005 2010 2015 2005 2010 2015 Solar-PV 25 kW 20 7.42 6.71 6.14 56 56 56 Wind 100 kW 25 3.80 3.61 3.49 193 193 193 (continued...) 61Distribution Loss Percentage = Average T&D Loss Percentage x Distribution Loss Rate = 17.2% x 0.7 = 12%. 222 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY (...Table A21.5 continued) Mini-grid Generating Types Rated CF USą/kWh US$/kW Output (%) 2005 2010 2015 2005 2010 2015 PV-wind Hybrids 100 kW 30 5.09 4.72 4.42 193 193 193 Geothermal 200 kW 70 2.53 2.38 2.34 193 193 193 Biomass Gasifier 100 kW 80 1.58 1.51 1.48 193 193 193 Biogas 60 kW 80 1.03 0.99 0.99 56 56 56 Micro-hydro 100 kW 30 2.43 2.36 2.36 193 193 193 Diesel/Gasoline 100 kW 80 3.08 2.94 2.97 193 193 193 Microturbines 150 kW 80 4.69 4.54 4.54 193 193 193 Fuel Cells 200 kW 80 3.99 3.72 3.58 193 193 193 Transmission Cost Calculation We assume voltage level and line-types suited to power station size as shown in Table A21.6.62 Table A21.6: Voltage Level and Line-type Relative to Rated Power Station Output Rated Output of Power Representative Line-type Capital Cost Station (MW) Voltage Level (kV) (US$/km) 5 69 DRAKE 1cct 28,177 10 69 DRAKE 1cct 28,177 20 69 DRAKE 1cct 28,177 30 138 DRAKE 1cct 43,687 100 138 DRAKE 2cct 78,036 150 230 DRAKE 2cct 108,205 300 230 DRAKE (2) 2cct 151,956 Source: Chubu Electric Power Company Transmission Planning Guidelines. 62These voltage levels and line-types are decided upon by the "Alternative Thermal Method," which is used for transmission power plan in Chubu Electric Power Company. 223 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES As with the distribution calculation, capital and O&M costs can be expressed on a per-circuit-km annualized basis by levelizing the capital cost and assuming annual O&M costs are a fixed fraction of capital costs (Table A21.7); transmission losses per kilometer are in Table A21.8. Table A21.7: Levelized Capital Costs and O&M Costs per Unit Rated Output (MW) Levelized Capital Cost O&M Cost (US$/km-year) (US$/km-year) 5 3,015 845 10 3,015 845 20 3,015 845 30 4,675 1,311 50 4,675 1,311 100 8,350 2,341 150 11,578 3,246 300 16,259 4,559 Table A21.8: Transmission Losses Generating-types Output CF Transmission Losses Transmission Losses (MW) (%) (kWh/km-year) (kW/km) Solar-PV 5 20 823 0.47 Wind 10 30 4,941 1.88 Wind 100 30 61,627 23.45 Solar-thermal 30 20 7,393 4.22 Geothermal 50 90 92,400 11.72 Biomass Gasifier 20 80 52,560 7.50 Biomass Steam 50 80 82,134 11.72 MSW/Landfill Gas 5 80 3,294 0.47 Mini-hydro 5 45 1,853 0.47 Large-hydro 100 50 102,711 23.45 Pumped Storage Hydro (peak) 150 10 16,635 18.99 Diesel/Gasoline Generator 5 80 3,294 0.47 Diesel/Gasoline Generator (peak) 5 10 412 0.47 (continued...) 224 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY (...Table A21.8 continued) Generating-types Output CF Transmission Losses Transmission Losses (MW) (%) (kWh/km-year) (kW/km) Fuel Cells 5 80 3,294 0.47 Oil/Gas Combined Turbines (peak) 150 10 16,635 18.99 Oil/Gas Combined Cycle 300 80 266,164 37.98 Coal Steam 300 80 266,164 37.98 Coal IGCC 300 80 266,164 37.98 Coal AFB 300 80 266,164 37.98 Oil Steam 300 80 266,164 37.98 The capital and levelized costs of transmission are calculated as per the method described above, and shown in Table A21.9. Table A21.9: Capital and Delivery Costs of Transmission (2004 US$) Generating-types Rated CF (USą x 10-2)/(kWh-km) US$/(kW-km) Output (%) (MW) 2005 2010 2015 2005 2010 2015 Solar-PV 5 20 4.80 4.75 4.71 5.64 5.64 5.64 Wind 10 30 1.60 1.58 1.57 2.82 2.82 2.82 Wind 100 30 0.54 0.53 0.52 0.78 0.78 0.78 Solar Thermal Without 30 20 0.64 0.62 0.61 1.46 1.46 1.46 Thermal Storage Geothermal 50 90 0.25 0.25 0.25 0.87 0.87 0.87 Biomass Gasifier 20 80 0.54 0.53 0.52 1.41 1.41 1.41 Biomass Steam 50 80 0.31 0.30 0.30 0.87 0.87 0.87 MSW/Landfill Gas 5 80 1.16 1.16 1.16 5.64 5.64 5.64 Mini-hydro 5 45 2.02 2.02 2.02 5.64 5.64 5.64 Large-hydro 100 50 0.37 0.37 0.37 0.78 0.78 0.78 Pumped Storage 150 10 1.57 1.56 1.55 0.72 0.72 0.72 Hydro (peak) Diesel/Gasoline 5 80 1.19 1.18 1.18 5.64 5.64 5.64 Generator Diesel/Gasoline 5 10 8.98 8.97 8.97 5.64 5.64 5.64 Generator (peak) (continued...) 225 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES (...Table A21.9 continued) Generating-types Rated CF (USą x 10-2)/(kWh-km) US$/(kW-km) Output (%) (MW) 2005 2010 2015 2005 2010 2015 Fuel Cells 5 80 1.24 1.22 1.21 5.64 5.64 5.64 Oil/Gas Combined 150 10 1.29 1.28 1.28 0.72 0.72 0.72 Turbines (peak) Oil/Gas 300 80 0.17 0.16 0.16 0.51 0.51 0.51 Combined Cycle Coal Steam 300 80 0.16 0.15 0.15 0.51 0.51 0.51 Coal AFB 300 80 0.15 0.15 0.15 0.51 0.51 0.51 Coal IGCC 300 80 0.17 0.16 0.16 0.51 0.51 0.51 Oil Steam 300 80 0.19 0.19 0.18 0.51 0.51 0.51 Forecasting Capital Costs of Generation The forecast value of the future price in 2010 and 2015 is calculated by considering the decrease of the future price as a result of both technological innovation and mass production. A forecast decrease in capital cost is done for each generation technology group as shown in Table A21.10, reflecting the relative maturity of each generation technology. Table A21.10: Forecast Rate of Decrease in Power Generation Technologies Decrease in Capital Cost Generating Technology-type (2004 to 2015) 0%-5% Geothermal, Biomass-steam, Biogas, Pico/Micro Hydro, Mini-hydro, Large-hydro, Pumped Storage, Diesel/Gasoline Generator, Coal-steam (SubCritical and SC), Oil Steam 6%-10% Biomass Gasifier, MSW/Landfill, Gas Combustion, Gas Combined Cycle, Coal Steam (USC), Coal AFBC 11%-20% Solar-PV, Wind, PV-wind Hybrids, Solar-thermal, Coal-IGCC >20% Microturbine, Fuel Cells Uncertainty Analysis Key uncertainties considered include fuel costs, future technology cost and performance, and resource risks. Each was systematically addressed using a probabilistic approach based on the "Crystal Ball" software package. All uncertainty factors are estimated in a band, and 226 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY generating costs are calculated by Monte Carlo Simulation. These probabilistic methods can also be applied to some other operational uncertainties, such as estimating the capacity factor of wind. The particular applications of uncertainty analysis techniques are described within each technology section. Generally speaking, the uncertainty analysis proceeds as follows: · Uncertainty factors are chosen; · High and low of uncertainty factors are set;63 and · Additional particular conditions are set (for example, resource variability, fuel cost, and so on, and so forth). Accommodating the Intermittency of Renewable Energy Technologies In case of solar-PV, wind-PV and wind-hybrids in a mini-grid area or off-grid configuration, battery costs or costs of a backup generator are included in the costs of the power system in order to smooth stochastic variations in the available resource and provide for a reliable power output. If the solar-PV or wind-PV system is grid-connected, intermittency is not a significant problem (unless renewable power penetration levels are very high) because the grid can absorb and accommodate such intermittency without requiring a back-up power supply. Conformance with the Costing Methods Used in EPRI TAG-RE 2004 The objective of this study is to provide a consistent set of technical and economic assessments on a broad range of power generation technologies, so that the performance and costs of these technologies in various settings can be easily and impartially compared. In searching for an assessment methodology, we chose the general approach and specific cost formulas contained in the Renewable Energy Technical Assessment Guide ­ TAG-RE: 2004,64 TAG-RE 2004, published by Electric Power Research Institute (EPRI). This source book provides a comprehensive methodology for assessing various power generating technologies, including RETs, and is the source of the detailed cost formulas used in the economic assessment. These formulations are described below. 63In order to make calculation results consistent, basic variables are set to ± 20%. 64EPRI (Electric Power Research Institute) publishes a series of Technology Assessment Guides, or TAGs, which contains very useful information about various generation, transmission, distribution and environmental technologies. This study relied on the quantification methods contained in Renewable Energy Technical Assessment Guide ­ TAG-RE: 2004. 227 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Capital Cost Formulas TAG-RE 2004 defines capital cost formulas for regulated utilities. There are three related formulations of capital cost offered ­ (a) total plant cost (TPC), (b) total plant investment (TPI) and (c) total capital requirement (TCR): (a) TPC = (Process Facilities Capital Cost + General Facilities Capital Cost + Engineering Cost) + (Home Office Overhead Cost + Project & Process Contingency) (Equation 9) (b) TPI = TPC + adjustment for the escalation65 of capital costs during construction + AFUDC (Equation 10) Where AFUDC is allowance for funds used during construction, representing the interest accrued on each expense from the date of the expense until the completion and commissioning of the facility. AFUDC is assumed to be zero, because the construction period is short in renewable generation systems. With an interest rate of 5-8 percent, and a two to five year construction period, typical for large hydropower plants, the effect of AFUDC could add several percentage points to the TPI. (c) TCR = TPI + Owners' Costs (Equation 11) Where owners' costs include land and property tax, insurance, preproduction, start-up and inventory costs. However, in this study, owners' costs are disregarded as negligible. After considering these three available formulations, we selected TPC as being the most useful for assessment purposes. The TPC formulation is capable of capturing the key differences in capital cost structure between the 22 generation technologies being assessed, without introducing additional complexities associated with financing, taxes and insurance, and other costs which are largely country-driven. Our use of TPC represents a strictly economic formulation of costs, allowing the results to be easily transferred from one country to another. A financial formulation of costs can then be easily overlaid onto TPC, which will, then, be 65The escalation rate adjustment for capital costs during construction is assumed to be zero. 228 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY reflective to country-specific conditions affecting power plant financing. We reiterate our capital cost formulation below: Capital Cost = TPC = (Process Facilities Capital Cost + General Facilities Capital Cost + Engineering Cost) + (Home Office Overhead Cost + Project & Process Contingency) (Equation 12) = Engineering Cost + Procurement Cost + Construction Cost + Contingency = Equipment Cost + Civil Cost + Construction Cost + Contingency Cost (Equation 13) We note that Process Facilities Capital Cost, General Facilities Capital Cost and Engineering Cost are equivalent to EPC (engineering, procurement and construction) cost. EPC cost also includes Equipment Cost (engineering et al), civil cost and erection cost (labor, tool). We also roll together Home Office Overhead Cost and Project and Process Contingency Cost under the overall category of Contingency Cost to obtain the simple formulation of Equation (8), which will be used throughout the assessment. Operating Cost and Generating Cost TAG-RE 2004 defines operating cost by the following formula: Operating Cost = (Fixed O&M Cost + Variable O&M Cost + Fuel Cost + Other Fixed Cost + Other Net Cash Flow) ś Net Electricity (Equation 14) 229 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Where Other Fixed Cost includes income taxes and debt service and Other Net Cash Flow includes cash reserves. We disregard Other Fixed Cost and Other Net Cash Flow because they constitute less than 10 percent of Fixed O&M Cost, Variable O&M Cost and Fuel Cost. This allows us to simplify the Operating Cost formulation to: Operating Cost = (Fixed O&M Cost + Variable O&M Cost + Fuel Cost) ś Net Electricity (Equation 15) We can then state the total power generation economic cost formulation as in TAG-RE 2004, and in this study as follows: Generating Cost = Capital Cost + Operating Cost (Equation 16) Capacity Factor and Availability Factor In order to express capital cost and operating cost on the same unit terms, we must know the hours of operation of the power generation technology. This section briefly describes how availability factor and capacity factor were used in expressing costs of different power generation technologies. Capacity factor is universally defined as "the ratio of the actual energy produced in a given period, to the hypothetical maximum possible." This definition applies regardless of power generation technology. We formulate the Capacity Factor calculation simply and universally as: Capacity Factor = (Total MWh Generated in Period x 100)/Installed Capacity (MW) x Period (hours) (Equation 17) 230 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY Several formulations of Availability Factor are found in the literature. The most common one is that in use by the North American Reliability Council (NERC): Availability Factor = Available Hours/Period Hours (Equation 18) Where Available Hours is the total Period Hours less forced outage, maintenance and planned outage hours. Availability Factor is a straightforward concept for conventional power generation technologies but becomes more difficult to apply with RETs, where the availability factor is driven by the renewable resource availability. The literature is not helpful, as different formulations yield counter-intuitive results for expressing availability (Table 21.11). A wind generator "Availability Factor" is defined as that fraction of a period of hours when the wind generator could be providing power if wind was available within the right speed range. This statement of availability does not factor in generator outages due to resource unavailability and therefore cannot be used to compare the power output of conventional vs. renewable energy power generators. Table A21.11: Availability Factor Values Found in the Power Literature Type of Power Station Value Fossil More than 75% Wind 95% Renewable 97% Solar-thermal 92.3% Ocean Wave 95% Geothermal More than 90% In consideration of this definitional difficulty, this report strictly relies on capacity factor as defined in Equation 12 for calculating generating costs on a per-kWh basis. 231 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Fuel Price Forecast Fuel prices used throughout this report are based on the IEA's (World Energy Outlook 2005) forecast. Since delivered fuel price is driven by the specific circumstances of exporting and importing countries, we developed the power generation cost estimation based on technology deployed and fuel consumed in India. This allows for the assessment results to be benchmarked and the numerical values extrapolated to other developing countries. We also levelize the forecast fuel price over the life span of each generating technology assessed. The procedure used for estimating fuel costs was as follows: · The fuel used for a cost model is chosen (for example: Australian coal); · The actual user end price is examined; · The fixed component of fuel provision (transportation cost, local distribution cost, refining cost and so on, and so forth)) is examined, and the end use price divided into a fixed and variable components; · The future price of fuel is calculated by linking the variable component of fuel price to the IEA's forecast base price; · A levelized fuel price is calculated specific to the life span of each generating technology; and · This levelized price is then used in the generating cost model. Fuel price fluctuates according to market forces, affecting both conventional and hybrid generating costs. We incorporate price fluctuation in the case study by defining a range of price fluctuation capped at 200 percent of forecast base fuel price (Table A21.12). Table A21.12: Fossil Fuel Price Assumptions (2004 US$) Crude Oil FOB Price of Crude Oil US$/bbl (US$/GJ) 2005 2010 2015 Crude Oil Base 53 (9.2) 38 (6.6) 37 (6.5) (Dubai, Brent, WTI) High ­ 56 (9.8) 61 (10.6) Low ­ 24 (4.2) 23 (4.0) (continued...) 232 ANNEX 21: DESCRIPTION OF ECONOMIC ASSESSMENT METHODOLOGY (...Table A21.12 continued) Coal FOB Price of Coal US$/ton (US$/GJ) 2005 2010 2015 Coal Base 57 (2.07) 38 (1.38) 39 (1.42 (Australia) High ­ 53 (1.92) 56 (2.04) Low ­ 30 (1.10) 30 (1.10) Natural Gas FOB Price of Natural Gas US$/MMBTU (US$/GJ) 2005 2010 2015 Gas Base 7.5 (7.1) 5.1 (4.8) 5.1 (4.8) (United States, European) High ­ 7.0 (6.6) 7.6 (7.2) Low ­ 4.0 (3.8) 3.3 (3.1) Note: "­" means no cost needed. Figure A21.1 compares the base price trajectory of each fossil fuel source. Figure A21.1: Fossil Fuel Price Assumptions The liquefied natural gas (LNG) price is estimated separately using a Japanese forecasting formula (Japan is one of the world's largest LNG importing countries). The formula estimates LNG price based on crude oil price. When the oil price exceeds a certain price band, the slope of the curve is moderated to reflect the likelihood of risk hedging by both sellers and buyers. The procedure and results are shown in Figure 21.2. 233 TECHNICAL AND ECONOMIC ASSESSMENT OF OFF-GRID, MINI-GRID AND GRID ELECTRIFICATION TECHNOLOGIES Figure A21.2: Procedure for Estimating LNG Prices Y: LNG Price (US$/MMBTU) Y= aX +b 4.4 3.3 16 X 24 : a=a1 X<16,24