Making the right choice
Choosing the right fuel is probably the most important decision a potential power project developer will have to make when considering the overall project economics. This report looks at the key considerations and the effects of fuel on project costs in India.
Chandan Roy and Sanjay Pande,
National Thermal Power Corporation,
New Delhi, India;
International Environmental and Energy Consultants,
Lisle, Illinois, USA
Electric power is critical to the socio-economic development of a country. The electric power sector in India has taken great strides since the beginning of the planning process some 45 years ago. However, it has been unable to keep pace with the rapid growth in demand, primarily due to resource constraints.
Industrial policy changes in 1991 also brought fundamental changes to the power sector. The opening up of the sector and the consequent changes in the power policy evoked great interest from private investors. However, mainly due to the poor financial position of the State Electricity Boards (SEBs), few proposals came to financial closure. Uncertainty relating to fuel, multiple negotiating agencies and finance posed great challenges for developers.
As of March 1997, the installed capacity of Indian utilities stood at 85 266 MW. The hydro, thermal and nuclear mix was 25 per cent, 72 per cent and 3 per cent, respectively. The thermal component has risen from 54 per cent in 1971 despite the government`s intention to maximize hydropower generation. Generation in 1996-97 was 394 billion units with a plant load factor of 64.5 per cent. The consumption profile in terms of domestic, commercial, agriculture, industry is 16.4; 4.5; 32.5; and 33.9 per cent, respectively. The share of agriculture and domestic load have increased steadily .
India faces acute energy shortage with a supply and demand gap of 11.4 per cent and peak to 18 per cent. At the current level of the ecomomy`s energy intensity, the power sector must grow at 10 to 11 per cent to achieve the desired rate of economic growth. The plan is to add about 50 000 MW in the 1997 to 2002 period. Fuel supply and cost would therefore be critical issues for thermal capacity additions.
Coal/lignite and natural gas are india`s indigenous fossil fuel sources for power generation. The country has modest reserves of petroleum crude. Coal is the mainstay fuel for conventional power generation with a share of 64 per cent followed by hydro (25 per cent), natural gas (7.5 per cent), nuclear (three per cent) and oil (0.5 per cent).
Lignite reserves are estimated at about 27.5 billion tons with about 94 per cent of the reserves located in Tamilnadu, southern India. The indigenous supply of petroleum fuels is not expected to improve much in the foreseeable future. Liquid fuel based generation is accordingly marginal in the country.
Although coal will continue to be the dominant fuel, there is a short term need to examine the possibility of using alternative fuels. There are two basic reasons for this need:
In the early years of the next century an annual shortage of about 70 million tons of coal is forecasted. This deficit will have to be met either by import of coal or other hydrocarbons. Developing new coal mines is a long gestation activity
There is an uneven geographic location of Indian coal reserves. For the load centres which are distant from indigenous coal sources, use of alternative fuel could also prove to be economical in the long term. Moving coal will become increasingly difficult in view of the huge demands being placed on railways from many sectors.
India`s energy sector has had a long history of government ownership and administered prices. Uniform prices were set irrespective of use or location. The purpose of uniform price setting was to encourage an even spread of industrialization throughout the country. This pricing system has, however, become a serious handicap for development because it fails to provide producers with an adequate cash incentive for investment. The subsidies and cross subsidies are introducing wide distortions into the sector.
As part of the economic liberalization which begun in 1990-91, there are serious moves underway to reduce and remove various price controls in an attempt to move to a much greater market determination in prices.
The customs duty on imported coal has been successively reduced to ten per cent. The use of imported coal is likely to increase especially for coastal stations.
The cost of building and running a power plant is very much determined by the fuel chosen. This technical-economic evaluation is based on fuels and technologies which are mature and merit use in the near future. Imported (Indonesian, African and Australian) coal, naphtha, orimulsion and LNG have been considered. The analysis is based on calculation of cost of generation (COG).
Calculations are made for fixed and variable costs motivated from the two part tariff concept applicable to India (Table 1). The matrix can be altered for other alternatives for an order of magnitude calculations. The exchange rate assumed is $1=Rs40. For other factors which are fairly volatile, average values have been used.
There were seven key inputs to the calculations: cost of project; fixed charges; station heat rate; auxiliary power consumption; cost of fuel; transportation cost; and working capital.
Cost of project: The cost of the project has been estimated for each case separately accounting for the changes in scope, sizing, type of equipment, fuel characteristics, plant locations, soil conditions etc. For example, low ash content of imported coal reduces the size of ash handling plant, higher heating value of coal calls for a smaller coal handling plant etc. Greenfield sites have been assumed for each case.
The indicated cost/kW is therefore only indicative and is included for convenience only. For orimulsion and HFO, FGD cost of Rs0.25 crore/MW ($70 000/MW has been considered. (The base figures are based on the awarded contract prices for some recent projects.)
Fixed charges: The fixed charges consider a number of components: O&M charges (at about 2.5 per cent of total project cost), depreciation (about 7.65 per cent of total project cost), interest charges (12.56 per cent of the 70 per cent of cost of the project); return on equity (at about 16 per cent of 30 per cent of project cost; interest on working capital (at about 18.5 per cent of 75 per cxent of working capital, balance is assumed to come from short term borrowing. These are based on the current guidelines of Central Electricity Authority (CEA).
Station heat rate: These are calculated according to the normative base figure of 2500 kcal/kWh for Indian coal fired stations and 2000 kcal/kWh for gas fired gas turbine based combined cycle power plant (CCGT). The base values have been corrected for the other fuel options. The boiler efficiency variation due to low ash content of imported coal compared to Indian coals was a prime consideration. For relatively high sulphur coals, the heat rate is attributed to the higher boiler exit gas temperature.
Auxiliary power consumption: Auxiliary power consumption for power stations using various fuels were estimated by correcting the normative base values of eight per cent for Indian coal fired conventional power stations and three per cent for CCGT. Variation in sizing of auxiliaries due to different characteristics of fuels has been accounted.
Cost of fuel: The costs of fuels considered in the evaluation are shown in Table 2. LNG prices used are at plant location and include all the transportation costs and duties.
Transportation cost: It is assumed that by the year 2002, all power plants will be linked to the nearest fuel supply source coal field or port. Liquid fuels are transported via pipelines or railways and coal by railways and sea. Regressions were fitted on freight data to estimate the fixed and variable cost. Components per tonne for liquid fuel and coal resulting in:
– Liquid fuel (railroad) Y(Rs) = 29.17 +1.39 *X(km)
– Liquid fuel (pipeline) Y(Rs) = 0.81*X(km)
– Coal (railroad) Y(Rs) = 23.76 + 0.67*X(km)
– Coal (sea route) Y(Rs) = 600 + 0.233*X(km)
These include port charges for port of embarking and disembarking.
LNG (pipeline) Y($/MBtu) = 0.44 (for 500 km); 0.97 (for 1000 km); 1.49 (for 1500 km)
Working capital: For calculation of working capital several key parameters were considered based on the current CEA directives. These were: fuel charges for one month; fuel stock 15 days for pit head stations and 30 days on for non-pit head stations; operation and maintenance expenses for one month; spares for one year; receivables for two months.
Table 3 presents the calculations for cost of generation for a) different fuels and b) conventional coal fired station and combined cycle power plant. It is also assumed that the source of the fuel is at the respective plant site.
Table 4, meanwhile, shows the cost of generation for various fuels and plant according to distance from the fuel source. This shows the effect of transportation on costs for the different fuels.
Table 5 shows the COG for various competing fuels based on what is termed as the “imputed” fuel costs. Six stations are considered. The imputed fuel cost is the maximum fuel cost of all competing fuels for any given station being considered by the prospective investor in order to match the least cost option from Tables 3 and 4.
The concept of imputed fuel cost thus provides a sound basis for prospective investors to evaluate fuel options and also the maximum price beyond which other fuels become uneconomical for the station under consideration. Negative prices have been included to reinforce the effect of transportation cost component. The natural gas option is excluded due to the non-availability from indigenous sources.
After all considerations, including the transport infrastructure, indigenous coal emerges as the least cost generation option for pit-head power stations.
For coastal power stations, LNG proves to be the least cost option. Until LNG terminals are developed, imported naphtha may have to be considered as a bridge fuel. Imported coal can also compete with indigenous coal and should be evaluated more closely by the prospective investor.
For non-pit head inland locations, indigenous coal also emerges as the least cost option. However, the economics are sensitive to the station location. LNG and imported coals merit consideration for inland locations even with coal transport constraints. With deregulation, coal prices will shift further towards the import option.
Indian gas due to the uniformly administered tariff, irrespective of location has the least COG. However, unavailability of gas and uncertain pricing makes it an impractical option.
Domestic fuel supply is likely to fall short of demand in the short to medium term and some imports may become inevitable. For conventional power stations, imported coal merits further detailed study.