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Merchant Power plants Merchant Power plants
By B.S. Meel

Merchant power plants differ from traditional rate-based power plants as to: 1) how they are financed and 2) where they sell the electricity they generate.
A merchant power plant is funded by investors and sells electricity in the competitive wholesale power market. Since a merchant plant is not required to serve any specific retail consumers, consumers are not obligated to pay for the construction, operations or maintenance of the plant.

A traditional rate-based power plant, on the other hand, is built and operated by a regulated electric utility specifically to serve that utility’s retail customers. In return, the customers are obligated to pay for the plant’s construction, operations and maintenance.
The merchant power plants are not tied up with long-term power purchase agreements (PPA). Independent power producers (IPPs) who opt for this route will have to do so at their own risk. Setting up a merchant plant would necessarily mean balance sheet financing by he developer, as financial institutions/lenders may as a rule, may not be comfortable with projects that don’t have long-term PPAs.
Though this would appear to be a gamble, experts say the risk could be fully taken care of IPPs develop projects that deliver power at competitive rates. Given considerable demand-supply mismatch, sale of competitively – priced power should pose a problem. Consider that in between April and May’06, against a demand of 95,583 MW, only 83,094 mw power was available – a peak shortage of 13.1%. This situation is likely to persist. Projections by the Central Electricity Authority show even if Xth Plan capacity addition together target of 32,084 mw is met, the all India peak shortages would be at an average of 16.3% or 18,913 mw. The ministry of power intends to add 10,000 MW capacity addition through MPPs in 11th Plan.
In its guidelines for the allocation of coal blocks and coal linkages for the power sector, the ministry of power said, “merchant power plants fill different niches in the market; some provide steady supplies to a power grid, while others fire up only when demand is highest and meet peak loads.” Merchant power plants operating competitively help assure that power is produces with efficiency and supplied to locations where it is needed most”.
The government has set the plant size between 500 MW and 1,000mw. This is not merely because the national tariff policy mandates all new private sector projects to come through the competitive bidding process. There are transmission constraints as well. The transmission system will not be able to support evacuation of power from large sized merchant plants.
To ensure that large volumes of power can be evacuated, dedicated transmission systems would be required. This would mean that customers for power produced by these plants have been tied up. Such projects would require transmission systems that are planned and executed in tandem with the generating plant. So that when the plant begins producing power, the transmission lines are in place to evacuate power from the plant to the consumer.
Merchant plants, by definition, do not have pre-identified customers. This would mean that these plants would have to depend on redundancies in the existing transmission system to evacuate power. The ministry is working on a via media where the merchant plant of capacity 500 mw to 1000 mw can be accommodated in the national grid, which would have redundancies.
The ministry of power, believes that a limited number of merchant plants will enable the development of an electricity market. “A few merchant plants of 500 mw to 1000 mw could be easily handled through the transmission system and it is an option for creating a market as it would promote power trading on short-term, medium –term and spot market basis.
But are we ready for the MPPs? Some of the key issues to be addressed in this regard are:
There are acute shortages in the country and we ration out use of electricity. The demand-supply gap is large.
The prices are fully regulated and there is no correlation between the cost of generation and the end-price paid by the consumer. There is a significant level of subsidy to all the consumer groups — in the form of lower-than-cost tariff or lower-than-cost recovery of infrastructure that go with the generation, transmission and distribution of electricity.
Thefts, pilferage, losses and inefficiencies arising out of transmission and distribution are high. This has resulted in higher-than-normal wheeling charges for transmitting electricity. There is no common charge across the country for wheeling. States discourage wheeling and banking for captive and third-party use.
Transmission — intra- and inter-State — is grossly inadequate. While Section 42 of the Electricity Act 2003 promises open access, it will be far from reality unless significant capacities are created in transmission.
Even 15 years after the power reforms policy, no private sector entry in transmission is seen or envisaged accept exception in the near future. PGCIL has the sole monopoly though efficient.
Cross-Subsidy Surcharge for open access by unrelated buyer-seller combine as stipulated by the EA 2003 has not been clearly defined yet. In some cases such as Gujarat and Tamil Nadu, it is as high as Rs 3.50 per unit sold. In the case of Maharashtra, the MERC has declared this as nil.
Some States, such as MP, have pegged this at lower than Re 1/-. There has been no stable policy from any of the States, though the Act stipulates that the surcharge is to be withdrawn in toto in five years.
Given these conditions, how would an MPP sell its output? There is no private market. Conditions are not conducive for development of a private market in the near future. Even if it exists, the cost economics will be dictated by high wheeling charges and the cross-subsidy surcharge as the States would not give up the creamy layer and would continue to levy high surcharge.
Selling to SEBs and discoms (distribution companies) during peak hours and lean season (summer) is a strong possibility. This is already being handled by NTPC and other agencies. There may be a few summers like last year when Maharashtra bought power at Rs 10 per unit. But these are far and few in between and MPPs cannot be set up based on summer demand alone. Trading licenses were encouraged but effectively there is no trading market, except between State utilities. No private trade has been signed so far, not even for a single unit of electricity.
The Ministry wants to encourage coal-based MPPs and allocate coal blocks to them. These plants cannot be switched on and off at will. They will require an eight- to ten-hour cycle time to stop and start, and even then the fuel loss is very high. MPPs typically have to supply whenever there is demand.
Peaking stations are to operate only in the peak hours. This being so, coal is not a recommended fuel at all for MPPs. Natural gas is the only option. Given the pricing and availability, natural gas-based stations are not feasible unless supplies are assured.
With so much uncertainty, who would finance the MPPs? While NTPC, BHEL, etc., alone can put up their balance sheet for these projects; no other private operator is capable of exposing their books for such ventures. Even in the case of NTPC or BHEL, they may set up a few peaking stations near the gas pipelines and but would not go for capacities such as 1000MW.
Thus, given the complexity of the Indian market, the scheme for MPPs may remain a dream unless the market reforms totally and free access is made available to the consumer for creation of a competitive market.