Electricity Market General Practice
A wholesale
electricity market exists when competing generators offer their
electricity output to retailers. The retailers then
re-price the electricity and take it to market. For economically efficient
electricity wholesale market to flourish it is essential that a number of
criteria are met, namely the existence of a coordinated spot market that has
"bid-based, security-constrained, economic dispatch with nodal prices. The
system price in the day-ahead market is, in principle, determined by matching
offers from generators to bids from consumers at each node to develop a
classic supply and demand equilibrium price, usually on an
hourly interval. The theoretical prices of electricity at each node on the
network is a calculated "shadow price", in which it is assumed that one
additional kilowatt-hour is demanded at
the node in question, and the hypothetical incremental cost to the system that
would result from the optimized redispatch of available units establishes the
hypothetical production cost of the hypothetical kilowatt-hour. This is known
as locational marginal pricing (LMP) or nodal pricing. A
constraint can be caused when a particular branch of a network reaches its
thermal limit or when a potential overload will occur due to a contingent event
(e.g., failure of a generator or transformer or a line outage) on another part
of the network. The latter is referred to as a security constraint.
A retail
electricity market exists when end-use customers can choose their supplier
from competing electricity
retailers. Generally, electricity retail reform follows
from electricity wholesale reform. If a wholesale price can be established at a
node on the transmission grid and the
electricity quantities at that node can be reconciled, competition for retail
customers within the distribution system beyond
the node is possible. Competitive retail needs open access to distribution and
transmission wires. There are two types of fees, the access fee and the
regular fee. The access fee covers the cost of having and accessing the network
of wires available, or the right to use the existing transmission and
distribution network. The regular fee reflects the marginal cost of
transferring electricity through the existing network of wires. In general, researchers have shown that with an open retail
market, individual consumer preferences are more likely to be served, the range
of products and services offered would be greater, and innovations would happen
faster.
CERC proposes MBED
In India, the discoms do not have
visibility of other cheaper options nor do they have the right to
requisition/schedule power from the generating stations with which they do not
have a contract. Whereas the international experience offers alternative market
designs in order to ensure optimum utilization of generation in different time
horizons. It is in this backdrop that a Market Based Economic Dispatch (MBED) model is proposed. The
model would function on a day-ahead time horizon and schedule and dispatch all
generation purely on economic principles, subject of course to technical
constraints.
The objective of the MBED will be to
meet the system load by dispatching the least-cost generation mix while
ensuring that security of the grid is maintained. This will ensure that the
total cost of generation i.e. system cost, to meet the system load in all
time-blocks for a day is minimized.
The system operation will address the
physical settlement of electricity, whereas the market operations will involve
bid solicitation and all financial settlements.
The generators are expected to bid
based on their variable/marginal cost of generation. The existing bilateral
contract holders will be paid the fixed cost separately outside the market and
as such would also be induced to bid in the market based on their
variable/marginal cost of generation. This is expected to ensure discovery of
the true system marginal cost. Once the bids and offers are received, the
market clearing engine will seek to optimize the dispatch of generation
sources. The buyers will be supplied electricity as per their load and the
generators will get dispatched in merit order up to the point where the total
system load is met; and the contracts would be settled bilaterally.
The market operator would discover
the market clearing price (MCP) after the bid period closes. The MCP in each
time-block would be the bid value of the last generator/sellers’ offer matched
to meet the demand offers which would reflect the marginal value of the electricity
i.e. the cost of producing one more unit of electricity to meet an additional
unit of demand. All the buyers will pay to the market operator at MCP for the
day-ahead demand. Similarly, all the generators will be paid at the MCP
according to execution of their selected bids. This uniform price settlement
will take place for all the demand bids and the generator/sellers offers that
are part of the dayahead period.
There would be a hedging arrangement
(to be referred as Bilateral Contract Settlement or BCS) of refunding the
difference between the market clearing price and the contracted price (the
contracted price in this case would mean the variable cost as determined by the
Appropriate Regulatory Commission, since the fixed cost would be paid
separately based on availability as per the current practice).
In the proposed MBED framework, under
transmission constraints, Discoms and Generators located in different bid
regions may face (apart from the ‘temporal risk’ being addressed through the
BCS explained in the previous section) the ‘Spatial Risk’ due to difference in
Area Clearing Prices (ACP) of bid areas. This risk can be addressed by
allocating the “Congestion Amount” to the entities having bilateral contracts
and paying the fixed charges for transmission.
The participation in the Market Based
Economic Dispatch model in Day-Ahead Market (DAM) time horizon would initially
be voluntary for the parties. Ideally all procurement by discoms should be done
through DAM. However, the discoms may retain some generators on the
self-schedule list and allow others, with whom they have long term PPAs to
participate directly in the market.
The existing arrangement of
self-scheduling of the long-term contracts described above should ideally hold
good during the transition period (of say one year), after which all such
generators as well as the discoms with whom they have contracts should also be
mandated to participate in the day ahead Market Based Economic Dispatch system.
CERC directs SCED
In a suo-motu Petition No. 02/SM/2019 CERC
directs POSOCO vide Order Dated 31.01.2019 to implement Pilot on Security
Constrained Economic Dispatch for ISGS pan India w.e.f. 01.04.2019 for six
months.
The main idea is that, in order to
satisfy the load at a minimum total cost, the set of generators with the lowest
marginal costs must be used first, with the marginal cost of the final
generator needed to meet load setting the system marginal cost. This is the
cost of delivering one additional MWh of energy onto the system. The historic
methodology for economic dispatch was developed to manage fossil fuel burning
power plants, relying on calculations involving the input/output
characteristics of power stations.
Security Constrained Economic Dispatch or SCED
is a mathematical model to generate the most economic generation dispatch while
considering key system operation constraints, such as power balance constraint,
reserve requirement constraints, transmission security constraints, as well as
generation limitations, such as ramp rates, minimum and maximum output levels. It aims to follow MoP’s concept of Flexibility in Generation and Scheduling of
Thermal Power Stations to reduce emissions to find an
optimal solution for minimising the total production costs of all thermal ISGSs
without disturbing grid security, and honouring the existing generation
scheduling procedure.
Pilot on Security
Constrained Economic Dispatch for ISGS which involves 28 power plants has cumulatively saved Rs. 63
crore in the first three weeks of its implementation. Few private power
units such as Reliance Power’s Sasan unit and Tata Power’s Mundra station are also part of the scheme.
The average potential savings per day from the pilot system was estimated to be
Rs 2.4 crore/day.
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