This paper is all about the process of introducing market and economic despatch of electricity in India

1. Towards a Wholesale Electricity Market
Compiled by Amitava Nag, Regulatory Affairs Cell, WBSETCL
Summery
CERC proposed the creation of a central electricity market for
day-ahead and real-time dispatch, which would be co-optimised with the
procurement of ancillary services. For the DAM, the proposal is a market-
based economic dispatch run by a central market operator (with
voluntary participation of generators) that would replace self-scheduling
and include congestion management and market splitting. With regard to
contractual financial obligations in existing PPAs, bilateral contract
settlement is proposed to make the best use of existing assets, while
respecting the contractual commitments of DISCOMs. Generators would
also be able to participate in the market without having a PPA. Reforms
are under preparation to create forward contracts to increase the options
for hedging, which are currently not available in India. The CERC
regulations for Open Access in Interstate Transmission require the
creation of a National Open Access Registry as a centralized electronic
platform owned and operated by the NLDC.
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 despatch 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 re-despatch of available units establishes the

2. 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.
Many of the principles underlying the market designs that were
employed in the past (and which survive today) are rooted in the historic
architecture of electric power systems. However, the electric power
systems of today and tomorrow ‘look’ considerably different than most
power systems did a decade ago.
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.

3. 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 day-ahead 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

4. “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

5. 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.
The pilot operation of SCED during the months of April and May,
2019, encompassing 150 ISGS plants, amounting to half a million
contracts per day across 36 States have resulted in increase in cheaper
generation, decrease in costly generation and reduced the average
variable cost of generation from 210 paise/ unit to 207 paise/ unit. During
these two months of pilot operation, a reduction of Rs. 196 Cr. in fuel
cost (without considering heat-rate compensation) has been noted. It was
also brought out that SCED has resulted in 42% reduction in number of
schedule changes and 32% reduction in schedule GW changes and finally
resulted in increased PLF of cheaper stations.
POSOCO submitted an interim feedback report on 19th August,
2019, highlighting benefits, and optimisation results for the period
between 01st April, 2019 - 28th July, 2019 on SCED Pilot. POSOCO
highlighted in its feedback report that the SCED pilot has been running
during summer/monsoon seasons of April to September 2019 and there
is a need for gaining the experience during the winter season as well.
The Commission recognizes the time required for framing the relevant
regulatory amendments / enactments and the need for gaining
experience across all the seasons in a year. Accordingly, the Commission
has decided to extend the SCED pilot for the period upto 31st March,
2020.
As informed in the interim report submitted by the POSOCO, 49
coal and lignite based thermal ISGS generators constituting 132
generating units and having total installed capacity of 55,940 MW are
participating in the SCED pilot. There is reduction of about Rs. 3.3 Paisa
in the average variable cost of generation during the period from
01.04.2018 to 31.03.2019.
There has been around ₹ 845Crore reduction in fuel cost for April
–December, 2019 period which has been facilitated by pilot on SCED.
Considering a base of approx. ₹54,000 Crore during April–December,
2019, around 1.5 % reduction in generation cost (without considering
heat rate compensation) has been observed. There is reduction of about
3 paisa in the average variable cost of generation during the April –
December’19 period. [Ref: PSOCO’s January 2020 Feedback Report on
Pilot]

6. Commission decides to extend implementation of the SCED pilot till
31st March, 2021 and expands its scope to all generating stations willing
to participate in the pilot.
Real Time Electricity Market in India
Intra-day market in the power exchange was specifically
introduced to address the need for meeting energy requirements closer to
real time. On 12.12.2019 CERC has introduced a new market mechanism
in the intra-day segment defined as ‘Real Time Market (RTM)’ by
amending Power Market Regulations 2010. Real Time Market to be
implemented from 1st June 2020.
Real Time Market will be a half hourly market. The concept of
gate closure is introduced, with timeline in consonance with half hourly
market. Buyers/sellers would have the option of placing buy/sell bids for
each fifteen minute time block in the half hourly real time market. The
generators having long term contract and participating in this market will
be required to share the net gains (after accounting for the energy
charge) with the discoms in the ratio of 50:50 as per the stipulation of
the Tariff Policy, 2016. Right to revision of schedule will be available up to
seven/eight time blocks before the actual delivery of power. Any revision
in schedule made in odd time blocks shall become effective from 7th time
block onwards, and any revision in schedule made in even time blocks
shall become effective from 8th time block onwards, counting the time
block in which the request for revision has been received to be the first
one. Once the real time market commences for any specific half-hour
delivery period, the revision in schedule for that half hour (two time
blocks) shall not be permitted.
Real Time Market would not only provide discoms an alternate
mechanism to access larger market at competitive price but would also
allow the generators to participate in the Real Time Market with their un-
requisitioned capacity.
With Real Time Market in place, the discoms would have a
revolving reserve available in the form of half hourly trading opportunity.
This would provide the discoms a multi-lateral platform to meet their real
time energy needs vis-à-vis the one-to-one bilateral contract based price
under the existing system of right to revision of schedule.
Existing intra-day segment of power exchange would continue
to clear the continuous transactions except for the time blocks for which
the real-time market operates.

7. All generators connected to the grid will be able to participate in
the Real Time Market. In case of forced outages the generator can
participate in the Real Time Market and buy power for the beneficiary to
honor its commitment.
The NLDC would prepare detailed procedures for collective
transactions under RTM in line with the outline specified in the
Regulations. The charges applicable for the participants would be
specified in relevant byelaws and rules of the power exchanges
accordingly.
NLDC shall indicate to Power Exchange(s), margin available in
each of the transmission corridors before the gate closure, i.e. before the
window for trade closes for a specified duration. Power Exchange(s) shall
clear the buy and sell bids for the said duration under consideration on
various interfaces or control areas or regional transmission systems as
intimated by NLDC. The limit for scheduling of collective transaction
during real time for respective Power Exchanges shall be worked out in
accordance with the directives of the Commission. NLDC shall furnish the
available transmission corridors to the Power Exchange(s) before the
trading for real time market for a specified duration closes. Based on the
information furnished by NLDC, Power Exchange shall clear the RTM bids
and announce the Market Clearing price and volume. Based on the
volume cleared by the Power Exchanges, NLDC shall communicate the
schedules to the respective RLDCs. After getting confirmation from
RLDCs, NLDC shall convey the acceptance of scheduling of collective
transaction to Power Exchange(s). RLDCs shall schedule the Collective
Transactions at the respective periphery of the Regional Entities.
The window for trade in real-time market for day (T) shall open
from 22.45hrs to 23.00hrs of (T-1) for the delivery of power for the first
two time-blocks of 1st hour of day (T) i.e., 00.00 hrs to 00.30 hrs, and
will be repeated every half an hour thereafter. The bidding mechanism for
the real-time market shall be double-side closed bid auction for each time
block of the delivery period.
While curtailing collective transactions, day-ahead transactions
shall be curtailed first followed by real time transactions.
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