Deviation Settlement Mechanism for Improving Grid Frequency Regime in India.pptx

Subrata Mukhopadhyay, LSIEEE (NSUT) , and
Bhanu Bhushan (formerly of CERC)
Presented by
Subrata Mukhopadhyay
Deviation Settlement Mechanism for Improving Grid
Frequency Regime in India
Paper # 447 (EDAS # 1570850151)
Electricity Market and Policy/ Regulatory Aspects
10th IEEE Power India International Conference 2022

Deviation Settlement Mechanism… in India
Introduction
What is deviation?
• Deviation is basically due to mismatch of schedule and actual exchange of
power vis-à-vis energy.
• It could be for load, it could be for generation as well.
• Deviation / variation could be due to change in actual drawl with respect to
scheduled load based on estimate / trend.
• In generation front, it may be due to changes due to sudden tripping on
account of failure, or as faced with nature in respect of solar irradiance / wind
speed from what was forecasted.

Introduction (contd.)
Why is it to be paid attention?
• Commercially with tariff in place based on energy scheduled to be drawn as
per contract, for changes accordingly payment has to take care of - for drawl
over schedule requiring extra payment to be made by and for less a refund, to
distribution companies.
• Similarly for injecting more energy, generating station should get extra
payment and for less injection, generator has to pay back.

Introduction (contd.)
What is Deviation Settlement Mechanism (DSM) then?
• For one-to-one generator and load it is easy to quantify deviation, and
commensurate payment to be made or received.
• For multi-entity system it is neither easy to identify source(s) of extra energy
drawn by an entity nor the recipient(s) of extra energy injected by a generator.
• It calls for devising certain ways and means to be adopted to work out how
much an entity (generator or recipient) should receive from or pay to whom for
such deviations. This is Deviation Settlement Mechanism or DSM in short.

Regulations
Who is to regulate?
• In India under federal system, as system regulator CERC or Central Electricity
Regulatory Commission is entrusted to take care of such matters, like deviation
settlement.
• Accordingly it has to devise a commercial mechanism for adherence to the
schedule by the entities regarding injection and drawl of electric energy to take
care of operating parameters for the security and stability of grid in its
integrated operation.
• Regulations after notification are applicable to all grid-connected entities and
those involved in purchase and sale of electric energy.

Regulations (contd.)
What are salient features?
• Deviation charge for over and under injection of power:
• General seller, excluding Run-Of-River (R-O-R) hydro-based generation
• No charge for deviation up to 2% for over-injection or under-injection
• Beyond 2% deviation charges to be paid by entity at 10% of normal rate for over-injection.
For under-injection beyond 2% generator is to pay deviation charges at 110% of normal rate.
• For R-O-R (i.e., without storage) for over-injection no charges for deviation. But for
under-injection at normal up to 12%, and beyond that 110% of normal rate.
• For municipal waste based generation seller continues to be paid at contract rate for
over-injection up to 20%. For under-injection up to 20% it has to pay back at 50%
contract rate, but beyond at contract rate.
• For wind and solar no deviation charge for over-injection. For under-injection up to
10% no deviation charge. For beyond that deviation charge at 10% normal rate.

• Deviation charges for under and over-drawl of power:
• There are basically three categories
• With schedule up to 400 MW
• With schedule less than 400 MW in the renewable-rich states
• For renewable-rich states
• Conditions center around
• Not to pay deviation charges for under-drawl
• For over-drawl up to 12% deviation normal rate, but beyond deviation charges of 110% of the
normal rate
• However, there are exceptions too
• For start-up power before commercial operation or for drawl of power to run auxiliaries
during shut down it is normal rate
• For inter-regional, cross-border transactions whether over-drawl or under-injection it is
normal rate.

• Entity is to pay due within 7 days of issue of statement of charges, failing which
there will be surcharge of 0.04% per day.
• Failure of an entity to pay during previous Financial Year (FY) on account of
deviation within specified time requires opening Letter of Credit (LC) equal to
110% of its average weekly liability for deviation in the previous FY within a
fortnight from the start of current FY. This LC may be encashed after some
specified period for continuous defaulter.

International Practices on Real Time Balancing of electricity
market
For example practices followed by entities in different countries may be looked into
to find how they are dealing with the issue.
• United Kingdom (UK):
• National grid uses Balancing Services to balance demand and supply to ensure security
and quality of electricity supply across Great Britain Transmission System.
• It covers about 20 balancing services and products in terms od system security, reserve,
frequency response, reactive power, etc.
• Imbalance price is the price of electricity suppliers / generators to pay for imbalance based
on contract with each other to sell to residential, commercial, and industrial consumers.
• National Grid handles real-time balancing based on above-mentioned contracts. It takes
action to correct imbalance based on submission by parties bids or offers to change positions
by certain volume at a certain price.

market (contd.)
• National Grid can take actions beyond this further to balance the system, such as,
• Short Term Operating Reserve (STOR)
• Firm Frequency Response (FFR) plants used to balance in real-time
• Reserve Services
• In extreme cases closing of power plant or disconnecting consumers
• For STOR, payment to providers is based on availability in terms of £ / MW/ hr for the
hours of commitment and on utilization in £ / MWh for the energy delivered.
• FFR service is to keep frequency closed to rated 50 Hz; hence effective to manage any
fluctuation in system frequency due to sudden loss of generation or demand. It is of
primary, secondary, and high types, first and second being for low frequency while the
third for high frequency condition. Payment to providers is for availability on £ / hr
basis for MW and hours contracted, but there is no payment for utilization.

market (contd.)
• National Grid with technical constraint followed, tries to minimize costs of balancing
posed due to under-estimation of demand by supplier, and / or power plant failure.
• The difference between contacted and actual position is charged with imbalance price.
• Energy imbalance prices for the settlement period are System Buy price, and System
Sell Price on half-hour basis (now appears to be used equal).
• Price is based on, besides net imbalance volume, other pertinent quantities, like, Price
Average Reference Volume, De Minimis Acceptance Threshold, Continuous
Acceptance Duration Limit, Market Index Definition Statement, Loss of Load
Probability, Value of Loss Load, Reserve Scarcity Price, and Utilization Price.

market (contd.)
• Australian Energy Market Operator (AEMO):
• As usual AEMO tries to manage electricity system to match power supply and demand
using spot market mechanism.
• Periodic spot market price tells generators how much electricity market needs at any
moment to keep physical power system in balance.
• When spot price increases (day-time and evening) generation ramps up output with
more expensive generators turning on (like, gas peaker, pumped hydro-plant or fast-
response battery support), and while decreases (early morning hours) similarly these
are to go off first gradually.
• With generators submitting offers, central dispatch system orders for least to most
expensive generators for dispatch to keep overall cost low (in 5-minute block).
• For settlement price is averaged over 30-minute, i.e., averaging six-interval prices that
is used by AEMO as spot price.

market (contd.)
• PJM, USA:
• The PJM RTO (Pennsylvania-New Jersey-Maryland Regional Transmission Organization)
operates in accordance with NERC (North American Reliability Council) resources and
demand balancing (i.e., BAL) standards to ensure its capability to utilize reserve to
balance supply and demand in real-time to maintain frequency (following deviation).
• To dispatch energy, ensure adequate reserve in real-time, and regulation a multi-
module software platform is used PJM.
• Real-time market consists of
• Ancillary Service Optimizer (ASO): It optimizes jointly for energy, reserve, and regulation with
commitment of all regulation resources and inflexible reserve resources on hour-to-hour
basis.

market (contd.)
• Real-Time Security Constrained Economic dispatch (RT SCED): It is for dispatching resources
to maintain system-wide balance of energy and reserve over a near-term lookahead period. It
jointly optimizes energy, regulation, and reserve on online, dispatchable resources
commensurate with system needs. Based on economics results show the energy base points,
non-synchronized reserve commitments , information about which are sent to resource
owners in real-time (assessing reserve-shortage, if any).
• Intermediate-Time Security Constrained Economic dispatch (IT SCED): It performs over 1-2
hours lookahead period various functions to anticipate generator performance along with
operating parameters under different scenarios.
• Locational Price calculator: Results give financially binding Locational Marginal Prices (LMPs),
reserve Market Clearing Prices (MCPs), LMPs for entire network model, Regulation MCPs, and
reserve MCPs for each locale, using the latest approved RT SCED case as reference and
associated input files, EMS (Energy Management System) inputs, information on constraint
control.

market (contd.)
• CAISO, USA:
• CAISO (California Independent System Operator) maintains a real time Energy Imbalance
Market (EIM) allowing participants to buy and sell energy when needed, while balancing
authority areas are allowed to buy and sell final few MWs of power to satisfy demand on hour-
to-hour basis.
• Utilities maintain control over assets and be responsible for balancing while sharing cost
benefits the market yields for participants. EIM doesn’t participate in Day Ahead Market
(DAM).
• CAISO employs 15-minute block for Real-Time Power Dispatch (RTPD) and within this period
there are 5-minute block dispatch optimization.
• RTPD dictates commitment and LMP, while 5-minute process sets dispatch instruction. For the
latter SCED runs along with contingencies to ensure no violation of reliability constraint.

Possible ways and means that may be thought further for
India
Even with the present state of affairs in system operation can there be some easy
and accurate solution rather than rough or on ad-hoc basis?
• Three components could be thought of with the available measurements in
place
• With Special energy Meters (SEMs) installed at electrical periphery of each entity
deviation in 15-minute time block is known.
• All over-drawing and under-injection entities pay for deviation to Regional Pool
Account (RPA). All under-drawing and over-injection entities get paid for deviation
from the same account.
• Rates for such payments are an issue. It could be price one has to pay for drawing
extra power at that time. Again this could be Market Clearing Price (MCP) or Area
Clearing Price (ACP).

India (contd.)
• Erratic pattern of MCP or ACP is a hindrance, as observed with difference between
ACPs of DAM (Day ahead Market) and RTM (Real-Time Market). This may be due to
dependence on weather forecast, speculative perceptions of buyers and sellers, etc.
• Hence for payment to and from RPA in Indian Rupees (INR) / MWh rather it could be
best estimate of System Marginal Price (SMP) at that time by NLDC (National Load
Dispatch Center) post-facto. In fact this is the lowest price at which extra power could
be got as per system-wide merit-order.
• Of course some school of thought may be to have rate of payment to the pool higher
than that from the pool for discouraging / penalizing for deviation from schedule.
However, same rate may be kept.

India (contd.)
• This first component ‘A’ for the deviation payment has 3 parameters, first ‘actual’
MWh interchange for every regional entity for every 15-minute time block, then
corresponding ‘scheduled’ MWh as the second (computed from ‘schedule in MW’, not
with step change but with ramp integrated over time for smooth operation of power
system). Load Dispatch Center, LDC, has to monitor actual MW drawl / injection of
each constituent minute-to-minute basis to take appropriate online action to minimize
deviation.
• Third parameter is the ‘System Marginal Price’ (SMP). Assuming grid intact and no
constraint in transmission systems for the whole country one SMP may be used.
Ideally it could be variable (fuel) cost in INR / MWh of a thermal plant, the lowest cost
among partly-loaded thermal plants (that can be loaded further), as identified by the
National load Dispatch Center (NLDC). In a post facto exercise actually error in
selection can be avoided.

India (contd.)
• Now comes the second component on account of transmission.
• For over-drawl losses increase, while for under-drawl losses decrease. Accordingly
deviation of charges could be negative or positive. Tentative realistic value of say,
Indian Rupees, INR 150 / MWh or 15 PAISE / kWh could be charged (i.e., with US$ 2 /
MWh or 0.2 cents / kWh with 100 PAISE = 1.0 INR, and US$ 1.0 = INR 75).
• However over-drawl in one 15-minute time block cannot be neutralized by under-
drawl in another 15-minute time block.
• In order to discourage deviation, therefore, under second component ‘B’ there
should be cash inflow only. This may be used to make up deficit, if any, arising under
component ‘A’.

India (contd.)
• Third component ‘C’ is intended for the participation of entities in frequency control
to bring back frequency in the range of 49.95 to 50.05 Hz, after excursion due to load-
generation imbalance.
• Entities failing to provide ‘primary, ‘secondary’, ‘tertiary’ response have to pay under
component ‘C’ at the tentative rate, say INR 30 / MW or US$ 0.4 per minute while
those making up for the short-fall shall be paid at the same rate instead.
• Some examples in this context may be worthwhile to explain.
• Say, the total system load be 100,000 MW while operating generating capacity under
FGMO (Free Governing Mode Operation) be 50,000 MW with a governor droop, R=4%.
Neglecting transmission losses (for ease in understanding) and assuming load
response to frequency change (load damping, D) directly proportional, i. e., 1% dip in
frequency would cause load to reduce 1%, consider tripping of a 2,000 MW power
station operating under FGMO.

India (contd.)
• For balancing load would need to come down by 2,000 MW (or 2%), meaning that
frequency to settle at 49 Hz from the rated value of 50 Hz in a few seconds (depending
upon inertia of the system).
• In the process remaining 48,000 MW generation on FGMO will be raising generation to
stop fall in frequency.
• Using AFRC (Area Frequency Response Characteristic) b = D + 1 / R in MW / Hz, an
equilibrium point of operation may be found with frequency around 49.926 Hz
meeting new system load of 99,852 MW with ‘primary’ control effective.

India (contd.)
• With the tripping of 2,000 MW, plant is under-injecting 2,000 MW and continues to
pay under component ‘C’ INR 100,000 per minute, over and above under components
‘A’, and ‘B’. To come out of the situation either it can come back and / or partially
loaded other plants can make up the short-fall under bilateral arrangement, which is
under ‘secondary’ control.
• In case it is not possible (till RLDC revises schedule) other entities would have a
consequential deviation in schedule in opposite direction in terms of under-drawl and
over-injection of 2,000 MW. It consists of remaining 148 MW due to short-fall in load
(due to lowering of frequency of operation) and 1,852 MW increase in generation due
to FGMO. Accordingly latter entities together will be entitled to receive INR 100,000
per minute.

India (contd.)
• As frequency of 49.926 Hz is still below the lower limit of 49.95 Hz one or more entities may
increase generation further to receive money to bring the frequency to 49.95 Hz, when
payment to ‘C’ will stop., although to ‘A’, and ‘B’ it will continue.
• On the other hand, if there is a 200 MW generator trip, frequency will fall to 49.9 Hz. But with
the frequency movement more than dead-band (say, 0.03 Hz) frequency is brought back to
49.99 Hz. Payment to ‘C’ will stop, although it will continue for ‘A’ and ‘B’ for deviation in
energy transaction actually with respect to schedule, and transmission respectively.
• Ideally total payment to RPA for components ‘A’, and ‘C’ should respectively be equal to be paid
out from RPA. But due to metering errors and / or actual transmission losses not being equal to
the assumed transmission losses, there may be difference. In such case ‘one-way’ payment to
‘B’ component may be used as buffer. The latter may also be used to meet any short-fall in
RPA, say for voltage-linked payment for time-based Reactive Power Exchanges.

India (contd.)
• Not only at regional level, but also at intra-state level this sort of method may
be used.
• There will be incentive for the usage of BESS (Battery Storage Energy System),
Pumped-Storage Hydro, etc. as felt.
• ‘Primary’ control due to FGMO takes place in a minute or so of imbalance with
immediate financial incentive not so significantly observed. But subsequently
through minute-to-minute deviation measurement under ‘secondary’ control it
would start getting paid for.

Conclusions and Future Scope of Work
From the thoughts and views presented, to summarize following conclusions may
be drawn:
• Using the available facilities or with bare minimum additions, it is possible to
develop some more logical and scientific Deviation Settlement Mechanism that
would be acceptable to the participants and hence could be applied to Indian
Power System.
• It is basically dependent on three components of Deviation in Energy
Transactions, Over-usage of Transmission Systems, and Frequency Response.
• This may be somewhat better than on ad-hoc basis, something to start with.
• Next step of course way ahead is to further incorporate Load forecasting,
adequacy, unit commitment, ramp, schedule leaps, reserves, besides age-old
Area Control Error (ACE) etc. in some form or other to make it comprehensive.

Declaration and Acknowledgment
• Opinions expressed in this presentation in segment or as a whole
are of the Authors and in no way those are of the Organizations
with which they were or are associated. At the same time Authors
will like to express gratitude to these Organizations, namely, Central
Electricity Regulatory Commission (CERC), Power System Operation
Corporation Ltd. (POSOCO), Netaji Subhas University of Technology
(NSUT), and Professional Colleagues over there for the available
published documents and views toward preparation of this
presentation.

References
• B. Koul, K. Singh, and Y. S. Brar, “Deviation Settlement Mechanism and Its Implementation in
Indian Electricity Grid”, Machine Learning, Advances in Computing, Renewable Energy and
Communication (Lecture Notes in Electrical Engineering), edited by A. Tomar, H. Malik, P.
Kumar, and A. Iqbal, vol 768. Springer, Singapore. https://doi.org/10.1007/978-981-16-2354-
7_22, 2022.
• Akhil K. Gupta, Deep Kiran, and Abhijit R. Abhyankar, “Towards Efficient Real Time Deviation
Settlement Mechanism For The Indian Grid”, IET Generation, Transmission and Distribution,
vol. 14(1) DOI: 10.1049/iet-gtd.2018.6789, Jan 2020.
• Manju Gupta. Sushma Gupta, and Tripta Thakur, “Implementation of new electricity regulatory
norms for deviation settlement mechanism: A case study of India”, Cogent Engineering, vol.
6(1), DOI: 10.1080/23311916.2019.1623152, May 2019.
• Jayashri Satre, and Surekha Deshmukh, “Deviation Settlement Mechanism Linked with Market
Price in Indian Power Sector”, 2018 IEEE Fourth International WIE Conference on Electrical and
Computer Engineering (WIECON-ECE), Pattaya, Chonburi, Thailand, DOI: 10.1109/WIECON-
ECE.2018.8783145, Dec 2018.

References (contd.)
• Central Electricity Regulatory Commission (Deviation Settlement Mechanism and Related
Matters) Regulations, 2022; https://cercind.gov.in/Regulations/168_reg.pdf.
• Central Electricity Regulatory Commission (Deviation Settlement and Related Matters)
Regulations, 2022 –Statement of Objects & Reasons (SOR);
https://cercind.gov.in/Regulations/168-SOR-DSM.pdf.
• Central Electricity Regulatory Commission (Deviation Settlement Mechanism and Related
Matters) Regulations, 2021; EXPLANATORY MEMORANDUM;
https://cercind.gov.in/2021/draft_reg/EM-DSMRegulations.pdf.
• CERC Public Notice No. L-1/260/2021/CERC, Sep 7, 2021.
• CERC Public Notice No. L-1/260/2021/CERC, Oct 8, 2021.
• POSOCO inputs on Draft (Deviation Settlement Mechanism and related Matters) Regulations,
2021, Oct 25, 2021.

From the Presenter for and on behalf of the Authors
Thank You

Deviation Settlement Mechanism for Improving Grid Frequency Regime in India.pptx

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