1. Ancillary Services
Accounting & Settlement
Mechanisms
H K Chawla
DGM, NRLDC
1

2. Regulatory Provisions
• Maiden definition in Indian context in the CERC (Indian Electricity Grid Code),
Regulations, 2010
“Ancillary services in power system (or grid) operation means services necessary
to support the power system (or grid) operation in maintaining power quality,
reliability and security of the grid, e.g active power support for load following,
reactive power support, black start etc”
Clause 11(1) (b) of the amended CERC UI Regulations, 2009
(Application of Fund Collected through UI)
“Providing ancillary services including but not limited to ‘load generation
balancing’ during low grid frequency as identified by the Regional Load
Despatch Centre, in accordance with the procedure prepared by it, to ensure
grid security and safety:”
• NLDC prepared the approach paper & submitted it to CERC
2

3. Present Scenario
• STOA Limitations
Fragmented capacity
Match Making
• Unscheduled Interchange (UI): Balancing Mechanism
for inadvertent interchange
Limits on UI Volume
Price Uncertainty
Frequent Start-Stop operation

4. • Impact
- Frequent Unplanned Load shedding
- Value of load lost.
• Need for
– Flexibility and customization
– Harnessing all available generation resources before load
shedding

5. Power Supply Position (Feb’ 2013)
Region Energy Deficit % Peak Deficit %
Requirement Demand
(MU) (MW)
Northern 19,967 -8.0 36,923 -9.3
Western 21,456 -1.9 37,343 -2.6
Southern 22,544 -16.5 35,901 -13.1
Eastern 8,133 -4.6 14,338 -5.3
North
Eastern
877 -6.7 1,934 -4.6
All India 72,977 -8.4 126,439 -7.9
Source: CEA Monthly Report

6. FREQUENCY DURATION CURVE APR'12 TO JULY'12 FREQUENCY DURATION CURVE APR'12 TO JULY'12
For Dated 1-4-2012 to 31-7-2012
50.7
50.5
Frequency Below 49.7 Hz for 39% of Time.
50.3
50.1
FREQ(In Hz)
49.9
49.7
49.5
49.3
49.1
48.9
48.7
0 10 20 30 40 50 60 70 80 90 100
Scroll
% of Time Zoom

7. Why Ancillary Services for India ?
• Reliability , Security, stability and Power quality
• Restructured Power Systems
• Lack of adequate Primary, Secondary and Tertiary
Response
Lack of Adequate Reserves
• Loose Power Pools
• Absence of Tight Frequency Control
7

8. Primary, Secondary and Tertiary
Responses
Primary Secondary Tertiary

9. Targets
• Harness Fragmented Generation at Optimum Cost
• Availability of more peaking capacity
• Opportunity for Generators
– Help the grid
– Monetary Incentive
– Mitigate load shedding
– Value of Lost Load
• Relieve of congestion
– (utilization of Kayamkulam despite congestion)
• Renewable Generation
- Handling Variation thereby facilitating integration
Confidence to Pumped storage plants
9

10. Kayamkulam
Flowgate Limiting injection
SR Import
would relieve
congestion
Flowgate Limiting towards SR
S1-S2 exchange
import
Kayamkulam
Generation
NLDC 10

11. Classifications of Ancillary Services
• Frequency Support Ancillary Services (FSAS)
• Voltage Control Ancillary Service
• Black Start Ancillary Service

12. Section 27 (2) of the Electricity Act 2003
“Provided further that no Regional Load
Despatch Centre shall engage in the
business of generation of electricity or
trading in electricity.”
Role
􀁻 Despatch Decision
􀁻 Involvement in trading in electricity is
avoided as Facilitation through power exchanges

13. Section 28 (3) of the Electricity Act 2003
‘The Regional Load Despatch Centre shall
a) be responsible for optimum scheduling
and despatch of electricity within the
region in accordance with the contracts
entered into with the licensees or the
generating companies operating in the
region.
b) keep accounts of quantity of electricity
transmitted through the regional grid.’

14. Section 32 (2) of the Electricity Act 2003
‘The State Load Despatch Centre shall
a) be responsible for optimum scheduling
and despatch of electricity within a
State in accordance with the contracts
entered into with the licensees or the
generating companies operating in that
State.
b) ..
c) keep accounts of quantity of electricity
transmitted through the State grid.’

15. Existing Mechanism for Energy Accounting
• Energy accounting on 15-minute time block basis.
• Three part tariff for both beneficiaries as well as generators
• Three parts are :
Generators Beneficiary (State)
Capacity Charge Declared Capacity Capacity Share
Energy Charge Scheduled Energy Schedule Drawal
UI Charge Difference between Difference between
Scheduled energy and Schedule drawal and
Actual Generation actual drawal
15

16. UI Mechanism
• For deviation from scheduled generation/ Drawal
• Monday to Sunday is the weekly accounting period
• Inputs – DC, Scheduled Injection/ Drawal, Bilateral/
collective exchanges, Metered Energy, Frequency
• Issued Weekly by RPCs
• Physical account maintained by RLDCs
• Interest on late payment of UI charges
• Responsibility of the State/SLDC- Further
apportioning/recovery of UI charges from the various
Discoms and embedded customers in the State
16

17. Unscheduled Interchange Curve
2000.00
UI Rate VS Frequency (w.e.f 17.09.2012)
1800.00 1800 (Payment Side)
Paisa/KWH
1600.00 FREQ Normal Range(50.20 - 49.50 HZ)
1400.00
1200.00 900 49.50
1000.00
800.00
49.70 HZ
600.00 28.12 49.80
400.00
200.00 28.50 Paisa/0.02 50.00 HZ
HZ
0.00
16.50
Paisa/0.02
49.72
50.04
49.00
49.04
49.08
49.12
49.16
49.20
49.24
49.28
49.32
49.36
49.40
49.44
49.48
49.52
49.56
49.60
49.64
49.68
49.76
49.80
49.84
49.88
49.92
49.96
50.00
50.08
50.12
50.16
50.20
50.24
50.28
HZ
Frequency (HZ)
4/15/2013 POSOCO 17

18. 2000
UI Charges ( payment side)
UI Rate VS Frequency (w.e.f 17.09.2012)
1800
1800 (Payment Side)
Paisa/KWH FREQ Normal Range(50.20 - 49.50 HZ)
ADDL UI for OD (in the range < 49.70 HZ & < 49.50 HZ & < 49.20 HZ)
1600
ADDL UI for APM (in the range < 49.70 HZ & < 49.50 HZ)
100 % 49.20 ADDL UI for UI (in the range < 49.70 HZ & < 49.50 HZ & < 49.20 HZ)
1400
1260 Addl UI for O/D
Paisa/KWH 49.50 HZ
1200
1080.00
40 %
Paisa/KWH 20 %
1000
20 %
800
900 10 %
49.70 HZ
590.63 Paisa/KWH
590.10paise/kwh 28.12
600 49.80
400 505.80 463.65 28.50 Paisa/0.02
HZ
200 49.50 421.50 paise/kwh
50.00 HZ
16.50
0 Paisa/0.02 HZ
49.52
49.00
49.04
49.08
49.12
49.16
49.20
49.24
49.28
49.32
49.36
49.40
49.44
49.48
49.56
49.60
49.64
49.68
49.72
49.76
49.80
49.84
49.88
49.92
49.96
50.00
50.04
50.08
50.12
50.16
50.20
50.24
50.28
Frequency (HZ)
4/15/2013 POSOCO 18

19. 1200
UI Charge receipt side UI Rate VS Frequency (w.e.f 17.09.2012)
1100 FREQ Normal Range
1000
900 Paisa/KWH (Infirm Liquid Fuel) Buyer/Bef UD>10 % of sch or 250 MW whichever is less &
Seller/Gen >20 % of sch subject to 105 % of inst Cap in a
900 block or 101 % of Inst cap over a day
APM for OG > 105% DC in a block or 101 % over Avg DC
800
49. 48 HZ
700
28.12 Paisa/0.02
600
49.80 HZ
28.50 Paisa/0.02
500 450 Paisa/KWH HZ
400 16.50 Paisa/0.02
421.50 Paisa/KWH 330 Paisa/KWHn (Infirm Imported Coal/RLNG)
HZ
300 260 Paisa/KWH ( Infirm APM Gas as fuel)
49.80 HZ 49.82 HZ
200 165 paisa/KWH (Infirm Coal /Lignite/hydro) 50.00 HZ
100
0
49.32
49.36
49.00
49.04
49.08
49.12
49.16
49.20
49.24
49.28
49.40
49.44
49.48
49.52
49.56
49.60
49.64
49.68
49.72
49.76
49.80
49.84
49.88
49.92
49.96
50.00
50.04
50.08
50.12
50.16
50.20
50.24
50.28
Frequency (HZ)
4/15/2013 POSOCO 19

20. Year-wise Status of UI Amount Billed

21. Existing Settlement System
RLDCs and SLDCs have a key role in the
metering and settlement system
• RLDCs at the regional level
• SLDCs at the State level
Objective of the settlement system is to determine
Who bills whom for how much quantum of power
and how much money?

22. 10 MW TRADER
10 MW
@ Rs. 2.00/ u @ Rs. 2.20/ u
A B
AGREEMENTS
A ACTUAL FLOW B
8 MW 12 MW
GRID

23. TRADER Rs. 2.20/ u for
Rs. 2.00/ u for
10 MW
10 MW
PAYMENTS
A B
UI for 2 UI for 2
MW MW
UI POOL A/C

24. Interchange: Possible Combinations
Scheduled-Scheduled Unscheduled-UnscheduledExisting
SI UI Possible
Combinations
SI UI
Scheduled-Unscheduled
Interchange
under FSAS
UI
SI
NLDC 24

25. FSAS
• Focus
– Stabilize the frequency by utilizing the left over fragmented
generation capacity.
• Umbrella (un-despatched generation)
– Liquid fuel based
– Diesel based
– Merchant/ IPPs/ CPPs
• Liquid fuel and diesel based capacity
– The load serving utilities partially harnessing intra-state and
inter-state sources.
– Un-despatched capacity and need of load serving entities
fragmented.
– Such Generations commercially feasible, if UI rates are
higher than their costs. 25

26. Framework of FSAS
• Facilitation of FSAS through Power Exchanges
• New product for introducing FSAS
• Separate category of user group
– Seller registration for FSAS
• Users to be Part of the existing settlement
mechanism including deviations
• Proper visibility with data, communication,
telemetry
• Standing clearance from concerned SLDC/RLDC
26

27. Procedure
• Competitive Bidding Process
• Window to open after closure of Day Ahead Market
– Sellers to bid in either of the exchanges
– Declaration of supplier, bid area, quantum, duration, price
• Adherence to the ‘anonymity philosophy
• Sellers in DAM with un-cleared bids and other sellers
with surplus/idle power can be the Prospective
participants.
27

28. Possible Opportunity for FSAS Ancillary
Lost Sell Volume (Sell Bid-Unconstrained MCV) (Apr-12 to Mar-13)
Volume in MWH

29. • Compilation and Stacking of bids
– For every time block of the next day
– Stacking based on bid price
• Overall optimization by stacking and despatch
of bids on National basis

30. Despatch under FSAS
• Despatch in real time
– System Conditions
– Deficit anticipation by the system operator .
• Lower limit in the IEGC frequency band ie 49.70
Hz as the threshold frequency.
• System operator will trigger FSAS below
threshold frequency.
– Merit Order of bids
• Despatch certainty of at least 12 time blocks (i.e 3
hours) to prevent frequent start-stop operation.
30

31. • Backing down,subject to system conditions, during
the said 12 time blocks, compensation to the extent
of their fixed cost.
• Despatch in case of Congestion
– Pan India merit order may be discounted
– TTC/ATC across Inter & Intra Regional to be
honoured
• Consent from seller to ascertain its readiness
– Participants option to schedule in STOA continue.

32. Scheduling & Accounting for FSAS
• Scheduling to be routed through Power Exchanges
similar to that of Day Ahead Market
• PXs to reveal the injection point/ identity of the
identified bidders.
• Despatched bids: incorporated in schedule of Sellers
• Unmatched one to one schedule
32

33. • Despatched bid quantum attributed towards
drawal of the POOL; a fictitious notional entity.
• Drawees/ users of despatched power quantum to
pay back for the service in the form of UI charges
• Scheduling as per present practice on regional basis
– By SLDCs for embedded players

34. Integration of Settlement Mechanism with UI
Mechanism
Seller 1 Buyer 1 Buyer 2
Day ahead schedule (MW) 100 75 25
Schedule under FSAS (MW) 15 0 0
UI (MW) 5 12 8
Total (MW) 120 87 33
15 MW @ 12 MW @ UI rate
FSAS clearing Buyer 1
rate
UI POOL
Seller 1 (Regional) 8 MW @ UI rate
Buyer 2
5 MW @
UI rate 34

35. Settlement under FSAS
• Settlement
Uniform pricing
– As paid to the costliest generator who was called in
last for that respective time block
• Energy based settlement
• Upper limit of CERC UI vector : ceiling price
35

36. • Payment to sellers through power exchanges
– Transfer of Funds from respective regional UI pool to
exchanges next day .
– Exchange to pay to the supplier of services same day
• Scheduling , Transmission charges(PoC) and losses as
applicable for STOA transactions

37. Voltage Control Ancillary Service
• VCAS to support & maintain voltage within the permissible
limit.
• Provision for Voltage control ancillary service
embedded in IEGC.
• Priced for regional entities except generating stations for
Reactive Energy Exchange when voltages beyond 103% or
97%.
• Cost of supplying reactive power
– The capital cost of the equipment .
• Generators
– Reluctant to operate synchronous condenser mode
Friction and windage losses.
– Sometimes reduction in real-power production capability.
• Participation in Voltage Control by Generators may be
compensated through Ancillary Service.

38. Black Start Ancillary Service
• Black start
– Process to recover or reenergize a system from total or partial
failure
• Generating units with black start facility
– Certain identified units
– Required for black start of an electrical power system
– Should be able to start without external support
• CEA (Technical Standards for Connectivity to the Grid)
Regulations, 2007
– Clause 6(4) (c)
“Participate in contingency operation such as load shedding,
increasing or reducing generation, islanding, black start,
providing start up power and restoration as per the procedure
decided by appropriate Load Despatch Centre;”.
• Mandatory service as of now

39. • Startup supply requirement
– 0.5% for hydro stations
– 2% of the installed capacity for gas turbines
• Expenditure associated with Black Start
– capital cost of the equipment used to start the unit
– cost of the operators
– routine maintenance and testing cost
– cost of fuel
• Equipment cost recovered as fixed charges in generation tariff.
• Units not reimbursed for the operating cost .
• Need for Black Start as an Ancillary Service for voluntarily
procurement from generating units.

42. ALL INDIA WIND ENERGY
GENERATION
250
225
2011-12: MAX-168 MU; MIN-7 MU; AVG-57 MU
200 2012-13: MAX-224 MU; MIN-9MU; AVG-81 MU
175
150
MU/DAY
125
100
75
50
25
0
01-Apr 01-May 31-May 30-Jun 30-Jul 29-Aug 28-Sep 28-Oct 27-Nov 27-Dec 26-Jan 25-Feb 26-Mar
MONTH
2011-12 2012-13

43. Wind Generation in Rajasthan from April'12 to Jan'13
1200
Apr-12
1050
May-12
Jun'12
900
Jun-12
750 Jul'12 Jul-12
May'12 Aug-12
600
MW
Sep-12
Aug'12
450
Apr'12
Oct-12
300
Dec'12
Nov-12
Sep'12
150 Dec-12
Jan'13
Oct'12 Nov12
Jan-13
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
TIME

44. Integration of Renewable Generation
• Renewables 26.36 GW installed capacity targeted for 45 GW by
2015 (RPO target level of 10% Nationally).
• Challenges for grid operators
– Reliability top priority
– Variability and uncertainty in aggregate electric demand .
– Unit Commitment
– Integration of intermittency nature of Renewable Generation
– Frequency Control
– Reactive Power Management
– Physical constraints (i.e., available transmission)
– Institutional constraints ( market structure)
• FSAS to complement the diurnal changes in renewable
generation.
• FSAS to facilitate renewable integration by reducing the impact of
their variation.

45. Summary
• Ancillary services separate from basic system services as such
to be remunerated appropriately
• Discovery of Information
– Undespatched generation: Quantum & price
– Spinning Reserves: quantum & price
• Home Grown Solution
• Competitive Bidding
• Cost to customers
– Imbalance price based on the prevailing UI vector
• Merit Order Despatch
– Overall Countrywide Optimization
45

46. • Operational Flexibility for drawees
• Generators
-Respond to price signals
-Incentive for response and helping the grid
• UI and Ancillary
– Two of the four pillars of market, Should co-exist
• Reliance on FSAS as a routine practice to be avoided
• Frequency Curve will get further smoothen with the
availability of FSAS
• Powerful signal for investment to Generators

47. Pillars of Market Design
Sally Hunt – ‘ Making Competition Work in Electricity’
47

48. Way Forward
• Staff paper by CERC
• National Diagolue
• Capacity Building at SLDC
• Procedure by Nodal Agency/NLDC
• Implementation
• Monitoring of actual delivery
• Demand Response
• NLDC/Nodal Agency indemnification.

50. Evolution of Power Market in India
Ancillary
Market
Transmission
Pricing (PoC)2011
PX
2008
Open Access
2004
ABT
2002-03
IEGC
Feb.’2000

51. A Typical Dispatch
Surpluses/Deficits - Balance supply and demand
36 Forecast Contingency Real-time
34 Day Ahead, UI
PX
32 Buy Buy
00 MW
30 Sell Sell
28
26
ADVANCE SHORT TERM BILATERAL CONTRACTS
24
22
FIRM SHARES IN ISGS
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hours

52. Pumped Storage Plants…….
facilitation through FSAS
• Nearly Rs. 2/kWh differential in peak and off peak prices of
power
• Increased standard of living……load curve with pronounced
humps.
• Higher level of pithead based coal generation……..lower off
peak prices
• Narrowing of frequency band would further increase the
differential between peak and off peak prices in the market.
• Absorbing large quantities of intermittent generation…..a major
challenge……….pumped storage a beautiful complement