Energy Market Development Programgy g
AVAILABILITY BASED TARIFFAn Overview
Dr. S. K. Agrawal, General Manager,POWERGRID
1Colombo : August 22, 2008
Chronological Sequence of Implementation of ABT
1990 1990 : K. P. : K. P. RaoRao Committee Committee –– Proposed Two Proposed Two –– Part Tariff Part Tariff structure consisting of Fixed and Variable chargesstructure consisting of Fixed and Variable charges
19931993--9494 : A structured study by M/s ECC, USA, funded by ADB, : A structured study by M/s ECC, USA, funded by ADB, sponsored by WB as a covenant of loans to POWERGRIDsponsored by WB as a covenant of loans to POWERGRID Availability Based Tariff (ABT)Availability Based Tariff (ABT) Availability Based Tariff (ABT)Availability Based Tariff (ABT)
19951995--9898 : NTF / RTFs, formed for ABT implementation. : NTF / RTFs, formed for ABT implementation. 1999 1999 : Matter transferred to CERC : Hearings etc.20002000 : CERC Order, but stayed due to petitions20012001--0202 : Problems of regional grid operation continued
M i t t bl i l di t l: Many intractable commercial disputes also arose20022002--0303 :ABT implemented successfully.
AUGUST 2008 SKA 2
Outline of the presentation• Need for ABTABT t• ABT concept
• How UI pricing works?• Amendments to UI rates• Payment of capacity & Energy Chargesy p y gy g• Many dimensions of UI mechanism• Settlement system and logistics• Settlement system and logistics• Impact of ABTLi it ti d h d
3
• Limitations and way ahead
Conditions when ABT was i dconceived
•Grid indisciplineNo respect for schedule by generating stationsas well as beneficiary SEBs
•Poor Frequency regimeLow frequency during peak periods, highfrequency during off peak periodsfrequency during off-peak periods
•ReasonPerverted incentives in the tariff regime at thattime – Recover of capacity charges based onPLF and no differential payment for deviations
4
PLF and no differential payment for deviationsfrom schedule
ABC of ABT
• Frequency actuated signal– Signal transmitted at the speed of dynamics to be
controlledQuasi-steady state assumption not valid– Quasi-steady state assumption not valid
• Real time pricing stretched to its physical limits– Merit order– Economic load management
• Incentives for helping the grid• Opportunities for a diligent player• Simple, dispute-free weekly settlement system
AUGUST 2008 SKA 5
Deviations from Schedule - UIDeviations from Schedule UI
AUGUST 2008 SKA 6
DECENTRALIZED SCHEDULING
TimeAvailability
Declaration (DC)Entitlements
09:00
10:00
Time
Entitlements
S
Requisition &Bilateral Agreements
I j i S h d l
10:00
15:00
RI LDC
Injection Schedule Drawal Schedule
Revision in DC Revision in Requisition
17:00
22:00
RLDC
ISGS
FinalInjection Schedule
FinalDrawal Schedule
23:00
S
AUGUST 2008 SKA 7Revisions during
Current dayRevisions during
Current day0 to 24 hours
Balancing Market guiding Vector
Unscheduled Interchange (UI) Rate
1000
1200 Applicable only for deviations from contract in real-time
800
1000
--->
Deficit Condition in the Grid
signal to serve more if ibl l
600
(Pai
se/K
WH
) Surplus condition in the Grid
Signal to use all available generating resources else reduce energy
consumer if possible else save fuel by reducing
generation
200
400Rate
280
else reduce energy consumption
0
200
5 6 7 8 9 9 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 1
AUGUST 2008 SKA 8
48.5
48.6
48.7
48.8
48.9 49 49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
49.9 50 50.1
50.2
50.3
50.4
50.5
50.6
50.7
50.8
50.9 51
Frequency (HZ)---> UI Rate wef 07th Jan 2008
Concept of ABTC it (fi d) Ch f t•Capacity (fixed) Charge recovery of generatorlinked to Availability
•Capacity charges payable by beneficiary based•Capacity charges payable by beneficiary basedon capacity allocated
•Energy (variable) charges based on scheduledgy ( ) genergy
•A third component known as UnscheduledI t h (UI) h i l i d f d i tiInterchange (UI) charge is levied for deviationfrom the schedules
•Rate of UI Charge is based on frequency•Rate of UI Charge is based on frequency•Settlement period of 15 minutes•Applicability - Central Generating Stations and
9
•Applicability - Central Generating Stations anddrawal from the grid by beneficiaries
Unscheduled Interchange (UI)Unscheduled Interchange (UI)
• For Generating Station
UI = Actual generation - Scheduled generation
• For beneficiary (getting supply from grid)• For beneficiary (getting supply from grid)
UI = Total actual drawal - Total scheduled d l
10
drawal
Normal Operating Band specified in IEGC
Kink at 49 8 HzKink at 49.8 Hz
11
How UI pricing works -High FFrequency
Example: Generating Stationsp g
A BEnergy Charge (INR /Kwh) = 1.04 0.88
Generating Station
gy g ( )
Frequency(Hz) =
UI Rate (INR /Kwh)=
50.2
1 2UI Rate (INR /Kwh)=
Gain (Paise/ KWh) for generation below schedule = 0.16 0.32Conclusion: G ti t ti A h ld t d i ti if f i b d
1.2
Generating station A should srart reducing generation if frequency rises beyondthe level at which UI rate is 1.04 INR/KWh i.e. 50.24 HzGenerating station B should start reducing generation if frequency rises beyondthe level at which UI rate is 88 INR/KWh i.e. 50.28 Hz
12
How UI pricing works -Low FFrequency
Example: Generating Station
UI Rate (INR /Kwh)= 2.8
2.4Energy charge of the generating station despatched below availability or having margins
Gain by generating over the schedule (INR /KWh) 0.4
Conclusion: This generating station should, if feasible, start generating aboveschedule if frequency dips below the level at which UI Rate is equal toits energy charge i.e. 49.9 Hz.
13
How UI pricing works -High FFrequency
Example: BeneficiaryFrequency (Hz) = 50.1
UI Rate (INR /Kwh)= 1.6
2.4Variable cost of costliest operating generating stationowned by the beneficairy (INR /Kwh)=
0.8Gain (INR/ KWh) for drawal above schedule (byreducing generation at own costiliest station)
Conclusion: Beneficiary should start reducing generation at the costliest operatingstation (and overdraw from the grid) if variable cost of this station exceedprevailing UI Rate
14
prevailing UI Rate.
How UI pricing works -Low Frequencyq y
Example: BeneficiaryFrequency (Hz) = 49.9
UI Rate (INR /Kwh)= 2.4
Variable cost of the cheapest standby generating resource2
Variable cost of the cheapest standby generating resourceowned by the beneficairy (INR /Kwh)=
Loss (Paise/ KWh) for each unit of drawal above schedule0.4
Conclusion: The distribution licensee should start generation at the cheapest standby unit if
(and not harnessing own standby generation)
frequency dips below the value (50 Hz in this case) at which UI rate becomesequal to variable cost of this unit.The distribution licensee should start loadshedding if UI rate is beyond its meansand there is no standby generating resource
15
and there is no standby generating resource.
Changing UI Rates
10
7
8
9
5
6
NR
/kW
h
2
3
4
I
0
1
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
16
Frequency (Hz)
upto 31.03.2004 w.e.f. 01.04.2004 w.e.f. 01.10.2004 w.e.f. 01.04.2007 w.e.f. 07.01.2008
Determination of Availability : Thermal Stations
• Availability means average of daily• Availability means average of daily Declared Capacities expressed as % of Installed capacity minus Normative p yAuxiliary Consumption
• Declaration of capacity taking into p y gaccount fuel availability
• Normative Availability 80% (exception for some specified generating stations)
• Availability to be certified by Member
17
Secretary of the RPC concerned.
Determination of Availability : Hydro Stations
C it I d (CI) f il bilit• Capacity Index (CI) as measure of availability• Daily CI = (Declared Capacity/Max available
capacity)*100p y)• Declared capacity over peaking hours of next
day (not less than 3 hours each day) taking intoaccount availability of water, optimum use ofaccount availability of water, optimum use ofwater and availability of machines.
• Max. available capacity is the max. capacity inMW the generating station can generate with allMW the generating station can generate with allunits running, under the prevailing conditionsof water levels and inflows, over the peakinghours of next day .hours of next day .
• Normative CI: 90% for Purely Run-of-river (ROR) stations and 85% for Storage and ROR stations with pondage
18
stations with pondage• CI to be certified by Member Secretary of the
RPC concerned.
Energy ChargesEnergy Charges
• Based on actually implementedBased on actually implementedscheduled energy
• Rate for thermal stations based on• Rate for thermal stations based onnorms of operationR t f h d t ti l t l t• Rate for hydro stations equal to lowestenergy charge of Central Sectorth l t ti i th R ithermal station in the Region
19
Mitigation of Gaming
• Thermal Stations: up to 105% of DC in time-block and 101% of average DC over the dayg yallowed. Generation beyond these limits to beinvestigated by RLDC and UI to be made zero ifgaming is foundgaming is found
• Hydro Stations: Schedule prepared for Day 4(based on DC) is adjusted by deviation from the
h d l D 1schedule on Day 1.• RLDC may ask generating station to
demonstrate DCdemonstrate DC• Penalty for first mis-declaration equals 2 days
fixed charges
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• Penalty to be doubled for 2nd mis-declarationand so on and so forth.
Multi-dimensional ABT
• A commercial mechanism for settlement ofdeviations from the scheduledeviations from the schedule
• A commercial mechanism for improvinggrid discipline and frequency regimegrid discipline and frequency regime
• A commercial mechanism to achieve near-i d imerit order operation
• A default market mechanism for trading
21
Settlement of DeviationsSettlement of Deviations
• Any market –liberalized or regulated, needs aAny market liberalized or regulated, needs amechanism for balancing to take care ofimbalances arising out of deviations from
t t d h d lcontracted schedules.
• In some markets, there is separate market forb l ibalancing.
• In India, UI mechanism attempts real-timebalancing.
22
Grid discipline and frequency profile
• Payment of Capacity Charges based onPayment of Capacity Charges based oncapacity available rather than energygenerated - Avoidance of unwanted
tigeneration
• UI Charges - Load shedding/ increasedti t l f d d ti igeneration at low frequency and reduction in
generation at high frequency
23
ABT encouragesid di i ligrid discipline
leading to betterleading to betterfrequency profiley
AUGUST 2008 SKA 24
Merit order operation
• Strict merit order operation if generation• Strict merit order operation - if generationscheduling is done for all the generatingstations in the grid by single entity (Centralizedscheduling)scheduling)
• In Indian decentralized scheduling system UIRate encourages:
* Backing down of generation in decreasingorder of variable cost as frequency goes up Picking up of generation in increasing order Picking up of generation in increasing order of variable cost as frequency goes down
25
Default market for trading
• Underdrawals with respect to schedule may beviewed as supply to the grid (at UI rate) andviewed as supply to the grid (at UI rate) andvice-versa
• Similarly under generation with respect toSimilarly, under generation with respect toschedule may be viewed as drawal from thegrid (at UI rate)
UI rate serves as default rate f t di
.for trading
26
Time Line For UI SettlementTime Line For UI Settlement
Settlement weekThree day grace periodFor Bank processing
0.04 % per day interest on defaulters
Mon
day
0000
unda
y 24
00 esda
y24
00 day
0 day
0 esda
y24
00esda
y24
00
rida
y 24
00
onda
y 24
00
M Su 2
Tu 2
Meter Data download & receipt at RLDC & preliminary checks
Thu
rs12
00
Satu
rd
2400 Tu 2
Tu 2 Fr 2
Disbursement to utilities from the pool account
Mo 2
Data validation, processing and computation at RLDC. Forwarded to Regional Power Committee Secretariat Account
Settled within 21 days
Data cross checking by Regional Power Committee Secretariat & Issue of Pool Account
Unscheduled Interchange Account Reactive Energy Account
Payment by utilities to the pool account managed by System Operator (RLDC)
AUGUST 2008 SKA 27
Settlement System• Settlement period- 15 minutes• Declaration, scheduling and UI accounting on, g g
15 minute basis• Special Energy Meters - for time differentiated
measurement of energy• Energy Accounting (capacity and energy
h ) thl b icharges) - on monthly basis• UI accounting on weekly basis• UI payments are received in a pool and
payments are made from the pool
28
Logistics• SEMs installed by CTU (POWERGRID)
M t di d l d d d t t• Meter readings downloaded and sent toRLDCs every week by staff of generatingstations, POWERGRID and beneficiaries
• RLDCs validate and submit data to RPCSecretariat by Thursday noon for the weekending midnight of previous Sundayending midnight of previous Sunday
• RPC Secretariat to carry out UI chargeaccounting (weekly basis) and energyaccounting (weekly basis) and energyaccounting (monthly basis)
29
P l POWERGRID co-ordinated and
provided all infrastructure for ABT
i l i
Pool Accounts Operated by
implementation.p y
RLDCs.
01.11.200301.12.2002
01.07.200201.04.2003
01.01.2003
ABT implemented in All Five
AUGUST 2008 SKA 30
01.01.2003Regions.
Impact of ABTImpact of ABT Comparison of frequency profile - Full year
Region P t f ti h f
p q y p yafter and before ABT
2001-02 2003-04 2001-02 2003-04 2001-02 2003-04Northern 11 2 4 8 76 2 89 4 12 6 5 8
Region< 49.0 Hz 49.0 - 50.5 Hz > 50.5
Percentage of time when frequency was
Northern 11.2 4.8 76.2 89.4 12.6 5.8Western 31.4 2.8 61.6 89.4 7.0 2.4Southern 78.0 2.3 17.9 97.3 4.1 0.4
2002 03 2003 04 2002 03 2003 04 2002 03 2003 042002-03 2003-04 2002-03 2003-04 2002-03 2003-04Eastern 13.0 2.9 55.7 95.9 31.3 1.2
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Impact of ABT Merit order
Schedules as percentage of Declared Capability (DC)p g p y ( )
97.5%99.0%
95 0%
100.0%
105.0%
pre-ABT (Dec 01-Nov 02)
86.7%89.9% 90.4%
95.0%
86 3%90.0%
95.0% post-ABT (Dec 02-Nov 03)
86.3%
81.3%80.0%
85.0%
75.0%Pithead Unchahar-I
+IIDadri (T) Combined
cycle ISGS
32
y
Limitations / ConstraintsLimitations / Constraints
• Shortage conditions
• Regular and timely payments to UI pool
• Expectation of rational behabiour from putilities and operating personnel
• Demand forecastingDemand forecasting
• Control over generation level and demand
33
demand
ABC of ABT• Scientific settlement system
for contracted sale & purchase of power– for contracted sale & purchase of power• Has three components
– Fixed Charges or capacity charge• Linked to day-ahead declared availability /
subscriptionsubscription
– Variable Charges or fuel charges• Linked to before the fact energy schedules• Linked to before the fact energy schedules
– Charges for deviation from commitments
AUGUST 2008 SKA 34
A Typical week UI Bill-Statewise Pattern 4 0
2 0
3 0
rore
s)
0
10
(Rs.
in C
- 2 0
- 10
UI B
illin
g
- 4 0
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h na ab du ar h NH
ra rh d iu m nd ra ry an SR K lhi
h la rh al m ur ya WR ka HP m al h rat
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ar P
rade
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nja
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ilnad Bih
ya P
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adra
& N
ahar
asht
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hand
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& D
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e lr.
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anip
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Kar
nata
k HA
ssam
est B
eng
ra P
rade
sG
ujar D
VO
riss
AUGUST 2008 SKA 35
Utt
Mad
hy M C D P A C U WA
ndh
A Typical Week UI Billing For ISGS ( UI Payables(-) / Receivables (+))3 .5
2 .5
3 .0
ores
)
1.5
2 .0
Rs.
in C
ro
0 .5
1.0
I Bill
ing
(
- 0 .5
0 .0
I P G I I I I G P P
U
TALC
HER
AIY
A G
PPN
GR
AU
LIB
A S
TPS
NA
THPA
AR
AK
KA
VELI
TPS
-EH
RI H
EPYA
CH
AL
NTA
GPP
AM
AG
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.VE
LI T
PS-
YAC
HA
LLA
L H
EPYA
CH
AL
ALG
AO
NN
D S
TPS
AM
AG
UN
.A
DR
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WA
S G
PPER
A H
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LIG
AN
GH
AH
AR
-IN
GA
NA
DH
AM
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UR
I HEP
RIH
AN
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AR
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CH
AH
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KA
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AN
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NG
NA
KPU
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KO
PILI
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GPP
AUGUST 2008 SKA 36
TA
UR
ASI
NK
OR F
NEY
V TVI
ND
H AN
RA
NEY
VVI
ND
HSA
VIN
DH
KA
HR
IHA RA DA
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WC
HA
MD
HA
UN
CR
AN C R
AG
UN
CN
EYV B
AK
H TAD
OY DA
ASS
TG
AN
D
The End Result …. Frequency is
• collectively controlledy• democratically stabilized
Wholesale market is workably competitive • allocative efficiency• productive efficiency
Economic signal available for Economic signal available for • optimum utilization of resource • investments in generation capacityg p y
Settlement is• streamlined
AUGUST 2008 SKA 37
• dispute-free
What lies ahead?What lies ahead?
• Intra-State ABT
• Modulating UI prices according toodu at g U p ces acco d g tochanging situations
38
Futuristic ScenarioFuturistic Scenario
• Adopt operating practices andAdopt operating practices and commercial mechanism for stricter frequency control (when shortages arefrequency control (when shortages are eliminated?)
AUGUST 2008 SKA 39
THANK YOUTHANK YOU
AUGUST 2008 SKA 40