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

20

• 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

31

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

- 3 0

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

VC sa

ar P

rade

sH

arya

nPu

nja

Tam

ilnad Bih

ya P

rade

sD

adra

& N

ahar

asht

rC

hand

iga

Jhar

khan

aman

& D

Sikk

imN

agal

anTr

ipu

ondi

cher

rR

ajas

tha

Goa

-SJ

&D

e lr.

Prad

esK

era

Cha

ttis

gar

Utt

aran

chM

izor

amM

anip

uM

egha

lay

Goa

- W

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

UN

.VE

LI T

PS-

YAC

HA

LLA

L H

EPYA

CH

AL

ALG

AO

NN

D S

TPS

AM

AG

UN

.A

DR

I TPS

WA

S G

PPER

A H

EPU

LIG

AN

GH

AH

AR

-IN

GA

NA

DH

AM

ERA

UR

I HEP

RIH

AN

D-II

AR

TALA

CH

AH

AR

-EL

I TPS

-IK

OPI

LILO

KTA

KA

IRA

SIU

LR

AN

GIT

AN

DO

NG

NA

KPU

RA

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HEP

KO

PILI

-IIA

DR

I GPP

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GA

STA

LCH

ERH

AR

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

KA

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