Electricity Market - Indian Institute of Technology Kanpur Training-2014/IITK - PPTs -...

Electricity Market

www.iexindia.com

Email: [email protected]

July 2014

Indian Institute of Technology Kanpur (IITK) and Indian Energy Exchange (IEX) are delighted to announce

Training Program on

"Power Procurement Strategy and Power Exchanges" 28-30 July, 2014

mailto:[email protected]

In this presentation

Introduction to Indian Power Market

Product Portfolio

Trading Mechanism

Market snapshot

Trade @ IEX

Indian Power Market: Present Status

Long Term Power Purchase AgreementsUpto 25 Years

Medium Term3 months- 3years

OTCLicensed traders

Short-Term

OTC Intraday- 3 months

Exchanges

Balancing Market

Intraday - 3 months

Unscheduled Interchange

1. Intra-day2. DAM3. DAC4. Daily5. Weekly

Real Time

89%

6%

3%

2%

Growth Trend of Short Term Power Markets

5.4%

7.8%8.8% 9.1% 9.3%

10.9%

0%

2%

4%

6%

8%

10%

12%

0

20

40

60

80

100

120

FY 08-09 FY 09-10 FY 10-11 FY 11-12 FY 12-13 FY 13-14 Shar

e of

Sho

rt T

erm

Vol

umes

Tra

ded

in T

otal

Po

wer

Gen

erat

ion

(%)

Volu

me

(BU

)

Bilateral PXs UI Share of ST Vol in Tot Gen

Source: Monthly MMC Reports

Market Development Milestones

2005 IEX Conceptualized Power Exchanges (PX)

2006 •Created awareness among Stakeholdersacross the country

2007 • CERC issued guidelines for setting PX• IEX got in principle approval

•• Day Ahead Market (Collective t/s)

commenced upon approval from CERC

Sep 2009 • Term Ahead market for Forward electricity contracts started

June 2008

Feb 2011 • Renewable Energy Certificate (REC) tradingcommenced

What is IEX

On-line

National

Automated

Electronic

StandardisedContracts

CentralCounterparty

Delivery…

Exchange as Organized Marketplace Power-specific

•Spot•Intra-Day•Day-ahead

•Forward•Weeks•Months

Voluntary

IEX capabilities

• Spot Auction (Closed or Open) for real time prices• Continuous Trading for Long-term contracts• Automated matching engine • Online risk management system• Online clearing & banking interface for margins & trade

proceeds payment • Derivatives - for Hedging & Price DiscoveryForwards Futures

• Physical or financial settlement

IEX Self Regulating Institution

• Due diligence before Membership• Networth Criteria• Security deposit & Margins• Voluntary participation • IEX Counterparty • SLDC Clearance

What benefits does the power exchange provide?

Nation-wide voluntary access

E-trading

No counterparty riskRobust Platform

Delivery Based contracts

Product Portfolio

Intra DayREC

Day Ahead Market (DAM)

Term Ahead Market (TAM)

Renewable Energy Certificates (RECs)

Trade for the following day

Contracts for every 15 min, closed auction

From 3 Hrs ahead to 11 days in advance

4 types of contracts

•Intraday•Day Ahead Contingency•Daily•Weekly

Trade green attributes of electricity

1 REC = 1 MWh of green energy

Product Segments

IEX Market SegmentsDelivery-based Contracts

Day-Ahead Marketsince June,08

Closed , Double-sided Auction 10-12 am biddingEach 15-min block , 0.1 MW min NOC required

Term-Ahead Marketsince Sep,09

Day-Ahead Contingency – Another window 3-5pm

Intra-Day - for the same day starting 2 pm

Daily- for rolling seven days (delivery starting after 4 days)

Weekly- for 1 week (Monday-Sunday)

Renewable Energy Certificatessince Feb,11

Next… Energy Saving Certificates

Green Attributes as CertificatesOnce in a month1MWh equivalent to 1 REC

Auction Continuous

Contract Characteristic

Delivery

Auction Type

Contracts

Trade Availability

Financial Settlement

Day Ahead Market

Next day

Closed Auction

15 min

All Days; 1000-1200

Pay-In- D-1; Pay Out – D+1

Intraday Contracts

1400 -2400 Hrs same day

Continuous trading

Hourly

All days; 1000-1700

Pay in: T+1Pay out: T+1

Day Ahead Contingency

For next day

Continuous trading

Hourly

All Days;1500-1700

Pay in: T+1Pay out: T+2

Daily Contracts

From 4th day to next 7 days

Continuous trading

Block of Hours (Fixed)

All Days;1200-1500


Weekly Contracts

For next week

Open Auction

Block of Hours (Fixed)

Wed & Thurs;1200-1600


TERM AHEAD MARKET

Contract Characteristics

T = TradeD = Delivery

Presenter

Presentation Notes

D+1 D

Trading Mechanism

Features of Day Ahead Market

A closed double-sided anonymous auction for each 15-min time block for the following day

The intersection between the aggregated sale and purchase curves defines the market clearing price (MCP)

12 Bid area defined

Congestion Management through market splitting and determining Area Clearing Price (ACP) specific to an areaBid types: Portfolio Orders or Block OrdersMinimum bid=Re.1 for 0.1MWhMinimum Price & Volume Step = 0.1p * 0.1 MWh

12 Bid Areas

Market Place Functionality(DAM)

Bids are validated, accepted andMatched

Bid entry

Receipt of Nodal RLDC Acceptance by IEX

Financial Settlement

Reports are generated

Prov. Format-1 & Format-2generated electronically & sent toMembers

IEX applies to Nodal RLDC

Informationdissemination

Market Place Functionality(TAM)

Member obtains SLDC Clearance

Member sends the SLDC Clearance to IEX

Margins are collected

DAM trading process

Bidding MatchingReview corridor

and funds availability

Result Confirmation Scheduling

Bids for 15- min each or

block bids can be placed

MCP &MCV

calculated

Corridor availability and funds

verified

Collective transaction

confirmation by NLDC

Final Schedule sent

to RLDC for incorporation

Final ACV and ACP

calculated. Market

splitting if congestion

10:00 am to 12:00 pm

12:00 pm to 1:00 pm

1:00 pm to 2:00 pm

3:00 pm 5:30 pm 6:00 pm

Bid Types

• Bids for each 15 min can be entered

• Varying price and quantum pairs

• Allow partial execution

Single/Portfolio Bid

• Relational Block Bid for any 15 min

• Mother or child bid• No circular links• No partial execution

Block Bid

BID MATCHING

Open/Closed Auction

Orders accumulated during call phase (no matching)

Orders matched after call period

Orders are used for calculation common price

i.e. Equilibrium Price.

All successful orders matched at Equilibrium

Price.

Continuous Trading

Price-time priority based continuous matching

The highest Buy order & lowest Sell order gets the

priority

If the prices are same then priority is given to the time

of the order received.

0 1 1.1 2 2.1 2.5 3 3.1 4 4.1 5 --- --- ---- 20

20 20 20 20 20 20 20 10 0 0 0 0 0 0 0

60 60 60 60 50 40 40 40 40 40 20 20 20 20 20

40 20 0 0 -40 -60 -80 -81 -120 -120 -120 -120 -120 -120 -120

120 100 80 80 70 60 60 50 40 40 20 20 20 20 20

0 0 0 0 -40 -60 -80 -81 -120 -120 -120 -120 -120 -120 -120

120 100 80 80 20 0 -20 -21 -80 -100 -100 -100 -100 -100 -100

Price Tick (Rs.)Portfolio A, MWBid Quantum

by different portfolios

Total Sell Quantum received, MWTotal Buy Quantum received, MW

Net Transaction, MW

Portfolio B, MWPortfolio C, MW

Pric

e

MW

Market clearingprice (MCP)

Market Clearing Volume (MCV)

Supply(Sell)

Demand(Buy)

Volume

2.5

60

Model Price Calculation algorithm

CONTINUOUS TRADING PROCESSTWS Screen

Pending Buy Order Pending Sell Order

Buy 10 MW @ Rs 4500/MWh Sell 15 MW @ Rs 5500/MWh

Sell 15 MW @ RS 5500/MWhBuy 10 MW @ Rs 4500/MWh

Trading EngineBuy 10 MW @ RS 4500/MWh Sell 15 MW @ RS 5500/MWh

TWS ScreenPending Buy Order Pending Sell Order

Buy 10 MW @ 5000/MWh

Sell 15 MW @ Rs 5500/MWhBuy 10 MW @ 4500

Trading EngineBuy 10 MW @ RS 5000/MWh

Buy 10 MW @ RS 5000/MWh

Buy 10 MW @ RS 4500/MWh

Sell 15 MWh @ 5500

TWS ScreenPending Buy Order Pending Sell Order

Sell 15 MW @ RS 5000/MWh

Sell 15 MW @ 5500

Trading EngineSell 15 MW @ Rs 5000/MWh

Buy 10 MW @ 5000

Buy 10 MW @ 4500

Sell 15 MW @ 5500Sell 5 MW @ Rs 5000/MWh

Trade 10 MW @ RS 5000/MWh

Buy 10 MW @ RS 4500/MWH

Bid Modified

Risk Management System- DAM

D-1 At 09:30 Hrs : Pre-trade Margin Check.

equal to the initial margins or average of last 7 days’ trading value, whichever is more.

D-1 At 12:30 Hrs : Preliminary Obligation Margin Check

Preliminary Obligation =< Funds Available (incl initial margin)

Block funds.D-1 At 15:30 Hrs : Pay-ins

At D+1 14:00 Hrs : Pay-out.

Trader Member Professional Member

D-1 At 09:30 Hrs : Pre-trade Margin Check. equal to the 100% of the

bid value to be provided by Client directly to IEX in Client Settlement account

D-1 At 15:30 Hrs : Pay-ins

At D+1 14:00 Hrs : Pay-out.

Risk Management in DAM/TAMProprietary/Trading Licensee

MembersProfessional Members

Initial Margin Basis/Additional Margin

Initial Margin Basis/Additional Margin

Day-Ahead Market

Margin equal to Last 7 Days Average of Buy turnover

As per Bank Balance including Hair Cut Factor

TAM-Intraday 105% of order - 105% of order Value -

TAM-DAC 105% of orderValue

- 105% of order Value -

TAM-Daily 5% of order Value 50% of Trade Value

5% of order Value 50% of Trade Value

TAM-Weekly 5% of order Value 50% of Trade Value

5% of order Value 50% of Trade Value

REC 100% of order Value

- 100% of order Value -

Member Client RMS

Credit facility can be provided by Trader Member to their clients

No credit or funding facility by Professional Members to their clients

NLDC Charges

• Application Fees is paid in advance = T• NLDC Scheduling & Operational Charges is paid on T+1• Transmission Charges CTU is paid on T+1

SLDC Charges

• SLDC Scheduling & Operational Charges is paid on T+1• Transmission Charges STU is paid on T+1• Area Transmission Charges (ATU) is paid on T+1• Area Load Dispatch Centre (ALDC) is paid on T+1

RLDC Charges

• Application Fees/PoC/SLDC/RLDC charges is paid on Within 3 working days of Acceptance

Timelines for payment of Charges: DAM/TAM

T = Trade Date

Congestion Management

SR WR

S150 MWRS 8000

B150 MWRS 8500

S150 MWRs 8/u

B150 MW

RS 8.5/u

B2150 MWRS 9000

B2160 MWRs 9/u

S240 MWRS 8500

S240 MWRs 8.5/u

S350 MWRS 7500

S350 MWRs 7.5/u

B1100 MWRs 6/u

S180 MWRs 9.5

B330 MWRs 7/u

B330 MWRS 7000

Deficit100 MW

S180 MWRS 9500

B1100 MWRS 6000

S2120 MWRS 8000

S220 MWRs 8/u

S3100 MWRS 5500

S2100 MWRs 5.5/u

Surplus100 MW

Required Flow

100 MW

Congestion Management

SR WR

S150 MWRS 8000

B150 MWRS 8500

B2160 MWRS 9000

S240 MWRS 8500

S350 MWRS 7500

B1100 MWRS 6000

S180 MWRS 9500

B330 MWRS 7000

Deficit100 MW

S220 MWRS 8000

S2100 MWRS 5500

Surplus100 MW

Allowed Flow

20 MW

Surplus20 MW

Highest Seller getting rejectedLowest Buyers getting rejected

Deficit20 MW

• Both Buyers and Sellers to absorb losses

• Average Transmission Losses of the Region where the Entity is geographicallylocated.

Treatment of Losses

Draw less than contracted power

(Contracted Power – losses)

Inject more than contracted power

(Contracted Power + Losses)

Buyer

Seller

Treatment of Losses… for buyer

• POC Loss: 1.5 %• S1 (State) loss: 4.85 %• Buyer X bids for 100 MW at its respective regional periphery

100 MW

at NR periphery

POC

Loss

1.5%

98.5 MWat State

periphery

State

Loss

4.85%

93.72 MW at Buyer End

X(Buyer)

Bid VolumeScheduled Drawal<= SLDC Clearance

Maximum Bid= Volume in standing clearance + Regional & State losses

Treatment of Losses… for seller

• POC Loss: 1.5%• State loss: 4.85%• Seller Y bids for 100 MW at its respective regional periphery

POC

Loss

1.5%

106.69MW Injected by

seller

State

Loss

4.85%

Y (Seller)

101.52MW at state

periphery

100 MW at regional periphery

Bid VolumeScheduled Generation

<= SLDC Clearance

Maximum Bid= Volume in standing clearance – Regional & State losses

Off-line Surveillance

Clearing and Settlement

Research Education (In Progress)

Certification

Trading and SurveillanceMembership

Member Admission

Member Inspection / Investigation

Member Compliance

Disciplinary Action

Training

Market Segment

Renewable Energy Certificate

Weekly Intra-Day

Day-Ahead Market Term-Ahead Market

Daily Day-Ahead Contingency

Helpdesk

New Business Initiatives

Admin Finance & Accounts

Corporate Communications HR

Market Operations Troubleshooting

Trading Platform –

NewDevelopment

Trading / Operating

Rules

Regulatory and Legal

Member Business

Development

Website Management

Information Technology

IT Development

IT Operations

IT Network IT Security

Disaster Recovery

Exchange Process LandscapeMarket

Intermediaries

NLDC

Utility/Discom

CPP/IPP/MPP

Regulatory / Statutory

Bodies

Professional Member

Industrial Consumer

Technology Vendors

Other Exchange

Media/ Educational Institutions

RLDCs

Electricity Trader

SLDCs

ISGS/CGS

Proprietary Member

ClientRegistration

On-line Monitoring

Margin Maintenance

Pay-in Pay-out settlement

Financial Risk Management

Delivery

Communication with NLDC/RLDCs/SLDCs

Delivery risk Management

Market Snapshot

Company Snapshot

96% Market Share ~80,000MWh average daily trade

3000+ Participants 2100+ Industries

Competition

LiquidityTransparency

Key statistics: Electricity & REC Market

Market Share(FY 13-14)

State Utilities

Generators

Industrial Consumers

Average Daily Volume

77%

16 States I 5 UTs

539

>3 million RECsHighest: 3,09,892 RECs

ELECTRICITY REC

96%

29 States I 5 UTs

273

~80,000 MWhHighest : 117,000 MWh

16142839

IEX Data as on 1 July, 2014

Increasing ParticipationParticipation

5 2

0 5

207 8

665 31

69 1

387 16

401 6

33 8

9 0

0 20 47

5 16

5 0

0 1

736 2

51 52

6 5

1 0

7 22

248 4

Consumer: 2835

Generator: 273

Participation at IEXNo Open Access

Consumers Generators

Uttar Pradesh Uttar Pradesh

Jammu & Kashmir Delhi

Himachal Pradesh Bihar

Delhi Jharkhand

Bihar Tamil Nadu

Goa Kerala

Jharkhand Union Territories

Sikkim

NE States (except Meghalaya)

DVC

Chattisgarh

West Bengal

Union Territories (except Daman & Diu)

NE States (except Assam, Meghalaya & Arunachal Pradesh)

Industrial segments with IEX

Textile29%

Manufacturer15%

Metal 24%

Chemical9%

Auto Components

6%

Cement4%

Paper3%

Cotton1% Others

9%

CERC MMC Report for FY 2012-13Prices

IEX Monthly Cleared Volume

TAM: Performance so far

Weekly Day-ahead Contingency

Intraday Daily

2,650,483 MWh 268,294 MWh

346,936 MWh 310,274 MWh

Total Volume traded3,576 MUs

REC Participants: Sellers/Eligible EntityIdentified Sources for RE

REC Market Participants : Buyers

Obligated Entities

• Distribution Companies • Open Access Consumers• Industries consuming Captive Power

Voluntary Entities • Corporates under CSR• Individuals

Salient Features of REC Mechanism

Participation Voluntary

REC Denomination 1 REC = 1 MWh

Validity 730 Days after issuance (As per CERC order dated 11th Feb’2013)

Categories 1. Solar REC 2. Non-Solar REC

Trading Platform Power Exchanges only

Banking/Borrowing Not Allowed

Transfer Type Single transfer only , repeated trade of the same certificate isnot possible

Floor Price (2012-17)* Solar: Rs 9,300/MWhNon Solar: Rs 1,500/MWh

Forbearance Price (2012-17)* Solar: Rs 13,400/MWhNon Solar: Rs 3,300/MWh

Penalty for Non-compliance ‘Forbearance’ Price (Maximum Price)

Price Guarantee Through ‘Floor’ Price (Minimum Price)*Reference :CERC in its order dated 23rd August, 2011 revised the floor & forbearance price for the period April, 2012 to March,2017

REC Mechanism

Procedure for ACCREDITION (Through State nodal Agency)

Procedure for REGISTRATION (Through Central Agency NLDC)

Procedure for ISSUANCE (Through Central Agency NLDC)

Procedure for TRADING & REDEMPTION(Through PXs)

Trading at IEX

Trading Day Last Wednesday of every Month

Market Clearing Closed Double sided auction

Trading Time 1300-1500 Hrs

By 1530 Hrs Verification by Central agency for Valid REC by cleared seller at IEX

By 1600 Hrs Central agency confirms REC

By 1630 Hrs IEX finalizes trade

By 1700 Hrs Buyer & Sellers informed to Central Agency

By 1800 Hrs Invoice raised (proof of REC trade)

N-Solar REC trade detail

Solar REC trade detail

1) National Open Access RegistryN

OA

R • Integrated IT based system, with national reach, to facilitate communication for Short term Open Access among Consumers, Applicants, LDCs, Traders , Power Exchanges, RPCs and ERCs

• Central, online clearing for all STOA Applications & Approvals• Depository and repository for OA approvals by SLDCs and ATC

for inter state transmission• One-click access to all stakeholders• Eliminate need for separate clearances for each transaction• Live Regulatory Information access to ERCs• Modeled on the concept of depositories in capital market

NOAR

STOA Appliation Processing

STOA Participants (Inter-state) SLDCs

RLDCs & NLDC PX / Traders

ERCs

Ecosystem

Financial Institutions(in future)

Trade @ IEX

Entities eligible for Membership: Inter-State Generating Stations (ISGS)

Distribution Licensees State Generating Stations IPPs CPPs and IPPs

(with consent from SLDC)

Open Access Customers(with consent from SLDC)

Electricity Traders / Brokers

Who Can become Members of IEX ?

IEX Membership Types

Proprietary Member

Right to trade and clear on its

own account

Generator-Distribution

licensees- IPPs -CPP- MPPs –O A

consumers

Professional Member

Trade and clear on behalf of its

Clients

NO CREDIT /FINANCING

Electricity Traders

Trade and clear on behalf of its

Clients

CREDIT /FINANCING

ClientsGrid Connected

Generator, Distribution licensees, IPPs, CPP, MPP, OA consumers

Trader Client With valid PPA

Financial Requirements

Membership Category: Proprietary / Professional Member The financial criteria for payment options available on IEX are:

FeesProfessional & Proprietary &

Electricity Trader(Full Payment Option)

Proprietary member (Light Payment

Option)Admission fee Rs. 35,00,000 Rs. 10,00,000

Interest Free SecurityDeposit

Rs. 25,00,000 Rs. 10,00,000

Annual SubscriptionFees

Rs. 5,00,000 Rs. 2,50,000

Processing Fees Rs. 10,000 Rs. 10,000

TOTAL Rs. 65,10,000 Rs. 22,60,000Exchange Transaction 2p/kWh 3p/kWh

IEX InitiativesContinuous communication with Users

IEX Daily SMS Service for Trade

Details

IEX Monthly Bulletin

IEX hourly Trade Prices displayed on its website

Best Power Exchange in India – Enertia Awards ‘13

Best Performing Power Exchange – Power Line Awards ’13 & ‘12

Best E-enabled consumer platform– India Power Awards ‘09

Thank You for your attentionwww.iexindia.com

Algorithm of Price Calculation

• Step 1: Unconstrained Solution (w.r.t. Transmission Capacity) - Find MCP and MCV; Demand=Supply on aggregated net curve.

• Step 2: After receiving the actual ATC, examine bid area for bottlenecks.• If a bottleneck is found, the market is split in two partial calculation area:

Source (surplus) and sink (deficit).• A new ACP is found in both source and sink.

- Surplus Lower ACP than MCP- Deficit Higher ACP than MCP.

• Each partial calculation area is examined for bottlenecks in the same way.• When no more bottlenecks are found internally in the calculation area, the

recursion stops.

Case Synopsis-I• Illustration of Price Matching and Market Splitting.• Two regions have been considered i.e. ER and SR.• Four Sellers and Two Buyers in a 15-Min Block are taken with following Bid Scenario: -

Portfolio Code Quantity (MW) Price (Rs./MWhr)

ER Seller-1 200 2000

ER Seller-2 100 3000

SR Seller-1 100 3000

SR Seller-2 100 4000

SR Buyer 300 4000

ER Buyer 100 3000

ER REGION

200 MW @2000 100 MW@3000

100 MW @3000

SR REGION

100 MW @3000 100 MW@4000

300 MW @4000

(200,2000)

Case-IUnderstanding Price Matching

ER Seller-1200 MW@

2000/MWhr

ER Seller-2100 MW@

3000/MWhr

SR Seller-1100 MW@

3000/MWhr

SR Seller-2100 MW@

4000/MWhr

SR Buyer300 MW@

4000/MWhr

ER Buyer100 MW@

3000/MWhr

(200,2000)

(400,3000)

(200,2000)

(400,3000)

(500,4000)

(400,3000)

(200,2000)

(400,3000)

(500,4000)

(200,2000)

(400,3000)

(500,4000)

(400,3000)

Market Clearing Price (MCP)= Rs. 3000/MWhrMarket Clearing Volume(MCV)= 400 MW

SRER

Net Demand 100

Net Supply 300 Net Supply 100

Net Demand 300

Net 100 – 300 = -200 Net 300-100 =200

Demand and Supply gap in two regions get balanced by unconstrained flow between the tworegions hence a common MCP is derived.

Case-IREQUIREMENT OF CORRIDOR FROM NLDC

Net Required Flow- 200 MW

ER REGION (PRICE=3/unit)

200 MW @2 100 MW@3

100 MW @3

Required Flow=200 MW SR REGION (PRICE=3/unit)

100 MW @3 0 MW@4

300 MW @4

Constraint Solution (Market Splitting)

Congestion was reported by NLDC from ER to SR corridor and flow is constrained to 100MW.Due to flow constraint, system will “Split” the market in to two regions i.e. Deficit (SRRegion) and Surplus region (ER Region),and will again run the calculation chronology forboth the regions separately considering the flow constraint and will derive the ACP and ACV.

ER-Surplus Region

Price(Rs./kWh) 0 999 1000 1999 2000 2999 3000 3001 3999 4000 4001 6000 8000 10000 20000

ER Seller-1 0 0 0 0 -200 -200 -200 -200 -200 -200 -200 -200 -200 -200 -200

ER Seller-2 0 0 0 0 0 0 -100 -100 -100 -100 -100 -100 -100 -100 -100

ER Buyer 100 100 100 100 100 100 100 0 0 0 0 0 0 0 0Net (Buy-Sell) 100 100 100 100 -100 -100 -200 -300 -300 -300 -300 -300 -300 -300 -300

Flow Towards SR of 100 MW

SR-Deficit Region

Price(Rs./kWh) 0 999 1000 1999 2000 2999 3000 3001 3999 4000 4001 6000 8000 10000 20000SR Seller-1 0 0 0 0 0 0 -100 -100 -100 -100 -100 -100 -100 -100 -100

SR Seller-2 0 0 0 0 0 0 0 0 0 -100 -100 -100 -100 -100 -100

SR Buyer 300 300 300 300 300 300 300 300 300 300 0 0 0 0 0

Net (Buy-Sell) 300 300 300 300 300 300 200 200 200 100 -200 -200 -200 -200 -200

ER Surplus Region Demand-Supply Curve

SR Deficit Region Demand-Supply Curve

Case Synopsis-II

• Illustration of a Simple Case.

• Different Scenarios to Bid by Buyers and Sellers.

Northern Region

Western Region

Southern Region

Eastern Region

No Corridor left in WR-SR Link for Exchange since booked in Long-Term and Medium Term

250 MW corridor from ER to SR Link.

Punjab State Utility-Heavy Demand and Agriculture Load (Paddy Season) in Punjab.

Buy bid at Exchange

Delhi Discom arranged sufficient power under Long-Term to meet the

demand. Sell in Off-Peak and calculated buy and

sell in Peak Hours

Maharashtra Discom- Elections in State; has to provide power all time; Buy Bid

at Exchange

IPP in Chhattisgarh; Pit-head power plant; Sell available to bid at low price

Industrial Consumer in Tamilnadu; Power cut by Discoms during Peak Hours hence buy bid in Peak Hour.

State Utility in Andhra Pradesh; Heavy Industrial Demand hence buy

bid.

IPP in Orissa; Sell power at moderate price since used

imported coal.100 MW available from

WR to NR Link.

150 MW available from WR to ER Link

P-1P-2

P-3P-4

P-5

P-6P-7

Time Q@P

Off-Peak Buy-400@5000

Peak Buy-600@6000

Time Q@P

Off-Peak Buy-300@4500

Peak Buy-500@5500

Time Q@P

Off-Peak Sell-250@4000

Peak Sell-200@5500; Buy-200@4000

Time Q@P


Peak Sell-350@4000

Time Q@P


Peak Sell-800@3000

Time Q@P

Off-Peak B-10@9000

Peak B-10@9000

Time Q@P

Off-Peak B-600@6000

Peak B-800@8000

800 MW available from ER to NR Link.

(More Demand Less Supply)

(Less Demand More Supply)

(Only Supply)

(Only Demand)

Final Price Calculation Details of Off-Peak Time

Final Price Calculation Details

of Peak Time

Northern Region

Western Region

Southern Region

Eastern Region

No Corridor in WR-SR Link.

250 MW availablefrom ER to SR Link; Actual Flow=250

MW

100 MW available from WR to NR Link; Actual

Flow=100 MW

150 MW available from WR to ER Link; Actual Flow=100 MW

P-1P-2

P-3P-4

P-5

P-6P-7

Time Q@P

Bid Buy-400@5000

Selection [email protected]

Time Q@P

Bid Buy-300@4500


Time Q@P

Bid Sell-250@4000

Selection 0 MW

Time Q@P

Bid Sell-400@3500


Time Q@P

Bid Sell-800@3000


Time Q@P

Bid B-10@9000


Time Q@P

Bid B-600@6000


800 MW available from ER to NR Link;

Actual Flow=300 MW



(Only Supply)

(Only Demand)

Analysis of Off-Peak Time

Northern Region

Western Region

Southern Region

Eastern Region

P-1P-2

P-3P-4

P-5

P-6P-7

Time Q@P

Bid Buy-600@6000


Time Q@P

Bid Buy-500@5500


Time Q@P

Bid Sell-200@5500; Buy-200@4000


Time Q@P

Bid Sell-350@4000


Time Q@P

Bid Sell-800@3000


Time Q@P

Bid B-10@9000


Time Q@P

Bid B-800@8000




(Only Supply)

(Only Demand)

No Corridor in WR-SR Link.

250 MW availablefrom ER to SR Link; Actual Flow=250

MW

100 MW available from WR to NR Link; Actual

Flow=100 MW

150 MW available from WR to ER Link; Actual Flow=100 MW

800 MW available from ER to NR Link;

Actual Flow=300 MW

Analysis of Peak Time

Electricity Market - Indian Institute of Technology Kanpur Training-2014/IITK - PPTs -...

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