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International Experiences

(UK/USA)

By

Dr SN SinghDepartment of Electrical Engineering

Indian Institute of Technology

Kanpur-India

Dept. of IME, IIT KanpurShort-term Course

Challenges and Implementation IssuespostElectricity Act 2003 :

Regulatory, Policy & Technical Solutions

April 10-14, 2004

This document can be downloaded from: www.ii tk.ac.in/ ime/anoops

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Deregulation is a re-structuring of the rules andeconomic incentives that government setup to control

and drive the electric supply industry. It is known in different names

Re-regulated market

Open Power MarketCompetitive power market

Vertically unbundled power system

Open accessPower system restructuring( Privatization and

deregulation)

Reforms

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Forces behind the deregulation are

High tariffs and over staffing

global economic crisis

regulatory failure

political and ideological changes

managerial inefficiencylack of public resources for the future development

technological advancement

rise of environmentalismpressure of Financial institutions

Rise in public awareness

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Reasons why deregulation is appealing

No longer necessary The primary reason for regulation,

to foster the development of ESI

infrastructure, had been achieved.

Electricity Price may drop Expected to drop due to innovation

and competition.

Customer focus will improve Expected to result in widercustomer choice and more attention

to improve service

Encourage innovation Rewards to risk takers and

encourage new technology and

business approaches,Augments privatization In the countries where Govt. wishes

to sell state -owned utilities,

deregulation may provide potential

buyers and new producers.

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What will be the transformation ?

Vertically integrated => vertically unbundled

Regulated cost-based ==> Unregulated price-based Monopoly ==> Competition

service ==> commodity

consumer ==> customer

privilege ==> choice Engineers Lawyer/Manager

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A number of questions to be answered

Is a deregulation good for our society?

What are the implications for current industry participants? What type of new participants will be seen and why ?

What should be structure of market and operation?

What might an electricity transaction of future look like ?

What are the key issues in moving towards the deregulation ?

What will be the Potential Problems ?

Congestion and Market power

Obligation to serve

Some suppliers at disadvantages

Price volatility

Environmental problems

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Deregulation around the world

Milestones of Deregulation- 1982 Chile

- 1990 UK

- 1992 Argentina, Sweden & Norway

- 1993 Bolivia & Colombia

- 1994 Australia

- 1996 New Zeeland

- 1997 Panama, El Salvador, Guatemala,Nicaragua, Costa Rica and Honduras

- 1998 California, USA and several others.

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England & Wales Electricity Market

Market started since April 1, 1990

Breakup of Central Electricity Generating Board(CEGB) - National Power, PowerGen & Nuclear

plants

Privatization of 12 Area Boards (Discos) into 12

regional electricity supply companies (RECs). National Grid became National Grid Company

(NGC), initially owned by 12 RECs. But now apublic traded corporation.

Scotish non-nuclear companies, Electricity de France(EdF) and IPPs became the member of pool.

Transmission capacity from Scotland is 1.6 GW andfrom France 2.0 GW. Max. Cap. available with E&W is 59 (48 GW demand)

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Four sub industries: Gen., trans., distrib. and retail

sector.

Retail side two customers: franchise and non-franchise

Non-franchise customers (earlier > 1 MW, later > 100

KW and now free) are given the option of choosing

their supplier from any RECs, National Power orPowerGen.

PowerGen (30 to 20 GW) and National power (19 to

15 GW) reduced their capacities. RECs hedge against pool price volatility using

Contracts for Differences (CFD).

It is financial instrument not contract to deliver

electricity.

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Com etin Generators Ancillary Services

Distributors

Power Exchan e PX S stem O erator

Transmission Facilities

ControlMonitor

DispatchBid

ForecastSell

NGC

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Market Rules

NGC works as ISO+PX.

48 half-hourly market.NGC uses GOAL (generation ordering and loading)

program to determine the merit order of dispatchinggeneration and reserve capacity.

Generators must submit the bids by 10.00 AM oneday ahead of operation.

The System Marginal Price (SMP) is the pricequoted by the most expensive generator which isaccepted for dispatch during each half-hourly timeslot when transmission constraints are ignoredsimple unconstrained dispatch.

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Capacity payments

If marginal stations cannot cover their costs, then

they will tend to shutdown, thus reducing the margin

of capacity.Every MW of capacity which is declared available

in a half-hour receives a capacity payment for that

1/2 hour, whether or not it is schedule to generate.

The probability that demand will exceed capacity

(Loss of Load probability, or LOLP) is calculated

by comparing expected demand with the capacity

expected to be available.PPP = SMP+CC (= LOLP*(VOLL-SMP))

CC = LOLP*(VOLL-bid) if not generating

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LOLP is calculated by a program based on

forecasted demand (& its variance)

disappearance ratio (probability that a gensetwas available at some point in 8-days becomeunavailable by the 9th day)

genset capacity available for last 8 days,

LOLP is extremely sensitive to the level ofcapacity relative to demand.

Capacity payments have been heavily criticized.

VOLL (value of lost load) was set by Govt.( 2/kWh in 1990 rose to 16.50).

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This additional expense is passed on toconsumers. On the other hand, some uneconomic

generators who are not selected in the day-aheadmarket but are called upon to generate due totransmission constraints or other reasons, are

paid their 'bid' price, which is higher than theprevailing PPP. This is, effectively, a paymentfor out of merit generator operation.

Constrained-off costs, out of merit payments andseveral additional expenses such as transmissionfixed charges, transmission losses, startup costs,and ancillary services charges are passed on toconsumers in the uplift

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The customer side of the market is simpler: allenergy is purchased at the pool selling price

(PSP). All of the extra costs of energy above thePPP are simply lumped together in uplift andspread over all kWh taken by customers throughthe calculation of a single half-hourly consumer

price, the PSP.

PSP=PPP+uplift

Problems

Pool rules

Market power

Metering

Customer choice

Price votality

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Spot prices

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New Electricity Trading Arrangement (NETA) in UK

Before the March 2001, any generator exporting

more than 50 MW on to the system is required tohold a generation licence and to trade its output via

an open commodity market, the Electricity Pool.

Essentially, each generating unit had to declare by10.00 hours each day its availability to the market,

together with the price at which it is prepared to

generate, for each and every half hour of the

following day CfDs are essentially financial instruments, the main

purpose of which is to hedge risk

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After March 2001, New wholesale electricity tradingarrangements (NETA) was introduced .

In the NETA design the old day- ahead pool basedon a coordinated - spot market with a market-clearing price was replaced by a three- and- a half-hourahead balancing system with a complex pricing

scheme that features pay- as- bid mechanism withrules intended to penalise imbalances.

The governance arrangements that supported NETAinclude the establishment of aBalancing and

Settlement Code (BSC) Panel, to oversee the Codeand to to provide or procure a range of operationaland administrative services, both directly andthrough contracts with service providers.

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ELEXON is the Balancing and Settlement Code Company(BSC Co) defined and created by the Balancing andSettlement Code. All licensed electricity companies are

obliged to sign the Code. The Code places obligations on ELEXON.

ELEXON procures, manages and operates services and

systems, which enable the balancing and imbalancesettlement of the wholesale electricity market and retailcompetition in electricity supply.

New trading arrangements designed to be more efficient

and to provide greater choice to market participants, whilemaintaining the operation of a secure and reliableelectricity system.

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The new arrangements include:

Forward and futures markets

a Balancing Mechanism in which the NGC, assystem operator, accepts offers of and bids for

electricity close to real time to enable it to balance

the system;

a Settlement Process for charging participants

whose contracted positions do not match their

metered volumes of electricity, for the settlement of

accepted Balancing Mechanism offers and bids andfor clearing costs of balancing the system.

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California Deregulation Process

Electricity costs in California were claimed to be about

50% higher than the national average and this was seenas necessary to change.

Competition has been seen as the answer to reduce highcosts. Public and political pressures have resulted in

ending the regulated monopolies Deregulation in the USproceed with the Public Utility Regulating Policies Actapproved in 1978 and the Energy Policy Act (EPAct) in1992.

Dramatic changes were put in place when the FederalEnergy Regulatory Commission (FERC) issued a noticeof proposed rulemaking (Mega-NOPR) in 1995 to

promote non-discriminatory open access to transmission

services.

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The three investor-owned utilities (IOUs) in California(Pacific Gas & Electric or PG&E, Southern CaliforniaEdison and San Diego Gas Electric) file with FERC on

April 29, 1996, outlining the proposed CaliforniaModel.

On March 31, 1998 California became the first sate tooffer all customers a choice of electric service

providers. There are three significant characteristics inCalifornia Model, though this model is still in theprocess of design.

- A Zonal approach is applied to simplify thetransmission pricing scheme, including nodal and

congestion charge assessing.- Multiple separate energy forward markets, each with a

supply and demand portfolio managed by a Schedulingcoordinator (SC) or PX, have been introduced.

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Com etin GeneratorsAncillary Services

Distributors

California PX

S stem O erators

Transmission systems

Scheduling

Co-ordinators

(SC)Brokers

ControlMonitor

DispatchBid

ForecastSell

California ISO

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- An adjustment bid approach is adopted to performinter-zonal congestion management.

- A total separation of the wholesale power exchange

and the market participants from ISO.- PX:

- The power exchange is an independent entity thatmanages bid for energy on a day ahead basis for each

half-hour which will be basis for ISO dispatchdecision.

- The use of PX will be mandatory for utility generationand procurement by the IOUs, but will be voluntary forall other market participants.

- The PX will set the prices based on bidding by theutilities fossil plants, as well as, participatingmunicipal, out-of-sate, and IPP generation.

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- It will provide a forward competitive spot market forelectric power, conduct day-ahead and hour-aheadauctions of generation and demand, ensure non-

discriminatory, transparent bidding interface andprotocols.

- The PX will also develop load generation balanceschedule for transmittal to the ISO, notify to bidders ofaccepted schedules, provide for settlement of day-

ahead and hour-ahead schedule and finally, bill PXcustomers and administer payments to PX suppliers.

- ISO:

- The ISO will control the power dispatch and the

transmission system. It will own no transmission,generation, or distribution facilities and will have nofinancial interest in the Power Exchange or in anygeneration or load.

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- The ISO will meet all North American Electricity

Reliability Council (NERC) and Western System

Coordinating Council (WSSC) reliability standardsand will coordinate the information exchange in an

open market.

- The ISO will post non-confidential information such

as pricing, availability, status, transmissionconstraints, load distribution and line losses.

- The ISO will procure ancillary services and will

coordinate day-ahead scheduling and balancing forall users of the transmission grid. This will make the

California ISO the fourth largest single control area

in the world.

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The California Energy Commission(CEC) is the state's primary energy policy and

planning agency, charged with ensuring a reliable and affordable energy supply. The

Commission has five major responsibilities: Forecasting future energy needs and

keeping historical energy data; Siting and licensing power plants; Promoting energy

efficiency through appliance and building standards; Developing energy technologies

and supporting renewable energy; Planning for and directing state response to energy

emergencies.

California Energy Oversight Board (EOB)

Formed by the California Legislature to perform three functions: To oversee the

Independent System Operator and the Power Exchange; To determine thecomposition and terms of service and to appoint the members of the governing

boards of the Independent System Operator and the Power Exchange; To serve as

an appeal board for majority decisions of the Independent System Operator

governing board.

California Public Utilities Commission (CPUC)

The CPUC regulates privately owned telecommunications, electric, natural gas,

water, railroad, rail transit, and passenger transportation companies. The CPUC is

responsible for assuring California utility customers have safe, reliable utility

service at reasonable rates, protecting utility customers from fraud, and promoting

the health of Californias economy.

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California Air Resources Board (ARB)

The California Air Resources Board (ARB) mission is to promote and protectpublic health, welfare and ecological resources through the effective and efficientreduction of air pollutants while recognizing and considering the effects on theeconomy of the state.

Federal Energy Regulatory Commission (FERC)

FERC is an independent regulatory agency within the Department of Energythat: regulates the transmission and sale for resale of natural gas in interstatecommerce; regulates the transmission of oil by pipeline in interstatecommerce; regulates the transmission and wholesale sales of electricity in

interstate commerce; licenses and inspects private, municipal and statehydroelectric projects; oversees related environmental matters; andadministers accounting and financial reporting regulations and conducts of

jurisdictional companies.

U.S. Department of Energy (DOE)

"The Department of Energy's mission is to foster a secure and reliable energy

system that is environmentally and economically sustainable. . .". The FERCwhich regulates the California ISO is part of the DOE.

North American Electric Reliability Council (NERC)

Since its formation, NERC has operated as a voluntary organization - onedependent on reciprocity and mutual self-interest of all those involved.

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Western Systems Coordinating Council (WSCC)

The California ISO is a member of the WSCC. WSCC is committed to

being the regional forum for actively promoting regional electric service

reliability through: development of planning and operating reliabilitycriteria and policies; the monitoring of compliance with these criteria and

policies; the facilitation of a regional transmission planning process; and,

the coordination of system operation through security centers.

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- Main Features of Market

- WEPEX (Western electric power exchange) allow only short-term(real time-, hour- and day- ahead) trading

- California rules dont prohibit other PX from operatingsimultaneously. American PX operates.

- Bilateral trading over short or long period is not only allowed butencouraged.

- Operation of transmission system in an open access manner.

- Open customer access at retail level.

- postage stamp pricing on a zonal basis. The fee covers

- certain stranded asset cost to be recovered under theagreements between utilities and the state government.

- All capital cost recovery involved in the transmissionsystem

- all equipment operating , maintenance, taxes, personal etc.

- all capital and fixed costs of the ISO.

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- Congestion management through adjustment ofzonal prices.

- Inter-zonal

- Intrazonal

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- Nuclear and renewable power are traded differently.

- Nuclear power do not bid. They are contracted ahead of timeas must run. The schedule and price are calculated and

disclosed publicly.- Renewable (solar and wind) must be bought as and when

available.

- Request for power transmission are calledportfolios- Only balanced portfolios are allowed.- requested day-ahead

- portfolios may include complicated network servicecombinations

- PX also submits portfolios.

- Schedulers must identify the output of each generatorpoint and demand at each delivery pint explicitly.

- Increment and decrement schedules can also be submitted.

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- Full competition at retail level. All customers could have achoice of electric suppliers.

- Mandated a 10 % roll back in prices for residential and smallcommercial customers (~ 5 cents/kWh).

- Large customers free to play at wholesale level. Smallcustomers (industrial , commercial and residential) have threeoptions:

- They can buy from their existing provider (verticallyintegrated)

- They can buy from spot market though distributioncompany.

- They can decide to buy from another competitive retailprovider.

6.00 PM ISO: Publish forecasted transmission conditions (Generator

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.

Meter Multipliers, system load forecast (by Zones), estimated

Ancillary Service requirements, scheduled transmission outages,

loop flows, congestion, ATC, etc.)

One day ahead

5.00 AM ISO: Notify Scheduling Coordinators of unit-specific Reliability

Must Run requirements

6.00 AM ISO: Update system load forecast and AS requirements.

SCs: Notify ISO of price option for Reliability Must Run(RMR) Units for which notification was provided at 5:00 a.m.

Provide direct access load forecasts to the ISO.

6.30 AM ISO: Provide net direct access load forecasts to UDCs

9.30 AM Gen: Submit individual unit schedules, AS schedules/ price bids

and incs/decs for CM to the PX.

9.45 AM PX: Validate individual unite schedules, AS schedule/price bidsand incs/decs.

10.00 AM PX: Finalize MCP and Initial preferred schedules. Communicate

MCP and resulting schedules to the PX participants.-Finalize AS schedules (self-provision) or AS price bids.

Communicate resulting AS schedules and/or price to PX

participants.

PX/SCs: Submit initial preferred energy schedules to the ISO

-Submit AS bids and/or self-provided AS schedules to the ISO.

ISO: Validate all SC energy schedules, including RMRrequirements and bids; notify and resolve incorrect schedules

and bids, if any.

-Validate all SC Ancillary Service schedules and bids; notifyand resolve incorrect AS schedules and bids, If any.-Start the inter-zonal congestion management evaluation process

and Ancillary Services bid evaluation.

11.00 AM ISO: If no inter-zonal congestion exists, go to line 27.

-Complete advisory dispatch schedules and transmission prices

if inter-zonal congestion exists.

-Complete the advisory schedules and prices of each AS.

-Notify all SC if inter-zonal congestion exists. Publish advisory

transmission prices, dispatch schedules, AS schedules andprices.

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.

11.05 AM ISO/PX/SCs: Start the process of developing revised schedulesand price bids (both dispatch and AS) (the PX may iterate withPX participants).

12.00 PM PX/SCs: Submit revised preferred schedules and price bids

(both energy and AS) to the ISO.ISO:Validate all SC schedules and bids (energy and AS); notify

and resolve incorrect schedules and bids, if any.-Start the inter-zonal congestion management evaluation process

and Ancillary Services bid evaluation.

1.00 PM ISO: Complete final dispatch schedules and transmission prices.-Complete final schedules and prices of each Ancillary Service.

-Inform all SCs their final dispatch schedules, AS schedules and

prices.-Publish transmission prices if inter-zonal congestion exists.

- Calculate and communicate with SC the specific SCs zonal

prices if asked.PX: Publish PX prices

- Communicate the final generation and load schedules & AS

schedule to PX participants.

1.00 PM ISO: Develop net schedules for each of the Control Area

interfaces. These interfaces include SC net schedules, ControlArea net schedules and/or individual transactions.

Call each adjacent Control Area and check that net schedules at

each interface point match. Search for discrepancies and identifytransactions that do not match. Resolve discrepancies with the

involved SCs or eliminate the transactions with discrepancies

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California Crisis

ACTION

Creating a power purchase portfolio to reduce the dependenceon spot market and provide price stability and certainty.

Expediting construction of new power plants.

Implementing an aggressive conservation and demand

management program. Optimizing use of existing transmission and expanding the

transmission grid.

Optimizing and coordinating use of state hydroelectric

resources. Promoting small distributed plants.

Augmenting small natural gas supplies, pipelines and storage

facilities.