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1/20

Capacity Payments and Supply Adequacy

in a Competitive Electricity Market

Shmuel OrenUniversity of California at Berkeley

VII SEPOPE, Curitiba-Parana Brazil

May 21-26, 2000


2/20

What is Reliability NERC (National Electric Reliability Council) defines

reliability as: the degree to which the performance of theelements of the electrical system results in power being

delivered to consumers within accepted standards and in theamount desired

Reliability encompasses two concepts:

Security: the ability of the system to withstand sudden disturbances.

This aspect concerns short-term operations and is addressed byancillary serviceswhich include:Voltage support, Congestion relief,

Regulation (AGC) capacity, Spinning reserves, Nonspinning reserves,

Replacement reserves.

Adequacy: the ability of the system to supply the aggregate electricpower and energy requirements of the consumers at all times. This

aspect concerns planning and investment and is addressed by Planning

reserves, Installed capacity, Operable capacity or Available capacity.


3/20

Markets and Reliability Security and Adequacy are both compliments and substitutes.

Security is apublic goodwhile Adequacy is mostly aprivate

good. Security can be provided through competitive procurement of

ancillary services. However, decisions concerning required

amounts, dispatch and cost allocation need be centralized due to

externalities and free rider effects.

Generation adequacy decisions can be decentralized and left to

the market. Inadequate supply will result in high prices which in

turn encourage new capacity. Customers should be allowed todecide how much they want to pay for and suppliers should

decide how much to invest. These are individual economic and

risk management decisions.


4/20

Alternative Approaches to Ensuring

Generation Adequacy

Rely on energy markets. Consumers and suppliers interact through

unrestricted energy spot markets. Energy spot and future energy prices

provide price signals and compensation for capacity investment. Technology

mix and generation capacity are determined by entry and exit of suppliers and

by customer choice of desired price risk. (California, Nordpool)

Central agency (ISO or Regulator) specifies requirements for planning

reserves based on traditional planning tools. Capacity market allow supplier

to trade reserves and efficiently reallocate the reserves requirements but the

capacity market and energy market may not be in equilibrium (PJM, New

York, New England)

Generators receive capacity payments based on availability, technology,

VOLL, LOLP to incent investment and availability. (old UK system,

Argentina, Spain)


5/20

Short-Term Vs. Long-Term Efficiency

Savings from improved dispatch under restructuring not likely

to be high (system operated quite efficiently).

Most efficiency gains from restructuring will be long-term

resulting from better investment decisions (technology choice,

location and generation capacity) and from demand side

response to price signals. The economic process that leads to long-term efficiency

involves entry and exit in response to energy price signals,

and customer choice of desired supply certainty and price risk.

Centrally determined installed capacity requirements orcapacity payments interfere with this economic process.


6/20

The Theoretical Foundation of Capacity

Payments Capacity payments originate in the theory of peak load pricing

(Boiteux)

Basic Idea: There are two commodities, energy and capacity. Theobjective of pricing is to recover cost while minimizing distortion of

efficient consumption. Peak load users are responsible for capacity

requirements while off peak user only consume energy. Hence, efficient

pricing must charge MC off-peak and MC+Capacity charge on-peak.

Peak Demand

Off-peak Demand

MC MC+CAP

MW

Peak Offpeak


7/20

Theoretical Foundation of Capacity Payments:

Extensions

Effect of Uncertainty

Basic Idea:The two commodities are energy and reliability

of supply. Additional capacity increases reliability (reduces

LOLP) on and off peak hence capacity cost should be

allocated over all time periods so as to reflect the value of

improved reliability Effect of Multiple Technologies

Basic idea:Recover production cost with optimal

technology mix through a nonlinear price structure basedon load factor (Wright tariff) or equivalently through a

combination of time of use MC- based energy rate and a

demand charge.


8/20

Cost Recovery Through a Combination of

Marginal Costs and Capacity Payment

M W

TIM ET 1 T 2 T 3

1 M W

$/M W H M A RG I NA L CO S T( P RI CE DURA T I O N CURV E )

C 1

C 2

C 3

TIM E

EN ER GY R EVEN UE

CAPAC ITY PAYMEN T PER M W= F1

M W

TIMET 1 T 2 T 3

G N 1

G N 2

G N 3

1 M W

C 1C 2

F 1

F 2

F 3

F3+C3*(T1+T2+T3)

C3*T 3C2*T 2

C1*T 1

F 1

T I M E

$/M W

F3+C3*(T1+T2+T3)=F1+C1*T1+C2*T2+C3*T3

CO S TFUNCTION

C 3


9/20

Capacity Payments Covered by Raising Energy

Prices to VOLL During Shortage PeriodsMW

TIMET1 T2 T3

1 MW

$/MWH MARGINAL COST(PRICE DURA TION CURV E)

C1

C2

C3

TIME

ENERGY REVENUE

MW

TIMET2 T3

GN 1

GN 2

GN 3

1 MW

C1C2

F1

F2

F3

F3+C3*(T0+T1+T2+T3)

C3*T3C2*T2

C1*T1

TIME

$/MW

F3+C3*(T0+T1+T2+T3)=VOLL*T0+C1*T1+C2*T2+C3*T3

COSTFUNCTION

C3

T1

CURTA ILED LOA DDEMA ND REDUCTION

T1

NO CA PACITY PAYMENT ( F1~VOLL*T0)

VOLL*T0

~


10/20

Demand Side Bidding Provides a Market Based

Alternative to Administratively set VOLLM W

T I M ET1 T2 T3

1 M W

$ / M W H M A R G IN A L C O S T(PRICE DURA TION CURV E)

C1

C2

C3

T I M E

E N ER G Y R E V E N U E

M W

T I M ET2 T3

G N1

G N2

G N3

1 MW

C1C2

F1

F2

F3

F3+C3*(T0+T1+T2+T3)

C3*T3C2*T2

C1*T1

T I M E

$ /MW

F3+C3*(T0+T1+T2+ T3) = +C1*T1+C2*T2+C3*T3

C O S TFUNCTION

C3

T1

CURTAIL ED L OA DDEMA ND REDUCTION

NO CAPACITY PAY MENT

D E M A N DBIDDINGC U R V E

c T dT T

( )0

0

c T dT T

( )0

0


11/20

MW

EnergyPrice

($/MWh) Price at7:00-8:00 p.m. without Capacity payment

Price at9:00 -10:00 a.m.

Price at2:00 -3:00 a.m.

GEN 1

Demand at2:00 - 3:00 a.m.

Q1 Q2 OptimalCapacity

GEN 2 GEN 3 GEN 4GEN 5

Demand at 7:00 - 8:00 p.m.

Demand at

9:00 - 10:00 a.m.

Energy Market With and Without Capacity

Market

GEN 6

Capacitywithcapacitypayments

Price at7:00-8:00 p.m. with Capacity payment


12/20

Example of Long Run Equilibrium in Energy

Only Markets

Supply: Two types of generators

G1: N=50 G2: N=100

Capacity=80MW Capacity=60MW

FC=$926,400/Month FC=$288,000/Month

MC=$15/MWh MC=$25/MWh

Demand: Two demand functions

Off-Peak: 420 Hrs./Month Peak: 300Hrs./Month

P=30-Q/1000 P=50-Q/1000

(This example is due to Severin Bornstein)


13/20


Only Markets (contd)

Peak price: $40/MWh Off-Peak price: $25/MWhFixed cost recovery:

G1: 80*[(40-15)*300+(25-15)*420)] - 926,400 = $9,600/Month (excess

profit)

G2: 60*(40-25)*300 - 288,000 = ($18,000/Month)(deficit)

0 4000 5000 10000 MW

MC $/Mwh

15

25

50

30

40


14/20


Only Markets (contd)

Long Run Equilibrium: Entry of 2000MW G1 capacity, Exit of 3000MW G2 capacity

Peak price $41/MWh Off-Peak price $24/MWh

G1: $926,400926,400= 80*[(41-15)*300+(24-15)*420] G2: $288,000288,000=60*(41-25)*420

0 4000 5000 6000 9000 10000 MW

MC $/Mwh

15

24

50

30

41 Peak

Off-Peak


15/20

Supply and Demand Uncertainty Cause High

Price Volatility in Energy Only Price Systems

Price volatility is an inherent aspect of electricity due to its

nonstorability and the steep supply curve.

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

0 20000 40000 60000 80000 10000 0

Demand (MW )

Marginal Cost

($/MW h)Marginal Cost

Resource stack includes:Hydro units;

Nuclear plants;Coal units;

Natural gas units;Mi sc .

WSCC Generation Resource Stack Electricity On-Peak Spot Price

$0.0

$20.0

$40.0

$60.0

$80.0

$100.0

$120.0

$140.0

$160.0

12/1/95 3/10/96 6/18/96 9/26/96 1/4/97 4/14/97 7/23/97 10/31/97 2/8/98 5/19/98

Time

Spot Price

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

ERCOT on-peak

COB on-peak

Electricity On-peak Spot Prices


16/20

Some Fundamental Aspects of Competitive

Electricity Markets

Obligation to serve replaced by Obligation to serve at a

price.

Prices determined by supply and demand and consist of

marginal production cost + scarcity rent.

Customers and suppliers are free to choose level of

exposure to price risk through risk management andcontractual agreements.

Reserve generation capacity beyond security needs is just a

hedge against high prices. Forward markets and hedging instruments provide a

competitive market alternative to capacity payments.


17/20

How it Can Be Done

Buyers decides how much they want to pay for capacity

according to the price risk they are willing to assume or price

level at which they are willing to be curtailed (buyer is

responsible for providing curtailment technology ordemonstrating ability to incur financial risk).

Generators diversify investment risk through forward supply

contracts that systematically link capacity payments to an

obligation to supply energy at a pre-specified strike price

(generator is liable to supply contracted energy or compensate the

buyer at VOLL).

Generators that do not receive capacity payments (uncontracted)are entitled to sell their energy at free market prices which can go

as high as VOLL.

Generation gets built if market value of capacity (as reflected by

contract markets) exceeds cost of new generation.


18/20

Demand can participate in mitigation of price risk by avoidingcapacity payments (not contracting) and subjecting their loadto curtailment (or self-curtailing) during high price periods.

VOLL can be set administratively or replaced by demand sideresponse to price signals. VOLL serves both as a price cap foruncontracted energy and as a penalty for contracted but notdelivered energy.

The role of regulatory agencies is reduced to ensuring that loadserving entities and generators have the resources (financial orphysical) to meet their obligations. Public risk exposure maybe regulated by imposing requirement for forward contracting

on load serving entities. Theoretical probabilistic models for calculating LLOP are

replaced by stochastic price models underlying the pricing offorward contracts but pricing is left to the market participants.

How it Can Be Done (cond)


19/20

Alternative Price Behavior Models Produce

Different Capacity Values

$0

$1 0

$2 0

$3 0

$4 0

$5 0

$6 0

$7 0

$8 0

$9 0

$100

0 0.5 1 1.5 2 2 .5 3

2 regime (Reg ime swi tching)

2 factor (Determ. Vol . Jump-Di f fus ion)

3 factor (Stoch. Vol . Jump -Di f fus ion)

Alternative Price Behavior Models

Spark Sp read Cal l und er Di fferent Models(Heat Rate: 9.5MMB tu/MWh, rf = 4%)

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0 0 .5 1 1 .5 2 2.5 3

Matur i ty Tim e (yrs)

Spark Spread C a l l

Mode l 1a (De term. Vo l . Jump-Di f fus ion)

Mode l 2a (Re g ime s wi tch ing)

Mode l 3a (S toch . Vo l . Jump-Di f fus ion)

G B M

Value of Spark-Spread Call Options

Under Alternative Models

The role of models is to forecast prices but not to set them.

The market figures the right price.


20/20

Conclusions Capacity Payments undermine the potential gains of deregulation by

leading to over-investment, wrong technology choices, and foreclosure ofdemand-side options.

Regulation should focus on facilitating decentralization, trading, customerchoice and demand side responses (foster metering communication andEC technologies)

The role of capacity payments in ensuring adequacy of supply can befulfilled by risk management approaches and hedging instruments that

permit diverse choices and promote demand side participation. The valueof capacity as a hedge for price risk should be determined by the market.

If capacity payment are intended to correct failures of capital markets thenregulatory intervention should address directly the availability and cost of

long-term financing for capacity expansion secured by short-termcontracts (e.g., through loan guarantees) and focus on promoting marketconfidence and rules that facilitate liquid markets for energy futures andother risk management instruments.

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