Review of State of the Market for 2002...Load Duration Curve for 2001 and 2002 Note: values are instantaneous top-of-hour actual loads. Intra-hour peaks are not included. 15,000 20,000

California Independent System Operator

California ISO DMA 1 2002 Annual Report: 4/24/03

Review of State of the Market for 2002

Report to the Federal Energy Regulatory Commission

April 30, 2003

Anjali Sheffrin, Ph.D.

Director of Market Analysis

California ISO



Overview of Control Area• 10 million customers served• 25,000 circuit miles of

network transmission• 42,441 MW peak load• 232,000 GWh annual energy • 45,000 MW of installed

generation capacity before derates for hydro and outages

• 5,000 MW net imports

*All statistics are for 2002

Imperial Valley

Adelanto

Miguel

N.Gila

Palo Verde Devers

Valley

Serrano Mira Loma

Lugo

Victorville

Mohave

Eldorado

McCullough

Market Place

Midway Diablo Canyon

Gates

Los Banos

Malin Captain Jack

San Onofre

Tesla

Metcalf Moss Landing

Tracy

Vaca Dixon

Table Mountain

Round Mountain

Olinda

Sylmar

NW3

Mead

Vincent

SF

NP15

ZP26

SP15

Maxwell

Path 26

NW 1

AZ3

Path 15

MX

AZ2 LA4 LA2



2002 Market Rule Changes• Current ISO markets

– Real Time Imbalance Energy Market (Zonal)– Day Ahead and Hour Ahead congestion management – Ancillary service mrkts: regulation,spin,non-spin,replacement– No Day Ahead energy market, State purchased energy to

make up the deficiency in utility generation

• Feb: Zero-bid requirement on import bids in real-time • April: Imports to be paid instructed energy price• May: New Automated Dispatch System (ADS)• October: MD02 Phase IA

– Soft price cap changed to $250/MWh from $91.87/MWh– Automated Mitigation Procedures (AMP)



2002 Market Highlights: Market Health and Costs

• Market health vastly improved since 2000-01 crisis due primarily to supply/demand fundamentals– Long-term contracts, new generation, significant imported

energy all helped to stabilize ISO markets– Moderate loads; few demand response programs but being

encouraged by new State and ISO initiatives– Real-time volumes small, improved accurate forward

scheduling

• Most load met by long-term contracts and utility-retained generation. Total market costs just over $10 billion in 2002 ($43/MWh), compared to $27 billion in 2000 and 2001, $7.4 billion in 1999



$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

Total 2002 Total 2001Total 2000Total 19991998 (9mo)

Year

Co

sts

(Mill

ion

s o

f D

olla

rs)

Ancillary Services***

Real-Time Energy**

Forward Energy Costs (Bilateral)*

Total wholesale electricity costs decreased 62% between 2001 and 2002,Including 95% decrease in real-time and ancillary services costs

Total Wholesale Electricity Costs in ISO Control Area, 1998-2002



Load Growth in 2002Total Energy Consumption was up 2% in 2002 due to warmer weather and

reduced conservation. Little change in Peak Load.Load Duration Curve for 2001 and 2002

Note: values are instantaneous top-of-hour actual loads. Intra-hour peaks are not included.

15,000

20,000

25,000

30,000

35,000

40,000

45,000

1

1001

2001

3001

4001

5001

6001

7001

8001

Hours

Lo

ad (

MW

)

Year ending 31-Dec-02 Actual Load Year ending 31-Dec-01 Actual Load



I. Nearly 4,000 MW of generation added since 20012001-2002 New Generation Additions and Retirements

3,928-1,4092,7642,573ISO Control Area

-286-1,401430685SP15

409071338ZP26

3,805-82,2631,550NP15

Net Generation Change (MW)

2002 Generation Reductions

(MW)

2002 Generation Additions (MW)

2001 Generation Additions (MW)

Congestion Zone

II. Reviewed and approved 22 transmission upgrades worth $700 million



Improved generation outage co-ordination in 2002 has kept outages below levels in 2001 Average Hourly Outages by Type

0

2

4

6

8

10

12

14

Jan-

01

Jan-

02

Feb

-01

Feb

-02

Mar

-01

Mar

-02

Apr

-01

Apr

-02

May

-01

May

-02

Jun-

01Ju

n-02

Jul-0

1Ju

l-02

Aug

-01

Aug

-02

Sep

-01

Sep

-02

Oct

-01

Oct

-02

Nov

-01

Nov

-02

Dec

-01

Dec

-02

Scheduled Forced

Thousands of MW out



1.8%

6.0%

0

5000

10000

15000

20000

25000

30000

35000

40000

4500020

01

2001

2002

2002

MW

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

Available Generation MW Net Interchange MW Load MW Reserve Margin %

July 3, 2001 HE 16 July 10, 2002 HE 16

Reserve Margin increased to 6% in peak hour of 2002 from 1.6% in peak hour of 2001

Annual Peak Hour Reserve Margins in 2001 and 2002



Average real-time Incremental dispatch price varied between $40 and $60/MWh for most days in 2002

Daily Average Real-Time INC and DEC Prices in 2002

-20

0

20

40

60

80

100

1/1/0

21/1

5/02

1/29/

022/1

2/02

2/26/

023/1

2/02

3/26/

024/9

/02

4/23/

025/7

/02

5/21/

026/4

/02

6/18/

027/2

/02

7/16/

027/3

0/02

8/13/

028/2

7/02

9/10/

029/2

4/02

10/8/

0210

/22/0

211

/5/02

11/1

9/02

12/3/

0212

/17/0

212

/31/0

2

Day

Pri

ce (

$/M

Wh

)

BEEP INC Price BEEP DEC Price



2

2.5

3

3.5

4

4.5

5

Jan-

02

Feb

-02

Mar

-02

Apr

-02

May

-02

Jun-

02

Jul-0

2

Aug

-02

Sep

-02

Oct

-02

Nov

-02

Dec

-02

Month

$/M

Mb

tu

PG&E Citygate (Northern CA)

SoCal Border (Southern CA)

Henry Hub (National)

Gas prices increased steadily in 2002,Causing electricity prices to rise in step

Monthly Average Prices for Natural Gas



-$10

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

Jan-02 Feb-02 Mar-02 Apr-02 May-02 Jun-02 Jul-02 Aug-02 Sep-02 Oct-02 Nov-02 Dec-02

Time Period

$/M

Wh

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Estimated Competitive Price Markup Ratio of Markup to Competitive Baseline

Favorable market conditions in 2002 checked suppliers’ ability to exercise market power, when compared to previous years

Estimated Monthly Mark –up of Prices above Competitive levels (Price-to-Cost Markup in Short-Term Energy)



Long-term market outcomes returned to workably competitive levels in 2002

Twelve-Month Competitiveness Index through Dec-02

-2,000,000

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

Apr

-98

Jun-

98

Aug

-98

Oct

-98

Dec

-98

Feb

-99

Apr

-99

Jun-

99

Aug

-99

Oct

-99

De

c-9

9

Feb

-00

Apr

-00

Jun-

00

Aug

-00

Oct

-00

De

c-0

0

Jan

-01

Feb

-01

Mar

-01

Apr

-01

Ma

y-01

Jun

-01

Jul-

01

Sep

-01

Nov

-01

Jan-

02

Mar

-02

Ma

y-0

2

Jul-

02

Sep

-02

Nov

-02

Month

Vol

um

e (M

Wh)

-$30

$0

$30

$60

$90

$120

$150

$180

$210

$240Short-Term Volume

Average Markup

12-Month Competitiveness Index$5 Threshold



0.80.9

11.11.21.31.41.51.61.71.81.9

22.12.22.32.4

1

61

7

12

33

18

49

24

65

30

81

36

97

43

13

49

29

55

45

61

61

67

77

73

93

80

09

86

25

RS

I In

de

x rsi_1999

rsi_2000

rsi_2001

rsi_2002

Return to Market Health with suppliers pivotal in fewer than 1% of hours in 2002

Residual Supply Index Duration Curves: 1999-2002

Hours with RSI < 1.1

(RSI less than 1.1 indicates suppliers able to set market prices )



Market Revenues in 2002 Supported Recovery Fixed Cost of New Generation at $72 - 77/kW-yr

Estimated Operating Revenue in ISO Energy and Ancillary Service MarketsNP15 SP15

Load Factor 61% 62%Average Energy Revenue ($/MWh) $ 40 $ 41Average Operating Cost ($/MWh) $ 26 $ 26Net Energy Revenue ($ /kW/yr) $ 66 $ 71A/S Capacity Revenue ($/kW/yr) $ 6 $ 6Total Net Revenue ($/kW/yr) $ 72 $ 77

•Net revenue can cover the lower end of annual fixed cost estimated at $70 to 90/kW/year

•Long-term contract with load is the more desirable means to ensure revenue adequacy and stability



Ancillary Services Costs Down 88% in 2002 from 2001 levelsAS requirements reduced from 13 % of system load to 9.3%, largely due to less purchases of regulation service; lower prices for all A/S

services

$0

$2

$4

$6

$8

$10

$12

$14

$16

Jan Feb March April May June July Aug Sept Oct Nov Dec

A/S

Co

sts

per

MW

h o

f IS

O L

oad

0%

2%

4%

6%

8%

10%

12%

A/S

Co

sts

as P

erce

nta

ge

of

En

erg

y

2001 A/S Costs per MWh Load

2002 A/S Costs per MWh Load

2001 A/S Costs as % of Energy

2002 A/S Costs as % of Energy



-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Jan-

02

Feb

-02

Mar

-02

Apr

-02

May

-02

Jun-

02

Jul-0

2

Aug

-02

Sep

-02

Oct

-02

Nov

-02

Dec

-02

Jan-

03

Feb

-03

Mar

-03

Apr

-03

Import Export Net Import

Strong import volumes into California overall Scheduled Imports and Exports - Monthly Averages



0

5

10

15

20

25

30

35

40

Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Ju

l

Aug

Se

p

Oct

Nov

De

c

Month

$ (M

illio

ns)

2001 2002

Congestion costs down 61% in 2002 from 2001 levels;2002 monthly costs significantly higher only in June and July,

due to derates of key transmission lines

Monthly Total Interzonal Congestion Costs: 2002 v. 2001



Increased (within zone) intrazonal congestion due to new generation additions and inadequate local market

power mitigationMonthly Total Intrazonal Congestion Costs in 2002 + $263 mil RMR Fixed Cost

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

Jan-

02

Feb

-02

Mar

-02

Apr

-02

May

-02

Jun-

02

Jul-0

2

Aug

-02

Sep

-02

Oct

-02

Nov

-02

Dec

-02

Mill

ion

s

RMR Variable Cost INC OOS DEC OOS



Critical Market Issues Going Forward

• Lack of an effective local market power mitigation mechanism– Expect increased local market power with new generation– Current local AMP threshold of $50 for INC and -$30 for

DEC makes mitigation ineffective

• Decline in import bids in real-time due to zero bid requirement may impact reliability

• Generators frequently decline dispatch instructions– Declined incremental dispatch was more than 50% in

December



Going Forward: MD02 Market Redesign• Lack of forward market mechanism to resolve intrazonal congestion

– Intrazonal congestion managed in real time since ISO startup; susceptible to exercise of market power (DEC game, etc.)

– MD02 Phase 2 Integrated Forward Market to simultaneously manage intrazonal andinterzonal congestion in day ahead

• No formal day ahead unit-commitment process– Must-Offer Waiver Process is a workaround used to maintain availability of

generation.– Integrated Forward Market set for 2004

• Slow development of price responsive demand– ISO markets can accommodate load-side bidding, but state has been slow in

developing necessary rate design and metering systems

– March 2003: CPUC begins 2600-customer pilot price-responsive demand study

• Other MD02 Development– AMP in effect since 10/30/02, but has not yet triggered mitigation– Real-time fully-automated economic dispatch software to be tested Summer 2003,

deployed Fall 2003– Locational Marginal Pricing still subject to discussion but targeting fall 2004



New Demand Response Programs in California

• ISO began Participating Load Program (PLP) in 1999; mostly pump load participating; about 1 MW of non-pump load participating as ancillary services

• Mar-03: ISO formed working group to update PLP technical standards

• Mar-03: California PUC approved three pilot programs to test demand response in 2600 end-users:– Peak/off-peak pricing– Day-ahead notification of peak pricing– Same-day notification of peak pricing

Documents

Review of State of the Market for 2002...Load Duration Curve for 2001 and 2002 Note: values are instantaneous top-of-hour actual loads. Intra-hour peaks are not included. 15,000 20,000