Dr. John L. JurewitzDirector, Regulatory Policy

Southern California Edison Company

Massachusetts Electric Restructuring RoundtableBoston, Massachusetts

January 29, 2001

Anatomy of California’sElectricity Crisis

(How to Make a Bad Thing Worse)

2.

“That’s why I never walk in front.”

3.

The Making of California’s Electricity Crisis

RestructuringRules

Market Rulesand

Market Power

MarketFundamentals

Regulatory and Political

Inaction

4.

Key Restructuring Rules

CPUC’s requirement that utilitiesbuy all power through Power Exchange and ISO

Generation divestiture without buy-back contracts

Retail rate freeze

Over-exposureto the spot market

5.

Why Did CPUC Initially Insist that Utilities Buy Everything Through the

PX and ISO Spot Markets? Wanted transparent pricing to assure against self-

dealing

Did not want utilities incurring long-term obligations and potentially stranded costs in their role as default provider

Wanted to encourage independent retailers

– Customers wanting price hedges should seek them from ESPs

6.

UnhedgedSpot Market

CAISO 40-50% 50-60%

% Market Hedged(long-term forward contracts,

self-owned generation)

PJM 85-90% 10-15%

New England 80% 20%

Australia 90% 10%

Comparison of Forward Contracting/Hedgingin Other Electricity Markets

Regulatory Constraints in Forward Contracting in CAISO Market Was a Key Source of High Costs in Summer 2000

7.

0

200

400

600

800

1000Ju

n-99

Jul-9

9

Aug

-99

Sep

-99

Oct

-99

Nov

-99

Dec

-99

Jan-

00

Feb-

00

Mar

-00

Apr

-00

May

-00

Jun-

00

Jul-0

0

Aug

-00

Sep

-00

Oct

-00

Nov

-00

Dec

-00

$/M

Wh

Min/Max Zonal Avg

PX SoCal Day-Ahead Electricity Prices

8.

California Market Prices have Skyrocketed in 2000Comparison of Average Cal PX SP15 Monthly* Prices

Actual prices for last six months of 2000 averaged more than four times 1998 and 1999 prices

*Simple average of all hourly prices within the month

0

50

100

150

200

250

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

199819992000

$/M

Wh

9.

Comparison of California Electricity Costs

Estimated cost to serve all load in the CA ISO’s control area– Cost includes energy and ancillary services

1998 cost is for nine monthsSource: ISO Board material, January 2001

5.67.4

28.0

0

5

10

15

20

25

30

$ (B

illio

n)

)

1998 1999 2000

10.

Cumulative Cost of California Electricity

Estimated annual cumulative cost to serve all load in the CA ISO’s control area– Cost includes energy and ancillary services

Source: ISO Board material, January, 2001

1999 and 2000 Cost of Electricity

0

5

10

15

20

25

30

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

$ (B

illio

ns)

20001999

11.

ISO Emergency Operations

Stage 1 Emergency 3 32 11 12» Operating reserve below 7%

Stage 2 Emergency 1 17 9 12» Operating reserves below 5%

» Interruption of voluntary customers

Stage 3 Emergency 0 0 1 10» Operating reserves below 1.5%

» Possible involuntary interruptions(rolling blackouts)

Rolling blackouts were initiated on 1/17, 1/18 January 2001 are through 1/23/01

Summer1999

Summer2000

Nov/Dec2000

Jan2001

Occurrences

12.

1

2

3

05/2

2/00

06/0

5/00

06/1

9/00

07/0

3/00

07/1

7/00

07/3

1/00

08/1

4/00

08/2

8/00

09/1

1/00

09/2

5/00

10/0

9/00

10/2

3/00

11/0

6/00

11/2

0/00

12/0

4/00

12/1

8/00

01/0

1/01

01/1

5/01

Em

erge

ncy

Stag

eISO Emergency Operations in 2000/2001

Rolling blackouts were initiated on 1/17, 1/18 Date is through 1/23/01

Blackouts Stage 1Stage 2Stage 3Blackouts

13.

Market Fundamentals

High rate of demand growth

Virtually no new plants sited

Reduced availability of imports

Skyrocketing gas prices

– Pipeline capacity shortages

Air emissions limitations and high priced emission credits

14.

SCE Sales Growth Rates(Weather Adjusted)

1981 1983 1985 1987 1989 1991 1993 1995 1997 1999-2

-1

0

1

2

3

4

5

Growth RatePercentages

15.

Natural Gas Prices in 2000

Prices peak at an unheard level of $60/MMBtu Gas prices for the second half of 2000 were more than four times higher than 1998 and

1999 prices

$-

$10

$20

$30

$40

$50

$60

$/M

MB

tu

16.

Summer/Fall 2000 Electricity PricesDisconnect From Natural Gas Prices

$-

$100

$200

$300

$400

$500

$600

Jun-9

9Ju

l-99

Aug-99

Sep-99

Oct-99

Nov-99

Dec-99

Jan-0

0

Feb-00

Mar-00

Apr-00

May-00

Jun-0

0Ju

l-00

Aug-00

Sep-00

Oct-00

$/M

WH

$-

$10

$20

$30

$40

$50

$60

$/M

MB

tu

SP15 On-Peak Avg $ MWH

CA Border Avg $/MMBtu

17.

Recent Electricity and Gas Prices

• ISO implemented its $150 soft cap on 1/1/01 and has made significant “out-of-market” (OOM) purchases

• ISO Real-time Average Price is a weighted average of OOM and real-time energy purchases

• Gas prices have dropped significantly from a high of over $50/MMBtu but remain 5-10 times higher than last year

0

100

200

300

400

500

600

700

800

12/4

12/1

2

12/1

5

12/1

8

12/2

1

12/2

4

12/2

7

12/3

0

1/2

1/5

1/8

1/11

1/14

1/17

1/20

$/M

Wh

0

10

20

30

40

50

60

70

$/M

MBt

u

PX Avg Price ISO Avg Price Topock Gas Price

18.

Market Structure, Rules, and Conduct

Flawed ISO/PX market protocols

Large amount of unhedged power purchases

Underdeveloped demand-side responsiveness

Exercise of supply-side market power

19.

High Prices Persist During Modest Loads (Sunday)

Markets do not produce competitive prices Under similar medium load conditions, 2000 prices have increased 700% over

1999 levels

1999 and 2000 Prices

0

50

100

150

200

250

300

350

400

450

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

$/M

Wh

20000

22000

24000

26000

28000

30000

32000

34000

36000

38000

40000

ISO Load MWh

7/30/00 SP15 Price

7/11/99 SP15 Price

7/30/00 ISO Load

7/11/99 ISO Load

20.

The ISO’s Market Surveillance Committee Has Consistently Concluded That Market Power Has

Been Exercised

MSC’s September 6, 2000 report “An Analysis of the June 2000 Price Spikes in California ISO’s Energy and Ancillary Services Market” concludes:

– Extraordinary amount of market power was exercised in June 2000

– Energy costs were 182% above the competitive benchmark

21.

Percent by Which Actual EnergyPrices Exceeded Competitive Benchmark

1998 1999 2000

Percent

6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6-50

0

50

100

150

200

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

Apr

-98

Jun-

98

Aug-

98

Oct

-98

Dec

-98

Feb

-99

Apr-

99

Jun-

99

Aug-

99

Oct

-99

Dec

-99

Feb

-00

Apr

-00

Jun-

00

Aug

-00

Avg

. Ene

rgy

Cos

ts (P

X +

Rea

l Tim

e, $

/MW

h)

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

Mar

ket P

ower

Inde

x

Costs Above Baseline Incurred During Hours of Scarcity

Market Power (No Scarcity)

Competative Baseline Cost

Market Power Index

California Market Produced Two Years of Moderate Prices and Low Mark Up Over Competitive Benchmark

1999 average mark-up was lower than 1998. Price spikes in summer 2000 was due to both higher cost, market power during tight

supply conditions, and scarcity rent

California Independent System Operator

22.

23.

FERC’s November 1 Report

California market is “seriously flawed” Rates have been “unjust and unreasonable” “California market structure and rules provide the

opportunity for sellers to exercise market power when supply is tight”

Insufficient study to determine the exercise of market power by individual sellers

FERC acknowledged its responsibility under FPA § 206 to ensure future rates are just and reasonable, subject to refund

24.

Joskow/Kahn Study

Summer wholesale prices far exceeded competitive benchmark prices

No evidence that wholesale price caps caused higher prices

Many price-setting units were withheld from production even though the market-clearing price well exceeded their marginal costs– This gap cannot be explained by ISO’s demand for reserves

25.

Substantial Output Gap for Most New Owners of Price-Setting Units (Joskow/Kahn)

0

500

1,000

1,500

MW

(Difference between Maximum Output and Average Actual Output for High Priced Hours for June 2000, EPA data)

NP 15 SP 15

Duke Southern AES/Williams Duke Dynegy Reliant

0

2,000

4,000

6,000

8,000

10,000

12,000

Oct 1999 Oct 2000 Nov 1999 Nov 2000

Ave

. Dai

ly O

utag

es (M

W)

ForcedScheduled

Capacity Outages or Withholding?

October 2000 total outages (MW) are 4 times higher than October 1999 November 2000 total outages (MW) are 5 times higher than November 1999

Source: “Market Analysis Report” by the ISO on December 1, 2000

26.

27.

How Can Rolling Blackouts Be Needed in Winter?ISO Load Conditions During Recent Blackout

This winter, the ISO initiated rolling blackouts at a demand of only 65% of last summer’s peak

On 1/23/01 PG&E reported it has exhausted its interruptible program (about 400MWs)

ISO Actual Load

20000

25000

30000

35000

40000

45000

1 3 5 7 9 11 13 15 17 19 21 23

Hour

MW

h

08/16/2000 01/17/2001

Load levels when rolling blackouts implemented

Summer 2000 Peak

28.

Generators and Marketers Reported Huge Profit Increases in the 3rd and 4th Quarters

(Enron is one good example)

4th Quarter 4th Quarter0

100

200

300

400

500

600

1999 2000

$151 Million

$538 Million

Profits Reported by Enron’s Gas and Electric Trading Division

29.

Regulatory and Political Inaction

FERC’s inability or unwillingness to regulate its “just and reasonable” standard

CPUC’s inaction in approving long-term contracts and setting reasonableness standards

CPUC’s unwillingness to end the retail rate freeze

30.

JUN JUL AUG SEP OCT NOV DEC

0

5

10

15

20

25

30

11.710.5

15.3

10.38.6

13.0

22.3

Seven Months of Red Ink

ExistingCustomerRateFreeze

6.2¢/kWh

CostsAbsorbedby SCE in¢/kWh(Approx.$4.5 Billionas of 12/00)

CustomerRates

2000

Average Wholesale Electricity Prices (SCE)

31.

Procurement Undercollections (SCE)

0

.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

June SeptJuly Aug Oct Nov Dec Total

$644Million

$457Million

$870Million

$387Million

$283Million

$561Million

$1,288Million

$4.5 Billion

$Billions

32.

The Regulatory Bankruptcy Squeezeand Its Consequences

Immediate Shortages and High Prices Reluctance of suppliers to supply Bankruptcy “risk premium” in wholesale prices No retail price signal to conserve Threat of bankruptcy-induced natural gas

shortages and “risk-premium” prices

Loss of Summer 2001 Resources Depletion of Northwest hydro Exhaustion of options on 2,000 MW of

interruptible customers

Cascading Broader Economic Impacts Impacts on banks and financial markets Loss of utilities’ ability to invest in needed

T&D infrastructure Shift of business out of California Economic recession

FERC inactionto regulate

wholesale prices

Imminent utilitybankruptcies

CPUC inactionto raise retail pricesand assure recoveryof undercollections

33.

Other Western States Have Found the Political Will to Raise Retail Rates

to Reflect Current Wholesale Markets(Examples)

Tacoma Power 50% Approved

Seattle City Light 28% Approved

BPA 30% Proposed

Snohomish County PUD 35% Approved

Clark County PUD 20% Approved

Portland General Electric 27% Proposed

Idaho Power 32% 8% Approved24% Proposed

Pacificorp (Oregon) 21% Proposed

Utah Power & Light 19% Proposed

34.

Is There Long-Term Relief ?New Generation In California

Generation Scheduled for Summer 2001Project Date MW

California

Sutter 8/1 500

Los Medanos 7/1 500

Various 6/1 - 9/1 1,070

California Total 2,070

Southwest 6/1 – 7/1 1,690

Northwest 7/1 500

Summer 2001 Total 4,260

Approved/Under Construction6,273 MWIn Licensing 7,716 MWProposed 5,780 MW

Total 19,769 MW

California 2001-2004

35.

California ISO Load/Resource Forecast

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2000 2001 2002 2003 2004 2005 2006 2007

11,260 11,260 11,260 11,260 11,260 11,260 11,260 11,260

45,565 45,602 50,011 62,861 62,878 62,861 63,190 63,180Max Avail. Gen. Capacity

Max Import Capacity

49,209 50,188 51,463 53,602 54,462 55,306 56,177 57,928Load Forecast + OR

Source: California Independent Operator

36.

What’s Needed in the Near Term?

Reasonable long-term wholesale contracts– CPUC/legislative approval needed

– FERC enforcement of its “just and reasonable” standard

Reasonable retail price increases Assurance of recovery of past and future procurement

undercollections Very serious statewide (and West-wide) conservation

program Continue to foster development of new generation