1. Anatomy of California’s Electricity Crisis (How to Make a Bad Thing Worse)
Dr. John L. Jurewitz
Director, Regulatory Policy
Southern California Edison Company
Massachusetts Electric Restructuring Roundtable
Boston, Massachusetts
January 29, 2001

2. “That’s why I never walk in front.”

3. The Making of California’s Electricity Crisis
Restructuring
Rules
Market
Fundamentals
Market Rules
and
Market Power
Regulatory and Political
Inaction

4. Key Restructuring Rules
CPUC’s requirement that utilities buy all power through Power Exchange and ISO
Generation divestiture without buy-back contracts
Retail rate freeze
Over-exposure
to 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. Comparison of Forward Contracting/Hedging in Other Electricity Markets Regulatory Constraints in Forward Contracting in CAISO Market Was a Key Source of High Costs in Summer 2000
% Market Hedged
(long-term forward contracts,
self-owned generation)
Unhedged
Spot Market
CAISO
40-50%
50-60%
PJM
85-90%
10-15%
New England
80%
20%
Australia
90%
10%

7. PX SoCal Day-Ahead Electricity Prices
1000
800
600
$/MWh
200
400
Jun-99
Jul-99
Jul-00
Aug-99
Sep-99
Oct-99
Nov-99
Dec-99
Jan-00
Feb-00
Mar-00
Apr-00
May-00
Jun-00
Aug-00
Sep-00
Oct-00
Nov-00
Dec-00
Min/Max
Zonal Avg

8. California Market Prices have Skyrocketed in 2000 Comparison of Average Cal PX SP15 Monthly* Prices
$/MWh
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

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 months
Source: ISO Board material, January 2001

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

11. ISO Emergency Operations
Occurrences
Summer
1999
Summer
2000
Nov/Dec
2000
Jan
2001
Stage 1 Emergency
Operating reserve below 7%
Stage 2 Emergency
Operating reserves below 5%
Interruption of voluntary customers
Stage 3 Emergency
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

12. ISO Emergency Operations in 2000/2001
Blackouts
Stage 1
Stage 2
Stage 3
Blackouts 3
Emergency Stage 2 1
05/22/00
06/05/00
06/19/00
07/03/00
07/17/00
07/31/00
08/14/00
08/28/00
09/11/00
09/25/00
10/09/00
10/23/00
11/06/00
11/20/00
12/04/00
12/18/00
01/01/01
01/15/01
Rolling blackouts were initiated on 1/17, 1/18
Date is through 1/23/01

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)
Percentages

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

16. Summer/Fall 2000 Electricity Prices Disconnect From Natural Gas Prices$-
$100
$200
$300
$400
$500
$600
Jun-99
Jul-99
Aug-99
Sep-99
Oct-99
Nov-99
Dec-99
Jan-00
Feb-00
Mar-00
Apr-00
May-00
Jun-00
Jul-00
Aug-00
Sep-00
Oct-00
$60
SP15 On-Peak Avg $ MWH
$50
CA Border Avg $/MMBtu
$40
$/MWH
$/MMBtu
$30
$20
$10 $-

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

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

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 Energy Prices Exceeded Competitive Benchmark
200
150
100 50
-50 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
1998
1999
2000

22. California Independent System Operator
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
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)
(Difference between Maximum Output and Average Actual Output for High Priced Hours for June 2000, EPA data) MW
Duke
Southern
AES/Williams
Duke
Dynegy
Reliant
NP 15
SP 15

26. Capacity Outages or Withholding?
12,000
Forced
10,000
Scheduled
8,000
Ave. Daily Outages (MW)
6,000
4,000
2,000
Oct 1999
Oct 2000
Nov 1999
Nov 2000
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
How Can Rolling Blackouts Be Needed in Winter? ISO Load Conditions During Recent Blackout
Summer 2000 Peak
Load levels when rolling blackouts implemented
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)

28. Profits Reported by Enron’s Gas and Electric Trading Division
Generators and Marketers Reported Huge Profit Increases in the 3rd and 4th Quarters (Enron is one good example)
Profits Reported by Enron’s Gas and Electric Trading Division
$538 Million
$151 Million

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. Average Wholesale Electricity Prices (SCE)
Seven Months of Red Ink
Average Wholesale Electricity Prices (SCE)
2000
JUN
JUL
AUG
SEP
OCT
NOV
DEC 30 25
22.3 20
Costs
Absorbed
by SCE in
¢/kWh
(Approx.
$4.5 Billion
as of 12/00)
15.3 15
13.0
11.7
10.5
10.3 10
8.6
Existing
Customer
Rate
Freeze
6.2¢/kWh 5
Customer
Rates

31. Procurement Undercollections (SCE)
$Billions
$1,288
Million
$4.5
Billion .5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
$561
Million
$283
Million
$387
Million
$870
Million
$457
Million
$644
Million
June
July
Aug
Sept
Oct
Nov
Dec
Total

32. The Regulatory Bankruptcy Squeeze and 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 inaction
to regulate
wholesale prices
Imminent utility
bankruptcies
CPUC inaction
to raise retail prices
and assure recovery
of 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% Approved 24% Proposed
Pacificorp (Oregon) 21% Proposed
Utah Power & Light 19% Proposed

34. Is There Long-Term Relief ? New Generation In California
Approved/Under Construction 6,273 MW
In Licensing 7,716 MW
Proposed 5,780 MW
Total 19,769 MW
California
Generation Scheduled for Summer 2001
Project
Date MW
California
Sutter
8/1
500
Los Medanos
7/1
Various
6/1 - 9/1
1,070
California Total
2,070
Southwest
6/1 – 7/1
1,690
Northwest
Summer 2001 Total
4,260
Total Capacity in Southern California 9,412 MW
Capacity of So. Calif. plants approved 1,048 MW
Capacity of So. Calif. plants with licensing in progress 4,834 MW
Capacity of So. Calif. proposed projects 3,530 MW

35. California ISO Load/Resource Forecast
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
2000
2001
2002
2003
2004
2005
2006
2007
Max Import Capacity
11,260
11,260
11,260
11,260
11,260
11,260
11,260
11,260
Max Avail. Gen. Capacity
45,565
45,602
50,011
62,861
62,878
62,861
63,190
63,180
Load Forecast + OR
49,209
50,188
51,463
53,602
54,462
55,306
56,177
57,928
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