Transcript Anatomy of California’s Electricity Crisis

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
“That’s why I never walk in front.”
2.
The Making of California’s Electricity Crisis
Restructuring
Rules
Market
Fundamentals
Market Rules
and
Market Power
Regulatory
and Political
Inaction
3.
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
4.
Why Did CPUC Initially Insist that Utilities Buy
Everything Through the
PX and ISO Spot Markets?

Wanted transparent pricing to assure against selfdealing

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
5.
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, Unhedged
self-owned generation)
Spot Market
CAISO
40-50%
50-60%
PJM
85-90%
10-15%
New England
80%
20%
Australia
90%
10%
6.
Min/Max
Dec-00
Nov-00
Oct-00
Sep-00
Aug-00
Jul-00
Jun-00
May-00
Apr-00
Mar-00
Feb-00
Jan-00
Dec-99
Nov-99
Oct-99
Sep-99
Aug-99
Jul-99
Jun-99
$/MWh
PX SoCal Day-Ahead Electricity Prices
1000
800
600
400
200
0
Zonal Avg
7.
California Market Prices have Skyrocketed in 2000
Comparison of Average Cal PX SP15 Monthly* Prices
250
1998
1999
2000
$/MWh
200
150
100
50
0
Jan

Feb Mar
Apr May Jun
Jul
Aug
Sep
Oct
Nov
Dec
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
8.
Comparison of California Electricity Costs
28.0
30
$ (Billion) )
25
20
15
10
7.4
5.6
5
0
1998


1999
2000
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
9.
Cumulative Cost of California Electricity
1999 and 2000 Cost of Electricity
30
$ (Billions)
25
2000
1999
20
15
10
5
0
Jan

Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
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
10.
ISO Emergency Operations
Occurrences
Summer
1999

Stage 1 Emergency
Summer Nov/Dec
2000
2000
Jan
2001
3
32
11
12
1
17
9
12
0
0
1
10
» 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
11.


01/15/01
01/01/01
12/18/00
12/04/00
11/20/00
11/06/00
10/23/00
10/09/00
09/25/00
3
09/11/00
Blackouts
08/28/00
08/14/00
07/31/00
07/17/00
07/03/00
06/19/00
06/05/00
05/22/00
Emergency Stage
ISO Emergency Operations in 2000/2001
Stage 1
Stage 2
Stage 3
Blackouts
2
1
Rolling blackouts were initiated on 1/17, 1/18
Date is through 1/23/01
12.
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
13.
SCE Sales Growth Rates
(Weather Adjusted)
Growth Rate
Percentages
5
4
3
2
1
0
-1
-2
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
14.
a
16 n
-J
a
30 n
-J
a
13 n
-F
e
27 b
-F
e
12 b
-M
a
26 r
-M
a
09 r
-A
p
23 r
-A
p
07 r
-M
a
21 y
-M
a
04 y
-J
u
18 n
-J
un
02
-J
u
16 l
-J
u
30 l
-J
u
13 l
-A
u
27 g
-A
u
10 g
-S
e
24 p
-S
ep
08
-O
c
22 t
-O
c
05 t
-N
o
19 v
-N
o
03 v
-D
e
17 c
-D
e
31 c
-D
ec
02
-J
$/MMBtu
Natural Gas Prices in 2000
$60
$50
$40
$30
$20
$10
$-

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
15.
Summer/Fall 2000 Electricity Prices
Disconnect From Natural Gas Prices
$600
$60
SP15 On-Peak Avg $ MWH
CA Border Avg $/MMBtu
$50
$400
$40
$300
$30
$200
$20
$100
$10
$-
$-
$/MMBtu
$/MWH
$500
16.
800
70
700
60
600
50
500
40
400
30
300
200
20
100
10
$/MMBtu
$/MWh
Recent Electricity and Gas Prices
0
PX Avg Price
ISO Avg Price
1/20
1/17
1/14
1/11
1/8
1/5
1/2
12/30
12/27
12/24
12/21
12/18
12/15
12/12
12/4
0
Topock Gas Price
• 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
17.
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
18.
High Prices Persist During Modest Loads
(Sunday)
1 9 9 9 a n d 2 0 0 0 P ric e s
450
400
7 / 3 0 / 0 0 S P 1 5 P ric e
350
300
$ /M W h
IS O L o a d
MW h
40000
38000
7 / 1 1 / 9 9 S P 1 5 P ric e
36000
7 / 3 0 / 0 0 IS O L o a d
34000
7 / 1 1 / 9 9 IS O L o a d
32000
250
30000
200
28000
150
26000
100
24000
50
22000
0
20000
1


2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Markets do not produce competitive prices
Under similar medium load conditions, 2000 prices have increased 700% over
1999 levels
19.
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
20.
Percent by Which Actual Energy
Prices Exceeded Competitive Benchmark
Percent
200
150
100
50
0
-50
6
7
8
9 10 11 12 1
1998
2
3
4
5
6
7
1999
8
9 10 11 12 1
2
3
4
5
6
2000
21.
California Independent
System Operator
California Market Produced Two Years of Moderate Prices and Low
Mark Up Over Competitive Benchmark
0.70
Costs Above Baseline Incurred During Hours of Scarcity
Market Power (No Scarcity)
$140
Competative Baseline Cost
$120
Market Power Index
0.60
0.50
$100
0.40
$80
0.30
$60
0.20
Market Power Index
$160
$40
0.10
0.00
Aug-00
Jun-00
Apr-00
Feb-00
Dec-99
Oct-99
Aug-99
Jun-99
Apr-99
Feb-99
Dec-98
Oct-98
Apr-98
$0
Aug-98
$20
Jun-98
Avg. Energy Costs (PX + Real Time, $/MWh)
$180

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.
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
23.
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
24.
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)
1,500
MW
1,000
500
0
Duke
Southern
NP 15
AES/Williams
Duke
Dynegy
Reliant
SP 15
25.
Capacity Outages or Withholding?
12,000
Ave. Daily Outages (MW)
10,000
Forced
Scheduled
8,000
6,000
4,000
2,000
0
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.
How Can Rolling Blackouts Be Needed in Winter?
ISO Load Conditions During Recent Blackout
ISO Actual Load
45000
08/16/2000
01/17/2001
40000
Summer 2000 Peak
35000
MWh
Load levels when rolling
blackouts implemented
30000
25000
20000
23
21
19
17
15
13
11
9
7
5
3
1
Hour


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)
27.
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
600
$538 Million
500
400
300
200
$151 Million
100
0
4th Quarter
1999
4th Quarter
2000
28.
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
29.
Seven Months of Red Ink
Average Wholesale Electricity Prices (SCE)
2000
30
JUN
JUL
AUG
SEP
OCT
NOV
DEC
25
22.3
20
15.3
15
11.7
13.0
10.5
10
Existing
Customer
Rate
5
Freeze
10.3
8.6
Costs
Absorbed
by SCE in
¢/kWh
(Approx.
$4.5 Billion
as of 12/00)
6.2¢/kWh
Customer
Rates
0
30.
Procurement Undercollections (SCE)
$Billions
$1,288
Million
$4.5
Billion
Dec
Total
4.5
4.0
$561
Million
3.5
3.0
2.5
$870
Million
2.0
1.5
1.0
$644
Million
$387
Million
$283
Million
$457
Million
.5
0
June
July
Aug
Sept
Oct
Nov
31.
The Regulatory Bankruptcy Squeeze
and Its Consequences
FERC inaction
to regulate
wholesale prices
Imminent utility
bankruptcies
CPUC inaction
to raise retail prices
and assure recovery
of undercollections
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
32.
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
33.
Is There Long-Term Relief ?
New Generation In California
California 2001-2004
Approved/Under Construction
6,273 MW
In Licensing
7,716 MW
Proposed
5,780 MW
Total
19,769 MW
Generation Scheduled for Summer 2001
Project
Date
MW
Sutter
8/1
500
Los Medanos
7/1
500
6/1 - 9/1
1,070
California
Various
California Total
2,070
Southwest
6/1 – 7/1
1,690
Northwest
7/1
500
Summer 2001 Total
4,260
34.
California ISO Load/Resource Forecast
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
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
35.
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
36.