Anatomy of California’s Electricity Crisis (How to Make a Bad Thing Worse)
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Transcript of Anatomy of California’s Electricity Crisis (How to Make a Bad Thing Worse)
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