Transcript How to ensure that the State will face a high

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Lightening Strikes Twice:
California Faces a Real Risk of A
Second Power Crisis
Taking The Right Steps To Ensure A Powerful Future
Lake Tahoe Energy Conference
July 30, 2004
THE STATE IS AT RISK OF ANOTHER POWER CRISIS, BUT 5 KEY STEPS
WILL HELP TO ENSURE A SUSTAINABLE POWER MARKET
Action needs to be taken today to
prevent another energy crisis
5 steps that will ensure a long-term
sustainable market for power
• CEC estimates indicate that
1. New generation needs to be built today,
given the long lead time, and a
mechanism for market-based contracts
with utilities needs to be introduced
2. California should introduce mandatory
time-of-use metering for all classes of
customers
3. New transmission needs to be built and
facilitated through a expedited and
coordinated approval process by the
PUC, ISO, CEC, and FERC
4. A formal capacity market combined with
a mandatory planning reserve target
(e.g., 15-20%) needs to be in place by
2006
5. The State should re-introduce elements
of retail choice, providing an opportunity
for large consumers to shop for power
•
•
operating reserves could drop below
typical “emergency” levels if we have
a hot summer
Unfortunately, the CEC’s demand
estimates appear low relative to
trend and a “high demand case” (i.e.,
hot summer) may be as likely as a
1-in-5 occurrence
Taking into account realistic levels of
future demand, operating reserves
could be extremely tight by 2006 –
as low as 5.8% (in a 1-in-5 year
demand case)
1
THE STATE’S ENERGY AGENCIES
PROJECT A NEAR-TERM RISK OF LOW
RESERVE MARGINS IN A HOT YEAR
CEC ESTIMATES
Demand
1-in-2 year (average)
Projected California state operating reserve margin*
Percent
1-in-10 year (hot)
Reserve margins
consistently drop
beginning in 2006
13.2
12.7
11.6
11.6
6.7
11.1
7% target =
Stage One
emergency
level
6.2
5.2
5.1
4.7
5% target =
Stage Two
emergency
level
August 2004
August 2005
August 2006
August 2007
August 2008
* Operating reserve margin calculated as (Available Supply – Peak Demand)/(Peak Demand)
Source: California Energy Commission (July 8, 2004 update to June 24, 2004 report)
2
ENERGY AGENCY FORECASTS OF FUTURE DEMAND ARE
OPTIMISTIC COMPARED TO ALTERNATIVE PROJECTIONS
Peak demand (average weather), after conservation
GW
ESTIMATES OF 1-IN-2
YEAR PEAK DEMAND
Different models
of demand
65
Regression model*
CEC-May 2003
Trend**
CEC-July 2004
60
55
50
For 2006, the CEC’s
estimate is ~1,000 MW
below trend-line
estimates and ~2,100
MW below a regression
model estimate
45
40
35
30
1982
1985
1988
1991
1994
1997
2000
2003
2006
* Regression projection based on historic weather, historic GSP, current GSP projections (5.6%), and average weather
** Based on historic CAGR for peak demand growth before including conservation (underlying growth of 1.88% for 1983-2003) and
adjusted for expected 2004-2008 conservation in California (provided by CEC)
Source: California Energy Commission; Bureau of Economic Analysis; Economy.com
3
THE POTENTIAL FOR A “HIGH DEMAND CASE” IS AS HIGH AS
A 1-IN-5 EVENT, RATHER THAN JUST A 1-IN-10 EVENT
Distribution of average statewide peak temperature
Number of years observed over past 40 years
1 in 5
101°
Potential 2006 peak demand*
GW
• 8 out of the last 40 years
1 in 10
101.5°
6
+3.4%
59,501
59,121
57,541
5
4
+2.7%
(or 20%), peak
temperatures have been
101 degrees or higher
• There is little demand
difference, though,
between 101 degrees
and 101.5 degrees
7
6
BASED ON
HISTORIC DATA
4
3
1
1
1
1
93- 94- 95- 96- 97- 98- 99- 100- 101- 102- 10394 95 96 97 98 99 100 101 102 103 104
Temperature range
Degrees Fahrenheit
* Based on BAEF regression-model estimates of 2006 peak demand
Source: California Energy Commission
1 in 2
demand
1 in 5
demand
1 in 10
demand
4
TAKING INTO ACCOUNT A DIFFERENT VIEW
OF FUTURE DEMAND, THE RISK OF
SHORTAGES IS EVEN STARKER
BAEF ESTIMATE
Demand
1 in 2 year
Projected California state operating reserve margin*
Percent
• 750 MW of new capacity will
•
9.9
8.7
6.9
be needed before 2006 to
maintain a 7% operating
reserve under a 1-in-5 case**
Given the lead time for new
construction, permitting and
demand side management
needs to begin today
6.5
5.8
2.7
August 2006
7% target =
Stage One
emergency level
5.4
3.8
August 2005
1 in 5 year
August 2007
5% target =
Stage Two
emergency level
August 2008
* Operating reserve margin calculated as (Available Supply – Peak Demand)/(Peak Demand)
** As much as 2,000 MW would be required to maintain a planning reserve margin of 15% for the 1-in-5 case,
which would equate to a 1-in-2 operating reserve of 12.1% and a 1-in-5 operating reserve of 9.1%
Source: California Energy Commission (July 8, 2004 update to June 24, 2004 report); McKinsey analysis
5
THE STATE IS AT RISK OF ANOTHER POWER CRISIS, BUT 5 KEY STEPS
WILL HELP TO ENSURE A SUSTAINABLE POWER MARKET
Action needs to be taken today to
prevent another energy crisis
5 steps that will ensure a long-term
sustainable market for power
• CEC estimates indicate that
1. New generation needs to be built today,
given the long lead time, and a
mechanism for market-based contracts
with utilities needs to be introduced
2. California should introduce mandatory
time-of-use metering for all classes of
customers
3. New transmission needs to be built and
facilitated through a expedited and
coordinated approval process by the
PUC, ISO, CEC, and FERC
4. A formal capacity market combined with
a mandatory planning reserve target
(e.g., 15-20%) needs to be in place by
2006
5. The State should re-introduce elements
of retail choice, providing an opportunity
for large consumers to shop for power
•
•
operating reserves could drop below
typical “emergency” levels if we have
a hot summer
Unfortunately, the CEC’s demand
estimates appear low relative to
trend and a “high demand case” (i.e.,
hot summer) may be as likely as a
1-in-5 occurrence
Taking into account realistic levels of
future demand, operating reserves
could be extremely tight by 2006 –
as low as 5.8% (in a 1-in-5 year
demand case)
6
MARKET-BASED LONG-TERM CONTRACTS SHOULD BE ADOPTED
TO FACILITATE GENERATION CONSTRUCTION
How contracts would work…
Who will build:
• Competitive RFP process allowing
utility affiliates or merchant
generators to bid
Who will buy:
• In the near term, utilities will be
responsible for signing contracts with
the winning bidders, with guaranteed
rate recovery of contract costs
How will contracts be priced:
• Will be market based contracts, with
an ROE on capital investment and
pass through of variable generation
costs
– Capacity payment will provide
return on capital investment
– Energy payment will be based on a
specified plant efficiency and
indexed to natural gas prices
1
… and what market-based prices would
look like under the contracts
California cost of generation
Dollars per MWh
ILLUSTRATIVE
100
90
80
DWR contract price
(2003 average)
70
Electricity price
under new marketbased contracts*
60
50
40
30
20
Capacity payment**
10
0
2003
2005
2007
2009
* All-in wholesale electricity price including capacity payment, gas price, energy costs
** Assumes 15% ROE, 8% cost of debt, $450/kW CCGT investment cost, 10-year return period
Source: California DWR; NYMEX; McKinsey analysis
2011
7
THERE ARE A NUMBER OF SOURCES OF CAPACITY THAT COULD
BE BROUGHT ON LINE BY 2006 IF THE STATE ACTS NOW
California capacity
Gigawatts
Plants that have been
mothballed, but could
be brought back on line
Plants partly constructed
, but incomplete due to
financing or lack of
contracts*
Estimated time to online
Months
1
Steps to bring
capacity online
• Relaxed environmental
restrictions
• Short term contracts
• E.g., Etiwanda
3-6
0.5
• Mid-long term contracts
(5-10 years)
• E.g., Metcalf, Pico
8-12**
3.7
• Long term contracts
Plants with permits
from the CPUC but not
under construction
6.5
(5-10 years)
12-18 • Extended permit
shelf life
• E.g., Tesla, San Joaquin
To ensure new capacity is brought on line by the summer of
2006, the CPUC must act now to ensure that long-term contracts
are available to generators to complete existing projects
* Includes projects under construction delayed more than 24 months from initial planned online date
** Assumes most of these plants are 40% complete (as of July 2004)
Source: California Energy Commission; McKinsey analysis
8
2
CALIFORNIA LAGS OTHER STATES IN ITS DEMAND SAVINGS
FROM LOAD MANAGEMENT PROGRAMS
Florida
California
Top 25 states in peak DSM savings from energy efficiency
2002 annual peak savings from energy efficiency, MW
Even though California is a leader
in energy efficiency, there is room
to improve by ~900MW
1,691
970
774 646
593 558 510 468
274 269 264 244 214 208 205 202 200 183
120 103 98
FL MN CA GA NC NE ND PA CO OH MD IA
DC OK NY AL VA AR
IL
97
WI AZ SD
94
75
67
IN MO ME
Top 25 states in load management DSM savings
2002 annual load management savings as percent of (Savings + Peak), MW
17.4
If California achieved levels of Florida, It
could see a reduction of demand by
~2 GW in load management alone
7.3 6.6
5.9 5.6
4.7 4.6 3.7 3.7
3.4 3.3 3.1 2.7 2.6
2.3 2.3 2.1 2.0 1.7 1.6 1.4 1.4 1.2
1.1 1.0
NE SD MN DC AR LA CO FL MD ME WY OK VT PA
Note: Includes only utilities reporting DSM activities
Source: EIA; state disclosures
IA
GA NC UT AK CA AL AZ VA DE NY
9
TIME OF USE PRICING IN CALIFORNIA IS A DEMAND SIDE
MANAGEMENT PROGRAM THAT COULD PAY FOR ITSELF
2
Californians will benefit in many ways from time-of-use pricing
$ Billions
4.8-5.1
1.0-1.7
Benefits of time-of-use pricing
2.7-3.8
• Ratepayers would
save approximately $270 million$380 million annually
• Fewer new peaker plants needed
• Gas demand reduced
• Environmental benefits
10-year
savings from
demand
response (load
shifting and
curtailing*)
Cost of
program**
Total 10-year
savings
(NOx reduction, water conservation,
etc.)
* Assumes real-time prices will cause large C&I customers to shift 4%-6% and curtail 1%-2% of their load, and time-of-use prices will cause
small C&I and residential customers to shift 5%-7% and curtail 9%-11% of their load
** Includes one-time real-time meter equipment capital cost and incremental maintenance costs for the remaining 70% of large C&I customers
in California without meters and one-time interval meter equipment capital cost for 50% of small C&I and residential customers
Source: 1999 CalPX hourly data; interviews; McKinsey analysis
10
MULTIPLE AGENCIES HAVE JURISDICTION OVER TRANSMISSION
PLANS, SLOWING SITING AND CONSTRUCTION
3
Shared
Duplicate
Participating
transmission
owners
CAISO
CPUC
Source: CEC reports
Required approval
Evaluation criteria
Typical time
• System impact
• Scope and cost of transmission
• 30-60 days
study
• Facilities studies
upgrades necessary for
interconnection
• System impact
• Verifies PTO analysis
study and facilities
studies
• Integrated grid
assessment
• Economic and reliability impact on
• Certificate of Public
• Economic and reliability impact on
Convenience and
Necessity (above
200kV)
• 60-90 days
overall grid
overall grid
• Environmental, societal and
aesthetic factors
• 12-30
months
11
4
OTHER STATES WITH RESERVE TARGETS AND CAPACITY MARKETS
HAVE SEEN STABLE CAPACITY AND LOW VOLATILITY
Wholesale electricity price volatility*
Percent
Incentive
payments
for capacity
Argentina
34
PJM
Mandated
quantity of
reserves
NYISO
ISO-NE
Alberta
No market
constraints
California
(2001)
2004 summer reserve margin**
Percent
49
40
20
26
18
25
30
16
71
125
2
* Measured by standard deviation divided by average of monthly wholesale prices. Later of April 1998 or market open through June 2004
(except California, through Jan 2001)
** Operating reserve margin calculated as (Available Supply – Peak Demand)/(Peak Demand)
Source: California PX; Alberta Power Pool; PJM ISO; CAMMESA; New England ISO; New York ISO; Platt’s PowerDat
12
RETAIL CHOICE IS SOUGHT AFTER MOST BY LARGE CONSUMERS,
BUT BENEFITS ALL CUSTOMER CLASSES
5
Case example: United Kingdom
In the UK, large consumers have
been the most frequent users of
competitive suppliers
All consumers have seen lower
electricity bills with market
restructuring and retail choice
Estimated savings per customer**
Percent
Not
switched
20
Industrial
34.1
Switched
80
30
Commercial
Not
switched
33.1
Switched
70
Switched
20
30.1
Residential
80
Not
switched
* Estimated savings in customer bills since privatization/deregulation adjusting for the effects of inflation
Source: EA Electricity Industry Review; EU-EPNG M&A Database, UK Power Market PD Dec. 2001; OFGEM
13
IMPLEMENTING A CORE/NON-CORE MARKET STRUCTURE IN
CALIFORNIA WILL REQUIRE CAREFUL PLANNING
Market power
Resource
adequacy
Switching
behavior
DWR cost
overhang
Environmental
issues
Concerns
Key success factors
• Controlling the market influence
• Strict market oversight committee and
of a dominant player or players
• Ensuring sufficient new capacity
5
penalties
• Sufficient generation capacity to limit gaming
• Capacity market mechanism to provide
built to serve core and non-core
customers
liquidity for trading capacity reserves
• Reserve margin targets (15-20%) required
for utility and non-utility suppliers
• Lead time required for long-term
• Reasonable notice period required by non-
planning by utilities
core customers who plan to switch linked
to the time to build new capacity
• Significant stranded costs from
• Equitable sharing of costs between core
DWR long-term power contract
obligations
and non-core market customers, with no
ability to avoid costs by shifting to a new
supplier
• Mixed results for market
mechanisms to manage
emissions
• Renewable portfolio standard
• Credits for reduced emissions and cleaner
burning technologies
14