Lightening Strikes Twice: California Faces a Real Risk of A Second Power Crisis

Lake Tahoe Energy Conference

July 30, 2004

CONFIDENTIAL

This report is solely for the use of client personnel. No part of it may be circulated, quoted, or reproduced for distribution outside the client organization without prior written approval from McKinsey & Company. This material was used by McKinsey & Company during an oral presentation; it is not a complete record of the discussion.

Taking The Right Steps To Ensure A Powerful Future

2

5 steps that will ensure a long-term sustainable market for power

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

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

• CEC estimates indicate that 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)

3

THE STATE’S ENERGY AGENCIES PROJECT A NEAR-TERM RISK OF LOW RESERVE MARGINS IN A HOT YEAR

*Operating reserve margin calculated as (Available Supply – Peak Demand)/(Peak Demand)Source: California Energy Commission (July 8, 2004 update to June 24, 2004 report)

1-in-10 year (hot)

1-in-2 year (average)

CEC ESTIMATES

August 2005 August 2006 August 2007 August 2008

Projected California state operating reserve margin*Percent

11.6

13.212.7

11.611.1

6.7

5.24.7

6.25.1

August 2004

7% target = Stage One emergency level

5% target = Stage Two emergency level

Reserve margins consistently drop beginning in 2006

Demand

4

ENERGY AGENCY FORECASTS OF FUTURE DEMAND ARE OPTIMISTIC COMPARED TO ALTERNATIVE PROJECTIONS

ESTIMATES OF 1-IN-2YEAR PEAK DEMAND

30

35

40

45

50

55

60

65

1982 1985 1988 1991 1994 1997 2000 2003 2006

Peak demand (average weather), after conservationGW

*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

Regression model*

CEC-July 2004

Trend**

Different models of demand

CEC-May 2003

For 2006, the CEC’s estimate is ~1,000 MW below trend-line estimates and ~2,100 MW below a regression model estimate

5

1

3

4 4

6

1

5

7

6

1 1

93-94

94-95

95-96

96-97

97-98

98-99

99-100

100-101

101-102

102-103

103-104

THE POTENTIAL FOR A “HIGH DEMAND CASE” IS AS HIGH AS A 1-IN-5 EVENT, RATHER THAN JUST A 1-IN-10 EVENT

1 in 2 demand

1 in 5 demand

1 in 10 demand

57,541

59,12159,501

Distribution of average statewide peak temperatureNumber of years observed over past 40 years

*Based on BAEF regression-model estimates of 2006 peak demand

Source: California Energy Commission

Temperature rangeDegrees Fahrenheit

• 8 out of the last 40 years (or 20%), peak temperatures have been 101 degrees or higher

• There is little demand difference, though, between 101 degrees and 101.5 degrees

1 in 10101.5°

1 in 5101°

Potential 2006 peak demand*GW

BASED ONHISTORIC DATA

+3.4%+2.7%

6

9.9

8.7

6.5

5.45.8

3.8

2.7

6.9

TAKING INTO ACCOUNT A DIFFERENT VIEW OF FUTURE DEMAND, THE RISK OF SHORTAGES IS EVEN STARKER

*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

1 in 5 year

1 in 2 year

BAEF ESTIMATE

7% target = Stage One emergency level

• 750 MW of new capacity will 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

August 2005 August 2006 August 2007 August 2008

Projected California state operating reserve margin*Percent

5% target = Stage Two emergency level

Demand

7

THE STATE IS AT RISK OF ANOTHER POWER CRISIS, BUT 5 KEY STEPS WILL HELP TO ENSURE A SUSTAINABLE POWER MARKET

5 steps that will ensure a long-term sustainable market for power

Action needs to be taken today to prevent another energy crisis

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

• CEC estimates indicate that 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)

8

0

10

20

30

40

50

60

70

80

90

100

2003 2005 2007 2009 2011

MARKET-BASED LONG-TERM CONTRACTS SHOULD BE ADOPTED TO FACILITATE GENERATION CONSTRUCTION

… and what market-based prices would look like under the contracts

DWR contract price (2003 average)

California cost of generationDollars per MWh

Capacity payment**

Electricity price under new market-based contracts*

ILLUSTRATIVE

* 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

How contracts would work…

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

Who will build:• Competitive RFP process allowing

utility affiliates or merchant generators to bid

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

9

THERE ARE A NUMBER OF SOURCES OF CAPACITY THAT COULD BE BROUGHT ON LINE BY 2006 IF THE STATE ACTS NOW

*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

Plants partly constructed , but incomplete due to financing or lack of contracts*

Plants with permits from the CPUC but not under construction

0.5

3.7

6.5

California capacityGigawatts

Estimated time to onlineMonths

Plants that have been mothballed, but could be brought back on line

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

Steps to bring capacity online

• Relaxed environmental restrictions

• Short term contracts • E.g., Etiwanda

• Mid-long term contracts (5-10 years)

• E.g., Metcalf, Pico

• Long term contracts (5-10 years)

• Extended permit shelf life

• E.g., Tesla, San Joaquin

3-6

8-12**

12-18

1

10

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

7.3

17.4

NE SD MN DC AR LA CO FL MD ME WY OK VT PA IA GA NC UT AK CA AL AZ VA DE NY

CALIFORNIA LAGS OTHER STATES IN ITS DEMAND SAVINGS FROM LOAD MANAGEMENT PROGRAMS

Note:Includes only utilities reporting DSM activities

Source:EIA; state disclosures

Top 25 states in load management DSM savings2002 annual load management savings as percent of (Savings + Peak), MW

774 646 593 558 510 468274 269 264 244 214 208 205 202 200 183 120 103 98 97 94 75 67

970

1,691

FL MN CA GA NC NE ND PA CO OH MD IA DC OK NY AL VA AR IL WI AZ SD IN MO ME

Top 25 states in peak DSM savings from energy efficiency 2002 annual peak savings from energy efficiency, MW

If California achieved levels of Florida, It could see a reduction of demand by ~2 GW in load management alone

Even though California is a leader in energy efficiency, there is room to improve by ~900MW

Florida

California

2

11

TIME OF USE PRICING IN CALIFORNIA IS A DEMAND SIDE MANAGEMENT PROGRAM THAT COULD PAY FOR ITSELF

*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

Benefits of time-of-use pricing

• Ratepayers would save approximately $270 million-$380 million annually

• Fewer new peaker plants needed

• Gas demand reduced

• Environmental benefits (NOx reduction, water conservation, etc.)10-year

savings from demand response (load shifting and curtailing*)

Total 10-year savings

Cost of program**

4.8-5.1

1.0-1.72.7-3.8

Californians will benefit in many ways from time-of-use pricing$ Billions

2

12

MULTIPLE AGENCIES HAVE JURISDICTION OVER TRANSMISSION PLANS, SLOWING SITING AND CONSTRUCTION

Source: CEC reports

Required approval

Participating transmission owners

• System impact study

• Facilities studies

Typical time

• 30-60 days

CAISO

CPUC • Certificate of Public Convenience and Necessity (above 200kV)

Evaluation criteria

• Scope and cost of transmission upgrades necessary for interconnection

Shared

Duplicate

• Economic and reliability impact on overall grid

• Environmental, societal and aesthetic factors

• System impact study and facilities studies

• Integrated grid assessment

• Verifies PTO analysis

• Economic and reliability impact on overall grid

• 60-90 days

• 12-30 months

3

13

OTHER STATES WITH RESERVE TARGETS AND CAPACITY MARKETS HAVE SEEN STABLE CAPACITY AND LOW VOLATILITY

*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

Wholesale electricity price volatility*Percent

Mandated quantity of

reserves

Incentive payments

for capacity

No market constraints

2

16

25

18

20

49

2004 summer reserve margin**Percent

125

71

30

26

40

34

California (2001)

Alberta

ISO-NE

NYISO

PJM

Argentina

4

14

70

30

80

20

RETAIL CHOICE IS SOUGHT AFTER MOST BY LARGE CONSUMERS, BUT BENEFITS ALL CUSTOMER CLASSES

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

Case example: United Kingdom

Industrial

Switched

Not switched

Commercial

Switched

Not switched

20

80Residential

Switched

Not switched

Estimated savings per customer**Percent

30.1

33.1

34.1

*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

5

15

IMPLEMENTING A CORE/NON-CORE MARKET STRUCTURE IN CALIFORNIA WILL REQUIRE CAREFUL PLANNING

Concerns

• Controlling the market influence

of a dominant player or players

Key success factors

• Strict market oversight committee and penalties

• Sufficient generation capacity to limit gamingMarket power

Resource adequacy

Environmental issues

Switching behavior

• Ensuring sufficient new capacity built to serve core and non-core customers

• Capacity market mechanism to provide liquidity for trading capacity reserves

• Reserve margin targets (15-20%) required for utility and non-utility suppliers

• Lead time required for long-term planning by utilities

• Reasonable notice period required by non-core customers who plan to switch linked to the time to build new capacity

DWR cost overhang

• Significant stranded costs from DWR long-term power contract obligations

• Equitable sharing of costs between core 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

5