CONFIDENTIAL This report is solely for the use

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 Mc. Kinsey & Company. This material was used by Mc. Kinsey & Company during an oral presentation; it is not a complete record of the discussion. 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 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 7% target = Stage One emergency level 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 Regression model* CEC-May 2003 Trend** CEC-July 2004 For 2006, the CEC’s estimate is ~1, 000 MW below trend-line estimates and ~2, 100 MW below a regression model estimate *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° 1 in 10 101. 5° BASED ON HISTORIC DATA Potential 2006 peak demand* GW • 8 out of the last 40 years • +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 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 +3. 4% 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 • 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 1 in 5 year 7% target = Stage One emergency level 5% target = Stage Two emergency level August 2005 August 2006 August 2007 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); Mc. Kinsey 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 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 DWR contract price (2003 average) Electricity price under new marketbased contracts* Capacity payment** * All-in wholesale electricity price including capacity payment, gas price, energy costs ** Assumes 15% ROE, 8% cost of debt, $450/k. W CCGT investment cost, 10 -year return period Source: California DWR; NYMEX; Mc. Kinsey analysis 7

THERE 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* Plants with permits from the CPUC but not under construction Estimated time to online Months 1 Steps to bring capacity online • Relaxed environmental 3 -6 • • restrictions Short term contracts E. g. , Etiwanda • Mid-long term contracts 8 -12** • (5 -10 years) E. g. , Metcalf, Pico • Long term contracts 12 -18 • • (5 -10 years) 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; Mc. Kinsey analysis 8

CALIFORNIA LAGS OTHER STATES IN ITS DEMAND SAVINGS FROM LOAD MANAGEMENT PROGRAMS 2 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 ~900 MW Top 25 states in load management DSM savings 2002 annual load management savings as percent of (Savings + Peak), MW If California achieved levels of Florida, It could see a reduction of demand by ~2 GW in load management alone Note: Includes only utilities reporting DSM activities Source: EIA; state disclosures 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 Cal. PX hourly data; interviews; Mc. Kinsey analysis 10

MULTIPLE AGENCIES HAVE JURISDICTION OVER TRANSMISSION PLANS, SLOWING SITING AND CONSTRUCTION 3 Shared Duplicate Participating transmission owners CAISO Required approval Evaluation criteria Typical time • System impact • Scope and cost of transmission • 30 -60 days • • System impact • CPUC Source: CEC reports study Facilities study and facilities studies Integrated grid assessment • Certificate of Public Convenience and Necessity (above 200 k. V) upgrades necessary for interconnection • Verifies PTO analysis • Economic and reliability impact on overall grid • Economic and reliability impact on • overall grid Environmental, societal and aesthetic factors • 60 -90 days • 12 -30 months 11

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 NYISO ISO-NE Alberta No market constraints California (2001) 2004 summer reserve margin** Percent 34 PJM Mandated quantity of reserves 4 40 26 30 71 125 *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 Power. Dat 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 Industrial Switched Not switched Commercial Switched Residential 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 • 5 penalties Sufficient generation capacity to limit gaming • Ensuring sufficient new capacity • 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 nonplanning 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