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

1. 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. 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

2. 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 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) • 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 • California should introduce mandatory time-of-use metering for all classes of customers • New transmission needs to be built and facilitated through a expedited and coordinated approval process by the PUC, ISO, CEC, and FERC • A formal capacity market combined with a mandatory planning reserve target (e.g., 15-20%) needs to be in place by 2006 • The State should re-introduce elements of retail choice, providing an opportunity for large consumers to shop for power

3. 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)

4. ENERGY AGENCY FORECASTS OF FUTURE DEMAND ARE OPTIMISTIC COMPARED TO ALTERNATIVE PROJECTIONS • ESTIMATES OF 1-IN-2 • YEAR PEAK DEMAND Peak demand (average weather), after conservation GW 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

5. THE POTENTIAL FOR A “HIGH DEMAND CASE” IS AS HIGH AS A 1-IN-5 EVENT, RATHER THAN JUST A 1-IN-10 EVENT • BASED ON • HISTORIC DATA • Distribution of average statewide peak temperature • Number of years observed over past 40 years • Potential 2006 peak demand* • GW • 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 +2.7% +3.4% • 1 in 5 • 101° • 1 in 10 • 101.5° • 1 in 2 demand • 1 in 5 demand • 1 in 10 demand • Temperature range • Degrees Fahrenheit * Based on BAEF regression-model estimates of 2006 peak demand Source: California Energy Commission

6. 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 • 1 in 5 year • 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 • 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); McKinsey analysis

7. 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 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) • 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 • California should introduce mandatory time-of-use metering for all classes of customers • New transmission needs to be built and facilitated through a expedited and coordinated approval process by the PUC, ISO, CEC, and FERC • A formal capacity market combined with a mandatory planning reserve target (e.g., 15-20%) needs to be in place by 2006 • The State should re-introduce elements of retail choice, providing an opportunity for large consumers to shop for power

8. 1 MARKET-BASED LONG-TERM CONTRACTS SHOULD BE ADOPTED TO FACILITATE GENERATION CONSTRUCTION • … and what market-based prices would look like under the contracts • How contracts would work… • Who will build: • Competitive RFP process allowing utility affiliates or merchant generators to bid • California cost of generation • Dollars per MWh • ILLUSTRATIVE • 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 • DWR contract price (2003 average) • Electricity price under new market-based contracts* • 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 • Capacity payment** * 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

9. 1 • California capacity • Gigawatts • Estimated time to online • Months THERE ARE A NUMBER OF SOURCES OF CAPACITY THAT COULD BE BROUGHT ON LINE BY 2006 IF THE STATE ACTS NOW • Steps to bring capacity online • Relaxed environmental restrictions • Short term contracts • E.g., Etiwanda • Plants that have been mothballed, but could be brought back on line 3-6 • Plants partly constructed , but incomplete due to financing or lack of contracts* • Mid-long term contracts (5-10 years) • E.g., Metcalf, Pico 8-12** • Long term contracts (5-10 years) • Extended permit shelf life • E.g., Tesla, San Joaquin • Plants with permits from the CPUC but not under construction 12-18 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

10. 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 • 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

11. 2 TIME OF USE PRICING IN CALIFORNIA IS A DEMAND SIDE MANAGEMENT PROGRAM THAT COULD PAY FOR ITSELF • Californians will benefit in many ways from time-of-use pricing • $ Billions • 4.8-5.1 • 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.) • 1.0-1.7 • 2.7-3.8 • 10-year savings from demand response (load shifting and curtailing*) • Cost of program** • Total 10-year savings * 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

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

13. 4 34 40 26 30 71 125 OTHER STATES WITH RESERVE TARGETS AND CAPACITY MARKETS HAVE SEEN STABLE CAPACITY AND LOW VOLATILITY Wholesale electricity price volatility* Percent 2004 summer reserve margin** Percent Incentive payments for capacity Argentina PJM Mandated quantity of reserves NYISO ISO-NE Alberta No market constraints California (2001) * 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

14. 5 RETAIL CHOICE IS SOUGHT AFTER MOST BY LARGE CONSUMERS, BUT BENEFITS ALL CUSTOMER CLASSES 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 • 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

15. 5 IMPLEMENTING A CORE/NON-CORE MARKET STRUCTURE IN CALIFORNIA WILL REQUIRE CAREFUL PLANNING • Concerns • Key success factors • Controlling the market influence of a dominant player or players • Strict market oversight committee and penalties • Sufficient generation capacity to limit gaming • Market power • Resource adequacy • 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 • Switching behavior • 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 • Environmental issues • Mixed results for market mechanisms to manage emissions • Renewable portfolio standard • Credits for reduced emissions and cleaner burning technologies