Dr. John L. Jurewitz Director, Regulatory Policy Southern California Edison Company Massachusetts Electric Restructuring Roundtable Boston, Massachusetts January 29, 2001 Anatomy of California’s Electricity Crisis (How to Make a Bad Thing Worse)

2.2. “That’s why I never walk in front.”

3.3. The Making of California’s Electricity Crisis Restructuring Rules Market Rules and Market Power Market Fundamentals Regulatory and Political Inaction

4.4. Key Restructuring Rules n CPUC’s requirement that utilities buy all power through Power Exchange and ISO n Generation divestiture without buy-back contracts n Retail rate freeze Over-exposure to the spot market

5.5. Why Did CPUC Initially Insist that Utilities Buy Everything Through the PX and ISO Spot Markets? n Wanted transparent pricing to assure against self- dealing n Did not want utilities incurring long-term obligations and potentially stranded costs in their role as default provider n Wanted to encourage independent retailers –Customers wanting price hedges should seek them from ESPs

6.6. Unhedged Spot Market CAISO40-50%50-60% % Market Hedged (long-term forward contracts, self-owned generation) PJM85-90%10-15% New England80%20% Australia90%10% Comparison of Forward Contracting/Hedging in Other Electricity Markets Regulatory Constraints in Forward Contracting in CAISO Market Was a Key Source of High Costs in Summer 2000

Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99 Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00 $/MWh Min/MaxZonal Avg PX SoCal Day-Ahead Electricity Prices

8.8. California Market Prices have Skyrocketed in 2000 Comparison of Average Cal PX SP15 Monthly* Prices n 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 $/MWh

9.9. Comparison of California Electricity Costs n Estimated cost to serve all load in the CA ISO’s control area –Cost includes energy and ancillary services n 1998 cost is for nine months Source: ISO Board material, January 2001

10. Cumulative Cost of California Electricity n 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

11. ISO Emergency Operations n Stage 1 Emergency »Operating reserve below 7% n Stage 2 Emergency »Operating reserves below 5% »Interruption of voluntary customers n Stage 3 Emergency00110 »Operating reserves below 1.5% »Possible involuntary interruptions (rolling blackouts) n Rolling blackouts were initiated on 1/17, 1/18 n January 2001 are through 1/23/01 Summer 1999 Summer 2000 Nov/Dec 2000 Jan 2001 Occurrences

/22/0006/05/0006/19/0007/03/0007/17/0007/31/0008/14/0008/28/0009/11/0009/25/0010/09/0010/23/0011/06/0011/20/0012/04/0012/18/0001/01/0101/15/01 Emergency Stage ISO Emergency Operations in 2000/2001 n Rolling blackouts were initiated on 1/17, 1/18 n Date is through 1/23/01 Blackouts Stage 1 Stage 2 Stage 3 Blackouts

13. Market Fundamentals n High rate of demand growth n Virtually no new plants sited n Reduced availability of imports n Skyrocketing gas prices –Pipeline capacity shortages n Air emissions limitations and high priced emission credits

14. SCE Sales Growth Rates (Weather Adjusted) Growth Rate Percentages

15. Natural Gas Prices in 2000 n Prices peak at an unheard level of $60/MMBtu n Gas prices for the second half of 2000 were more than four times higher than 1998 and 1999 prices

16. Summer/Fall 2000 Electricity Prices Disconnect From Natural Gas Prices $/MWH $- $10 $20 $30 $40 $50 $60 $/MMBtu 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

18. Market Structure, Rules, and Conduct n Flawed ISO/PX market protocols n Large amount of unhedged power purchases n Underdeveloped demand-side responsiveness n Exercise of supply-side market power

19. High Prices Persist During Modest Loads (Sunday) n Markets do not produce competitive prices n Under similar medium load conditions, 2000 prices have increased 700% over 1999 levels

20. The ISO’s Market Surveillance Committee Has Consistently Concluded That Market Power Has Been Exercised n 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 Energy Prices Exceeded Competitive Benchmark Percent

California Market Produced Two Years of Moderate Prices and Low Mark Up Over Competitive Benchmark n 1999 average mark-up was lower than n 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 n California market is “seriously flawed” n Rates have been “unjust and unreasonable” n “California market structure and rules provide the opportunity for sellers to exercise market power when supply is tight” n Insufficient study to determine the exercise of market power by individual sellers n FERC acknowledged its responsibility under FPA § 206 to ensure future rates are just and reasonable, subject to refund

24. Joskow/Kahn Study n Summer wholesale prices far exceeded competitive benchmark prices n No evidence that wholesale price caps caused higher prices n 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) MW (Difference between Maximum Output and Average Actual Output for High Priced Hours for June 2000, EPA data) NP 15SP 15 DukeSouthernAES/WilliamsDukeDynegyReliant

0 2,000 4,000 6,000 8,000 10,000 12,000 Oct 1999Oct 2000Nov 1999Nov 2000 Ave. Daily Outages (MW) Forced Scheduled Capacity Outages or Withholding? n October 2000 total outages (MW) are 4 times higher than October 1999 n November 2000 total outages (MW) are 5 times higher than November 1999 Source: “Market Analysis Report” by the ISO on December 1,

27. How Can Rolling Blackouts Be Needed in Winter? ISO Load Conditions During Recent Blackout n This winter, the ISO initiated rolling blackouts at a demand of only 65% of last summer’s peak n On 1/23/01 PG&E reported it has exhausted its interruptible program (about 400MWs) 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) $151 Million $538 Million Profits Reported by Enron’s Gas and Electric Trading Division

29. Regulatory and Political Inaction n FERC’s inability or unwillingness to regulate its “just and reasonable” standard n CPUC’s inaction in approving long-term contracts and setting reasonableness standards n CPUC’s unwillingness to end the retail rate freeze

30. JUNJULAUGSEPOCTNOVDEC Seven Months of Red Ink Existing Customer Rate Freeze 6.2¢/kWh Costs Absorbed by SCE in ¢/kWh (Approx. $4.5 Billion as of 12/00) Customer Rates 2000 Average Wholesale Electricity Prices (SCE)

31. Procurement Undercollections (SCE) JuneSeptJulyAugOctNov DecTotal $644 Million $457 Million $870 Million $387 Million $283 Million $561 Million $1,288 Million $4.5 Billion $Billions

32. The Regulatory Bankruptcy Squeeze and Its Consequences Immediate Shortages and High Prices n Reluctance of suppliers to supply n Bankruptcy “risk premium” in wholesale prices n No retail price signal to conserve n Threat of bankruptcy-induced natural gas shortages and “risk-premium” prices Loss of Summer 2001 Resources n Depletion of Northwest hydro n Exhaustion of options on 2,000 MW of interruptible customers Cascading Broader Economic Impacts n Impacts on banks and financial markets n Loss of utilities’ ability to invest in needed T&D infrastructure n Shift of business out of California n Economic recession FERC inaction to regulate wholesale prices Imminent utility bankruptcies CPUC inaction to raise retail prices and assure recovery of undercollections

33. Other Western States Have Found the Political Will to Raise Retail Rates to Reflect Current Wholesale Markets (Examples) Tacoma Power50%Approved Seattle City Light28%Approved BPA30%Proposed Snohomish County PUD35%Approved Clark County PUD20%Approved Portland General Electric27%Proposed Idaho Power32%8% Approved 24% Proposed Pacificorp (Oregon)21%Proposed Utah Power & Light19%Proposed

34. Is There Long-Term Relief ? New Generation In California Generation Scheduled for Summer 2001 ProjectDateMW California Sutter8/1500 Los Medanos7/1500 Various6/1 - 9/11,070 California Total2,070 Southwest6/1 – 7/11,690 Northwest7/1500 Summer 2001 Total4,260 Approved/Under Construction6,273 MW In Licensing7,716 MW Proposed5,780 MW Total 19,769 MW California

35. California ISO Load/Resource Forecast 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80, ,260 45,56545,60250,01162,86162,87862,86163,19063,180Max Avail. Gen. Capacity Max Import Capacity 49,20950,18851,46353,60254,46255,30656,17757,928Load Forecast + OR Source: California Independent Operator

36. What’s Needed in the Near Term? n Reasonable long-term wholesale contracts –CPUC/legislative approval needed –FERC enforcement of its “just and reasonable” standard n Reasonable retail price increases n Assurance of recovery of past and future procurement undercollections n Very serious statewide (and West-wide) conservation program n Continue to foster development of new generation