加州电力危机

Lightening Strikes Twice:California Faces a Real Risk of A Second Power CrisisLake Tahoe Energy ConferenceJuly 30,2004CONFIDENTIALThis 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 Future5 steps that will ensure a long-term sustainable market for powerTHE STATE IS AT RISK OF ANOTHER POWER CRISIS,BUT 5 KEY STEPS WILL HELP TO ENSURE A SUSTAINABLE POWER MARKETAction needs to be taken today to prevent another energy crisis1.New generation needs to be built today,given the long lead time,and a mechanism for market-based contracts with utilities needs to be introduced2.California should introduce mandatory time-of-use metering for all classes of customers3.New transmission needs to be built and facilitated through a expedited and coordinated approval process by the PUC,ISO,CEC,and FERC4.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 powerCEC estimates indicate that operating reserves could drop below typical“emergency levels if we have a hot summerUnfortunately,the CECs 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 occurrenceTaking 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)1THE STATES 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 ESTIMATESAugust 2005August 2006August 2007August 2021Projected California state operating reserve margin*PercentAugust 20047%target=Stage One emergency level5%target=Stage Two emergency levelReserve margins consistently drop beginning in 2006Demand2ENERGY AGENCY FORECASTS OF FUTURE DEMAND ARE OPTIMISTIC COMPARED TO ALTERNATIVE PROJECTIONSESTIMATES OF 1-IN-2YEAR PEAK DEMANDPeak 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 2004-2021 conservation in California(provided by CEC)Source:California Energy Commission;Bureau of Economic Analysis;Economy Regression model*CEC-July 2004Trend*Different models of demandCEC-May 2003For 2006,the CECs estimate is 1,000 MW below trend-line estimates and 2,100 MW below a regression model estimate3THE POTENTIAL FOR A“HIGH DEMAND CASE IS AS HIGH AS A 1-IN-5 EVENT,RATHER THAN JUST A 1-IN-10 EVENT1 in 2 demand1 in 5 demand1 in 10 demandDistribution of average statewide peak temperatureNumber of years observed over past 40 years*Based on BAEF regression-model estimates of 2006 peak demandSource:California Energy CommissionTemperature rangeDegrees Fahrenheit 8 out of the last 40 years(or 20%),peak temperatures have been 101 degrees or higherThere is little demand difference,though,between 101 degrees and 101.5 degrees1 in 10101.51 in 5101Potential 2006 peak demand*GWBASED ONHISTORIC DATA+3.4%+2.7%4TAKING 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 analysis1 in 5 year1 in 2 yearBAEF ESTIMATE7%target=Stage One emergency level750 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 todayAugust 2005August 2006August 2007August 2021Projected California state operating reserve margin*Percent5%target=Stage Two emergency levelDemand5THE STATE IS AT RISK OF ANOTHER POWER CRISIS,BUT 5 KEY STEPS WILL HELP TO ENSURE A SUSTAINABLE POWER MARKET5 steps that will ensure a long-term sustainable market for powerAction needs to be taken today to prevent another energy crisis1.New generation needs to be built today,given the long lead time,and a mechanism for market-based contracts with utilities needs to be introduced2.California should introduce mandatory time-of-use metering for all classes of customers3.New transmission needs to be built and facilitated through a expedited and coordinated approval process by the PUC,ISO,CEC,and FERC4.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 powerCEC estimates indicate that operating reserves could drop below typical“emergency levels if we have a hot summerUnfortunately,the CECs 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 occurrenceTaking 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)6MARKET-BASED LONG-TERM CONTRACTS SHOULD BE ADOPTED TO FACILITATE GENERATION CONSTRUCTION and what market-based prices would look like under the contractsDWR contract price(2003 average)California cost of generationDollars per MWhCapacity 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 periodSource:California DWR;NYMEX;McKinsey analysisHow contracts would workWho will buy:In the near term,utilities will be responsible for signing contracts with the winning bidders,with guaranteed rate recovery of contract costsWho will build:Competitive RFP process allowing utility affiliates or merchant generators to bidHow 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 prices17THERE 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 analysisPlants partly constructed,but incomplete due to financing or lack of contracts*Plants with permits from the CPUC but not under constructionCalifornia capacityGigawattsEstimated time to onlineMonthsPlants that have been mothballed,but could be brought back on lineTo 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 projectsSteps to bring capacity onlineRelaxed environmental restrictionsShort term contracts E.g.,EtiwandaMid-long term contracts(5-10 years)E.g.,Metcalf,PicoLong term contracts(5-10 years)Extended permit shelf lifeE.g.,Tesla,San Joaquin3-68-12*12-1818CALIFORNIA LAGS OTHER STATES IN ITS DEMAND SAVINGS FROM LOAD MANAGEMENT PROGRAMSNote:Includes only utilities reporting DSM activities Source:EIA;state disclosuresTop 25 states in load management DSM savings2002 annual load management savings as percent of(Savings+Peak),MWTop 25 states in peak DSM savings from energy efficiency 2002 annual peak savings from energy efficiency,MWIf California achieved levels of Florida,It could see a reduction of demand by 2 GW in load management aloneEven though California is a leader in energy efficiency,there is room to improve by 900MWFloridaCalifornia29TIME 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 customersSource:1999 CalPX hourly data;interviews;McKinsey analysisBenefits of time-of-use pricingRatepayers would save approximately$270 million-$380 million annuallyFewer new peaker plants neededGas demand reducedEnvironmental benefits(NOx reduction,water conservation,etc.)10-year savings from demand response(load shifting and curtailing*)Total 10-year savingsCost of program*Californians will benefit in many ways from time-of-use pricing$Billions210MULTIPLE AGENCIES HAVE JURISDICTION OVER TRANSMISSION PLANS,SLOWING SITING AND CONSTRUCTIONSource:CEC reportsRequired approvalParticipating transmission ownersSystem impact studyFacilities studiesTypical time30-60 daysCAISOCPUCCertificate of Public Convenience and Necessity(above 200kV)Evaluation criteriaScope and cost of transmission upgrades necessary for interconnectionSharedDuplicateEconomic and reliability impact on overall gridEnvironmental,societal and aesthetic factorsSystem impact study and facilities studiesIntegrated grid assessmentVerifies PTO analysisEconomic and reliability impact on overall grid60-90 days12-30 months311OTHER 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;Platts PowerDatWholesale electricity price volatility*PercentMandated quantity of reservesIncentive payments for capacityNo market constraints2004 summer reserve margin*Percent1257130264034California(2001)AlbertaISO-NENYISOPJMArgentina412RETAIL CHOICE IS SOUGHT AFTER MOST BY LARGE CONSUMERS,BUT BENEFITS ALL CUSTOMER CLASSESIn the UK,large consumers have been the most frequent users of competitive suppliersAll consumers have seen lower electricity bills with market restructuring and retail choiceCase example:United KingdomIndustrialSwitchedNot switchedCommercialSwitchedNot switchedResidential SwitchedNot switchedEstimated savings per customer*Percent*Estimated savings in customer bills since privatization/deregulation adjusting for the effects of inflationSource:EA Electricity Industry Review;EU-EPNG M&A Database,UK Power Market PD Dec.2001;OFGEM513IMPLEMENTING A CORE/NON-CORE MARKET STRUCTURE IN CALIFORNIA WILL REQUIRE CAREFUL PLANNINGConcernsControlling the market influence of a dominant player or playersKey success factorsStrict market oversight committee and penaltiesSufficient generation capacity to limit gamingMarket powerResource adequacyEnvironmental issuesSwitching behaviorEnsuring sufficient new capacity built to serve core and non-core customersCapacity market mechanism to provide liquidity for trading capacity reservesReserve margin targets(15-20%)required for utility and non-utility suppliersLead time required for long-term planning by utilitiesReasonable notice period required by non-core customers who plan to switch linked to the time to build new capacityDWR cost overhangSignificant stranded costs from DWR long-term power contract obligationsEquitable sharing of costs between core and non-core market customers,with no ability to avoid costs by shifting to a new supplierMixed results for market mechanisms to manage emissions Renewable portfolio standardCredits for reduced emissions and cleaner burning technologies514