The California electricity crisis threatens notonly the economic well-being of ratepayers inCalifornia but the economic well-being of theUnited States as well. Unfortunately, the politicaland economic commentary surrounding the cri-sis is shedding more heat than light.

California has been victimized by severalsimultaneous and severe supply and demandshocks—most notably, a run-up in wholesale nat-ural gas prices—that are outside the state’s polit-ical control. Those shocks were made moresevere by air pollution regulations and retailprice controls. Although California’s “deregula-tion” of the electric utility business is beingblamed for the crisis by both the political left andthe political right, we find that the 1996 restruc-turing law has little to do with the run-up inwholesale power prices. That law is primarilyresponsible for the blackouts, however, in that itprohibits utilities from passing on increases infuel costs to consumers.

Virtually all the increase in wholesale pricescan be explained by increases in production costsand overall scarcity. While there is some evidenceof the existence of excessive generator “market

power” (created not by the unfettered exercise offree markets but by poorly conceived regulation),it is relatively minor and responsible for only asmall fraction of the price spike, if it exists at all.

We find little evidence to support the argu-ment that environmentalists are primarily toblame for the crisis. We likewise are unconvincedthat, had the state allowed utilities to enter intolong-term contracts with generators, the crisiscould have been either averted or made less severe.

None of the remedies thus far proposed—such as a state takeover of the industry, the so-farminimal increase in power rates, energy conser-vation subsidies, prohibitions of “wasteful” ener-gy use, more vigorous wholesale price controls,or the adoption of long-term power contractswith generators—will get the state through thenext two years without frequent and widespreadblackouts and significant economic damage. Infact, all of those alleged remedies would makematters worse.

The only remedy to the crisis is the elimina-tion of the retail rate cap and the institution ofreal-time pricing mechanisms for the largest seg-ment of demand possible.

California’s Electricity CrisisWhat’s Going On, Who’s to Blame, and What to Do

by Jerry Taylor and Peter VanDoren

_____________________________________________________________________________________________________

Jerry Taylor is director of natural resource studies at the Cato Institute. Peter VanDoren is editor of Cato’sRegulation magazine.

Executive Summary

No. 406 July 3, 2001

Introduction

Skyrocketing wholesale power prices inCalifornia and the daily threat of brownoutsand blackouts have cast a pall over the meritsof electricity deregulation. Liberals, led byCalifornia’s governor, Gray Davis, blame therestructuring law passed in 1996 for the cri-sis, arguing that it left the state vulnerable tomarket manipulation by greedy power pro-ducers. According to Davis, the crisis is large-ly artificial but nonetheless a harbinger ofthings to come, not only in national electric-ity markets but in industries throughout theeconomy, if we continue our mad rushtoward laissez faire.

Conservatives for the most part agree thatthe 1996 reforms are primarily responsiblefor the crisis. They charge, however, that theregulations attached to those “reforms”—pri-marily the prohibition of long-term con-tracts between utilities and power generatorsand the imposition of a centralized daily spotmarket—are largely responsible for the pricespike. The political right argues thatCalifornia’s regulations, crafted by environ-mental activists and anti-growth consumergroups, have long discouraged investment innew generating capacity and that the black-outs are a long-overdue flock of chickenscoming home to roost.

While both sides are busily settling politi-cal scores, the real story of what happened inCalifornia is largely absent from most analy-ses. Accordingly, the important lessons thatthis crisis teaches about regulation and elec-tricity are largely being overlooked: retailprice controls are a recipe for disaster, andstate regulators have little idea how to orga-nize markets and certainly shouldn’t attemptto do so under the mantle of “deregulation.”

The Anatomy ofCalifornia’s “Deregulation”

On the last day of the 1996 legislative ses-sion, California’s legislature adopted by

unanimous vote A.B. 1890, the first of manystate attempts to “deregulate” the electricitybusiness. The roots of the confusion overwhat California did and did not deregulatebegan with the PR campaign to sell the bill.Unlike deregulation of the airline and truck-ing industries—which largely curtailed regu-latory oversight of those industries—the“deregulation” of the electricity industry inCalifornia was heavily prescriptive and not,on balance, a loosening of regulatory over-sight at all. A.B. 1890 simply replaced the oldset of regulations with a new set of regula-tions, some of which were less interventionistthan the old, some of which were more.

The central thrust of A.B. 1890 was to cre-ate a competitive retail market for electricity.Traditional rate-of-return regulation of state-sanctioned monopoly power companies hadnot kept electricity prices at reasonable levels.By the mid-1990s, California electricity priceswere 35 percent higher than the U.S average,and California residential customers paid 35percent more than the average U.S. residen-tial customer.1 Those excessive costs threat-ened to slow expansion in California andmake the grid itself obsolete as ratepayersfled to nonutility power providers.2

The remedy was to allow competitionamong and free entry of electric generators.The generators owned by incumbent utilitieswould compete with nonutility power gener-ators for business, and customers couldchoose from whom they wished to purchasepower. Competition would protect con-sumers from the excessive investments andcost overruns that occurred under tradition-al cost-of-service regulation.

The Crusade against Market PowerWhile virtually all the nonutility interest

groups endorsed this reform in principle,many of them—particularly the large indus-trial users of electricity, the independentpower producers, and the “consumer rights”lobby—feared that incumbent utilities woulduse their control of the electricity grid (theincumbent-owned network of wood, steel,and wire that connects power plants to con-

2

While both sidesare busily settling

political scores,the real story of

what happened inCalifornia is

largely absentfrom most

analyses.

sumers) to disadvantage independent gener-ators. Incumbent utilities would excludeindependent generators from the grid, priceaccess exorbitantly, or load the grid with theirown power and thus use congestion torestrict entry. Or utilities could charge retailcustomers below-cost rates while recoupingthose losses through excessively high trans-mission and distribution rates for competi-tors. Because most analysts assume that thegrid is a natural monopoly (building alterna-tive grids is widely thought to be prohibitive-ly costly and impossible politically because offierce community resistance), it was fearedthat allowing nonutility firms to enter thegeneration market would not result in a com-petitive market for wholesale power.

Reformers thus concluded that electricity“deregulation” would require a whole new setof regulations and government interventionsto ensure that a competitive market wouldarise. The important provisions of A.B. 1890follow.3

• Mandatory Open Access: Utility compa-nies must allow any generator access tothe electricity transmission systemunder terms, conditions, and pricesestablished by the state.

• Vertical Disintegration: Incumbent utili-ties are to become transmission anddistribution companies, divestingthemselves of generators. And thedivested generators can sell power onlyto a state-managed power exchange.

• Centralized Power Exchange: Any electric-ity the incumbent utilities need fortheir default customers (those who donot switch to competitive suppliersunder the retail choice program) has tobe purchased from a centralized, state-managed power exchange. Indepen-dent marketers can buy through theexchange voluntarily. The exchangecreates an electricity supply curve fromgenerators’ hourly willingness-to-pro-duce offers. The hourly price is set bythe highest-cost producer whose out-put is necessary to meet estimated

demand from the utilities.• Utility Retail Price Caps: For those cus-

tomers who remain with the threeincumbent utilities (Pacific Gas andElectric, Southern California Edison,and San Diego Gas and Electric), retailrates are frozen at levels 10 percentbelow June 1996 rates until the incum-bent utilities recover their “strandedcosts” or March 2002, whichever occursfirst.

• Independent System Operator (ISO): Theday-to-day operation of the grid (thatis, the management of electricity trafficalong the wires) is directed, not by theutilities that actually own the grid, butby a nonprofit organization governedby a 26-member advisory board of rep-resentatives of grid users. The ISO isfurther empowered to procure electrici-ty on an emergency basis if on any givenday the amount of power procured inthe centralized power exchange isinsufficient to meet demand.

“Stranded Costs” and Retail PriceControls

Although utilities were never particularlyexcited about the proposed change from tra-ditional rate-of-return monopoly regulationto managed competition, they were particu-larly worried that, were they forced to com-pete with independent power generators inthis new wholesale marketplace, some oftheir generating assets (nuclear power plantsand long-term contracts with nonutilitypower producers) would not produce suffi-cient revenues to recover their total costs.This would reduce the market value of thoseassets to much less than their “book” valueon the utilities’ balance sheets. Electricityanalysts coined the phrase “stranded costs”to describe the difference between book andmarket values of certain generating assets. InCalifornia, stranded costs were estimated tobe between $21 billion and $25 billion.4

Estimates for the United States ranged from$70 billion to $200 billion; the higher figure

3

Reformers con-cluded that elec-tricity “deregula-tion” wouldrequire a wholenew set of regulations andgovernmentinterventions.

was double the total shareholders’ equity inthe industry.5

Utilities and several prominent academicsjustified recovery of those stranded costs byarguing that a “social contract” existedbetween investors in utilities and state regu-lators. In their view, the investors and thegovernment agreed that, if the companieswould serve all customers in an area as astate-sanctioned monopoly, the investorswould receive a regulated but reasonablereturn on their investment.6 Thus, deregula-tion without compensation of investors forthe capital losses they suffer as a resultbreaches the contract. It “takes” investors’property without compensation—a violationof the Fifth Amendment’s Takings Clause—and raises the cost of capital in any other sec-tor of the economy in which potentialchanges in public policy create risk.

Economists disagree about whetherstranded-cost recovery is either efficient or“fair.”7 Those who oppose stranded-costrecovery argue that investors surely knowthat the rules of the regulatory game are sub-ject to change, and investors can and do takethat into account when investing theirmoney. You place your investment bets andyou take your chances.8

Moreover, if taxpayers were constantlyreimbursing businesspeople for investmentsthat become less attractive once the rules ofthe game are changed, beneficial regulatoryreforms might never occur. Furthermore,many of those stranded costs were enthusias-tically embraced by the utilities at the time.Few utilities were dragged kicking and scream-ing into those costly investments; many utilityexecutives wisely passed them by.

Nevertheless, A.B. 1890 allows recovery ofutilities’ stranded costs through the imposi-tion of a mandatory “competitive transitioncharge” on all ratepayers. Of course, it wouldbe hard to sell ratepayers on a deregulationscheme that raised rates in the short run viasome incomprehensible “competitive transi-tion charge.” So A.B. 1890 imposes a ratefreeze on industrial and large commercialutility customers and a 10 percent reduction

in residential and small commercial utilityrates. Those rate controls are to stay in placeuntil a utility recoups its allotted share ofstranded costs, or no later than March 2002.

How could the state mandate a rate cutand impose a “competitive transition charge”at the same time? Simple: it issued tax-exemptbonds through the off-budget CaliforniaInfrastructure and Economic DevelopmentBank to amortize the rate cut over a period oftime longer than the period during which therate cut was actually given to consumers. SoCalifornia and federal taxpayers pay for therate relief in the form of tax receipts forgonebecause the interest is tax-exempt.

The Mirage of Retail ChoiceUnder A.B. 1890, consumers not only

enjoy a rate cut, they also are allowed tochoose their power company in much theway they choose their long-distance tele-phone company. And the competitionamong electric generators is supposed tokeep rates down. But A.B. 1890 sets the ratefor default electric service from the incum-bent utilities for the period 1998 to March2002 at 10 percent less than the 1996 rate;the difference is to be paid for, in part, by thetax-exempt bonds. New independent firmshave not been able to underprice this defaultservice. Only 1 percent of California’s resi-dential ratepayers had switched suppliers byearly 2000 despite large advertising invest-ments by power marketers.9 One of the lead-ing power marketers, Enron, actually aban-doned the California residential market afteronly three weeks because consumers had lit-tle incentive to leave their traditional suppli-ers. Competition was largely confined to thecentralized power exchange, where nonutilityfirms competed in a mandatory day-beforespot market to sell power—not directly toconsumers but to the incumbent utilities act-ing as default suppliers to customers.

The Precrisis MarketAlthough the public may not have

grasped exactly what A.B. 1890 was all aboutbeyond some vague notion that “competi-

4

California andfederal taxpayers

pay for the raterelief in the form

of tax receipts for-gone because the

interest is tax-exempt.

tion” was on the way because of deregulation,energy analysts were less certain that any ofthis would work. While most analysts feltthat, on balance, the new regime would provea valuable first step toward further deregula-tion, some, including the authors of thispaper, seriously doubted it and wrote asmuch at the time.1 0

Still, California’s electricity market underthe new regime appeared to work reasonablywell from April 1998 through the spring of2000. Even though retail competition forelectricity ratepayers never fully materializedbecause of the price controls on default ser-vice, wholesale electricity prices averaged $30per megawatt-hour (MWh), or 3 cents perkilowatt-hour (kWh), in 1998 and 1999.11

Those low prices allowed utilities to earn areturn on sales and recover stranded costseven with the retail rate cap.12 Between April1998 and April 2000, when the wholesalecost was lower than the retail price cap, thethree incumbent utilities retired $17 billionin debt.13 Incumbent utilities were also ableto recoup some stranded costs by selling fos-sil-fuel power generators with a total bookvalue of $1.8 billion for a combined $3.1 bil-lion retail price.1 4

Analysts did not predict that the crisiswould occur.1 5 University of California-Berkeley, economist Severin Borenstein, forexample, remarked: “If we [economists] hadunderstood better, we would have warned bet-ter. . . . There were many things we didn’t see.”16

In its summer 2000 system reliability report,the North American Electricity ReliabilityCouncil estimated the reserve margin in theCalifornia-Mexico interconnection to be 15percent over the estimated July peak demand, alarger reserve margin than in several otherregions of the United States.17 The assessmentdid warn that the region “may not have ade-quate resources to accommodate a widespreadsevere heat wave or higher than normal genera-tor forced outages,”18 but NERC was muchmore worried about the supply-demand imbal-ance in New York and New England than inCalifornia.19 Even in March 2000 the CaliforniaEnergy Commission forecast a weighted-aver-

age price for 2000 of 2.85 cents per kWh and apeak monthly weighted-average price inSeptember of 4.5 cents per kWh. The actualweighted-average prices were 11.3 cents perkWh for 2000, and the highest monthly averageprice was 37.2 cents per kWh in December.20

And as late as November 2000 NERC argued inits 2000–01 winter assessment that generationin all regions would be able to meet demandshould normal weather prevail.21

The Perfect Storm

California’s happy state of regulatoryaffairs changed radically in 2000–01 whentwo large supply shocks and one largedemand shock simultaneously hit the state.None of those shocks was triggered by statepolicy. All of them, however, had a seriousimpact on wholesale electricity prices.

The Natural Gas Price SpiralThe first supply shock was a massive

increase in regional wholesale prices for natur-al gas, the fuel input for 49 percent ofCalifornia’s electricity capacity in the first ninemonths of 200022 and nearly all its peakingcapacity. In 1998–99 the average price of nat-ural gas delivered to utilities in California was$2.70 per million British thermal units (Btu).23

By the summer of 2000, however, wholesalespot gas prices at the southern California“gate” had risen to $5 per million Btu, andthey had risen to an average of $25 per millionBtu by December24 (the price reached $60 permillion Btu on December 9).2 5

The increase in natural gas prices wasnationwide. Wholesale natural gas pricesthroughout the United States duringNovember and December 2000 averagednearly $10 per million Btu compared to $2per million Btu during 1999.2 6 Mark Mazur,acting administrator of the EnergyInformation Administration, testified to theSenate Energy and Natural ResourcesCommittee that “gas prices previously hadnot remained this high for a sustained periodof time.”2 7

5

Two large supplyshocks and onelarge demandshock simultane-ously hit thestate. None ofthose shocks wastriggered by statepolicy.

The increase in the price of natural gaswas the logical consequence of the first sig-nificant cold winter after several mild wintersand less-than-average amounts of natural gasavailable from storage.2 8

The price increase was worse in Californiabecause demand was greater relative topipeline capacity and total storage.2 9 Anexplosion in August 2000 shut down the ElPaso pipeline, which carries natural gas fromTexas to southern California. That accidentreduced pipeline capacity into the state by 10percent for several weeks, a large supply dis-ruption that has not been fully remedied.3 0

The surge in demand and the subsequentprice increase caught the industry by surprise.Natural gas prices had, after all, declined 25percent in inflation-adjusted terms between1985 and 1999.3 1 Consumption from 1995through 1999 was essentially flat.32 Thus therewere very limited incentives to increase pro-duction or hold inventory going into 2000.

With the increase in prices, however, theoil and gas industry increased domesticexploration and development budgets by 40percent in 2000; another 20 percent increaseis expected in 2001.33 Unfortunately, newinvestments in production will increase out-put only after several years. The EnergyInformation Administration, a semi-inde-pendent analytic arm of the U.S. Departmentof Energy, believes that prices will resumetheir historical trend by 2004.3 4The NationalPetroleum Council concurs, forecasting thatthe average wellhead price through 2010 willbe approximately $2.74 per million Btu.3 5

Given that 90 percent of a naturalgas–fired generator’s cost of producing elec-tricity stems from fuel costs,3 6 increased nat-ural gas costs must increase electricity prices.A natural gas price of $20 per million Btu, forexample, translates into a production cost ofat least 20 cents per kWh for an average nat-ural gas–fired plant and 32 cents per kWh forthe least-efficient power plants.37

Why Natural Gas–Fired ElectricityDetermines Wholesale Prices

The least-efficient plants’ costs are rele-

vant because in commodity markets, likeelectricity, the costs of the most costly pro-ducer whose output is necessary to meetaggregate demand set the price for all theelectricity sold, even power produced fromother fuels. Thus, the California wholesalemarket cannot be understood without a fullunderstanding of the increased cost ofgas–fired electricity.

This is doubly important because manycommentators have argued that, if utilitieshad signed long-term contracts with cheapersources of power, the price spiral would havebeen less dramatic. Underlying that argumentis the belief that the price of electricity in a freemarket would be a weighted average of long-term and spot prices.38 While this belief hassuperficial plausibility, pricing output as aweighted average of differing prices of inputswould result in shortages.

Imagine that supermarket lettuce priceswere different depending on individual farm-ers’ costs. Once people realized that differentprices existed for lettuce, shoppers wouldsnap up the low-cost lettuce first. The super-market would then ask the low-cost lettuceproducer for more output at lower prices.But could the lettuce producer easily expandoutput at the same low costs? He could if hedidn’t have to pay market prices for addi-tional inputs, but that would be the case onlyif he had additional inputs under long-termcontract. And if he or other producers hadsuch spare capacity lying around under con-tract, market prices would already havedecreased to reflect the competition amongthe owners of excess supply to use the unitsfor which they had contracted.

If the low-cost producer did not havespare capacity under long-term contract andhad to pay market prices for additionalinputs like land and fertilizer, he would haveto charge higher prices for the additionaloutput to cover costs. In addition, the low-cost lettuce producer would realize that,rather than increase output at higher prices,he could raise prices on his existing low-costoutput, eliminate the shortages, make moremoney than if he used weighted-average pric-

6

Pricing output asa weighted aver-age of differingprices of inputswould result in

shortages.

ing, and not have to increase production.Electricity markets are analogous to the

lettuce example.39 Even if California utilitieshad contracted for 99 percent of their supplyat low prices, demand would exceed supply atthose prices. And if the utilities attempted toexpand output, they would have to pay mar-ket prices for the fuel input and would losemoney on every additional sale unless theadditional output was sold at market prices.

Thus, uniform prices for all sources ofelectricity regardless of their respective inputcosts is a (good) characteristic of free marketsand not the result of the prohibition of long-term contracts in the California system or ofthe mandate that transactions take placethrough a centralized spot market. In fact,this very point was once made quite energet-ically by the political left to justify energyconservation subsidies. Amory Lovins, afamous advocate of energy conservation, hasargued correctly that traditional state regula-tion of the electric utility business deliveredaverage costs, not marginal costs, to ratepay-ers, which resulted in economically ineffi-cient (excessive) levels of consumption andlosses for the utilities whenever marginalcosts exceeded average costs.4 0Lovins’s reme-dy for this market distortion, however, wasnot a “first-best” solution—the introductionof marginal cost pricing—but a “second-bestsolution”—to have electric utilities subsidizeratepayer purchases of energy efficient appli-ances and technologies, which would becheaper for utilities than investments inadditional generation (a matter we’ll returnto later in this paper).

The WeatherThe second supply shock was caused by a

three-year dry spell that reduced reservoirand river-flow levels and thus reduced hydro-electric generation in California by 20 per-cent from 1998 to 1999.4 1In addition, before1998 hydropower was more abundant thannormal, reducing the returns that wouldcome from investment in natural gas–firedproduction, just as California was switchingto “deregulated” generation. Hydro output

in the Canadian and U.S. West in 1997 wasmore than 30 percent greater than in 1992.42

Hydropower from the Pacific Northwest fur-ther declined from an hourly average of20,805 megawatts (MW) in 1999 to 18,075MW in 2000. California hydropower likewisedeclined from an hourly average of 4,395MW in 1999 to 2,616 MW in 2000.4 3 FromJune through September 2000, hydro pro-duction throughout the West was, on aver-age, 6,000 MW less than during the samemonths in 1999, equivalent to the output of7 to 10 nuclear plants.44

Unfortunately, the water shortage willalmost certainly get worse before it gets bet-ter. Stream flows in the Pacific Northwestlast January were only about 60 percent ofaverage4 5 and snowpack in the CascadeRange was likewise only 60 percent of nor-mal,4 6 prompting the Northwest PowerPlanning Council to warn that hydroelectricpower generation this summer will be 5,000MW below normal.4 7 As of March 30, 2001,California’s Department of Water Resourcesreported that snow and rain accumulationwas 34 percent less than normal in thatstate.4 8 The practical effect of this reductionin hydroelectric generation was to leaveCalifornia with little spare generating capaci-ty during peak-demand periods.

In addition to the negative supply shocks(natural gas price increase and hydro short-age), a demand shock hit during the summerof 2000 because of unseasonably warm tem-peratures (a 13 percent increase in coolingdegree-days across the Pacific region from1999 to 2000).49 Temperatures in the Arizonasubregion of the western grid averaged threeto five degrees higher than normal.5 0 TheCalifornia-Nevada subregion of the westerngrid experienced the 99th hottest summer ofthe last 106 in June 2000, compared with 59thand 14th in 1999 and 1998, respectively.5 1

Accordingly, energy consumption andaverage daily loads during the summer of2000 grew rapidly compared with the sameperiod in 1999. Electricity consumption inthe western states, excluding California,increased by 4.7 percent in from May 1999 to

7

The second sup-ply shock wascaused by a three-year dry spell thatreduced reservoirand river-flowlevels and thusreduced hydro-electric genera-tion inCalifornia.

May 2000, and energy consumption inCalifornia increased by 5.8 percent over thesame period. The increase in energy con-sumption from June 1999 to June 2000 waseven greater—7.3 percent for the WesternSystems Coordinating Council states,excluding California, and 13.7 percent forCalifornia. Within the ISO, average dailypeak loads grew by 11 percent in May and 13percent in June compared with the samemonths of 1999.52

Even though the increase in electricitydemand may not sound dramatic, the effect onnatural gas consumption was dramatic becauseof the hydropower reductions. DuringMay–September 2000, natural gas consump-tion in California by utilities was 22.4 percentgreater than for the same months in 1999.5 3Inthe West as a whole natural gas use for electric-ity generation increased an astonishing 62 per-cent during the same period.5 4

The hot summer of 2000 was then fol-lowed by a historically cold winter in 2001,ensuring that demand would remain highthroughout the region.55

Some commentators have questionedwhether this seemingly moderate increase indemand could really explain price increasesthat are severalfold more severe on a percent-age basis than the increase in demand.56

Given the relative inelasticity of demand forelectricity in general (made worse by the exis-tence of retail rate caps, discussed below),even moderate increases in demand willincrease prices dramatically if supply is fixedin the short term, which is exactly what hashappened in the western power market.5 7

We draw two conclusions from our analy-sis of supply and demand changes inCalifornia. First, the reductions in supplyand increases in demand that resulted inwholesale electricity price increases are theresult of natural weather variation interact-ing with market forces.5 8No state politician,regulator, or businessman could have headedthem off. Second, no regulatory system—notthe pre-1996 regulatory regime, not the post-1996 regulatory regime, not a completelylaissez faire regime, and certainly not any of

the various regulatory regimes put in place inother states—could have prevented wholesaleelectricity prices from climbing to record lev-els under these circumstances.

Political Cloud Seeding

While we believe that the hydro shortage,natural gas price increases, weather shocks,and pipeline disruptions are the proximatecauses of increased prices for wholesale elec-tricity in California—“the perfect storm,” ifyou will—the price increases were exacerbatedby the existence of two politically createdphenomena: nitrogen oxide (NOx) emissionpermits and retail price controls. That “polit-ical cloud seeding” made the perfect stormeven more intense and unpleasant.

NOx Emission PermitsAlthough environmental regulations, in

general, affect both generating costs and theability to site new capacity, California’srequirement that generators have sufficientN Ox emissions credits before going onlineplayed a particularly important role in theprice spiral of 2000–01. “To the extent thereis a smoking gun, it’s NOx,” J. Stuart Ryan,vice president of AES Pacific, an independentpower generator, told the Federal EnergyRegulatory Commission. “The cost of creditsfor NOx emissions in the L.A. Basin has sky-rocketed.”5 9

It is well understood that NOx emissionsare often (but not always) an important con-tributor to urban smog in the summertime.60

Accordingly, California adopted regulationsin 1994 (known as the RECLAIM program)that allotted a certain number of NOx emis-sions credits to existing emissions sources insouthern California and allowed them totrade those credits on the open market sothat the overall costs of emission reductionacross plants would be minimized. Plantsthat found it cheaper to buy emissions per-mits than to reduce facility emissions wouldpurchase permits from firms that found itcheaper to reduce emissions than to hold

8

No regulatory sys-tem could have

prevented whole-sale electricity

prices fromclimbing to

record levelsunder these

circumstances.

emissions permits. Each year the pool ofcredits is reduced by 8 percent. Power genera-tors must purchase enough credits to offsetemissions before they can go online or paylarge fines to the state.6 1

In the winter of 1999, NOx credits wereselling for about $2 per pound. By the sum-mer of 2000, those same credits were sellingfor $30 to $40 per pound where they havestayed ever since.6 2 Because an efficientgas–fired plant emits about a pound of NOxper MWh and an inefficient plant emitsabout two, NOx credit prices of $30 to $40per pound necessitate an additional cost of$40 to $80 per MWh ($0.04 to $0.08 perkWh).63 In January 2001, California regula-tors initiated a waiver of NOx permit require-ments for power generators for the next threeyears, but the damage had been done.6 4

Although it’s true that the RECLAIM pro-gram affects only those generators in the L.A.Basin—the source of only a fraction of thestate’s power—remember that the highest-costsource of electricity sets the price for all elec-tricity sold through the western grid. AaronThomas, a manager at AES Pacific, points outthat generators in the L.A. Basin “are settingthe clearing price for everybody in California.And to the extent that that market is influenc-ing markets in the West, all of a sudden you’regetting these basin units driving costs for 50million people in the West.”6 5

The Damage from Price ControlsThe wholesale electricity price increases in

California were exacerbated by the existenceof retail price controls.6 6Normally, firms thatincrease prices experience fewer sales as aconsequence. With retail price controls, how-ever, power generators could increase priceswithout fear that those price increases wouldreduce revenue.

Academic economists have tested thisproposition. Vernon Smith and his col-leagues at the University of Arizona have con-ducted experiments to compare the behaviorof auction prices under two scenarios: one inwhich consumers face rigid retail prices and asecond in which 16 percent of customers face

real prices that reflect supplier bids. Prices inthe second scenario are as much as 30 per-cent less than prices in the first scenario.Prices are dramatically lower as long as somecustomers face the real costs of peak-demandelectricity.6 7 Industry consultant Eric Hirstargues that if only 20 percent of the totalretail demand faced hourly prices, and as aresponse to those prices reduced demand by20 percent, the resulting 4 percent drop inaggregate demand could cut hourly prices byalmost 50 percent.6 8

In addition to the lack of demand respon-siveness created by the price controls, the ISOplaces an infinite value on “keeping the gridup,” which exacerbates the problem. Aswholesale prices increased after May 2000,the ISO enacted price controls in the marketfor daily backup and load-following (ancil-lary) reserves. On June 28, 2000, prices werelimited to 50 cents per kWh and on August 7,2000, to 25 cents per kWh.69 On November 1FERC issued a “soft” price cap of 15 cents perkWh for both the California day-aheadpower exchange and the real-time and ancil-lary ISO markets.7 0Given our analysis of theeffects of the prices of natural gas and NOxpermits on the marginal costs of the least-efficient natural gas–fired generators, theprice ceilings had the practical effect of dri-ving backup and load-following peak-demand generators out of the market.

FERC data support this conclusion. Thecommission reports that out-of-state genera-tors reduced their sales to California fromMay through August 2000 relative to Maythrough August 1999 by an average of 3,000MW a day and their sales to the daily marketoperated by the ISO by 2,000 MW a day.71

Tom Williams, an executive at Duke Energy,confirmed that those price caps discouragedthe company from selling power inCalifornia during peak-demand periods, fur-ther shortening supply on the day-beforemarket.72

But the ISO still had the responsibility tokeep the grid operating and had to ask thosesame generators to supply on an emergencybasis regardless of price. In January 2001, for

9

If only 20 percentof the total retaildemand facedhourly prices, theresulting 4 per-cent drop inaggregatedemand could cut hourly pricesby almost50 percent.

example, the ISO paid $461 million for last-minute purchases whereas in January 2000the ISO spent only $2.7 million on last-minute grid support. The price controls com-bined with unlimited willingness to pay foremergency power on the part of the ISOinduced high-cost suppliers to stay out of theday-before market operated by the powerexchange and hope for emergency calls fromthe ISO at very high prices. A vignette in theNew York Times illustrates the problem:

With its employees focused solely onkeeping the lights on—and with thebills to be paid not by itself but bythe utilities—critics say the agencywas ripe to be outfoxed by powersuppliers.

“My people are not trained astraders or arbitrageurs,” concededJim McIntosh, director of schedulingfor the system operator.

When traders were asking $2,000for a megawatt-hour of electricity,enough to light 1,000 typical homesfor an hour, Mr. McIntosh and oneof his bosses refused.

But the price they settled on—$1,500—was arbitrary, Mr. McIntoshacknowledged.7 3

Moreover, as the fiscal plight of the utili-ties became public knowledge (a plightentirely caused by retail price controls thatprevented the utilities from raising enoughrevenue to pay for electricity from the statepower exchange), some generators left themarket out of fear that the IOUs they werereceiving from the utilities would never berepaid. The California ISO, for instance,reports that the March blackout was largelycaused by generators’ shutting down 2,000MW of production because they had notbeen paid for the power they sold to the util-ities for three or four months.7 4

Other generators reflected the risk of non-payment in the prices they charged the state.Gary Ackerman, executive director of theWestern Power Trading Forum (a trade

group representing western power genera-tors), forthrightly acknowledges that thepolitical and financial uncertainties of doingbusiness in California have driven up theprices that forum members charge forpower.7 5 Duke Energy confirms Ackerman’sassertion, acknowledging that the prices itcharged California utilities included a creditpremium to cover the risk of nonpayment.76

Pacific Gas & Electric agrees. The compa-ny alleges that on January 18, for instance, sixsuppliers that had provided 36 percent of itsdaily supply had stopped service to the utili-ty or threatened to do so. PG&E later lostmore suppliers that had provided another 30percent of supply.77 And on March 19 abouthalf of the capacity of independent powerproducers (3,100 MW) who had contracts tosupply the incumbent utilities was shutdown because of nonpayment.78 In light ofPG&E’s bankruptcy on April 6, 2001, thatbehavior seems very prudent.

Explaining the BlackoutsIn a free market, reductions in supply do

not result in shortages because pricesincrease enough to equate supply anddemand. Higher prices induce firms to createadditional supply as quickly as possible toobtain profits. Eventually, the high priceseliminate the shock.

Wholesale electricity prices in Californiasince the spring of 2000 have averaged morethan 15 cents per kWh.7 9 Retail electricityprices, however, were capped at less than 7cents per kWh. Wholesale prices signaledthat electricity was increasingly scarce, butretail prices told consumers that nothing hadchanged. Accordingly, consumers demandedmore electricity than was available. Blackoutsare the inevitable result of attempts to regu-late and legislate basic economic laws out ofexistence.

Unexpected shortfalls in transmission capaci-ty also have contributed to the blackouts. Themain transmission line between northern andsouthern California (Path 15) has at times beenlimited to half its normal capacity, significantlycomplicating northern California’s power supply;

10

The political andfinancial uncer-

tainties of doingbusiness in

California havedriven up the

prices that gener-ators charge for

power.

thus the rolling blackouts have been confinedlargely to that region.8 0

Market Manipulation and“Price Gouging”

Do supply and demand shocks fullyexplain high California electricity prices?Industry analyst Edward Krapels believes thatsupply and demand shocks explain theDecember 2000 wholesale price in Californiabut do not explain 5 cents per kWh of the aver-age April through November price.81 MIT’sPaul Joskow and economic consultantEdward Kahn also conclude that “high whole-sale prices observed in summer 2000 cannotbe explained as the natural outcome of ‘mar-ket fundamentals’ in competitive marketssince there is a very significant gap betweenactual market prices and competitive bench-mark prices . . . high prices experienced in thesummer of 2000 reflect the withholding ofsupplies from the market by suppliers.”82

Where Did All the Power Go?Californians served by the ISO typically

demand 45,000 MW of electricity duringpeak periods in the summer, and that elec-tricity was available during the summer of2000. By contrast, Californians served by theISO demand only about 30,000 MW duringpeak periods in the winter. How could 15,000MW of power disappear and result in black-outs during the winter of 2000–01?

One answer, of course, is that it was soldto other markets in which wholesale pricecaps are not in place. The $250 per MWhwholesale price cap established by the ISO inAugust was below the marginal costs of theleast-efficient natural gas units with thegreatest NOx emissions in the Los AngelesBasin. A number of power generators simplystopped producing as soon as the cap wasput in place.83

Another possible explanation is that thehydropower that was lost during the summerof 2000 was replaced by many old natural gasunits that postponed needed maintenance

and repairs until this winter.8 4Approximate-ly 65 percent of the state’s generating capaci-ty, after all, is in plants 35 years old or older.85

This is particularly the case with the plantsused to meet summer peak demand. Thosegas–fired plants seldom operated steadilyuntil the summer of 2000, and, because theyare older and more inefficient, they requireadditional repair and upkeep. At varioustimes during the winter of 2000–01 powerplants were out of service in unprecedentednumbers.8 6 During the first blackout onJanuary 17, for instance, fully 11,000 MW ofin-state capacity was offline for repair andmaintenance work.87

Disbelief of the repair-and-maintenanceargument is rampant. Harvey Rosenfield andDoug Heller of the Foundation for Taxpayerand Consumer Rights call for state agents to“obtain search warrants and subpoenas toenter the power plants to determine the truecause of the shortages. If necessary, theplants should be seized to protect the publichealth and safety.”8 8 Of course, it’s unlikelythat such investigations would unearth theequivalent of a smoking gun. After all, com-panies are more than capable of justifyingmaintenance work. An investigation byFERC found that “generating outages inCalifornia at plants owned by Dynergy, NRG,and Reliant appeared to stem from increaseddemand and age of the units (boiler tube andseal leaks, turbine blade wear, valve andpump motor failures, etc.).”8 9

Economists are divided about the role ofmarket power in explaining the behavior ofCalifornia electricity markets.9 0 Using pub-licly available estimates of the heat rates ofelectric generators and natural gas price data,Severin Borenstein, James Bushnell, andFrank Wolak from the Universities ofCalifornia-Berkeley and Stanford generatedestimates of the marginal costs of electricity.They then compared those estimates withactual prices observed on the CaliforniaPower Exchange. They argue that the exerciseof market power raised California electricityprices at least 16 percent above the competi-tive level (marginal cost) from June 1998

11

Supply anddemand shocksexplain theDecember 2000wholesale price inCalifornia but donot explain 5cents per kWh ofthe average AprilthroughNovember price.

through September 1999.9 1 Joskow andKahn studied the summer 2000 Californiamarket and concluded that an inordinatenumber of plants were taken offline formaintenance when the price spikes weremost intense. While that could be coinci-dence, it would also be perfectly consistentwith market power: the withholding of someunits of production to raise the price of elec-tricity produced by other units owned by thesame firm.9 2

An Alternative Explanation: RegulatoryPerversity

But Harvard’s Bill Hogan and ScottHarvey of LECG, a consulting firm, arguethat generators in California priced abovemarginal cost, not because they had marketpower, but because two characteristics of theCalifornia market created incentives forthem to place high bids.9 3 The Californiamarket solicited hourly bids from all genera-tors a day in advance of production. In addi-tion, once the day-ahead market cleared andproduced hourly prices, the ISO asked forbids for reserve power. Under ideal condi-tions, arbitrage would result in similar pricesfor day-ahead and reserve energy in eachhour, but because the ISO auction was con-ducted after the power-exchange auction,uncertainty existed about whether a genera-tor would receive a higher price if it waitedfor the ISO to call on a unit as a reserve unit.This sequential feature converted the day-ahead auction from an everyone-gets-the-market-price auction (and thus generatorswould bid at marginal cost to ensure beingselected to produce as long as costs were cov-ered) to a pay-as-you-bid auction in which allparticipants, if selected, receive what they bidrather than the (potentially) higher market-clearing price.

Under such a market structure, firmslacking market power will bid at expectedmarket-clearing prices rather than at margin-al cost.94 And market-clearing prices for thereserve market during a capacity shortage inwhich retail consumers do not face highprices will be very high indeed because under

the engineering procedures developed by theNERC, electric system operators such as theISO must maintain generation reserves avail-able in 10 minutes regardless of cost.95

Producers have no reason not to name astratospheric price for their power in thosecircumstances because the price they chargewill not alter demand (remember, retailprices are capped and, even were they not,ratepayers face lagged-average rather thanreal-time marginal prices for electricity). AsUniversity of California-Berkeley economistSteven Stoft puts it, “The failure of con-sumers to respond [because of price controls]is the fundamental flaw that makes pricesreach exorbitant levels when there is a littlescarcity or when suppliers have even a littlemarket power.”9 6

University of Maryland and Resources forthe Future economist Tim Brennan arguesthat another characteristic of the Californiaauction market also created incentives forhigh rather than low market-clearing prices.97

The rules of the auction allowed generators tooffer different amounts of electricity at differ-ent prices rather than all of their output at oneprice. Under those rules, generators had theincentive to offer a small amount of their out-put at very high prices because, if the high bidwas accepted, they would receive that price forall their output. And if the bid was not accept-ed, the generators would lose only the sale of asmall fraction of their possible output.Normally such bidding behavior would beunprofitable because the probability of thehigh bid’s being accepted would be small, but,in a very tight supply situation, the probabili-ty of the bid’s being accepted rises consider-ably, and the opportunity cost of the unsoldpower falls.

“Price Gouging” in Perspective Even though perverse behavior by electric

generators—induced either by actual with-holding or by characteristics of the Californiaauction—may have played some role in theprice spike, the populist charge that theentire price spike can be explained by pro-ducer manipulation is clearly nonsensical.98

12

Generators hadthe incentive to

offer a smallamount of their

output at veryhigh prices

because, if thehigh bid was

accepted, theywould receive that

price for all theiroutput.

Input costs and natural scarcities are respon-sible for most of the price hike. Some of thetop economists in the electricity “establish-ment”—individuals on both sides of the dis-pute—agree that, although market manipula-tion may be present, it is not the fundamen-tal cause of the crisis.9 9

Consider the data available on wholesaleprices in January and February 2001. FERCmaintains that it cost 27 cents, on average, toproduce a kilowatt-hour of electricity in nat-ural gas–fired generators during stage 3emergencies in California last January.100 TheCalifornia ISO reported, however, that it paidan average of just over 28 cents for powerpurchased in the real-time spot market.101

During February, wholesale natural gasprices increased dramatically, resulting inFERC estimates of production costs of 43cents per kilowatt-hour during stage 3 emer-gencies.102 Unfortunately, there are no pub-lished data that allow a comparison of theFERC estimate and actual prices observed inthe real-time spot market, but if the Januaryrelationship held in February, wholesaleprices were not more than a few cents higher,on average, than production costs.

To be sure, industry analysts believe thatactual production costs during power emer-gencies are far higher than FERC believes—largely because FERC relies on a monthlyaverage for wholesale natural gas prices thatinadequately reflects day-to-day pricechanges,103 but at least FERC has recognizedthat input prices and the NOx quantityrestrictions explain most of the price increaseand that the highest-cost source of supplynecessary to meet demand sets the legitimateprice for all power sold in the market.104

Big Profits? Big DealThe evidence most commonly used to jus-

tify charges of price gouging is the huge prof-its earned by many independent power gen-erators doing business in California.California Senate president pro tem JohnBurton, for instance, supports his charge ofprice gouging by noting that power genera-tors and power marketers have seen their

profits rise by an average of 508 percent overthe past year.1 0 5But large profit margins arenot themselves evidence of prices above mar-ginal costs of the most-expensive unit.

The key to understanding the electricitymarket is, again, to remember that the high-est-cost source of supply necessary to meetdemand sets the price for all electricity in themarketplace. Thus, inframarginal genera-tors—such as those who have access to cheapgas through long-term contracts or who havehighly efficient power plants—can and do sellat the market-clearing price and make profits(a state of affairs that is found satisfactory byboth FERC and the California ISO).Marginal generators—those who have noaccess to cheap gas or who operate old, inef-ficient plants—have no such market advan-tages and thus fewer profit opportunities.The profits reported in the media largelyreflect the profits made by inframarginal, notmarginal, producers.

Are Environmentaliststhe Culprit?

Many observers have argued that theCalifornia electricity shortage is the result ofenvironmentalists’ and consumer activists’efforts to block new generation and transmis-sion capacity, slowly starving the state of need-ed power.106 California’s reserve generatingcapacity decreased from 40 percent in 1990 to15 percent at the beginning of 2000.107 Lastsummer, demand for electricity was up 23 per-cent compared to 1992, yet generating capaci-ty had grown by only 6 percent.108

A Murder with No Body?Although it’s certainly true that California

has not seen a boom in power plant construc-tion over the past decade, the claim that nonew power plant has been built in Californiain more than 10 years is utterly false.According to the California Energy Commis-sion, 11 power plants (10 gas fired, 1 coalfired) with a generating capacity of 1,206 MWbegan operation in California in the 1990s.109

13

Although marketmanipulationmay be present, itis not the funda-mental cause ofthe crisis.

Only two licensed projects with a generatingcapacity of 229 MW were dropped in the1990s (one because of bankruptcy), and onlyone project was blocked by communityactivists: a 240 MW set of barge-mounted gen-erators that were to supply peaking capacity tothe San Francisco Bay area.

Opposition to new power plants is notconfined to environmentalists, and someenvironmental groups actually support newplants. The Calpine Co. has proposed build-ing a 600 MW gas–fired plant in San Jose.Many environmental groups, including theSierra Club, actively support the plant. Themain opponent, ironically, is the Internetgiant Cisco Systems, which fears that a powerplant near its facilities would be aestheticallyunpleasing and thus reduce its ability toattract employees.110

Not only were environmentalists a relativenonfactor in generator investment decisionsin the early to mid-1990s, they scarcelyplayed any role in blocking new capacity inthe months leading up to the crisis. SinceGovernor Davis was elected in 1998,California has approved the construction of9 power plants, and 44 plants with 22,600MW of generating capacity are currentlyunder consideration by the California EnergyCommission.111 All of them will almost cer-tainly be approved, but they will take severalyears to build.112 Tens of thousands of addi-tional megawatts of capacity are under con-struction in other states that are part of thewestern regional electricity grid. A new studyby Resource Data International, a division ofFinancial Times Energy, concludes, “Even inthe West, where shortages and unprecedent-ed high prices have been the rule in 2000,more than enough new capacity is underdevelopment to bring power markets intobalance and perhaps provide a mild over-cor-rection within the next couple of years.”1 1 3

One could argue that investors’ fear ofenvironmental opposition and the costs offighting that opposition to a successful com-pletion explain the lack of plant constructionin the 1990s, but little evidence exists to sup-port that claim.

More obvious explanations for the lack ofinvestment in new capacity are low prices andregulatory uncertainty. As discussed earlier,wholesale power prices in California were solow that there was little profit to be gained byincreasing production. William Keese, chair-man of the California Energy Commission,explains that the demand for generation thatbuilt up through the 1990s was for “needlepeak demand,” defined as the additional sup-ply that would be needed to meet a 4,000 MWsurge on the third consecutive day of record-high temperatures. Such peaks are rare (31 inthe last 40 years), making new peaking capaci-ty difficult to pay for. “To say people shouldhave built power plants is not rational becausethey would have lost money.”114

Moreover, regulatory uncertainty keptinvestors out through much of the mid-1990s. No power plant applications werefiled with the California Energy Commissionfrom 1994 to 1998 because of the investoruncertainty created by deregulation.1 1 5

Low prices and regulatory uncertaintyalso explain why states in which environmen-tal activism is low experienced no moreinvestment in new power plants thanCalifornia. Arizona’s population grew 40 per-cent in the 1990s. The state has a pro-busi-ness climate, and yet its power productionrose only 4 percent during the 1990s, mostlyat existing plants. No one applied to build amajor plant in Arizona between the late1980s and late 1999.116

If California had built more power genera-tors during the 1990s, they would almost cer-tainly have been gas–fired facilities becausethose were the cheapest and easiest plants tosite. And because the electricity price increaseis largely a reflection of the regional increase inthe price of natural gas, those hypotheticalplants would have reduced California pricesonly if enough plants had been built so thatthe new plants (with their lower heat rates)became the marginal source of electricity(rather than older natural gas plants withhigher heat rates) and enough plants had beenbuilt to eliminate any scarcity rents that arecurrently in California prices.

14

Obvious explana-tions for the lackof investment innew capacity are

low prices andregulatory

uncertainty.

In short, given the increase in natural gasprices observed in California, a massiveinvestment in natural gas plants would stillhave resulted in 15 cent per kWh electricity.And if retail consumers were still paying 6.7cents per kWh, bankruptcies and blackoutswould still occur.

Environmentalist and NIMBY (Not in MyBack Yard) agitation, however, has sloweddown the regulatory approval process, whichrequires much more time in California than inother states (several years versus severalmonths). A running joke reportedly popularat the California Energy Commission is that“no plant gets approved unless the paperworkweighs as much as the plant itself.”117 Theinability to respond quickly to the supplyshock with new power generation can fairly beblamed on rules written to please California’sactivist community, but again, the Greens arebut one part of that community.

Did Killing the Nukes Kill California?California’s well-known campaign against

nuclear power has also been blamed for thecrisis. In 1989 the nuclear reactor at RanchoSeco was prematurely decommissionedbecause of environmentalist agitation, sacri-ficing 913 MW of power daily. In 1992 theSan Onofre Unit-1 reactor (one of three reac-tors on the site), generating 436 MW ofpower daily, met the same fate.

Blaming the crisis on California’s anti-nuclear activists, however, makes little sense.First, even states without well-organized anti-nuclear organizations and growing electricitydemand failed to attract investment innuclear power, suggesting that other factorswere at work in discouraging investment innuclear power plants. Second, naturalgas–fired plants throughout the 1990s weresimply better investments than nuclearpower plants; they were quicker and cheaperto build and, with fuel costs so low, not thatmuch more expensive to operate.1 1 8 Evenwithout state prohibitions and environmen-talist opposition, it’s extremely unlikely thatinvestors would have chosen to build nuclearplants instead of gas–fired generators.

Similarly, if the Rancho Seco and the SanOnofre Unit-1 reactors had been kept open,prices would be lower today only if the extranuclear capacity reduced the number ofhours in the day for which natural gas unitsset the market price. But neither hydro nornuclear is the costliest source of power dur-ing the daytime, and thus they have no effecton daytime prices. Additional nuclear capac-ity could have lowered off-peak prices if ithad been used instead of natural gas unitsduring off-peak hours.

We repeat: wholesale prices are driven bythe costliest source of power at the margin,so the price shock would have been morebenign had those nuclear plants been onlineonly if they had displaced the use of naturalgas during off-peak hours. An additionaldaily supply of 1,400 MW might well haveheaded off some of the blackouts, butbecause transmission constraints into north-ern California play such a large role in thoseblackouts, only the 913 MW from RanchoSeco, located near Sacramento, would havehelped.1 1 9

How Green Is the Grid?Concern only about California’s generating

capacity, however, ignores the fact that theelectric power market in the West is one large,interconnected system. There is no reason todemand that California internally generate allits power any more than to demand thatRhode Island produce all the food it con-sumes. Generation not built in San Franciscofor Bay Area ratepayers, for example, simplygets built elsewhere in Utah, Arizona, orNevada and is sent to the Bay Area over wire.

But the transportation of electricityrequires transmission capacity. Even thoughtransmission capacity costs only one-tenth asmuch as generation, landowners and otherlocal residents resist new transmission capac-ity.120 From 1989 through 1997, transmis-sion capacity per MW of summer peakdemand declined by 16 percent. Between1997 and 2007, transmission capacity rela-tive to summer peak demand is expected todecline another 13 percent.121

15

The inability torespond quicklyto the supplyshock with newpower generationcan fairly beblamed on ruleswritten to pleaseCalifornia’sactivist community.

But the problem of transmission con-straints exists all over the country, not just inCalifornia. While environmentalists havebeen known to agitate against new powerlines, they’re scarcely the only—or even thelargest—group of NIMBY-ites to do so.

Moreover, the lack of new transmissioncapacity—like the lack of new generation capac-ity—has as much to do with economics as withpolitics. Incumbent utilities have little incentiveto build new capacity that would make it easierfor ratepayers to buy cheaper power from com-petitors in neighboring states.122 And utilitiesdo not have an incentive to invest in new capac-ity when the profits allowed them by regulatorsare too low to make those investments particu-larly worthwhile relative to unregulated invest-ments.123 And with transmission rules still upin the air and unsettled at both the federal andstate level, regulatory uncertainty is also damp-ing investment.124

News stories also claim that natural gaspipeline capacity constraints are the productof environmentalist or NIMBY-ite opposi-tion.125 But there is little evidence to suggestthat investors have been inhibited fromincreasing pipeline capacity when profitopportunities presented themselves. Extensivenew pipeline capacity into northern Californiafrom Canada, for example, was built in the1990s.1 2 6 The Energy Information Adminis-tration observes that pipeline capacity “hasgrown with end-use demand, and as new sup-plies have developed, new pipelines have beenbuilt to bring this gas to markets.”1 2 7The GasResearch Institute likewise finds that “growthin pipeline capacity is not a constraint ongrowth in gas supply. . . . If supply is available,history has demonstrated that the pipelineswill be built as needed. It is simply an invest-ment and engineering issue.”128

Little pipeline capacity into southernCalifornia was added during the past decadebecause investors found few opportunitiesfor profit in the construction of newpipelines. The existing pipelines were notfully utilized until this year.1 2 9 High naturalgas prices, however, have revived interest inpipeline capacity expansions, and three sig-

nificant projects were recently announced totake advantage of the newly discovered prof-it opportunities in transmission.130 Clearly,the barriers to pipeline expansion in Califor-nia are not too terribly high when profitopportunities exist.

Accordingly, it’s hard to single out theenvironmentalists as the “cause” of transmis-sion constraints. While they’ve certainlyplayed a role in opposing grid expansion,even states without well-organized environ-mentalist lobbies have found it difficult toremedy transmission congestion.

Did Other States Adopt“Better” Designs Than California?

Many analysts have argued that otherstates deregulated more intelligently thanCalifornia and thus did not experience thesame high prices and shortages.1 3 1 After all,the average price for wholesale power inCalifornia was $313 per MWh in the middleof January 2001 compared to $74 per MWhin New England, $63 per MWh in New York,and $39 per MWh in Pennsylvania, NewJersey, and Maryland.132

Fuel Inputs Explain AllAlthough other states have restructured

their electricity regulations differently thanCalifornia has and have not experienced largewholesale price increases, the characteristicsof the state plans are not responsible for thelower prices. Pennsylvania, for example, didnot force utilities to sell off nearly as manygenerating assets as did California andallowed long-term contracting for power andestablished a more robust retail and whole-sale market of competing suppliers.133 Butthe price differential between power inCalifornia and power in the other states thatrestructured their electricity regulations isthe result of fuel composition, not of a “bet-ter” regulatory climate.

States east of the Rocky Mountains do notrely on natural gas for their electricity during

16

The lack of newtransmission

capacity—like thelack of new gener-

ation capacity—has as much to dowith economics as

with politics.

the winter (and only a few rely heavily on nat-ural gas during peak-demand periods in thesummer). For example, during the first ninemonths of 2000, 19 percent of electricity wasgenerated by natural gas units in NewEngland, 18 percent in New York, 49 percentin California, and only 4 percent in Pennsyl-vania, New Jersey, and Maryland.1 3 4 Easternstates’ reliance on nuclear, coal, and hydro-power (which in the East has not sufferedfrom drought) in the winter explains why theelectricity crisis has been confined thus faralmost exclusively to California and neighbor-ing states, which have had to substitute natur-al gas for hydro in the production of electrici-ty in the winter.

If major exogenous supply and demandshocks were to hit the states touted as dereg-ulatory “successes,” they, too, would findthemselves experiencing an increase inwholesale electricity prices. Blackouts wouldprobably not occur, however, because, as bestas we can tell, all states except California havefuel pass-through provisions that allow ris-ing fuel costs to be incorporated sooner orlater into electricity rates.1 3 5

Is Coal “Better” Than Gas?In light of the above, some people might be

tempted to argue that California “went wrong”by not embracing coal generation. A typical coalplant is more expensive (almost four times) tobuild per kW of capacity and less efficient tooperate (more Btu from coal are required togenerate a kWh of electricity than Btu from nat-ural gas in a new combined-cycle plant), but thecost of coal per million Btu of heat output isless than that of natural gas.136 Thus compar-isons of the two technologies require a compar-ison of capital and expected fuel costs at expect-ed utilization rates. In 1996 two EIA analystsdetermined that under all reasonable scenariosnatural gas plants are more cost-effective thancoal.137 The EIA again echoed that finding lastyear in Annual Energy Outlook 2001: “Natural gastechnologies tend to dominate projected capac-ity additions because the total cost of electricitygeneration from these technologies is less thanthe other options.”138

Thus, California regulators cannot befaulted for not encouraging additional coal-fired generation. Investors, not state regula-tors, determine what sort of power plants arebuilt, and investors acted rationally byeschewing coal-fired facilities in favor of nat-ural gas–fired facilities.

Reservations about Reserve CapacityCan California’s regulatory regime be

blamed for providing less reserve capacity thanis maintained in other states? Does someoneneed to “think about” reserve capacity, or canthe choice be left to market forces?139

New England, New York, and the mid-Atlantic states have installed-capacity require-ments in their deregulated markets. Utilitiesare required to have available generationcapacity to meet their peak demand or facepenalties. New York, for example, sets thepenalty at three times the estimated averagecost of building a peak-demand unit, whichpresumably induces utilities to build or con-tract for sufficient peak-demand units.140

California and Ontario do not have installed-capacity regimes. When supplies are tight inthose regions, prices will rise sufficiently toinduce the installation of new supply.

Retail power prices in the installed-capac-ity regimes are higher, on average, to pay forthe excess capacity, but peak prices are prob-ably lower.141 But damped peak prices, ineffect, socialize the costs of meeting peakdemand and induce less consumption reduc-tion by consumers during peak periods, bothof which are economically inefficient. Theinstalled-capacity regimes are a holdoverfrom the cost-of-service regulated era with itsbias toward new supply rather than demandreduction through the use of price signals.

In an unregulated market, excess capacitywould lead to prices equal to marginal cost.Because electricity generation is very capitalintensive (thus fixed costs are high relative tomarginal costs), firms would not recovertheir fixed costs under marginal cost pric-ing.142 Thus excess capacity would be builtonly if subsidies were offered or regulationsenacted rather than as the result of simple

17

Eastern states’reliance onnuclear, coal, andhydropower inthe winterexplains why theelectricity crisishas been con-fined almostexclusively toCalifornia andneighboringstates.

market forces. Therefore, unregulated elec-tricity prices will be more volatile than pricesin other markets in which marginal costs arenot much lower than average costs. ThoughCalifornia may appear to provide evidence ofthe failure of the market system and supportfor the installed-capacity regime, that is trueonly because of retail price controls, whicheliminate demand reduction when suppliesare tight and exacerbate the price increasesobserved in the wholesale market.

The Difference between California andthe Rest of the West

Even though electricity regulation andpolicy discussion occur at the state level, theUnited States really has three electricity sys-tems: the eastern interconnection, the west-ern interconnection, and the Texas system,which has limited direct- rather than alter-nating-current connections with the easterninterconnection.

The focus on California creates theimpression that the other states in the west-ern interconnection are exempt fromCalifornia’s difficulties. That is only partiallycorrect. Because electricity supplies arebought and sold all over the western inter-connection, in the absence of transmissionconstraints, transportation-cost-adjustedprices everywhere in the West will be thesame.143 Thus it is not possible for any west-ern state to insulate itself from a shock tosupply or demand that occurs anywhere inthe western interconnection.144

Even though the transmission grid doesnot allow states to insulate themselves fromeach other’s electricity situations, the percep-tion exists that other western states built moresupply than did California in the 1990s rela-tive to demand increases and thus are shoul-dering more than their share of responsibilityfor electricity supply.145 That is incorrect.

Demand has been exploding outsideCalifornia, and supplies have not increasedcommensurately. Eighty-five percent of thegrowth in electricity demand in the West since1995 has occurred outside California.146 Butno state except Montana has increased electric

power production more than populationgrowth. In the 1990s Arizona’s populationgrew by 40 percent and electricity demandgrew at nearly double that rate, but power pro-duction rose only 4 percent despite Arizona’shaving almost none of the environmentalrestrictions blamed for keeping Californiafrom expanding capacity.147 In Nevada duringthe same period, population grew by 66 per-cent but power production by only 44 per-cent.1 4 8 John Harrison, a member of theNorthwest Power Planning Council, whichrepresents Idaho, Montana, Oregon, andUtah, said: “Our supply is extremely tight too.We haven’t been building any new powerplants either.”149

The main difference between Californiaand other western states and the explanationfor the lack of “crisis” mentality in the otherstates is that the latter have increased prices toconsumers whereas until recently Californiahas not. Nevada will have raised residentialrates by 75 percent from 2000 to 2003.150

Rates in Tacoma, Washington, have risen 50percent, and utilities in Idaho, Arizona, andUtah have also announced large increases.151

These price increases are average rather thanreal-time, but at least prices are rising. Thusutilities do not go bankrupt, and suppliers donot withhold because of fears of nonpayment.

The Rescue Plans

A number of initiatives have been under-taken to alleviate the power crisis inCalifornia, and other plans remain on thedrawing board. Unfortunately, few if anyaccurately diagnose the problem or treat any-thing beyond the superficial economic symp-toms of the underlying disease.

Price ControlsGov. Gray Davis and most of the

California political establishment believethat political management of supply shocksis better for consumers than economic man-agement via free prices. Their argument issimple: When supply and demand are fairly

18

The main differ-ence between

California andother western

states is that thelatter have

increased pricesto consumerswhereas until

recentlyCalifornia has

not.

rigid in the short run—in this case, because ofboth natural market characteristics and bur-densome regulatory policies—high prices willover the short run mostly transfer wealthfrom consumers to firms rather than inducenew supply or decrease demand. This is par-ticularly true for baseload coal and nuclearplants, the marginal costs of operation ofwhich are much less than those of the oldinefficient natural gas units used to meetaggregate demand in California.152 So gov-ernments institute price controls and issuelegal orders to require supply increases anddemand reductions rather than allow pricesto achieve the same result.

What if regulators attempted to reducewholesale prices by restricting the profitopportunities of inframarginal supplierswith, say, a windfall profits tax or some sortof “cost-plus” rate cap? Negative supply anddemand effects would likely result.

On the supply side, such policies wouldreduce the incentive to invest in cheap energyproduction. After all, why care whether yourplant is more efficient or cost competitivethan the competition if the state ensures thatyour profit margins are no greater than thoseof your less-efficient competitors? Such poli-cies would also bias investment away fromfacilities with high up-front costs and lowmarginal costs (coal, nuclear, and mostrenewables) and toward facilities with lowerup-front costs and higher marginal costs(natural gas and fuel oil). Both fuel diversityand economic efficiency would suffer.

On the demand side, mandating pricesbelow market-clearing levels would send thewrong price signals about the cost of con-suming additional units of electricity, artifi-cially increasing demand at the very time thatdemand reductions are necessary to preventcollapse of the grid into blackout status.Such a demand increase would have the per-verse effect of actually increasing the price ofpower from marginal suppliers (more con-sumers chasing a fixed amount of service).

Can politicians intervene in the electricitymarket to reduce the wealth transfer and yetpreserve the important incentive functions of

prices? In theory, governments can enactprice controls on inframarginal (existing)output but leave incremental supply freefrom controls. This preserves static efficiencyby pricing incremental demand and supplycorrectly and reduces the wealth transferfrom consumers to producers. But, to theextent investment occurs because of the pos-sibility of making profits during periods oftight supply, dynamic efficiency is negativelyaffected by even this policy. In addition, oncethe government controls prices on existingoutput, political struggles ensue over accessto that output. As economist Ben Zycherwarns, “Feel free to bet the rent money on theprospect of politicized electricity rates,designed to subsidize various consumergroups and geographic regions with impor-tant allies in the Legislature at the expense ofother groups.”153

Consider two past policy schemes that areanalogous to the schemes that GovernorDavis proposes for California: the federalintervention in oil markets after the 1973 oilshock and rent control in New York City. TheEmergency Petroleum Allocation Act of 1973allowed “new” supplies of crude oil andincreases from “old” supplies to commandmarket prices but controlled prices for exist-ing supplies. Because of historical patterns,some refineries had 0 access and others 100percent access to old oil, which caused enor-mous variation in profits because gasolinesold at market-clearing prices, which werehigh regardless of the amount of “old” oilused in the refining process. That, in turn, ledto a political fight over access to the wealthcreated by price-controlled “old” oil. Theonly winners were the lawyers who wrote theregulations and tried the cases about whatwas and was not “old” oil and refineries thathad access to cheap “old” oil.154

Similarly, in New York City after WorldWar II rent controls were left on the existinghousing stock, but new units were unaffect-ed. The city has since reneged on its pledge tonot impose controls on units built after1947, and the controls have led to a blackmarket in which access to rent-controlled

19

Once the govern-ment controlsprices on existingoutput, politicalstruggles ensueover access to thatoutput.

units is “sold” with the proceeds going toexisting tenants and brokers rather than tothe legal owners.155

In both the oil and housing policy experi-ments, the wealth transfers suppressed byprice controls were not recycled to the publicat large. They were instead captured by oilrefineries and lucky tenants who happened tolive in price-controlled housing. And becauseof investors’ concerns about future confisca-tion of profits, investment has been less thanoptimal, particularly in NYC housing.

Legal OrdersLegal orders can reduce demand, but at

best they are much more costly to developand enforce than price increases, which leadall people, not just government lawyers, tothink about how to conserve. Even if theywork, many orders have only symboliceffects. And at worst they have perverse eco-nomic consequences.

News articles often describe the manychanges in behavior that mangers proposeafter a legal order is issued. For example, inresponse to an order by the governor to allstate departments to reduce energy use by 5percent, the California Department of WaterResources announced that it would use aque-duct pumps at night rather than during thedaytime peak.1 5 6 The implication is thatorders are effective. But under real-time mar-ket prices, use of aqueducts off peak, as wellas many other changes no one has everthought about, will occur without orderstelling people what to do.

The category of symbolic but ineffectivelegal orders is well represented by GovernorDavis’s proposed regulation to require cardealerships to turn off most of their lights atnight.157 But electricity is relatively cheap andplentiful at night. It’s electricity during thedaytime—particularly on warm summerafternoons and early evenings—that is expen-sive and scarce. Nighttime conservation doesnothing to prevent blackouts.

The perversity of regulation is superblyillustrated by a proposal to ban power produc-ers from exporting electricity to other states.158

Such a regulation would lead to other states’restricting electricity exports to California.And because California typically importsmuch more power annually than it exports,such a trade war would have devastating con-sequences for California ratepayers.159

Subsidizing ConservationDesperate to reduce electricity demand by

some mechanism other than the eliminationof retail price caps, California has adopted an$850 million energy conservation initiative,which consists primarily of programs to sub-sidize ratepayer purchases of energy efficientappliances and technologies.1 6 0

The fundamental problem with such sub-sidies in a price-controlled market is thatenergy efficient appliances reduce the costsof operation. That may not be a major issuewhen it comes to, say, the television set (wewon’t watch more TV just because it costs alittle less to turn on the set), but for appli-ances like air conditioners that make all thedifference during peak-demand periods,energy efficiency simply reduces the margin-al cost of energy services and thus increases—not decreases—energy consumption. This isknown as the “rebound effect,” and it’s beenwell established by economic researchers.161

The upshot is that the gains of energy effi-cient appliances are at least partially offset byincreases in appliance operation time.

It’s not as if we haven’t tried such pro-grams before. Utilities across the nation havespent about $20 billion since the mid-1980sto subsidize ratepayer investments in energyefficiency.1 6 2 Yet examination of the datareveals that utilities that invested heavily insubsidies experienced no reduction in elec-tricity demand relative to utilities that didnot invest in subsidies.163

There are several reasons in addition tothe rebound effect for this. First, most con-sumers who take advantage of these pro-grams are “free riders”; they would havebought those devices with or without thehandouts.1 6 4 Second, the high initial cost ofmany of those technologies (like the fabled$40 light bulb) implies that it can take years

20

Legal orders canreduce demand,but at best theyare much more

costly to developand enforce than

price increases,which lead all

people, not justgovernment

lawyers, to thinkabout how to

conserve.

to recoup the costs of those investments,even after the subsidy. Other investments arefar more attractive by comparison.1 6 5 Third,many of the “wonder-techs” are known to bepoor performers, trading off other consumerconveniences to eke out a little more efficien-cy at the margin. People are understandablyleery of pitching thousands of dollars worthof appliances with years of life left in them toembrace unknown technologies that oftenhave their own problems and save moneyonly after years of operation, if ever.

The hard truth is that people will conserveenergy only when they think that the incon-veniences of doing so are outweighed by themoney saved by such investments or by suchbehavioral changes. Reducing the marginalcost of energy consumption is exactly thewrong approach. And even were it the rightapproach, government programs that puttheir faith in subsidized energy conservationrather than free energy prices helped give usthe California mess in the first place. Only byletting prices do their job can energy conser-vation be achieved. Everything else is politicalsmoke and mirrors.

Public OwnershipSome people in California argue for pub-

lic ownership in addition to price controlsand legal orders. They point out that the LosAngeles Department of Water and Powercontinues to sell power to ratepayers at pricesfar below wholesale prices in the Californiaspot market without incurring the debtsincurred by the investor-owned utilities.

The correct framework in which to ana-lyze LADWP is the one we used in our dis-cussion of installed-capacity regimes.Currently, LADWP has excess hydro- andcoal-fired generators under contract. It sellsthe excess on the spot market, earning largeprofits just like private owners of similarfacilities, and uses the profits to subsidize theconsumption of its current customersinstead of returning them to taxpayers as pri-vate utilities would return profits to share-holders.166

The LADWP policy has the appearance of

a free lunch, but it is not. Until the spring of2000, when those excess supplies becamevaluable on the spot market, in order to payfor the unused excess capacity, LADWP cus-tomers had to pay more for electricity thanthey would have paid in a spot market.

In addition, if LADWP supplements thosepower supplies with gas–fired electricity, itsincremental costs are similar to those of pri-vate generators. But unlike the deregulatedwholesale market, LADWP prices its outputon a weighted-average basis passing on thelow costs of coal and hydro to consumersrather than charging for all output on thebasis of the price of the most expensive input,natural gas. As we demonstrated earlier, suchpricing is unsustainable because it encour-ages extra demand, the costs of which aremore than incremental revenues. Eventually,LADWP will have to obtain more capacitythan it would under marginal-cost pricingbecause consumers are not charged enoughto reflect their incremental demands on thesystem and thus LADWP’s ultimate costs arehigher than they otherwise would be becauseof its pricing policies.

Long-Term ContractsIn early February, the California legislature

adopted A.B. 1X, authorizing the state to direct-ly contract with generators and marketers forelectricity. Governor Davis, the author of theplan, hoped that 95 percent of the state’s elec-tricity demand could be secured through suchcontracts, leaving only 5 percent of the state’sneeds to the spot market. The governor furtherhoped that 3- to 10-year contracts would allowCalifornia to lock in prices at a weighted averageof 5.5 cents per kWh ($55 per MWh). Davis’sexpectations were dashed, however, when 38power suppliers submitted bids at a weightedaverage of 6.9 cents per kWh.167 Although thegovernor announced that the state had agreedto pay $42 billion for this power over 10 years,little else is known of the arrangements.168

But will the contracts really lower pricesfrom current spot levels? First, the 6.9 cent fig-ure is for nonpeak rather than peak supply.While information is sketchy, reports suggest

21

Only by lettingprices do theirjob can energyconservation beachieved.Everything else ispolitical smokeand mirrors.

that bids for long-term peak supply averagearound 25 cents per kWh.169 Second, the 6.9cent figure is a weighted average. As discussedearlier, the proper price for electricity is not theaverage price but the price paid for the mostexpensive source used during any one-hourperiod. Even if the state were to resell thatpower to ratepayers at cost, it would presum-ably be sold on the basis of the average acqui-sition cost and thus would be priced too cheaprelative to an unregulated market.

If long-term contracts could hold downmarket-clearing prices in free markets, whatare we to make of the natural gas market?According to the American Gas Association,only 9 percent of all wholesale natural gas pur-chases are made from the spot market,170 butthe price spike occurred. If long-term con-tracts could dampen wholesale prices duringspikes, we wouldn’t have seen anything likethe natural gas price explosion of 2000–01.

There’s also good reason to think thatlong-term contracts signed by the state willbe more expensive than long-term contractssigned by private parties. Because futurepoliticians will be tempted to renege on thosecontracts if spot prices fall below the contractprice, producers will include a premium intheir bids to cover that risk. Confidence inthe state’s good faith is not enhanced by thecurrent talk of confiscating plants and crim-inalizing pricing activity when prices are arbi-trarily thought to be “too high.”171

Regardless of the details of California’sarrangements, the argument that long-termcontracts will reduce costs in the long run isitself extremely dubious. First, there is thequestion of timing. As Nobel Prize–winningeconomist Daniel McFadden recently point-ed out, “Negotiating long-term contractsright now, when California is in a weak mar-ket position and out-of-state generators arein the driver’s seat, is likely to put the state ata future competitive disadvantage.”172

Remember, below-market prices in theshort term can come only at the expense ofabove-market prices for years to come, andlocking in long-term prices at the peak of aprice spike is hardly the best way to minimize

cost in the long run. Peter Navarro, a profes-sor of economics at the University ofCalifornia-Irvine, estimates that, by 2003 orso, wholesale electricity prices in Californiawill average about 5 cents a kilowatt-hour,given the additional generating capacityunder construction or in the planning stages.“By using huge sums of taxpayer money tolock in long-term power contracts, Californiais making a mistake that will haunt its econ-omy for years.”173

Second, long-term contracts do not offera “better deal” than spot market purchases.174

Borenstein writes, “On average, a purchaser buy-ing power in forward markets (or through long-term bilateral contracts) will not receive lowerpower costs than a purchaser buying in the spotmarket.”1 7 5 Long-term contracts simply real-locate the risk of price volatility from theconsumer to the generator or marketer thatprovides the fixed-price guarantee. But theguarantee is not free. Sellers of such guaran-tees require a premium to accept this reallo-cation of risk. Generators (or marketers) donot offer fixed prices that result in lowerreturns than sales on the spot market. In fact,spot market prices for electric and gas utili-ties have historically been more favorable toconsumers than contract prices.176

Everyone has forgotten that we’ve beendown this road before. In the late 1970s, soar-ing electricity prices led Congress to pass thePublic Utility Regulatory Policies Act. Thatlaw forced utilities to sign long-term con-tracts with independent power producers atthe costs a utility would avoid because it didnot have to build new supply itself.Regulators in California and New York set“avoided cost” administratively at ratherhigh levels on the basis of the expectation ofhigh prices for conventional fossil fuels, andutilities signed long-term contracts based onthose expectations.177 It seemed like a gooddeal at the time. But when electricity pricescollapsed in the mid-1980s, the power com-panies had to keep buying this power whilespot prices were around 2–3 cents per kWh.Largely because of the PURPA contracts,Californians by the mid-1990s were paying

22

Long-term con-tracts do not offer

a “better deal”than spot market

purchases.

35 percent more for their electricity thanratepayers in other states.

An important goal of California’s mis-named “deregulation” of 1996 was to elimi-nate the cost disadvantage for California con-sumers created by the long-term PURPA con-tracts. If power generators had to competewith one another and sell in a spot market, thereasoning went, ratepayers would never againbe saddled with such contractual boondog-gles. Of course, California went overboard.The state has no business telling companieswhat kind of contracts they can and cannotsign and under what terms and conditionsthey can and cannot enter a market. But that’snot to say that a wholesale replay of the disas-trous 1970s regime is in order.

What if California’s utilities had signedlong-term contracts before the wholesale elec-tricity price increases occurred? Wholesaleprices would still be sky-high. That’s becausethe causes of the increase—skyrocketing whole-sale natural gas prices, a decline in regionalhydroelectric power because of a three-yeardrought, and sharp weather-related increasesin demand—have little to do with state policy.Had utilities entered into long-term contractsbefore the spike hit, independent power pro-ducers would be obligated to sell power at, say,6 cents per kWh despite the fact that it coststhem 15–50 cents per kWh to make thatpower. It wouldn’t be long before the indepen-dent power plants started to declare bankrupt-cy and tear up the contracts, which is whathappened during the mid-1980s in the naturalgas industry. It’s already happening to the fewgenerators (including Enron) that signed long-term contracts in California.178

The Best Way Out

The electricity crisis in California willmost likely run its course by 2003 or 2004regardless of what the state or federal govern-ment does or does not do in the meantime.179

As noted previously, huge investments innew electricity generation will be largelyonline by then, eliminating the supply short-

age and bringing prices down to—or evenperhaps below—historic levels.180 Moreover,investments in natural gas supply driven bytoday’s high wholesale prices will almost cer-tainly burst the gas price bubble even if thefederal government refuses to open promis-ing gas fields on public lands currently off-limits to the industry.1 8 1

As the old saying goes, however, “in thelong run, we’ll all be dead.” It’s the short runthat counts now in California. How can thestate get through the next two years so that amarket-driven return to normality occurswith the least amount of economic pain?

At the time of this writing, California isalleging that it will have enough power at itsdisposal to meet summertime demand. Butunless the state is the beneficiary of extreme-ly mild weather, those assertions are thread-bare and wishful thinking.182

Kill the Retail Price CapsEven Governor Davis understands that

the repeal of retail price controls is the surestand quickest solution to the problem: “If Iwanted to raise prices, I could solve this prob-lem in 20 minutes.”1 8 3 Initially, he did notchoose to do so because of the perceptionthat demand is fixed in the short run and notsignificantly affected by price. Thus, freeingelectricity prices would simply allow suppli-ers to charge whatever they wish, transferringwealth from consumers to producers.184

Very little evidence exists on the effects ofchanges in electricity prices on demandbecause, under regulation, prices have notbeen allowed to vary much. But consumers inSan Diego were part of a natural experimentfrom July 1999 through the end of August2000. Under the terms of A.B. 1890, SanDiego Gas and Electric had accumulatedenough extra revenue from the start of“deregulation” in April 1998 to recover itsstranded costs by the end of June 1999, so itsrates were freed from controls and became afive-week moving average of wholesaleprices.185 By the time rate controls were reen-acted after August 2000, retail rates had dou-bled. Bushnell and Mansur estimate that,

23

Even GovernorDavis under-stands that therepeal of retailprice controls isthe surest andquickest solutionto the problem.

after controlling for weather and othersources of non-price-related demand varia-tion, a doubling of prices resulted in ademand reduction of 2.3 percent.186

This is an extremely low price elasticity,giving some support to the sentimentsexpressed by Governor Davis. But becauseCalifornia politicians were already discussingrate rollbacks during the summer of 2000,consumers may not have altered demand asmuch as they would have if they had believedthat market prices were permanent.Ratepayers probably altered their investmentand consumption very little because theybelieved (correctly) that the rate hikes wouldbe temporary. Had they been convinced thatprices would stay high for some time, evengreater demand reductions would have beenobserved. Thus, the price responsiveness esti-mated by Bushnell and Mansur should beconsidered an extreme lower bound of thetrue value.

There is circumstantial evidence to backthis point. Energy consultant Bill LeBlancreported in a recent study that large com-mercial, industrial, and institutional con-sumers consider 17 percent of their aggregatedemand load “nonessential” and that, wereretail electricity prices at 50 cents per kilo-watt-hour (a threshold crossed by the whole-sale market on dozens of occasions over thepast year), 27 percent of the demand fromthose firms would be eliminated, resulting in“a huge, cost-effective dent in California’selectricity shortfall.”187

Price controls in petroleum markets in the1970s were also justified on the basis of thelack of short-run price responsiveness on thepart of consumers. But petroleum marketshave been free of controls since the early1980s, and in 1990–91 and 2000 price shocksoccurred. How did consumers respond?

In 2000 gasoline prices increased by about50 percent. Despite the booming economy,all those SUVs, and an aggregate increase invehicle registrations of 1.8 percent, aggregategasoline consumption declined by about 1percent from 1999, the first nonrecessionreduction in recent history.1 8 8 Ronald J.

Planting, manager of information and analy-sis at the American Petroleum Institute, said,“The increase in prices was enough to spur atleast some consumers to lessen lower prioritytravel and take other fuel-saving mea-sures.”1 8 9 The belief that high prices do notaffect demand in relatively inelastic marketsand that voters will not accept price increasesdoes not hold in gasoline markets. Given theinelasticity of both the supply and thedemand side of the electricity market, evenmoderate reductions in demand, as a resultof freeing prices, would have a major effecton wholesale prices.

Institute Real-Time PricingAlthough eliminating retail rate caps is a

crucial component of any reform, it will fallshort of fixing the fundamental problem inthe electricity market. Monthly charges basedon average costs do not keep up with thedaily fluctuations in wholesale prices. Nor dothey send the correct signals regarding mar-ginal costs, a flaw long understood even byenvironmentalists who argued that average-cost pricing produced artificially low pricesand, thus, excessive energy consumption.

Unfortunately, few consumers in Califor-nia or elsewhere have meters that can registerhourly consumption. The installation ofload-sensitive meters would take time, butthe technology is well established. In fact,load-sensitive meters have operated well inFrance for years.1 9 0Borenstein proposes thatlarge commercial users be required to usereal-time meters by this summer. The largest18,000 customers account for about 30 per-cent of peak load in California, and the 10million remaining customers account for theremaining 70 percent.1 9 1 Borenstein believesthat real-time pricing for the largest cus-tomers would have large benefits for the sys-tem as a whole because generators wouldthen worry about the possible demand-reduction consequences of their pricingbehavior. And the cost, time, and politicaldifficulties of installing real-time meters forthe remaining 10 million customers wouldbe avoided.

24

Monthly chargesbased on averagecosts do not keepup with the daily

fluctuations inwholesale prices.Nor do they send

the correct signalsregarding margin-

al costs, a flawlong understoodeven by environ-

mentalists.

According to EPRI (formally known as theElectric Power Research Institute), users of8,000 MW of load in California already havereal-time meters in place.192 If real-time pricingwere available on a voluntary basis, EPRI esti-mates that peak demand would be reduced by2.5 percent and prices by 24 percent.193

Abolish the ISOThe underlying belief animating the case

for control of the day-to-day operation of thepower grid by a nonprofit stakeholder-gov-erned institution (the ISO) is the idea thatefficient operation of the grid is more anengineering challenge than an economicchallenge. That belief is dubious in theory,and it has been destructive in practice.

Economist Robert Michaels persuasivelyargues that efficient investment decisions aremost likely to result from a form of gover-nance in which wealth maximization is thesole interest of the governors. And becausethe ISO is an organization of stakeholders(industrial and residential consumers, gov-ernment buyers, marketers, independentpower producers, environmentalists, andunion representatives), battles about distrib-ution, rather than wealth maximization andeconomic efficiency, are likely to dominateits decisionmaking because the membersmanage an asset that they do not own.194

The operation of the grid should there-fore be given back to the utility owners. Toaddress the concern that utilities will manip-ulate traffic along the grid to disadvantagecompetitors, generators and large consumersshould be allowed to purchase equity inter-ests in the grid. This would help to resolvedisputes and provide the necessary incentivesfor efficient operation and improvement ofthe system. A similar arrangement for inter-state oil and gas pipelines works well with lit-tle litigation or government intervention.195

Conclusion

H. L. Mencken once said that “democracyis the system that lets the people say what

they want and then gives it to them, goodand hard.” That appears to be the case inCalifornia today. A recent Field poll askedCalifornians whether they would prefer aregime that capped the retail prices of elec-tricity but produced the occasional blackoutor a regime that had higher retail prices butno blackouts. Nearly two-thirds of therespondents favored the former.196 GovernorDavis is imposing an East German policy onthe electricity market because mostCalifornians prefer it.

A return to the old pre-1996 monopoly,cost-of-service, obligation-to-serve regimepromises little. California regulators havedemonstrated that they’re not very good atoverseeing that sort of enterprise. Remember,electricity rates in those “good old days” were35 percent above the national average by theearly 1990s.197

A complete state takeover of the systempromises even less. The problem with stateownership of industries in, say, EastGermany was not that those industries wererun by ignorant East Germans rather thansmart Californians. If the 20th century hastaught us anything, it’s that government is ahorrible business manager and an incompe-tent economic planner no matter whatindustry we’re talking about or what thenationality of the planner may be.

The simple fact is that high prices forpower must be paid. Because it’s politicallydifficult to have ratepayers pick up the tab ontheir monthly bill, California’s politicianshave decided to have taxpayers pick up thetab out of the state budget surplus. SoCalifornians will not escape high prices. Theproblem with paying bills that way, however,is that the high prices will not affect electric-ity demand and thus will not play theirintended role in allocating scarce goods asthey would if they were simply passed onthrough the market.

Our arguments are not particularly contro-versial within academia. Electricity economistsidentified with both the left and the right havemade similar arguments in “Manifesto on theCalifornia Electricity Crisis,” produced under

25

Governor Davisis imposing anEast German policy on the electricity marketbecause mostCalifornians prefer it.

the auspices of the Institute of Management,Innovation, and Organization at the Universityof California-Berkeley.198 That’s largely becausethe California electricity crisis is not really astory about environmentalists gone bad,deregulatory details ignored, or unrestrainedcapitalists running amuck. It’s a story aboutwhat happens when price controls are imposedon scarce goods.

NotesThe authors would like to thank Douglas Hale,Tim Brennan, Richard Gordon, Rob Bradley, andCharlotte Le Gates for their comments on earlierdrafts of this paper.

1. In 1996 average revenue per kilowatt-hour was6.9 cents for the United States and 9.3 cents forCalifornia. In 1996 average revenue per kilowatt-hour for residential customers was 8.4 cents forthe United States and 11.3 cents for California.See Energy Information Administration, ElectricPower Annual 1996, vol. 1, Tables 21, 27, pp. 37, 42,http://tonto.eia.doe.gov/FTPROOT/electricity/0348961.pdf.

2. For a discussion of why the rate-of-return regulato-ry system, which seemed to work satisfactorily for somany decades, finally broke down, see PeterVanDoren, “The Deregulation of the ElectricityIndustry: A Primer,” Cato Institute Policy Analysis no.320, October 6, 1998, pp. 3–8. For a discussion of thepolitical dynamics that forced legislative restructuringin the mid-1990s, see Benjamin Zycher, “MarketDeregulation of the Electric Utility Sector,” Regulation15, no. 1 (Winter 1992): 13–17.

3. A.B. 1890 can be read in its entirety at the ReasonFoundation’s “California Electricity Crisis Center,”http://www.rppi.org/electricity/background. html.

4. Robert Michaels, “Stranded in Sacramento: Cali-fornia Tries Legislating Electricity Competi-tion,”Regulation 20, no. 2 (Spring 1997): 52–56.

5. Peter Passell, “A Makeover for Electric Utilities,”New York Times,February 3, 1995, p. C1. A Departmentof Energy study in 1997 placed the figure at between$72 billion and $169 billion. U.S. Department ofEnergy, Energy Information Administration, ElectricityPrices in a Competitive Environment, p. ix.

6. See Alfred Kahn, “Let’s Play Fair with UtilityRates,” Wall Street Journal, July 25, 1994, p. A15;James Q. Wilson, “Don’t Short-Circuit Utilities’Claims,” Wall Street Journal, August 23, 1995, p. A12;

William J. Baumol and J. Gregory Sidak,Transmission Pricing and Stranded Costs in the ElectricPower Industry (Washington: American EnterpriseInstitute Press, 1995); William J. Baumol, Paul L.Joskow, and Alfred E. Kahn, The Challenge for Federaland State Regulators: Transition from Regulation toEfficient Competition in Electric Power (Washington:Edison Electric Institute, 1995); and J. GregorySidak and Daniel F. Spulber, Deregulatory Takingsand the Regulatory Contract (New York: CambridgeUniversity Press, 1997). For a summary of the argu-ments, see Peter Fox-Penner, Electric UtilityRestructuring: A Guide to the Competitive Era (Vienna,Va.: Public Utility Reports, 1997), pp. 390–97.

7. For arguments against stranded-cost recovery, seeRobert Michaels, “Stranded Investments, StrandedIntellectuals,” Regulation 19, no. 1 (Winter 1996):47–51; William Niskanen, “The Case against BothStranded Cost Recovery and Mandatory Access,”Regulation 19, no. 1 (Winter 1996): 16-17; RichardGordon, “An Insider’s Upside-Down View ofDeregulation,” Regulation 22, no. 2 (Spring 1999):54–56; and Timothy J. Brennan and James Boyd,“Stranded Costs, Takings, and the Law andEconomics of Implicit Contracts,” Journal of RegulatoryEconomics 11, no. 1 (January 1997): 41.

8. Peter VanDoren, “Transitional Losses: Criteria forCompensation,” Regulation 20, no. 1 (Winter 1997):41–47.

9. Theresa Flaim, “The Big Retail ‘Bust’: WhatWill It Take to Get True Competition?” ElectricityJournal 13, no. 2 (March 2000): 41; and AhmedFaruqui, “Electric Retailing: When Will I SeeProfits?” Public Utilities Fortnightly, June 1, 2000, p.33. Faruqui reports that more than 20 percent ofCalifornia industrial customers had switched byFebruary 2000.

10. For a contemporaneous critique of A.B. 1890,see Jerry Taylor, “A Freer Market Would LowerEnergy Costs: Half Measures Fall Short,” San DiegoUnion Tribune, February 2, 1997. For an even earlierattack on this restructuring model, see Jerry Taylor,“Electric Utility Reform: Shock Therapy orManaged Competition?” Regulation 19, no. 3(Summer 1996): 64–76.

11. Paul Joskow and Edward Kahn, “A Quanti-tative Analysis of Pricing Behavior in California’sWholesale Electricity Market during Summer 2000,”Table 1, p. 8, Unpublished manuscript, http://web.mit.edu/pjoskow/www/JK_ PaperREVISED. pdf.

12. Paul Joskow, “California Can Tame Its Crisis,”New York Times, January 13, 2001, p. A31.

13. Rebecca Smith and John R. Emshwiller, “Califor-nia’s PG & E Gropes for a Way Out of Electricity

26

The Californiaelectricity crisis is

a story aboutwhat happens

when price con-trols are imposed

on scarce goods.

Squeeze,” Wall Street Journal,January 4, 2001, p. A1.

14. Anthony York, “The Deregulation Debacle,”January 30, 2001, http://www.salon.com/ news/feature/2001/01/30/deregulation_mess/print.html. In hindsight, the bids over book value shouldhave been seen by analysts as a signal that indus-try insiders were betting with their investmentdollars that future reductions in supply wouldmake existing generators very profitable.

15. Robert McCullough, “Price Spike Tsunami:How Market Power Soaked California,” PublicUtilities Fortnightly, January 1, 2001, pp. 22–32

16. Quoted in Steve Schmidt, “Expertise onEnergy No Longer Academic,” San Diego UnionTribune, March 24, 2001, p. A3.

17. North American Electric Reliability Council,“2000 Summer Assessment,” May 2000,ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/summer2000.pdf. Table 2, p. 8, projects a9,728 megawatt reserve over a projected demandof 49,273 megawatts.

18. Ibid., p. 39.

19. Ibid., pp. 3–4.

20. Joskow and Kahn, Table 1, p. 8.

21. North American Electric Reliability Council,“2000/2001 Winter Assessment,” reported in “PowerSystems Sufficient to Meet Winter Demand, NERCSays,” Energy Report,December 4, 2000, p. 2.

22. Edward Krapels, “Was Gas to Blame?Exploring the Cause of California’s High Prices,”Public Utilities Fortnightly, February 15, 2001, p. 29.

23. Energy Information Administration, Electric PowerAnnual 1999, vol. 1, Table A20, p. 46, http://www.eia.doe.gov/cneaf/electricity/epav1/epav1. pdf.

24. Krapels, p. 32.

25. Bruce Radford, “Key to the Citygate,” PublicUtilities Fortnightly, January 1, 2001, p. 4.

26. Krapels, p. 31.

27. Mark Mazur, “Statement to Committee on Energyand Natural Resources U.S. Senate,” December 12,2000, p. 1, http://www.eia.doe.gov/ pub/oil_gas/natural_gas/presentations/2000/testimony_on_natural_gas_demand/1211sen-test. pdf.

28. EIA estimated that, as of February 16, 2001, theUnited States had 1,038 billion cubic feet of natur-al gas in storage, 32.9 percent less than the five-year

average. See Energy Information Administration,Natural Gas Update, February 22, 2001, http://www.eia.doe.gov/oil_gas/natural_gas/special/natural_gas_update/natgas_update.html. For a discussionof the “boom and bust cycle” that struck the natur-al gas market last year, see Judith Gurney, “U.S. FacesNatural Gas Price Shock,” Energy Economist 229(November 2000): 15–18.

29. Storage in the West was an astonishing 55.6percent less than the five-year average. OnFebruary 21, 2001, spot prices were $5.20 per mil-lion Btu at Henry Hub, Louisiana, $5.51 inChicago, and $21.69 in Southern California. SeeEnergy Information Administration, Natural GasUpdate, February 22, 2001.

30. Energy Information Administration, “A Look atWestern Natural Gas Infrastructure during the RecentEl Paso Pipeline Disruption,” no date, available on theEIA Natural Gas Update Web site, http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_arti-cles/2000/elpaso_disruption/elpaso. pdf

31. Alex Barrionuevo, John Fialka, and RebeccaSmith, “How Federal Policies, Industry ShiftsCreated the Natural Gas Crunch,” Wall StreetJournal, January 3, 2001, p. A1.

32. Energy Information Administration, MonthlyEnergy Review, February 2001, Table 4.1, p. 73.

33. “Rig Count Expected to Jump by 31% in2001,” Energy Report, December 25, 2000, p. 8.

34. Mazur, p. 7.

35. “Group Calls on FERC to Cap WholesalePrices,” Energy Report, February 12, 2001, p. 11.

36. Personal conversation with A. Michael Schaalat Energy Ventures Analysis, Arlington, Virginia,December 19, 2000.

37. The rate at which the energy contained in nat-ural gas is converted into electricity is called the“heat rate.” A standard heat rate for an older plantis around 10,000 Btu per kWh. The most ineffi-cient plants require 16,000 Btu per kWh. Newercombined-cycle cogeneration plants have heatrates of around 7,000 Btu per kWh. The rate of10,000 Btu per kWh is often used for rough cal-culation because natural gas prices in dollars permillion Btu become electricity prices in cents perkWh. For example $10 per million Btu naturalgas results in 10 cents per kWh electricity costs fora 10,000 Btu per kWh electric generating plant.See Krapels, p. 32, for an example of use of therough calculation for an average and an ineffi-cient plant. See J. Alan Beamon and Steven H.Wade, “Energy Equipment Choices: Fuel Costs

27

and Other Determinants,” Monthly Energy Review,April, 1996, Table 3, p. x, for a heat rate estimateon a new natural gas combined-cycle plant.

38. For representative discussions, see JimYardley, “Texas Learns How Not to Deregulate,”New York Times, January 10, 2001, p. A12; andSmith and Emshwiller, “California’s PG & EGropes for a Way Out.”

39. Severin Borenstein, “The Trouble withElectricity Markets (and Some Solutions),” Programon Workable Energy Regulation Working Paper(PWP-081), January 2001, http://www.ucei.berkeley.edu/ucei/PDF/pwp081.pdf.

40. Lovins’s arguments are analyzed in Franz Wirl,The Economics of Conservation Programs (Boston:Kluwer Academic Publishers, 1997), pp. 83–84.

41. Energy Information Administration, Electric PowerAnnual 1999, vol. 1, Table A12, p. 39, http://www.eia.doe.gov/cneaf/electricity/epav1/epav1. pdf.

42. S. A. Van Vactor and F. H. Pickle, “Money,Power and Trade: What You Never Knew aboutthe Western Energy Crisis,” Public UtilitiesFortnightly, May 1, 2001, p. 35.

43. Krapels, p. 30.

44. Van Vactor and Pickle, p. 35.

45. “BPA Mulls Possible 30% Rate Increase,”Energy Report, January 29, 2001, p. 12.

46. Robert Skai and Colleen Woodell, “Northwest U.S.Drought to Challenge Utilities,” Standard & Poor’s,April 5, 2001, http://www.standardandpoors.com/Forum/RatingsCommentaries/CorporateFinance/Articles/; and “Dry Winter Dampens NorthwestPower Outlook,” Energy Report, March 19, 2001,pp. 9–10.

47. “Northwest Short 5,000 MW of Hydro,”Energy Report, May 7, 2001, p. 14.

48. “West Coast Water Woes Mulled,” WaterTechOnline, April 3, 2001, http://www.watertechonline.com/news.asp?mode=4&N_ID=21276.

49. Krapels, p. 30.

50. “Staff Report to the Federal Energy RegulatoryCommission on Western Markets and the Causes ofthe Summer 2000 Price Abnormalities,” p. 5-5,http://www3.ferc.fed.us/ bulkpower/bulkpower.htm.

51. Ibid.

52. Ibid.

53. Consumption by utilities in May throughOctober 1999 was 65.718 billion cubic feet (BCF).During the same period in 2000 consumptionwas 80.463 BCF. See Natural Gas Monthly, March2001, Table 18, p. 43.

54. Van Vactor and Pickle, p. 36.

55. The average temperature in the lower 48states in November and December 2000 was 33.8degrees Fahrenheit, the coldest since the start ofmodern nationwide record keeping in 1895. SeeAndrew Revkin, “Record Cold November–December in 48 Contiguous States,” New YorkTimes, January 6, 2001, p. A28.

56. California Senate president pro tem John Burton,for instance, argues that while electricity demand roseonly 4 percent for the period May through December2000 compared to the same period in 1999, totalwholesale electricity costs rose by 328 percent.“California Lawmakers to Investigate Gas Costs,‘Manipulation,’” Energy Report, March 19, 2001, p. 9.

57. Ibid.; and Fereidoon Sioshansi, “The SummerIs Over; California’s Market Problems Are Not,”Energy Informer, October 2000, pp. 1–5.

58. The events of 2000 took place in the context of anunderlying trend of demand rising faster than supply.During the 1990s demand grew at 3 percent per yearthroughout the West, and supply increased by 1 per-cent per year. But the trend came about because of thevery large glut in capacity in the early 1990s. See “StaffReport to the Federal Energy Regulatory Commis-sion,” p. 5-3 and introduction to section on “AreEnvironmentalists the Culprit?” p. 28.

59. Quoted in Carl Levesque, “EmissionsStandards: EPA, High Court, and Beyond,” PublicUtilities Fortnightly, January 1, 2001, pp. 46–47.

60. National Research Council, Rethinking theOzone Problem in Urban and Regional Air Pollution(Washington: National Academy Press, 1991).

61. Gary Polakovic, “AQMD Moves to OverhaulPower Plant Emission Rules,” Los Angeles Times,January 20, 2001, p. A23.

62. Levesque.

63. Krapels, p. 32.

64. Polakovic. In return for the waiver, power gen-erators must install costly pollution controlequipment over the next two years that wouldreduce emissions by 90 percent. Generators thatremain in the RECLAIM market will be able toavoid buying credits by paying into a specialaccount used to fund clean-air projects across the

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region.

65. Quoted in Levesque.

66. Even customers who switched suppliersunder the retail choice program and were not offi-cially governed by price controls were insulatedfrom the increases in wholesale prices because thestranded-cost recovery charge varies inverselywith the actual costs of electricity. High electricityprices severely reduced the stranded-cost recoverycharge. See Severin Borenstein, James Bushnell,and Frank Wolak, “Diagnosing Market Power inCalifornia’s Deregulated Electricity Market,”Program on Workable Energy Regulation WorkingPaper (PWP-064), August 2000, pp. 8–9,http://www.ucei.berkeley.edu/ucei/PDF/pwp064.pdf.

67. Stephen J. Rassenti, Vernon L. Smith, and Bart J.Wilson, “Using Experiments to InformPrivatization/Deregulation Movements inElectricity,” Cato Journal, forthcoming; See alsoSteven Stoft, “The Market Flaw CaliforniaOverlooked,” New York Times,January 2, 2001, p. A19.

68. Eric Hirst, “Price-Responsive Retail Demand:Key to Competitive Electricity Markets,” PublicUtilities Fortnightly, March 1, 2001, pp. 34–41.

69. Smith and Emshwiller, “California’s PG & EGropes for a Way Out”; and Joskow and Kahn, p. 29.

70. Robert J. Michaels, “FERC’s California Fix:Opportunities Lost and Found,” Public UtilitiesFortnightly, January 1, 2001, pp. 34–36. OnDecember 15, 2001, FERC updated the order, andon March 9, 2001, FERC defined prices above 27.3cents per kWh during stage 3 emergency periodsin California in January 2001 as violating the softprice cap. See FERC press release, http://www.ferc.gov/news1/ pressreleases/refunds.pdf. OnMarch 16, FERC defined prices above 43 cents perkWh during stage 3 emergencies in California inFebruary 2001 as violating the soft price cap. SeeCraig D. Rose, “Leaders Fault FERC, Call forTougher Action,” San Diego Union Tribune, March17, 2001.

71. Krapels, p. 30.

72. “California Generators Tell Hoeker They ActedProperly,” Energy Report, December 4, 2000, p. 3.

73. Laura M. Holson and Richard A. Oppel Jr.,“Trying to Follow the Money As Energy SystemFlounders,” New York Times, January 12, 2001, p. A1.

74. “California Suffers Two Days of RollingBlackouts,” Energy Report, March 26, 2001, p. 1.

75. Nancy Vogel and Jennifer Warren, “California

Utilities Were Overcharged, State Agency Says,”Los Angeles Times, March 2, 2001, p. A3.

76. “Generators: Sales Just and Reasonable,’”Energy Report, April 2, 2001, p. 18.

77. “Feds Order Sales to Continue to CaliforniaUtility,” Energy Report, January 29, 2001, p. 4.

78. Todd S. Purdum, “Rolling Blackout Affects aMillion across California,” New York Times, March 20,2001, p. A1.

79. Joskow and Kahn, Table 1, p. 8.

80. “White House Extends Emergency Orders AsCalifornia Suffers under Threat of Blackouts forSecond Week,” Energy Report, January 29, 2001, p. 6.

81. Krapels, p. 33.

82. Joskow and Kahn, p. 30.

83. “FERC Takes Action to Repair Calif. Market,But Few Are Pleased,” Energy Report, December 25,2000, p. 4.

84. Van Vactor and Pickle, p. 36.

85. “Reliability Picture Bleak in California,” EnergyReport, May 7, 2001.

86. Rebecca Smith, John Emshwiller, and MitchelBenson, “California Power Crisis: Blackouts andLawsuits and No End in Sight,” Wall Street Journal,January 19, 2001, p. A1.

87. Rebecca Smith, John Emshwiller, and MitchelBenson, “California Is Hit with Series of Blackouts,”Wall Street Journal, January 18, 2001, p. A1.

88. http://www.consumerwatchdog.org/ftcr/co/co000918.php3.

89. Federal Energy Regulatory Commission, “Reporton Plant Outages in the State of California,” February1, 2001, as described in Public Utilities Fortnightly,March 1, 2001, p. 18.

90. Market power is defined as the withholdingof some output by one or more producers toincrease the price of other output owned by thesame producers. In electricity markets this occurswhen one owner shuts down a lower-cost generat-ing unit in order to induce the usage of a high-cost unit that sets the market price for all otherunits with lower costs under similar ownership.

91. Borenstein, Bushnell, and Wolak, p. 34.

92. Joskow and Kahn, p. 20.

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93. Scott Harvey and William W. Hogan, “Issuesin the Analysis of Market Power in California,”October 27, 2000, http://ksghome.harvard.edu/~whogan.cbg.ksg/HHMktPwr_1027.pdf. We donot discuss the California system’s method forresolving transmission congestion, which Harveyand Hogan discuss on p. 8.

94. Ibid., pp. 9–14.

95. Ibid., pp. 4, 19; and Van Vactor and Pickle,pp. 40–41.

96. Stoft.

97. Tim Brennan, “The California ElectricityExperience,” Paper presented at the 20th AnnualWorkshop in Advanced Regulatory Economics,Tamiment, Pa., May 24, 2001, p. 31.

98. Nguyen T. Quan and Robert J. Michaels arguethat, because generators have so many differentopportunities to sell in the western market, thedifferentiation of market power from generators’simply pricing at their opportunity costs isimpossible. See Nguyen T. Quan and Robert J.Michaels, “Games or Opportunities? Bidding inthe California Markets?” Electricity Journal 14, no.1 (January–February 2001): 99–108.

99. “Manifesto on the California Electricity Crisis,”http://haas.berkeley.edu/news/california_electricity_crisis.html.

100. Federal Energy Regulatory Commission,Press release, March 9, 2001, http://www.ferc.gov/news/pressreleases/refunds.pdf. Stage 3 emergenciesare declared by the California ISO when potentiallyavailable supply exceeds estimated demand by 1.5percent or less.

101. California Energy Commission, “WholesaleElectricity Price Review,” January 2001, Table 2, p. 4,http://www.energy.ca.gov/electricity/wepr/2001–01/index.html.

102. Jeff Gerth, “Some Evidence of Overcharges,”New York Times, March 23, 2001, p. A14.

103. “FERC Orders Refunds or More Proof fromCalifornia Suppliers,” Energy Report, March 19, 2001.

104. The California ISO concedes the same butcalculates that the average production cost for themost costly power plant necessary to meetdemand was $180 per MWh in January 2001 and$260 per MWh in February. The estimates arelower than FERC’s primarily because FERC wascalculating only costs during peak-demand peri-ods during power emergencies whereas theCalifornia ISO was calculating the weighted aver-

age of prices throughout the entire month.“California Claims $6.2 Billion in Excess PowerCharges,” Energy Report, April 2, 2001, p. 9.

105. “California Lawmakers to Investigate GasCosts, ‘Manipulation,’” Energy Report, March 19,2001, p. 9.

106. See “California Messes Up,” Editorial, WallStreet Journal, December 28, 2000, p. A10.

107. Daniel Eisenberg, “Which State Is Next?”Time, January 29, 2001, p. 45.

108. Alejandro Bodipo-Memba, “DeregulationHas Been Smooth—So Far,” Detroit Free Press,January 18, 2001.

109. California Energy Commission, “Power PlantProjects before the California Energy Commissionsince 1979,” January 16, 2001, http://www.energy.ca.gov/sitingcases/projects_since_1979.html.

110. Mark Arax and Terence Monmaney, “PowerPlant Juggernaut Slowed by Internet Giant,” LosAngeles Times, January 10, 2001; and Damien Cave,“Power and the People,” January 30, 2001,http://www.salon.com/tech/feature/2001/01/30/power_regulation/print.html.

111. From 1999 to the present, the California EnergyCommission approved permits for 13 plants with acombined generation capacity of 8,464 MW. Thecommission is currently reviewing 13 additionalprojects with a combined generation capacity of6,989 MW (none of which would be up and runninguntil 2004); another 14 projects totaling 8,080 MWhave been publicly announced but not yet submit-ted for state review. Two dozen additional projectstotaling 12,425 MW are known to be under consid-eration by the investment community. “CaliforniaAgency Confirms State Will Be Short Power ThisSummer,” Energy Report, April 9, 2001, p. 6.

112. John Greenwald, “The New Energy Crunch,”Time, January 29, 2001

113. “Study: Power Short Despite Surplus,”Energy Report, December 25, 2000, p. 10.

114. “CEC Chairman Says Summer 2001 Going toBe Tight,” Energy Report, February 19, 2001, p. 5.

115. Hal R. Varian, “Economic Scene,” New YorkTimes, April 5, 2001, p. C2.

116. Peter Gosselin, “Most of West in Same PowerJam As California,” Los Angeles Times, February 26,2001.

117. Cave.

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118. Nuclear power plants that were completedsince the mid-1980s in the United States had cap-ital costs that averaged about $3,000 per kW ofgenerating capacity. See Mark Holt and Carl E.Behrens, “Nuclear Energy Policy,” CongressionalResearch Service Issue Brief for Congress, March22, 2001, p. 2, www.Cnie.org/nle/eng-5.html.Coal plants in the mid-1990s had capital costs of$1,501 per kW of generating capacity, and natur-al gas combined-cycle plants had capital costs of$419 per kW of generating capacity. Beamon andWade, Table 3, p. x, discuss coal versus natural gascosts. In a competitive generation market ratherthan the traditional guaranteed rate-of-returnenvironment, investors would build nuclearpower facilities only if they believed that the priceof electricity would exceed the marginal costs of anuclear plant by sufficient margins over a longenough period of time so that the expected valueof profits would be greater than profits frominvestments in the less capital intensive naturalgas facilities. No nuclear plants have been orderedin the United States since 1978. It is not clearwhether nuclear power was imprudent from thestart or was made excessively costly by federalsafety regulation (in the form of the NuclearRegulatory Commission). In 1975 Resources forthe Future projected that the total costs ofnuclear plants in 1985–88 would be less than thetotal costs of equivalent coal plants. See WilliamSpangar Peirce, Economics of the Energy Industries(Westport, Conn.: Praeger, 1996), pp. 216–17. Aset of costly nuclear plants came online duringthe early 1980s, and electricity rates rose 60 per-cent from 1978 to 1982. See Caleb Solomon, “AsCompetition Roils Electric Utilities, They Look toNew Mexico,” Wall Street Journal, May 9, 1994, p. A1.By 1990 nuclear plants had total costs that wereabout double those for coal plants. Peirce, p. 216.Not all nuclear plants are more expensive thancoal-fired plants. Peirce, pp. 217–18, reports thatthe least-expensive nuclear plants have total costslower than the cheapest coal plants but that, atevery other point in their respective cost distribu-tions, nuclear plants are more expensive.

119. The San Onofre plant is located south of LosAngeles, and thus its output could not have beenshipped into northern California because of day-time transmission constraints.

120. Brendan Kirby and Eric Hirst, “MaintainingTransmission Adequacy in the Future,” ElectricityJournal 12, no. 9 (November 1999): 64.

121. Kirby and Hirst, pp. 62–63.

122. Peter Behr, “Shortage of Power LinesLooms,” Washington Post, February 20, 2001, p. A1.

123. Ibid.; Rebecca Smith and John Emshwiller,

“California Isn’t the Only Place Bracing for ElectricalShocks,” Wall Street Journal, April 26, 2001; andCambridge Energy Research Associates, High Tension:The Future of Power Transmission in North America, citedin “Lack of Investment Jeopardizes Power Grid, StudySays,” Energy Report, October 16, 2000, p. 1.

124. Behr.

125. Douglas Jehl, “Weighing a Demand for Gasagainst the Fear of Pipelines,” New York Times,March 8, 2001, p. A1.

126. Energy Information Administration, “ALook at Western Natural Gas Infrastructure dur-ing the Recent El Paso Pipeline Disruption,” pp.3-4, reports that capacity from Canada has grownby more than 50 percent since 1990.

127. See Stanley Horton, “Gas Pipelines: Solution,Not Problem,” Energy Perspective 9, no. 2 (January25, 2001): 3.

128. See ibid., pp. 3, 6.

129. Chip Cummins, “Natural-Gas CompaniesDiscover California Is a Surprise Bonanza,” WallStreet Journal, February 7, 2001, p. C1; and EnergyInformation Administration, “Status of NaturalGas Pipeline System Capacity Entering the2000–2001 Heating Season,” Natural Gas Monthly,October 2000, Table SR1, p. xiv, which reportsthat pipeline capacity from the southwest intoCalifornia was only 55 percent utilized during1999.

130. “Pipe Expansions on Tap to SupplyCalifornia Power Plants,” Energy Report,September 4, 2000, p. 7; and “Herbert: PowerSector Responsible for Spike in Gas Prices,”Energy Report, March 5, 2001, p. 5.

131. For a representative article, see Yardley. See alsoLynne Kiesling, “Getting Electricity DeregulationRight: How Other States and Nations Have AvoidedCalifornia’s Mistakes,” Reason Public PolicyInstitute Policy Study no. 281, April 2001.

132. Energy Information Administration datacited by Greenwald, p. 43.

133. About 10 percent of all Pennsylvania resi-dential ratepayers and users of a third of the totalload have signed power contracts with nonutilitypower generators, a switchover rate that leads thenation. Commercial and industrial users, howev-er, are migrating back to the utilities as wholesaleprices rise higher than the default rates, a patternconsistent with that playing out today inCalifornia. Xenergy Corp., Retail Energy Markets2000, reported in “Competition Developing

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Slowly, Consultancy Finds,” Energy Report, April 9,2001, p. 9.

134. Krapels, p. 29.

135. Laurence D. Kirsch and Rajesh Rajaraman,“Assuring Enough Generation: Whose Job andHow to Do It,” Public Utilities Fortnightly April 15,2001, pp. 40–41. Rhode Island and Pennsylvaniahave been slow in passing on costs.

136. Beamon and Wade, Table 3, p. x.

137. Ibid., pp. ix–xii.

138. “Electricity Demand to Grow Faster ThanExpected, EIA Says,” Energy Report, December 4, 2000,p. 2.

139. Remember that California had sufficientspare capacity until the hydro shortage occurred,and any installed-capacity requirement wouldnecessitate adoption of some “measure” of hydrocapacity, given that it can vary so much.

140. Brattle Group, “Shortening the NYISO’sInstalled Capacity Procurement Period:Assessment of Reliability Impacts,” Report pre-pared for the New York Independent SystemOperator, May 2000, p. 3, http://www.nyiso.com/services/documents/studies/pdf/shortening_iso_inst_cap_procure_period_asses_rel_impacts.pdf.

141. Ibid., pp. 22–23.

142. Borenstein, “The Trouble with ElectricityMarkets,” p. 3

143. Arthur S. De Vany, “Electricity Contenders:Coordination and Pricing on an Open Transmis-sion Network,” Regulation 20, no. 2 (Spring 1997):48–51.

144. Gary Locke, “Caught in the Electrical Fallout,”New York Times, February 2, 2001, p. A21.0

145. Sam Howe Verhovek, “California Gets ScantSympathy from Neighbors,” New York Times,January 26, 2001, p. A1.

146. William Booth, “States Locked into Grid FaceSevere Energy Test,” Washington Post, January 28,2001, p. A3.

147. Gosselin.

148. Ibid.

149. Quoted in Booth.

150. Tom Gorman, “Vegas Lights Undimmed,”

Los Angeles Times, April 2, 2001.

151. Smith and Emshwiller, “California Isn’t theOnly Place”; and Locke.

152. One estimate of the profits for coal units inCalifornia when high-cost natural gas units are set-ting the market price comes from an offer of fivetimes book value by an independent power producer(AES) for 56 percent ownership of a SouthernCalifornia Edison coal-fired unit. See “News Digest,”Public Utilities Fortnightly, March 1, 2001, p. 16.

153. Benjamin Zycher, “Political Meddling MadeThis a Mess—And Here They Go Again!” LosAngeles Times, January 17, 2001.

154. Joseph P. Kalt, The Economics and Politics of OilPrice Regulation (Cambridge, Mass.: MIT Press,1981).

155. Peter D. Salins and Gerald C.S. Mildner, Scarcity byDesign: The Legacy of New York City’s Housing Policies(Cambridge, Mass.: Harvard University Press, 1992).

156. James Sterngold, “California Acting to RelieveCrisis,” New York Times, January 13, 2001, p. A1.

157. Rene Sanchez, “California Promotes a NewLifestyle—Conservation,” Washington Post, April 18,2001, p. A1; and “California Retailers Must CutOutdoor Lighting,” New York Times, February 5,2001, p. A18.

158. Steve Johnson, “State Reviews Draft Plan toProhibit Energy Exports,” San Jose Mercury News,March 11, 2001.

159. In 1998, for example, California exported 6,236MWh and imported 51,125 MWh. See “Staff Reportto the Federal Energy Regulatory Commission onWestern Markets and the Causes of the Summer 2000Price Abnormalities,” Table 2-4, p. 2–7.

160. Sanchez, “California Promotes a NewLifestyle.”

161. Wirl; J. D. Khazzoom, “EconomicImplications of Mandated Efficiency Standards,”Energy Journal 1, no. 4 (1980): 21–39; idem, AnEconometric Model Integrating Conservation in theEstimation of the Residential Demand for Electricity(Greenwich, Conn.: JAI Press, 1986); idem,“Energy Savings Resulting from More EfficientAppliances,” Energy Journal 8, no. 4 (1987): 85–89;idem, “Energy Savings Resulting from MoreEfficient Appliances: A Rejoinder,” Energy Journal10, no. 1 (1989): 85–89; Jeffrey Dubin, AllenMiedema, and Ram Chandran, “Price Effects ofEnergy Efficient Technologies: A Study ofResidential Demand for Heating and Cooling,”

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RAND Journal of Economics 17 (1986): 310–25; EricHirst, “Changes in Indoor Temperature afterRetrofit Based Electricity Billing and WeatherData,” Energy Systems and Policy 10 (1987): 1–20; H.D. Saunders, “The Khazzoom-Brooks Postulateand Neoclassical Growth,” Energy Journal 13, no. 4(1992): 131–48; F. P. Sioshansi, “Do DiminishingReturns Apply to DSM?” Electricity Journal 7, no. 4(May 1994): 70–79; Paul Joskow, “Utility-Subsidized Energy Efficiency Programs,” AnnualReview of Energy and the Environment 20 (1995):526–34; and David Greene and L. A. Greening,“Energy Use, Technical Efficiency, and theRebound Effect: A Review of the Literature,”Report to the Office of Policy Analysis andInternational Affairs, U.S. Department of Energy,December 1997. For a review of the literature onthe rebound effect and automobile transporta-tion (where the same dynamics apply), see DavidGreene, James Kahn, and Robert Gibson, “FuelEconomy Rebound Effect for U.S. HouseholdVehicles,” Energy Journal 20, no. 3 (1999): 6–10.

162. Robert L. Bradley Jr., “Renewable Energy:Not Cheap, Not ‘Green,’” Cato Institute PolicyAnalysis no. 280, August 27, 1997, p. 5.

163. See Wirl, particularly pp. 186–88.

164. The few detailed analyses of the phenome-non indicate that 50–60 percent of the partici-pants in utility-sponsored energy efficiency pro-grams would have invested in the technologiesregardless of the subsidy. Wirl, pp. 120–26; andPaul Joskow and Donald Marron, “What Does aNegawatt Really Cost? Evidence from UtilityConservation Programs,” Energy Journal 13, no. 4(1992): 41–74.

165. Perhaps the most comprehensive study todate on the subject, undertaken by sympatheticresearchers from the Denmark Institute for LocalGovernment, found that among industrial con-sumers “the cost of finding electricity conserva-tion projects is higher than the savings due to therealized investment.” Mikael Togeby and AndersLarsen, “The Potential for Electricity Conserva-tion in Industry: From Theory to Practice,” in Intothe 21st Century: Harmonizing Energy Policy,Environment, and Sustainable Economic Growth(Cleveland: International Association for EnergyEconomics, 1995), pp. 48–55. For similar analysesof residential ratepayers, see Albert Nichols, “HowWell Do Market Failures Support the Need forDemand Side Management?” National EconomicResearch Associates, Cambridge, Mass., August12, 1992, pp. 22–25; Ruth Johnson and DavidKasserman, “Housing Market Capitalization ofEnergy-Saving Durable Good Investments,”Economic Inquiry 21 (1983): 374–86; Kevin Hassettand Gilbert Metcalf, “Energy Conservation

Investment: Do Consumers Discount the FutureCorrectly?” Energy Policy 21 (June 1993): 710–16;Gilbert Metcalf, “Economics and RationalConservation Policy,” Energy Policy 22 (October1994): 819–25; and Avinash Dixit and RobertPindyck, Investment under Uncertainty (Princeton,N.J.: Princeton University Press, 1994).

166. Nancy Vogel and Richard Simon, “DWPEarns Top Dollar on Recent Sale of Power,” LosAngeles Times, February 16, 2001, p. A13.

167. Mitchel Benson, “Davis Report Fails toReflect Highest Bids,” Wall Street Journal, January26, 2001, p. A2; and “California Enacts BillAllowing State to Buy Power for Utilities,” EnergyReport, February 12, 2001, p. 7.

168. “California Regulators Approve Orders onIOUs, Conservation,” Energy Report, April 9, 2001,p. 6. The Wall Street Journal earlier reported that thegovernor had reached agreement with 20 powergenerators to furnish the state with 8,900 MW forperiods as long as 20 years but at an unspecifiedprice. Rebecca Smith, Mitchel Benson, and JohnEmshwiller, “Major Kinks Emerge in GovernorDavis’ Plan to Power California,” Wall Street Journal,March 8, 2001, p. A4.

169. Richard A. Oppel Jr., “California LawmakersDebate Bill to Compensate Utilities,” New YorkTimes, January 27, 2001, p. B1.

170. “High Gas Prices Result of Over-Reliance,Senators Say,” Energy Report, December 18, 2000, p. 6.

171. Mike Florio, senior attorney with the UtilityReform Network, said that, instead of raisingrates, Davis should follow through on his threatsto seize electricity generated by privately ownedpower plants. “They have got to get tough withthese generators, and if that means commandeer-ing the output of these plants, that’s what he’s gotto do,” Florio said. “The only way to stop theseguys is to cut them off at the pockets.” Quoted inDan Morain, Nancy Vogel, and Stuart Silverstein,“PUC Chief to Urge Rate Hike, Favors ‘Tiered’System,” Los Angeles Times, March 24, 2001, p. 1.

172. Daniel McFadden, “California NeedsDeregulation Done Right,” Wall Street Journal,February 13, 2001, p. A26.

173. “Experts Concerned California SettingDangerous Precedents,” Energy Report, March 19,2001, p. 10.

174. The exception arises if firms exercise marketpower. Under such circumstances, the greater thepercentage of output the firm has sold in advance,the less the incentive for the firm to restrict output to

33

raise the spot price. And once firms face both forwardand spot sale possibilities, competition in both mar-kets becomes more vigorous. See Borenstein, “TheTrouble with Electricity Markets,” p. 8.

175. Ibid. Emphasis in the original.

176. Ronald Sutherland, “Natural Gas Contractsin an Emerging Competitive Market,” EnergyPolicy, December 1993, p. 1196.

177. A 1981 Southern California Edison studyforecast 1995 avoided electricity costs at 16.73cents per kilowatt-hour, so the company willinglysigned contracts to buy solar power at 15 centsper kWh even though the wholesale price ofpower in 1995 was actually about 2 to 3 cents perkWh. See Jeff Bailey, “Carter-Era Law Keeps Priceof Electricity Up in Spite of a Surplus,” Wall StreetJournal, May 17, 1995, p. A1.

178. Don Oldenburg, “Losing a Good NaturalGas Deal,” Washington Post, January 31, 2001, p.C4; James Sterngold and Matt Richtel, “PowerSource Ends Direct Flow to CaliforniaBusinesses,” New York Times, February 1, 2001, p.A15; “Ford Suing Dominion over Gas Deal,”Energy Report, April 9, 2001, p. 14; Ben Fox,“Californians Return to Old Utilities,” AssociatedPress, February 11, 2001; and Cave.

179. A typical analysis can be found in a report byDeutsche Banc’s Alex Brown: “We continue to beconfident that the question of excess generatingcapacity in the United States is a question of‘when,’ not ‘if.’ Like many other asset-intensivecommodity businesses, we expect developers toadd too much capacity to the U.S. generationmarket.” Alex Brown, “Electricity Supply &Demand in the U.S.,” quoted in “Analysts SeeExcess Capacity by 2005,” Energy Report, March19, 2001, p. 15. There are two caveats, however.First, a sharp increase in populist demagoguerycould trigger investors’ fears of plant confiscationor mandated refunds, terminating projects nowunder way. This is already having an effect on newcapacity. For instance, Calpine has withdrawnfour of its five applications for permission tobuild peaking power plants that would have goneonline this summer for exactly that reason. See“Calpine Drops Plans for California Plants,”Energy Report, December 4, 2000, p. 9. Enron isalso said to have scrapped plans for additionalpeaking generators. See “FERC Acts to HaltCalifornian ‘Meltdown,’” Energy and Power RiskManagement, December 2000, p. 4. Second, con-tinued constraints on intrastate natural gas deliv-ery systems due to regulatory inertia might wors-en pipeline bottlenecks and thus inflate electrici-ty prices despite increases in generating capacityand interstate gas pipeline delivery capacity.

180. The flood of investment in new power gener-ation to serve the western market is also occurringin regional markets outside the West. Energy ana-lyst Chris Seiple of RDI Consulting points outthat 90,000 megawatts of new electricity genera-tion capacity are scheduled to come online beforethe end of 2002. “There’s an extraordinary,unprecedented power-plant building boom goingon in this country,” he notes. The EnergyInformation Administration of the Departmentof Energy likewise reports that 190,000megawatts of new generating capacity will bebuilt by 2004. The Electric Power SupplyAssociation (a trade organization representingindependent power generators) is a bit more con-servative, but it, too, reports record investment innew generation, which is expected to produce150,000 megawatts of new electricity by 2004.Margaret Kriz, “The Future Megawatt Factor,”National Journal, April 21, 2001, p. 1170.

181. For a review of the size of North Americannatural gas reserves, see “Industry Confident U.S.Has Enough Gas to Meet Demand,” EnergyReport, March 5, 2001, p. 10; “Report EstimatesU.S. Gas Supplies Good for 60 Years,” EnergyReport, April 9, 2001, p. 10; “Canadians CheerWhite House Pro-Gas Remarks,” Energy Report,April 9, 2001, p. 12; and Judith Gurney, “U.S.Faces Natural Gas Price Shock,” Energy Economist229 (November 2000): 15–18. For a discussion oftechnological advances on the near horizon thatcould dramatically expand natural gas supplies ifprices stay high, see Jennifer Considine et al.,“North American Natural Gas Markets,” OxfordEnergy Forum, February 2001, pp. 7–9.

182. Mark Golden, “Power Points: CaliforniaGovernor Fiddles As Summer Likely to Burn,”Dow Jones Energy Service, February 26, 2001; and“California Heads from Crisis toward Calamity,Experts Say,” Energy Report, March 19, 2001, p. 1.

183. Quoted in Smith, Benson, and Emshwiller,“Major Kinks Emerge.”

184. As we wrote this paper, the California PublicUtilities Commission did increase rates 36 per-cent and made their temporary 10 percent hikepermanent. The governor initially distanced him-self from the increase but later supported it. SeeTodd S. Purdum, “In California, Reversal onEnergy Rates,” New York Times, April 6, 2001, p.A11.

185. James Bushnell and Erin Mansur, “TheImpact of Retail Rate Deregulation on ElectricityConsumption in San Diego,” Program onWorkable Energy Regulation Working Paper(PWP-082), April 2001, p. 4, http://www.ucei.berkeley.edu/ucei/PDF/pwp082.pdf.

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186. Ibid., p. 17. Steven Braithwait and AhmadFaruqui, “The Choice Not to Buy: Energy Savings andPolicy Alternatives for Demand Response,” PublicUtilities Fortnightly, March 15, 2001, p. 60, report elastic-ity estimates of .07 to .135 (a reduction in demand of 7to 13.5 percent for a doubling of prices).

187. “Experts Concerned California SettingDangerous Precedents,” Energy Report, March 19,2001, p. 11.

188. Matthew Wald, “Gasoline Use Fell Last Year,Oil Group Says,” New York Times, January 20,2001, p. B1.

189. Quoted in Ibid.

190. McFadden.

191. Severin Borenstein, “Frequently Asked Questionsabout Implementing Real-Time Electricity Pricing inCalifornia for Summer 2001,” March 2001,http://www.ucei.org/PDF/ faq.pdf.

192. Ahmed Faruqui et al., “California Syndrome,”

Regulation , forthcoming.

193. Ibid.

194. Robert J. Michaels, “Can Nonprofit Trans-mission Be Independent?” Regulation 23, no. 3(Summer 2000): 61–66.

195. For a detailed examination of how such aregime could be structured, see Douglas Houston,“User-Ownership of Electric Transmission Grids:Towards Resolving the Access Issue,” Regulation 15,no. 1 (Winter 1992): 48–57.

196. Rene Sanchez, “California Crisis HasResidents Seething,” Washington Post, February 11,2001, p. A1.

197. John McCaughey and Kennedy Maize, “IsCalifornia Too Late for the Learning?” EnergyPerspective 9, nos. 3–4 (February 8, 2001): 2.

198 “Manifesto on the California ElectricityCrisis,” http://haas.berkeley.edu/news/califor-nia_ electricity_crisis.html.

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