Chapter 7 DESIGN FLAWS AND A WORSENING CRISIS During the first two successful years of restructuring in California, prices declined. This initial success meant that the restructured market s design flaws were mostly overlooked by market participants. However, in 2000, these design flaws became very significant. The collaborative restructuring process built a market design with some questionable design components. These include: The CPX and CAISO created multiple sequential markets that encouraged strategic bidding. IOUs were required to buy and sell virtually all electricity in the spot market. The CPUC limited long-term purchase power or hedging contracts. The CAISO was required to purchase electricity outside of market (OOM) at prices above California s market caps to ensure reliability. The CPUC retained the freeze on retail electricity prices even as wholesale prices surged. The CAISO was unable to control or coordinate scheduled electric generation outage schedules. Below we will discuss each of these flaws and explain how each contributed to the California electricity crisis. Sequential Markets and Strategic Bidding Under AB 1890, a new entity know as a Scheduling Coordinator (SC) was established. The SCs were responsible for arranging generation dispatch, transmission, energy, and capacity for market participants. SCs were
64 The California Electricity Crisis: What, Why, and What s Next required to be certified by the CAISO, paid CAISO s charges, submitted weekly and annual forecasts, day-ahead and hour-ahead schedules, and paid for non-self provided ancillary services. The CAISO serves as the control area operator for most of California and matches generation with loads. The CAISO starts with the CPX s day-ahead bid schedules and with these schedules is responsible to maintain system reliability, coordinate generation dispatch, and provide open access to the grid. To fulfill these responsibilities, the CAISO can redispatch the CPX market results. There were three primary markets in California s restructured electricity market under AB 1890: (1) the CPX Day-ahead market; (2) the CPX hourahead market; and (3) the CAISO Real-Time market. The CPX day-ahead market was designed and intended to be the primary wholesale electricity market. It worked in the following manner. Initially, supply and demand bids were submitted to the CPX 24 hours in advance. The CPX would then validate the bids and build supply and demand curves. The intersection of these curves established the single MCP received by all sellers. After the CPX market closed, those Scheduling Coordinators (SCs) whose bids were selected by the CPX would submit transmission access requests to the CAISO. The SCs could also submit offers to provide ancillary services 1 to the CAISO. If the transmission requests caused congestion, the CAISO resolved these congestion problems by adjusting the SC s requested transmission access and issuing usage charges on congested paths. The CPX also operated an hour-ahead market. In this market, participants could revise incrementally their schedules up to two hours before the trading hour begins. The third sequential market was the CAISO Real-Time market. This market was originally designed to accommodate about 3 percent of the total energy in the market and was designed to allow the CAISO to adjust load on a ten minute basis. The CAISO sorted the bids in price merit order and called upon the bids as necessary to balance generation and load. Each hour is divided into six ten-minute intervals, with separate incremental and decremental prices set during each interval. For two years, the CPX and CAISO markets operated more or less as designed, and wholesale prices (about $25 per MWH) were less than retail prices (about $50 per MWH) (or 2.5 per kwh versus 5 per kwh). During 2000, the relationship between the CPX s day-ahead and the CAISO s realtime market changed drastically with an unexpected shift to the CAISO s real-time or energy-imbalance market began. In California s wholesale power market, PG&E and SCE purchased nearly 90 percent of the energy traded. Due to the sequential nature of the 1 Spinning reserves, non-spinning reserves, regulation up and down, etc.
Design Flaws and a Worsening Crisis 65 market, with the CAISO s real-time day-of market following the CPX s dayahead market, buyers knew they had a second opportunity to purchase energy to cover their demand. This created an incentive for buyers to underschedule their next day s electricity demand in order to reduce demand and drive down CPX s single market-clearing price. By underscheduling in the CPX market, buyers hoped to pay less for their CPX purchases and would make up the remainder of their needs in the CAISO s real-time market, paying higher prices for this portion of their needs. Sellers quickly responded to this strategy by underscheduling the supply side. By reducing the amount of energy available in the CPX s day-ahead market, supply would decrease, potentially increasing the CPX s marketclearing price. Sellers would sell fewer MWHs, but at a higher price in the CPX market. Sellers could then try to sell any remaining electricity in the CAISO s secondary real-time market, perhaps at a lower price. This strategic bidding resulted in under-scheduling both supply and demand in the CPX market. This game resulted in a standoff in the CPX day-ahead market. However, the game caused the CAISO s real-time market to grow in importance, ultimately increasing volatility and price levels. The IOUs had historically been able to forecast the next day s electricity demand within about 2 to 3 percent of actual demand that is, within 500 to 1000MW each day depending upon the time of year. Underscheduling in 2000 significantly exceeded underscheduling in 1999. In 1999, the IOUs underscheduled by more than 2,000 MW a day only about a dozen times. In 2000, IOUs underscheduled by more than 2000 MW hundreds of times. During the last 40 days of 2000, underscheduling caused about 30 percent (not the 3 percent it was designed for) of the market s MWHs to flow through the CAISO s energy imbalance market. The CAISO would pay any price necessary to maintain system balance and reliability. Consequently this shift to the CAISO s market caused wholesale price levels to increase drastically in California in 2000. The CAISO was often forced to make emergency OOM purchases at price and quantity levels that had been neither anticipated nor built into the initial market design. The CAISO was often hard pressed to locate the increased supply demanded in real time. This triggered power emergencies that signaled even higher prices. Often, the CAISO made OOM purchases at exorbitant prices to guarantee system reliability, which was the CAISO s primary mandate. Subsequent to the time the FERC imposed price caps in California, these OOM purchases also became a means for sellers to avoid price caps. This may have been efficient. Regardless, the failure of California s price caps to stem the crisis meant that the FERC had to adopt region-wide price caps that we describe below to tame the market in June 2001.
66 The California Electricity Crisis: What, Why, and What s Next Long-Term Contracts Were Not Available As illogical as it seems, the California competitive market was overregulated. The CPUC, FERC, and the CAISO all took shots at regulating this market. From this over-regulation came the requirement that virtually all IOU wholesale electricity be bought and sold in short-term commodity or spot markets. Forward and long-term bilateral contracts for electricity allow a purchaser to buy a certain amount of electricity at a pre-established price over some future period of time. These contracts provide future price certainty and supply security. However, even after the CPX began offering hedging instruments to the market, the CPUC initially restricted the value of these contracts to the IOUs by making their costs potentially unrecoverable under the continuing distribution company (DISCO) cost-of-service regulation. California s reliance on spot markets was unique in restructured electricity markets. Table 7-1 shows that other states and countries restructured competitive electric markets under nearly opposite design conditions. Almost all power in these other restructured markets is sold under long-term or forward contracts. Very little power was sold in the spot market. Other deregulated energy markets sensibly used short-term commodity and spot markets to satisfy a small portion of their power requirements. These long-term contracts permitted these other jurisdictions to hedge that small percentage of power that was not secured through longterm contracts. California s approach took the exact opposite route, exposing the majority of its market to the volatile spot market and severely limiting the ability of market participants to hedge this risk. Consequently, prices elsewhere were less volatile and single price MCPs were applicable to only a small fraction of the MWHs in those other markets.
Design Flaws and a Worsening Crisis 67 Table 7-1. Market Hedges compared to the Spot Market in Other Deregulated Electricity Markets Pennsylvania, New Jersey, Maryland (PJM) Percentage of Market Hedged (long-term forward contracts or selfowned generation) Percent of Unhedged Spot Market 85%-90% 10%-15% New England 80% 20% Australia 90% 10% Norway 85%-90% 10%-15% Sweden 85%-90% 10%-15% On May 26, 1999, FERC approved the CPX s request to offer a block forward market service. The CPX s new product was a long-term trading instrument designed to allow participants to hedge their short-term price risk. Buyers purchase 16-hour power blocks, from 6 a.m. to 10 p.m., for each day of the month except Sundays and holidays. The energy would then be delivered from one to six months following the month of the order. On February 24, 2000, FERC conditionally approved the CPX s request to offer forward contracts to cover peak hours, when energy demand was highest. California s two largest IOUs sought CPUC authority to buy future energy in the CPX block-forward market. In July 1999, the CPUC granted that authority. However, the CPUC limited the amount of power the two IOUs could buy through the forward market to one-third of their respective historical minimum hourly demand by month. Further, the utilities had to take delivery of these purchases no later than October 2000. The CPUC loosened these restrictions in March 2000, when it authorized requests by the two larger IOUs to increase their ability to forward contract through the CPX up to the amount of their respective net short position. 2 The CPUC did, however, reserve the right to conduct future prudence or reasonableness reviews, subjecting the IOUs to potential refunds. The prospect for cost disallowance made the IOUs very wary about entering such long-term contracts. With no assurance that they would be allowed in the future to recover the contract costs from ratepayers, the IOUs did not fully utilize this hedging opportunity. As matters deteriorated in California, the CPUC began to ease these restrictions somewhat. The CPUC, in August 2000, allowed SCE and PG&E to enter into bilateral contracts ending by December 31, 2005. 2 3,000 MW for PG&E and 5,200 MWs for SCE.
68 The California Electricity Crisis: What, Why, and What s Next However, the CPUC did not expand the already established purchasing limits and again refused to guarantee cost recovery, leaving the IOUs subject to regulatory second-guessing in future prudence reviews. This essentially eliminated the IOUs incentives to enter into these long-term contracts. Consequently, the IOUs remained overly dependent on spot market sales during the summer of 2000. Market data show that the utilities did, in fact, underuse this hedging option. FERC and the CAISO data show that SCE used about 80 percent of its forward contracting authority of 2,200 MW in June 2000 and about 58 percent to 67 percent of its 5,200 MW limit for the months of July through August 2000. PG&E used approximately 37 percent of its 3,000 MW limit in June 2000 and roughly 60 percent of its limit in both July and August 2000. SDG&E did not participate in the CPX forwardcontract market at all during this period. Nevertheless, according to the CPX, even this limited use of the CPX forward market saved the IOUs about $706 million from May through September 2000. Not bad, but still too little and much too late. The Retail Rate Freeze Between June and December 2000, conditions deteriorated rapidly. The IOUs were paying extremely high prices for their power and, because of AB 1890 s retail rate freeze, were unable to pass on to their customers these high prices. One cannot long buy high and sell low without incurring huge losses. The California IOUs were no different and soon incurred billions of dollars in liabilities. Credit rating firms watched the utilities deteriorating financial condition and, in January 2001, downgraded the California IOUs credit to junk-bond status. This meant that the IOUs could neither enter into long-term contracts nor purchase electricity from the spot markets. This forced the state of California, through the California Department of Water Resources (CDWR), to begin purchasing electricity for retail utility consumers in early 2001. Eventually, the state treasury s financial credit ratings also dropped. The political and financial fallout continues into 2004. The FERC finally took action by issuing a mitigation order on December 15, 2000. This order eliminated the requirement that the IOUs buy and sell all electricity through the CPX. This action effectively eliminated the CPX as California s primary wholesale spot market for electricity, leaving the state without a primary wholesale spot market. The CPX promptly went out of business and filed for bankruptcy in January 2001. The IOUs were thus free to enter into bilateral and forward contracts. Unfortunately, the IOUs creditworthiness, or lack thereof, meant that no generator was willing to enter into contracts with them. Consequently, starting mid-january 2001,
Design Flaws and a Worsening Crisis 69 the CDWR had to buy the power needed to meet utilities daily net short positions. Price Caps and MWH Laundering The FERC addressed the higher prices in California by initiating a CAISO price cap of $250 per MWH during times of high demand. Likely, the price cap caused some sellers to bid into the CAISO market through OOM transactions, which were not subject to the price cap. This practice was known as MWH laundering. To see how this worked, assume that a $250 per MWH price cap is in effect at the CAISO. A generator could sell directly to a non-market participant (e.g., a municipal utility or out-of-state entity) for $350 per MWH. Non-market participants were not subject to the CAISO price cap, and could resell these same MWHs to the CAISO at a price unconstrained by the price cap (e.g., $375 per MWH) in an OOM trade. California is part of a larger western states energy market. This made it easier for participants to engage in MWH laundering. Thus, when FERC lowered the price cap in the CAISO, OOM purchases increased. We show this in Table 7-2. Table 7-2. Volume of Megawatts Purchased Out of Market, June-December 2000 June July Aug Sept Oct Nov Dec Average Hourly OOM MWs Purchased (Hours 12-19) 26,880 79,205 46,872 45,150 40,796 208,950 487,382 Source: ISO Market Analysis Group Market Analysis Report, January 16, 2001. Some California municipal utilities and out-of-state entities purchased electricity directly from generators and resold the electricity to the CAISO at prices at or above the cap. The FERC unwittingly accommodated this practice by converting its hard CAISO price cap into a so-called soft price cap under which OOM sales could exceed the price cap without affecting the single market-clearing price for in-state generators. Scheduling Outages and Maintenance The CAISO had no authority over scheduled plant outages for maintenance. When the CAISO was being formed, it argued that it needed to be able to coordinate planned outages to effectively maintain the system s reliability.
70 The California Electricity Crisis: What, Why, and What s Next The generation owners, however, contended that they should control scheduled outages. Ultimately, the generation owners prevailed. As a result, the CAISO had virtually no control over scheduled outages 3 until the FERC took remedial steps in 2001 to correct this design flaw. The CAISO s lack of authority to coordinate outages may have contributed to the problems in late 2000 when scheduled plant outages coincided with high demand. This decreased supply likely lead to higher prices. Unscheduled outages exacerbated these problems. Independent system operators for PJM, New York, and New England do have some control over scheduled outages. If the CAISO had similar authority in 2000/2001, it could have coordinated outages more effectively to help alleviate the price consequences of shortages in supply. CONCLUSION Design flaws that had been masked when supply exceeded demand, were painfully exposed when market forces conspired to increase demand and reduce supply. Next, we explore several hypotheses to analyze econometrically these various facts and data. 3 The one exception was Reliability Must Run (RMR) contracts with certain generating units.