California At Sea: The Perfect Political Storm
Power companies and banks with investments in California had best batten down the hatches: the storm they weathered last summer when electricity prices soared to unprecedented levels is likely to repeat next summer.
The experience holds lessons for regulators and participants in deregulating markets everywhere.
The high prices that rocked the western power markets last summer were caused in part by lack of generating capacity, relatively low hydroelectric generation, high natural gas prices, and high costs for emissions trading credits. Flaws in California’s electric market were also to blame.
The California legislature voted unanimously for deregulation of the electricity market in 1996. The plan had support from utilities, large customers, labor unions, independent power producers and small customers, providing what one observer called “something for everyone.”
Under the plan, two new entities were created – an independent system operator, called the “Cal ISO,” and a power exchange, called the “Cal PX.”
The Cal ISO operates the transmission system. It is also charged with assuring reliability of the electric grid by managing transmission congestion through usage charges, administering a real-time market for imbalance energy usage, and procuring ancillary services.
The Cal PX is the spot market for buying and selling power that operates day-ahead and day-of hourly energy markets, as well as offering block forward power contracts. The Cal PX currently dominates California’s wholesale power market because the utilities have an obligation to buy all of their power requirements and to sell all of the output from their power plants through the Cal PX.
Aside from the creation of the Cal PX and Cal ISO, utilities were allowed to recover generation-related stranded costs through a non-bypassable transition charge during a transition period to end no later than March 31, 2002. Utility plant divestiture was encouraged to mitigate potential market power concerns and to pay down stranded costs. Retail rates were frozen during the transition period, with recovery of stranded costs being inversely proportional to wholesale power prices. Customers were allowed choice in selecting energy service providers.
Calm Waters: 1998 and 1999
The early consequences from deregulation were encouraging.
Power prices were reasonable, if not low. In its first year of operation in 1998, the Cal PX day-ahead market averaged $24 per MWh, while prices the next year averaged $28 per MWh. During those years, the Cal PX accounted for 80% to 90% of the power volume transmitted through the Cal ISO. Meanwhile, the Cal ISO maintained system reliability during a period of record electric demands and four “Stage 2 emergencies” when the reserve margin on the Cal ISO-controlled grid fell below 5%.
Over 186,000 customers – primarily large commercial and industrial customers – took advantage of the opportunity to strike favorable power purchase agreements with third-party providers. Some of these arrangements were short-term deals that were tied to the spot price of power from the PX. Other agreements were longer-term and included hedging against power price volatility.
Industry restructuring opened the floodgates for development of new power generating facilities in California. At present, the California Energy Commission, or “CEC,” has more power plant applications pending and expected than at any other time in its history. Five power plants, representing 3,628 megawatts of new capacity, have been approved (but only two are expected to come on line in 2001). There are applications pending at the CEC for another 7,892 megawatts of new capacity. Finally, there are at least four additional plants (representing 2,750 megawatts of new capacity) that are expected to file applications for siting approval with the CEC in the near future.
Over $500 million in funding was pledged to reinvigorate the renewable energy industry in California. So far, over $162 million has been pledged for the development of 500 megawatts of new renewable resources, while customers have received about $76 million in credit against electricity bills for buying power from renewable energy providers.
The state’s investor-owned electric utilities – Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric – divested over 17,000 megawatts of capacity, receiving an average of 1.8 times book value for generation assets, or $180 a kilowatt hour. Almost 7,000 megawatts of additional capacity could be divested in the next two years. Relatively high sale prices for generating assets, combined with low power prices, allowed utilities to pay down some or all of their stranded costs. San Diego Gas & Electric was able to pay off its stranded costs by June 1999. This ended the rate freeze in San Diego, which meant that customers’ rates would reflect the volatility in spot power prices from the Cal PX unless San Diego Gas & Electric hedged against this uncertainty.
In short, the first two years of the restructured power market appeared to be successful in terms of prices, opening markets, and rationalizing ownership of generating assets.
Storm Clouds Appear: Early 2000
By early 2000, there were small yet noticeable signs that all was not well in California.
These included complaints by a number of market participants that the restructured power market was dysfunctional. The Cal ISO’s market surveillance committee also expressed concern that individual generators or power marketers possessed too much market power at least some of the time.
The Cal ISO attempted to respond to these concerns by making over thirty sets of changes to its tariffs, including major changes in the operation of the Cal ISO’s ancillary services markets to try to curb very high prices in certain markets. A number of retail energy service providers abandoned the California market because of thin margins, market design problems, and very low market acceptance of their products.
Most municipal utilities, including the Los Angeles Department of Water and Power, declined to cede operational control of their transmission facilities to the Cal ISO. In addition, California was either unwilling or unable to reduce the time or complex regulatory requirements that power project developers faced in obtaining permits to site new generation. Finally, the utilities complained about their limited ability to hedge against price volatility through forward contracting. However, because power prices were reasonably low, customers and regulators did not sense any immediate need to resolve these concerns.
The Storm Hits: Summer 2000
The storm rocked California and western power markets with punishing force in the summer 2000.
Power prices moved in ways previously unseen in the west. Not only did power prices soar to unprecedented levels during peak load hours – for example, greater than $1,000 per MWh in certain bilateral markets – prices also were very high during some off-peak periods. Figure 1 shows the Cal PX price versus load scheduled through the Cal ISO. As seen in Figure 1, prices in the summer of 2000 appear to have increased to record levels almost without regard to electric demand.
Loads increased at the same time electricity imports fell. The Cal ISO saw its loads increase by 7% in June and July 2000 compared to the same two months the year before, even though the summer 2000 was not a record-setting demand year. Demand in the Pacific northwest and the southwest also grew, resulting in less excess power being exported from those regions to California. For example, net hydroelectric imports from the northwest into California decreased by more than 3,200 megawatts in August.
Meanwhile, due to construction and regulatory delays, no major new power projects came on line in California in time to help supply the higher loads in 2000.
By July, the average price of power in California had risen to $109 a MWh, with August prices spiking to $166 a MWh. Hourly prices hit $750 a MWh in the Cal PX. Figure 2 shows hourly market-clearing prices since the Cal PX began operation. Figure 3 shows off-peak prices, which also soared in the summer 2000.
The quality of service suffered. In June, the Cal ISO required the involuntary curtailment of power deliveries to about 100,000 customers in the San Francisco Bay area as a result of transmission limitations. This was the first time in history such an action had been taken in California. In addition, the Cal ISO declared 32 “Stage 1” – less than 7% reserve margin – and 17 “Stage 2” – less than 5% reserve margin – emergencies. These emergencies resulted in interruption of service to participants in the utilities’ interruptible load management program. Since the inception of these programs, participants had never experienced this frequency of interruptions.
These gyrations in the power markets had significant impacts on different stakeholders.
San Diego Gas & Electric, having ended its rate freeze, passed along the increased costs of wholesale power to its customers, resulting in rate increases of over 70%. Because of the public outcry resulting from these rate increases, the California Public Utilities Commission initially imposed retroactive rate caps on San Diego Gas & Electric, with undercollections accruing to a balancing account. These caps were further reduced as a result of passage of Assembly Bill 265. These retail rate caps have resulted in San Diego Gas & Electric being unable to recover its cost of service fully.
The wholesale cost of power for the other two utilities – Pacific Gas & Electric and Southern California Edison – also soared. However, these utilities were unable to pass along the spiraling costs to consumers because they still had frozen rates. This has caused a major cash flow crisis for the utilities. The bond ratings for these companies have suffered as a result. In fact, these utilities – which are subsidiaries of holding companies – have implied that bankruptcy is a possibility if the CPUC fails to grant them additional borrowing authority and other forms of relief. These claims are being investigated by the CPUC, with the utilities being asked to produce extensive documentation of the problems and how affiliated unregulated companies may have profited during the summer 2000.
The Cal ISO imposed much lower price caps on its markets than were in effect before in response to pressure from California governor Gray Davis, the state legislature, utilities and ratepayers. This has created incentives for in-state generation to be sold out of state, where such price caps do not exist, resulting in even less generation being available to meet California’s power demands.
The state legislature, the Electricity Oversight Board, the Federal Energy Regulatory Commission, the state attorney general and the CPUC have all opened investigations into the cause of the high summer prices in western power markets. As part of these investigations, a number of owners of generation in California – particularly companies that acquired the utilities’ divested generation – have been served with subpoenas to produce documents disclosing their bidding and operating strategies.
Owners of generation in or around California – for example, LADWP, the utilities, the “new generation owners,” and other independent power producers – and power marketers have reported very strong quarterly profits as a result of the high prices.
Causes of the Storm
The storm last summer had two causes: structural defects with the market design, and supply and demand issues.
The Federal Energy Regulatory Commission identified three major flaws in California’s market structure.
One is the limited ability of the local utilities to purchase forward, requiring almost complete reliance on spot markets. The CPUC required utilities to purchase almost all of their power requirements through the Cal PX, which until recently offered only a day-of and day-ahead market. Thus, the utilities had limited ability to hedge against spot price volatility.
Another structural defect is chronic underscheduling of both loads and supply, requiring the Cal ISO to purchase too much power through the real-time markets. Lower price caps in the Cal ISO than in the Cal PX caused load-serving entities to bid their demand in the day-ahead markets only up to the price cap in the Cal ISO real-time market. As a result, as prices rose in the Cal PX, a greater and greater share of the load-serving entities’ demand was being met through the Cal ISO’s real-time market. In fact, at its peak, the Cal ISO had to procure over 15,000 megawatts in real time. Purchases of such magnitude were never anticipated in the design of the real-time market.
The third structural defect is lack of demand responsiveness because of frozen retail rates. The CPUC froze rates for retail customers in order to allow the utilities to recover their stranded generation costs. However, when wholesale power prices rose, most customers did not reduce consumption because the high prices had little or no economic impact on them. This resulted in higher bids from suppliers and higher market clearing prices.
The Federal Energy Regulatory Commission proposed several short-term measures to repair these market failures in early November. However, the commission warned that it does not have jurisdiction either to give load-serving entities the right to hedge or to end the retail rate freeze in order to provide some measure of demand responsiveness. Only the CPUC can fix these problems.
Supply and demand issues
A number of market fundamentals also contributed to the soaring prices.
Higher loads: Electric demand in the western region has grown significantly over the past several years. There were several days last summer when temperatures reached unusually high levels – for example, temperatures reached 111 degrees in parts of the San Francisco Bay area on June 14.
Lower hydro generation: Load growth in the Pacific northwest coupled with relatively low hydroelectric production resulted in less power being sent to California from the northwest, which is an area that has traditionally supplied California with low-cost power during the summer.
California power was exported: After the Cal ISO ordered the reduction in price caps in California, prices in markets outside of California were more favorable to suppliers than the markets with capped prices in California. As a result, some marketers sold power into out-of-state power markets. FERC estimates that net imports declined by about 3,000 megawatts from May through August, which is the period over which the Cal ISO reduced its price caps.
Higher variable operating costs for gas-fired generators: Power plant owners saw significant increases in their variable operating costs, resulting in higher bid prices. First, natural gas prices at the southern California border reached an all-time high in the summer 2000, with month-ahead prices reaching almost $7.00 an mmBtu in September. These high prices were a result of greater demand for natural gas and deliverability problems on the interstate gas transportation system. Second, a general tightening on the supply of emissions trading credits in southern California as well as higher demand for these credits – in part a result of greater operation of power plants in California – caused the price for these emissions trading credits to spike. Emissions credits that had once sold for $6 a pound or less were trading for over $40 a pound in August. Figure 4 shows the hypothetical operating costs for generators in the summer of 2000.
The potential for the high prices seen in the summer 2000 existed since the time the California market was restructured. However, because of a lucky series of events – for example, cool summers and high hydroelectric output – prices never reached the prices seen last summer. It was only when electricity demand was “normal,” net imports into California were down, and forced outages of thermal generating plants were up that the market structure problems began to take their toll, allowing the “Perfect Storm” to occur.
California’s battered power market is not yet out of the storm. Many of the root causes of the high prices last summer cannot be changed immediately.
California is working to bring on new peaking capacity in the near term, but it is not clear that this and other stopgap measures will be enough to avoid a replay in 2001. Without significant new generation coupled with improved demand responsiveness, prices next year will be as high or higher than this year absent price caps that the Federal Energy Regulatory Commission is proposing to implement. However, these price caps will weigh heavily on the minds of new power plant developers when analyzing the risks and potential rewards of investments in the western power market versus other locations. There are no easy evacuation routes to avoid the storm of 2001.
by Dr. Robert B. Weisenmiller, William A. Monsen, and Steven C. McClary, with MRW & Associates, Inc. in Oakland, California