FEATURE ARTICLE
Reengineering the Electric Grid
Deregulation places new demands on one of the world's largest engineered structures—and presents new opportunities for educated consumers
Thomas Overbye
Development of Power Markets
FERC Orders 888 and 889 provided the broad guidelines for opening the U.S. power industry to competition. How best to achieve this restructuring was left to the individual state governments. Given the divergent political views of the states and the differences in their average electric rates, it should not come as too much of a surprise that restructuring is progressing at vastly different rates across the country. (Nearly 40 percent of the nation's population now lives in states where there is competition.) States such as California, with high electric rates, a strong environmental movement and plentiful alternative sources of power, have been the first to jump on the bandwagon. Other states are finding it difficult to see any advantage to changing the status quo. Regional differences also come from the grid itself; the Eastern Interconnect is highly meshed with lots of relatively short transmission lines, whereas the Western system is dominated by long transmission lines, supplying power from distant generation to load centers primarily situated along the Pacific rim.
The result has been a vast diversity of market structures. In many states it is now possible for retail customers to shop for electric service from a variety of suppliers, but in others the local vertically integrated utility is still the only game in town. In a bid to ensure open and fair access by all to the transmission system, in Order 888 FERC envisioned the establishment of several regionwide entities known as ISOs, or Independent System Operators. The purpose of the ISO is to replace the local utility's operation of the grid by a private, not-for-profit organization with no financial interest in the economic performance of any market players. In short, the job of the ISO is to keep the lights on, staying independent of and therefore impartial to the market players. As of the end of 1999 ISOs were operating the electrical grid in California, New England, New York, Texas and the coordinated power market known as PJM (Pennsylvania–New Jersey–Maryland). An ISO covering parts of at least 11 states in the Midwest has been approved by FERC but has not yet begun operation.
In theory, under the benevolent gaze of the ISO, buyers and sellers find each other either through private contracts or through the use of a spot market. This brave new world is being accomplished by a disaggregation of the vertically integrated utility. The generators are being sold, the transmission system is now controlled by the ISO, and customers at each level are free to buy from competitors. The only natural monopoly that remains are the distribution wires themselves. The previously captive retail customer can now either contract directly with a generation company, buy on the spot market or sign up with a "load aggregator," a company that signs up many customers to act as a buying bloc. For many the bottom line will be lower.
But beware: The old cost-plus business is rapidly vanishing, being replaced by one with market-driven electricity prices. The new unregulated generation companies are now free to charge whatever price the market will bear. If the power demand is low or moderate, this results in a market with lots of generators competing for the same load, resulting in low prices. In fact, the spot-market price can go to zero, resulting in free electricity. But when the load climbs, so do the prices, often with breathtaking speed. The underlying physics of the system is unchanged, but the new open market means customers at various levels may begin to feel the impact of those physical laws in the form of price fluctuations.
An example is given in Figure 8, which illustrates the marginal prices of electricity at locations throughout Pennsylvania, New Jersey and Maryland at 6 p.m. on July 19, 1999. The marginal price reflects what you would pay for an extra unit of energy consumption, for example when you turn on your air conditioner. The same map would show little variation under low-load conditions; however, as congestion begins to take place on a hot, high-load day, the cost of delivering more power to some regions grows disproportionately. In the same centrally dispatched area, spot-market prices actually fell to zero during a typical low-load week in the fall.
A particularly extreme example of the new sensitivity of prices occurred during the latter part of June 1998. For several days, spot-market prices for electricity in the Midwest experienced almost unheard-of volatility, soaring from typical values of about $25 per megawatt-hour (2.5 cents per kilowatt-hour) up to $ 7,500 per megawatt-hour ($7.50 per kilowatt-hour). Because the affected utilities were selling the power to their customers at fixed rates of less than 10 cents per kilowatt-hour, they lost a lot of money very quickly.
The run-up in prices was so staggering that it might take an everyday analogy to appreciate it. In the 1970s, drivers howled when the price of gasoline tripled. Imagine your consternation if, one day, you pulled into a gas station and discovered the price had increased three hundredfold, from $1.50 per gallon to $450 per gallon. Most of us would look for alternative transportation. But with electricity you do not have options. With no way to store it, the affected utilities had a choice of either paying the going rate, or pulling the plug on their customers on the hottest day of the year. The total additional charges incurred by the utilities as a result of the price spike were estimated to be $500 million.
Although the causes of this volatility are complex, they essentially reflect the underlying characteristics of the electric grid. During the June 1998 price spike, load levels were at or near record levels in the Midwest. As the load went up with no way to store electricity, generation became an increasingly valuable commodity. Recognizing this, companies with generation available to sell were able to raise their prices accordingly.
Interestingly, while generation was in short supply in the Midwest, it was available elsewhere on the grid. However, because of congestion arising from thermal limits on just two elements—a transmission line in Northwest Wisconsin and a transformer in Southeast Ohio—no additional power could be transferred into the Midwest from either the West or the East. The reason for this was loop flow. For example, as Figure 7 shows, a power transfer from Pennsylvania to Illinois would have required that some of the power travel through the congested transformer in Ohio, increasing its overload. Therefore the transfer was not allowed to take place. The overload on this single transformer in Ohio actually prevented utilities from as far away as South Carolina from selling to the affected utilities in Illinois and Wisconsin. This situation allowed the remaining suppliers of power to raise prices to unheard-of levels.
This should not be construed as price gouging on the part of the suppliers: Spot prices 100 times costs may raise eyebrows, but Figure 9 shows why, in the presence of congestion, the fair market value of electricity can be higher than the cost of generation at any of the individual generators. Efficiently managing electricity markets, when congestion on a single element can have such a tremendous systemwide impact, will continue to be a significant challenge for the ISOs.
From the retail customer's point of view, the most noticeable kind of volatility is not measured in dollars and cents, but in minutes and hours: the time spent without electricity during a blackout. During the summer of 1999, the Eastern Interconnect experienced several blackouts or "reliability events" (for example, unexpected voltage drops) affecting as many as 200,000 people at a time. These all happened during unusual heat waves, so high demand was obviously a factor behind the events. But the DOE Power Outage Study Team concluded that the market pressures of deregulation also played a significant role. "Market rules for system operation during times of system emergencies have not been fully developed or agreed upon by market participants," the report concluded.
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