TIME TO BUILD

High demand, low supply, upward-bound prices. The problem of electricity competition in California and across the nation centers on the lack of generation capacity and an overburdened transmission system.

Policymakers embarked on the restructuring of the electric utility industry to encourage competition, with the expectation that doing so would lower prices for power and spur development of new products and services. To date, 24 states and the District of Columbia have adopted competition, and the electricity industry is now in a transition to competitive markets.

Recent experiences seem to be tainting those policy goals. During this market evolution, short-term price increases, due to surges in the demand for power, have raised some consumer concerns about the effectiveness of state retail competition programs and have caused others to reject electricity competition generally.

However, even in mature competitive industries, the inability to produce enough of a commodity consistently to meet demand, and/or the inability to get the commodity to market, will cause prices to rise—sometimes significantly—with the ebb and flow of supply and demand. Electricity also has a characteristic that makes it unique: Unlike oil, for example, it cannot be stored, so it must be consumed generally at the instant that it is produced.

The underlying problem causing price volatility and potential outages is the significant increase in the demand for more electricity that can only be addressed by assuring that there is adequate generation and transmission capacity. The short answer is that we need to build more generation and transmission facilities. But there are several policies that need to be supported to do this, including the use of pricing that reflects the market value for power, incentives that increase investment in transmission, a balancing of environmental and siting policies to encourage construction, and a way to educate the public about how those issues in competitive markets differ from such issues in regulated ones.

Generation: Lagging Behind Demand Growth
The demand for electricity has been spurred by an unprecedented period of sustained economic growth and by a booming technology-reliant economy. The growth in demand is due, in part, to the proliferation of computer and high-tech peripherals including servers, printers, and fax machines. Since 1990, by some lights, high-tech equipment has added around 1 percent annually to national power demand. The high-tech effect is difficult to measure—in terms of the nation's total power demand, estimates run from 3 to 20 percent. Some predict that share to rise even higher.

Compounding the acceleration in demand was a lag in construction of new generation. In the 1970s and 1980s, America had power surpluses. As a result, state regulators, seeking to keep consumer rates down, often disallowed the costs of some excess capacity and did not allow utilities to recover in rates all of their costs for building new plants. In many cases, utilities were required by their regulatory commissions to buy power from other suppliers rather than build their own plants. That, and the advent of deregulation, engendered a cautious attitude toward investment costs that might not be recoverable. The result was a construction lag, while demand for power increased by about 2 percent per year.

Nevertheless, between 1978 and 1992, America's utilities had reserve margins that averaged between 25 percent and 30 percent to meet emergency demand situations such as those encountered during heat waves. Since 1992, the reserve margin has dropped significantly—to less than 15 percent nationwide.

In 1990, the North American Electric Reliability Council (NERC) estimated that national demand for power would grow about 1.8 percent annually; in actuality, the rate has been between 2 percent and 3 percent. Some parts of the country are growing faster. In California, for example, demand has increased 1,000 megawatts (MW, or 4-6 percent) per year—enough to power 800,000 homes!

On a regional basis, demand growth has resulted in reserve margins that are so small that NERC has identified regions as "areas of concern" in which utilities may not be able to meet their generation reserve obligations during peak load conditions or during extended heat waves. These areas include New England, New York, and the southwestern states—New Mexico, Arizona, southern Nevada, and California.

Moreover, in its most recent assessment, NERC estimates that more than 10,000 MW of capacity nationally will have to be added each year between now and 2008 to keep up with even the 1.8-percent annual growth rate. However, since 1990, actual annual capacity additions have been averaging only about 7,000 MW.

Transmission: Rapidly Nearing Its Limits
Utilities originally built transmission lines to move power from their generating plants to their customers. Over the years, the roles of utility transmission systems have expanded. As regions of the country grew, utilities interconnected their transmission systems to enhance reliability by allowing power companies to share power during emergencies. Following that, transmission was employed to exchange economical power on the wholesale market among neighboring utilities. The newest role, fostered by competition, is to use transmission systems as the means of carrying power across greater distances to customers in competitive markets.

To have fair and open competition, companies wishing to sell power must be able to use transmission lines to deliver it to their customers. To ensure that all power providers have fair, nondiscriminatory, and open access to transmission lines, the Federal Energy Regulatory Commission (FERC) issued a series of orders. First, the orders required transmission-owning utilities to open their transmission systems to all suppliers. Second, the orders encouraged utilities to turn over operational control of their transmission facilities to regional transmission organizations (RTOs) by the end of 2001.

There has been significant progress in forming RTOs. Today, a third of all electricity customers are already being served by existing RTOs, and an additional 22 percent would be covered by RTOs that are waiting for approval. In the near future, more than 79 percent of the total number of electricity customers will be served by proposed RTOs and those under active development.

Despite progress in forming RTOs, it is important to note that the number of transactions and the way power flows into transmission systems are increasingly different from the ways networks were originally designed to handle power. Today, more suppliers are trying to put more power on transmission lines, challenging the limits of their capacity. Most of today's transmission systems were not designed to be electrical "superhighways" for delivering large amounts of power over long distances or for supporting the ever-expanding competitive trade of wholesale power—the sale of power from one utility or power provider for resale to an end-use customer.

Indeed, transmission capacity is becoming an increasingly scarce resource in certain regions of the country. For example, in 1995, 25,000 inter-regional electricity transactions were made. In 1999, the number hit 2 million. In a growing number of areas, the transmission lines are carrying all of the power they can. The effect of this congestion is that consumers may not have easy access to low-priced power, and reliability may be threatened.

Obstacles to Expansion
The ultimate solution to transmission capacity scarcity is to build new transmission facilities and upgrade existing ones—a fairly simple answer. Unfortunately, siting transmission is extremely difficult. Unlike the strong federal eminent domain authority resting with FERC in the case of natural gas pipelines, transmission line siting usually involves several state and federal agencies as well as local governments and citizen groups.

A prominent example is the planned construction of a line linking West Virginia and Virginia. (See the sidebar, "Back and Forth") Proposed in March 1990 and not yet finally approved, the project has cost about $30 million for applications and studies and involves state regulators from both states and four federal agencies.

Another example is the Chisago transmission line project, begun in 1996 as a proposal for a 39-mile, 230-kilovolt (kv) line that would link facilities in Minnesota and Wisconsin. Because the project is in two states, involves an electric cooperative, would cross a river, and involves a national park, reviewing agencies include the Public Service Commission of Wisconsin, the Minnesota Environmental Quality Board, the Rural Utilities Service, the Army Corps of Engineers, the National Park Service, and local governments. Project managers now expect construction of a scaled-down line (161-kv) to begin in 2003 or 2004.

Building new generation facilities also can be difficult because of regulatory and social concerns. For example, in San Francisco, the Pacific Gas & Electric Company quit efforts to install four new gas-fired turbines in early August of last year because anticipated regulatory hurdles would cause untimely delays—despite the critical need for extra generation. "We've had ongoing discussions with several state and local agencies that have oversight. As these discussions progressed it became apparent to us that the approval process was not going to coincide with the summer peak season," a company spokesman said.

Frequently, citizen coalitions will object to the siting of facilities in their own communities. "In regulated monopoly days, residents knew that if a powerplant was built in their backyard, it would generate electricity for their community based on its needs," said Gerald Nordlinger, executive director of the Public Utility Law Project, in a recent article. "Now, when power can be sold like...any other commodity, the perceived social costs of a powerplant are higher because no community can be sure where the electricity will go."

Regional Power Concerns
During the summer of 2000, the most salient factor affecting the price of power was high temperatures that increased demand for electricity to the point where it nearly outstripped generation and transmission capacity. For example, in early August, a four-day string of 100-plus temperatures in California pushed electricity prices in San Diego to twice the rate that they were the year before and threatened rolling blackouts. By contrast, the Eastern seaboard—experiencing its coolest July in 75 years—did not have California's price volatility and threats of blackouts.

Under California's 1996 electricity competition law, consumers received a 10-percent rate reduction and a rate freeze until utilities recovered their transition costs. According to the law, after costs were recovered by utilities, the price consumers paid for power would be based on market rates.

California's power shortages and high prices reflect the fact that for the past decade virtually no new powerplants were built, despite soaring power consumption. Stringent environmental rules and the failure of regulators to anticipate the state's Silicon Valley-driven economic boom have been the major reasons for not building needed plants. As a result, electric demand has grown 25 percent in the past eight years, while instate power generation has increased only 6 percent.

Contributing to San Diego's August power problems was the fact that its utility was the first in the state to shift from charging consumers regulated rates for power (which previously had been frozen) to charging consumers prices that were determined by the retail market. The rest of the state is still functioning under provisions of the restructuring law that provide capped rates and a 10-percent rate reduction. The result was that while power supplies were tight in San Diego, the rest of the state had no incentive to conserve electricity. (See the sidebar, "Key Facts on California Markets.")

California's lack of instate generation resources is affecting not only San Diegans: It is affecting the prices of power and the health of the economy throughout the Northwest. That is because California has to import a fifth or more of its power. As demand and prices rose in California, the price of power increased regionally. In August, the Wall Street Journal reported that spot-market prices as high as $1,300/MWH in the Northwest sent shock waves through the local economy. As of mid-August, aluminum plants, pulp mills, cold-storage facilities, and mines had laid off workers and curtailed production. For example, the owners of the Continental Copper Mine near Butte, MT, suspended production and laid off 365 workers when their old power contract, at $38/MWH, expired on July 1, and the market price had risen to $65-$100/MWH.

Other regions of the country also are vulnerable to volatile power prices when temperatures push demand beyond the limits of constrained power reserve margins. For example, last May, the New York independent system operator (ISO) forecast a peak demand that was 1.7 percent higher than the summer of 1999.

"The basic laws of supply and demand indicate that near-term wholesale prices will be higher as demand increases and supply does not," said the state's ISO president and CEO William Museler in a recent "Megawatt Daily" article. "Higher prices should ultimately elicit investment in new generation; however, licensing new generation is not a smooth process. The peak demand is growing with New York's robust economy, while the building of new generation has remained stagnant. One outcome of those conditions could be a degree of volatility in wholesale electric prices this summer."

Assuring Adequate Generation and Transmission
Competitive markets are expected to supply the incentives needed to build new production facilities, but siting approvals and construction will take time. In the near term, electricity suppliers will have to manage the demand for power, especially during times of extreme temperatures. Customers can contribute to these efforts by using energy efficiently and reducing power consumption during times of high electricity demands.

To foster adequate generation and reliability, policymakers should:

• Support transparent pricing (for all ultimate consumers) that reflects the market value for power to help assure that markets will provide the incentives needed to build sufficient generation facilities.
• Avoid the long-term use of price caps in competitive power markets. While both the California ISO and FERC reduced price caps in the state last year, price caps have produced mixed reviews among utility industry observers. On one hand, caps limit the prices that consumers will pay for power. At the same time, caps are a short-term solution that discourages the investment needed to build the new generation and transmission facilities that can address the underlying problem.
• Adopt uniform interconnection standards, such as those now being developed through the Institute of Electrical and Electronics Engineers, for integrating small-scale generators or distributed generation.
• Support efforts at EPRI, the Department of Energy, and in the private sector to research and commercialize more efficient generation technologies in order to promote reliability and environmental protection.

Likewise, upgrading and building new transmission capacity are vital if the country's electricity system is to continue its critical infrastructure role in the economy and be the superhighway of electricity competition. To achieve these goals, several policy changes are needed:

• FERC should implement its revised transmission pricing policies broadly to provide rates of return and other appropriate pricing incentives to attract capital to fund needed investments in transmission expansion.
• The commission should provide incentives, such as performance-based rates, that provide opportunities for transmission providers to earn higher returns in exchange for more efficient use of the grid, superior customer service, and productivity gains.
• The Internal Revenue Code should be brought into line with changes in the electricity industry to enhance competition and reliability.
• State and local decisionmakers must cooperate to address siting problems, and consumers must realize that transmission lines must be built to assure continued reliable electric service.
• New "rules of the road" must be developed so that all transmission users abide by the same essential reliability requirements. Congress should adopt a consensus proposal to change NERC into a self-regulating reliability organization under FERC oversight.
• Congress should support the transmission technology research program of EPRI that aims to enhance the use of the grid.

Consumer Expectations and the Need for Education
For the better part of the last century, we have had a regulated electric supply system. That system required utilities to supply as much power as needed to all customers in a geographically defined service territory on demand. The rate system flattened out the prices that consumers paid for power by eliminating price spikes caused by changing fuel prices or any of the other factors that influence the cost of making electricity.

As a result, Americans expect that power will be there—at a fixed price, regardless of demand—when they flip the switch.

Early proponents of electricity competition promoted restructuring as a way to cut costs and seldom discussed the difficulties that would be encountered in transitional markets. Nor was it emphasized that in fair competitive markets it would be normal for electricity prices to rise and fall much as they do for gasoline, heating oil, and natural gas.

To assure a successful transition to competition, policymakers and other industry stakeholders should include educational components in their restructuring programs to help consumers understand that prices will fluctuate.

Electricity competition will have the best chance for smooth implementation if the generation and transmission infrastructures are adequate to meet anticipated peak demands and the stresses of competition. If they are not, circumstances will certainly arise in which demand will exceed resources—a situation that will result in price increases and supply interruptions.

© 2008 Edison Electric Institute