POWER DISTURBANCES COST U.S. ELECTRIC CUSTOMERS about $26 billion each year: nearly three times the anticipated annual saving from deregulation.
Competition and restructuring will only turn up the pressure, as the grid carries more low-cost power over longer distances to a wider variety of customers.
Already we are seeing a rapid rise in wholesale power transactions. Some utilities now complete as many such transactions in one day as they previously made in one week. Overall, the value of wholesale transactions has increased fourfold over the last decade. About one-half of the electricity now generated in the United States is sold in the wholesale market. This figure may rise to two-thirds with more deregulation.
Can the grid carry this new burden?
The rapid growth in bulk power markets comes at a time when many parts of the North American transmission system are operating close to stability limits. Loads are growing by 2 to 2.5 percent each year - about 30 percent in a decade - but the annual addition of new transmission circuit miles has declined by more than 60 percent over the last decade. The considerable political problems in siting new lines heightens the need for technological and managerial solutions.
On July 2 and Aug. 10, 1996, electrical disturbances on the western transmission system disrupted power to millions of customers in several states and adjacent areas of Canada and Mexico. It has been estimated that the financial losses suffered by the California industry for the Aug. 10 outage alone, due to lost production, spoilage, etc., ranged between $1 billion and $3 billion. In addition, power flows along the Northwest-to-California interties were decreased about 10 percent to provide a greater margin of stability, a fix that imposed an economic loss for the utilities involved.
To guarantee a reliable system that can meet the increased demands of open access, the capacity and reliability of transmission networks will have to be improved. The industry needs technological advances that improve physical control of grid operations through accurate monitoring and data sharing. It also needs legislation to determine who is ultimately responsible for keeping the lights on.
The technological challenge is clear. Yet, any guarantee of efficient power delivery in the 21st century will prove as much a matter of politics as technology.
Reliability: An Institutional Challenge
At the institutional level, the proposed creation of independent system operators marks the most prominent response yet to the challenge of achieving open access on the transmission system while maintaining grid stability.
ISOs control the flow of power over transmission networks under agreement with the transmission owners. (A recent study by the U.S. Department of Energy elaborates on the move to ISOs. %n1%n) Specifically, ISOs are required to provide open, nondiscriminatory access to the grid for both buyers and sellers, while making sure that system reliability is maintained. So far, the utility industry itself is taking the lead in creating ISOs, which enjoy substantial latitude from the Federal Energy Regulatory Commission in terms of their attributes and particulars.
The FERC has already reviewed ISO applications for California, New England, the mid-Atlantic and upper Midwest regions. Applications for two other regions follow close behind. (The first ISO to become operational affected only the state of Texas and thus did not require FERC approval.) Thus far, these ISOs vary in terms of functions and governing structures. %n2%n
Nevertheless, the industry has not yet answered the question of how ISOs will maintain system reliability in an increasingly decentralized and competitive bulk power market. Traditionally, that responsibility lay with the North American Electric Reliability Council, which relied on voluntary cooperation from utilities and power pools that belong to its regional councils. In January 1997, NERC decided to make its rules and procedures mandatory and to create a new system featuring measurable performance standards. %n3%n This action, however, has raised a new issue - how to enforce the standards. Many have come to doubt whether the FERC maintains sufficient statutory authority to require all market participants to comply with NERC rules.
To clarify this issue, the Secretary of Energy Advisory Board's Task Force on Electric System Reliability has proposed that Congress adopt legislation to enable the FERC to approve a system of self-regulating organizations for transmission system reliability. %n4%n This concept is already commonly used in the securities industry, where the Securities and Exchange Commission authorizes various SROs, such as the National Association of Securities Dealers, to regulate the operations of their own members. For transmission system reliability, the proposed legislation would enable FERC to recognize the status of NERC as an SRO for establishing reliability standards for the electricity industry. As a result, ISOs would then be bound to monitor and enforce compliance with NERC standards in their regions. The FERC would ensure that NERC's governing procedures, its standards and its enforcement activities met the public interest. It is anticipated that this institutional structure would also meet the challenge of reliability if ISOs eventually should give way to transcos - network operators that also own the physical grid assets but remain independent of power generators and retail service providers.
A Technological Problem
In the long term, however, legislative fiat and institutional restructuring cannot ensure that transmission systems will address the reliability problems that may come with open access. Eventually, both the capacity and reliability of transmission networks will have to be improved simultaneously through development of a highly automated, "smart" power system. The grid will need technological advances in four major areas:
1. Improved physical control to expedite grid operations by switching power more quickly and preventing the propagation of disturbances;
2. Monitoring systems that can improve reliability by surveying network conditions over a wide area;
3. Analytical capability to interpret the data provided by the wide area monitoring system for use in network control; and
4. A hierarchical control scheme that will integrate all the above technologies and facilitate flexible network operations on a continental scale.
Electric utilities are now adding these technologies to their transmission systems, creating smart networks.
"Flexible AC transmission system," for example, denotes a family of high-voltage electronic controllers that can boost the power-carrying capacity of individual transmission lines up to 40 percent. These controllers also improve overall system reliability by reacting almost instantly to disturbances. Four FACTS controllers are already operating on utility systems, with more to come. American Electric Power Co., for example, is installing at its Inez substation in eastern Kentucky the most advanced FACTS device, known as a "unified power flow controller." To achieve widespread utility use of FACTS, researchers must reduce the cost of individual controllers to get them ready for mass production. This next generation of devices should be inherently more cost-effective and energy-efficient.
A "wide-area measurement system" uses real-time information to monitor conditions throughout a group of neighboring power systems simultaneously, detecting abnormal conditions over the horizon. It allows controllers to correct disturbances before they spread. WAMS works like this:
Step 1: Satellites send signals to sensors that affix a "time-stamp" to data at numerous points throughout multiple power systems.
Step 2: These data are sent to control centers, which analyze the information to check for abnormal conditions.
Step 3: Control centers then share this information, allowing adjacent regions to coordinate their operations.
The first WAMS is being developed for the western transmission network. However, the problem of assimilating and communicating all the data produced by WAMS remains a major gap in technology development.
Of course, operators will need the right tools to interpret the information supplied by WAMS in real time, to send commands to the control devices that maintain stability. Such online analysis allows expert systems to optimize network configuration for maximum power transfer. Such online system analysis is just beginning. The first generation of online software, now available, provides operators with near-real-time information on system conditions - but not the ability to analyze in realtime. Ultimately, this sort of analysis will require the use of parallel processing computers, now in the early stages of development.
Finally, we need to be able to tie together FACTS, WAMS, and online analysis into an overall control scheme. Called hierarchical control, this system will coordinate the intelligent local operation of power flow devices with broader system needs. Local control of transmission devices now exists. In the future, more of the burden of control will need to shift to centralized control centers to make transmission capacity more dispatchable, in much the same way that generation capacity is dispatched today.
Distribution Systems: More Options Needed
Retail deregulation means more choice among a wider range of services. Utilities must customize services in a way that will attract and hold diverse groups of ratepayers. Specifically, technologies are needed that can:
• Provide perfect power to customers with sensitive
• Offer rate flexibility to customers concerned primarily with cost;
• Integrate multiple utilities services for customers who want the convenience of one-stop shopping.
Again, several specific technologies are becoming available that can help fulfill these needs. "Custom power," for instance, is a type of power electronic controllers designed for use on distribution systems. Custom-power devices
provide the key to enhanced reliability on distribution
systems. One custom-power device, for example, the "Dynamic Voltage Restorer," or DVR, smooths out power disturbances on a line before they can affect a particular customer's sensitive load. Another, the "Distribution Static Compensator" (also known as D-STATCOM), protects the line from electrical "pollution" created by large customer equipment, such as a sawmill. These devices are used currently in utility operation.
In the future, distribution utilities can couple custom-power controllers to energy storage units to provide outage ride-through capability. Again, cost marks a major obstacle to widespread use of custom-power techniques. Development of advanced semiconductor devices, improved magnetics and mass markets will address this barrier over the next two decades.
One innovative way to expand power system flexibility involves so-called "distributed resources." Examples include a variety of energy sources, such as wind power, small combustion turbines, photovoltaics, fuel cells and storage devices. Their deployment on distribution systems bypasses transmission networks and may offer a way to reduce retail rates. Custom-power controllers will help integrate DR into existing distribution networks. Most DR technologies, however, will require substantial cost reductions before they can achieve broad market penetration.
Technology is one thing, but can customers use it? This problem calls for new communications standards and customer interfaces. The Electric Power Research Institute proposes using "utility communications architecture" as a technical basis for nationwide direct access. UCA provides a plug-and-play standard for linking distribution system hardware and software from different vendors.
Improved customer interface technology through the development of "smart" meters will provide the physical connection to integrate electricity, natural gas and telephone services with automatic meter reading and the capability for real-time pricing.
Clearly, the retail market for electricity is going to be more customer-driven in the years ahead. Through restructuring and new technologies, utilities will be able to offer their customers new types of customized services including power that is 100-percent reliable and available. F
Philip R. Sharp is director of the Institute of Politics at the Kennedy School of Government, Harvard University. Karl Stahlkopf is vice president of energy delivery & utilization at the Electric Power Research Institute. Sharp is chairman and Stahlkopf is a member of the Secretary of Energy Advisory Board's Task Force on Electric-System Reliability. EPRI is working with the U.S. Department of Energy and other interested stakeholders on an Electricity Technology Roadmap, which can help guide future
R&D efforts on a national scale.
1. U.S. Department of Energy, Maintaining Reliability in a Restructured Electric Power Industry: The Role of Transmission System Operators (ISOs or TransCos), 1997.
2. See, "ISOs: A Grid-by-Grid Comparison," Public Utilities Fortnightly, Jan. 1, 1998, p. 44.
3. Note: NERC also has formed an Electric Reliability Panel to explore the best ways to ensure future reliability and to review institutional options that might replace NERC with another reliability organization. The panel met most recently in Austin, Texas, on Dec. 6-7. It planned to issue recommendations by the end of December, in time for consideration by NERC's Board of Trustees in a meeting set for early January.
4. Secretary of Energy Advisory Board's Task Force on Electric-System Reliability, Maintaining Bulk-Power Reliability Through Use of A Self-Regulating Organization, 1997.
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