operating conditions may ease some operating issues as a result of well-designed markets that vary the prices that retail customers pay in real time.
Notwithstanding the many technical similarities, many differences also exist in the electric system within and across sub-regions. The differences stem from numerous factors, including asset ownership, operational control, indigenous natural resources, market development, topography, weather conditions affecting energy production and use, regulatory practices and traditions, business differences (e.g., business confguration), and so forth.
For example, energy use peaks at different times of the day in different regions. Some regions have generation capacity surpluses, whereas others are generation constrained. Some regions have adequate transmission capacity to allow for economic and reliable transfer of energy to other regions; others are transmission constrained, preventing otherwise economic generation to serve customer demand. Because of social and political factors and environmental, health, and public safety concerns (not to mention perceived adverse impacts on property values), some regions have great diffculty adding new transmission capacity on new or even existing rights-of-way; others are able to build new transmission readily.
Likewise, regions with plentiful coal have a history of reliance on coal-fred generation, whereas other regions burn less coal because it must be transported great distances, or because air pollution problems have inhibited signifcant coal use, or because there is adverse public reaction to the use of coal because of global climate change concerns. In a number of instances, different states have enacted more stringent environmental regulations than has the U.S. government, most notably in the area of carbon emissions, but these regional differences in environmental standards can also lead to greater problems for systems operators in meeting their reliability objectives. Public concerns about conventional energy sources have lead to some states and communities promoting the use of renewable-energy-based resources for generation, like wind and hydropower, but these energy sources are frequently located far from the customers and may not be available when demand for electricity is greatest, so their use imposes even greater complications on system design and operation.
Again, some regions have large, investor-owned utilities, while others have many small publicly owned utilities (known as cooperative utilities and municipal utilities). Some regions have vertically integrated electric utilities that own generation, transmission, and distribution systems, while other regions have ownership patterns that focus on one part of the business or another. Some regions have regional transmission organizations (RTOs) that administer central wholesale markets, whereas others do not.
Such differences in system confguration, generation and fuel mix, ownership, and so forth create complexities in the operation of the system, even though all parts of the country's electric grid operate according to industry norms and standards.
In the United States, a variety of entities exercise some form or other of operational control or coordination over parts of the grid. For example, in most regions, owners of transmission facilities operate them according to standards set by NERC with the input of companies participating in regional reliability councils. In other regions, particularly where market mechanisms determine wholesale power transfers, entities such as ISOs or RTOs carry out some operating functions on behalf of the transmission asset owners and other users of the system.
Real-time monitoring of the transmission system is performed using telemetry along with other data and analytic tools, such as state estimators, to evaluate system conditions on a continuing basis. Conditions monitored include power fows, various physical limits on transmission and other facilities, interchange with adjacent regions, and demand drivers such as weather.
The enforcement of NERC standards is still evolving. Until the passage of the Energy Policy Act of 2005, the electric industry's standards were entirely voluntary.1 In the absence of federal legislation mandating compliance with NERC rules, programs were developed to encourage compliance with NERC reliability standards. These were “enforced” by peer pressure, regulatory pressures, “enforcement contracts,” regional enforcement programs of the reliability councils, and industry norms for best practices, but no penalties were imposed for noncompliance with NERC standards. The Energy Policy Act of 2005 led to these standards becoming mandatory with substantial fnancial penalties imposed for non-compliance.
The U.S. electric power industry today is composed of a wide variety of players, entities, and institutions, all of which play different roles, and the actions of individual asset owners and operators affect each other. It is a highly regulated industry, and facilities need to operate according to common standards and in coordinated operations. The “system” may behave as one large electrical machine, but its parts are owned and operated by more than 3,000 entities. Table 2.1 highlights the major industry players that own and operate electric power systems. Still, there are numerous
1Changes in reliability enforcement as a result of the Energy Policy Act of 2005 are discussed below in this chapter.