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Electric Power, Generation of

ELECTRIC POWER, GENERATION OF

INTRODUCTION

Electric power systems can be thought of as being comprised of three important sectors: generation, transmission, and distribution. For most utilities, generation capital equipment costs account for approximately 50 percent of total plant in costs. Generation also accounts for close to 75 percent of total operation and maintenance expense.

Generation is the production process center of the power industry. This production process is multifaceted and starts with the conversion of primary energy, such as fossil fuels, uranium, and the kinetic energy of water, to electrical energy. The process by which this primary energy is converted to electricity varies depending upon the prime mover, or technology, of the power generator. Mainstream generation technologies include hydroelectric facilities, internal combustion or combustion turbine facilities, and steam generation facilities. Alternative electric generation can include prime movers powered by the wind, sun, or some other renewable fuel such as bio-mass or solid waste.

Hydroelectric facilities use the kinetic energy of falling water to turn a water turbine to create electricity. These facilities usually have limited technical applicability and are located in geographic regions that meet certain elevation, water level, and stream flow requirements. The advantage of hydroelectric facilities is that they are virtually free of fuel costs. Their disadvantage, in addition to their limited geographic applicability, is that they have relatively high capital costs.

Historically, internal combustion engines and combustion turbines have been considered unique and limited types of generation facilities. These are similar in many respects to engines used in the automotive and aeronautics industries. Both technologies burn one or a combination of various fossil fuels (oil, diesel, propane, or natural gas) to create mechanical energy to turn electric generators. The advantage of these technologies is that they have relatively low capital costs. Since these technologies are run on fossil fuels, their disadvantage rests with their relatively high and potentially volatile operating costs.

The traditional power generation work horse has been the steam generator. This technology uses fossil fuels (coal, natural gas, and oil) to heat water in a boiler to create steam. The steam, in turn, drives an electricity generator. Nuclear power is a special case of the steam generator, using uranium and nuclear fission to create steam. While these facilities have high capital costs, their operating costs are lower than their nearest competitor, combustion turbines.

On the fringe of electricity generation technologies are alternate-fuel generators, including solar photovoltiac and thermal applications, wind powered applications, and the use of waste agricultural byproducts such as rice hulls or bagasse, and even garbage. These technologies have traditionally played a small role in the overall generation portfolio of utilities in the United States, given their relatively high cost and limited capacity. Most of these technologies have been promoted under the auspices of research and development or within the context of relatively unique niche applications.

GENERATION PLANNING AND OPERATION

In the past, generation planning consisted of developing and maintaining a portfolio of facilities to meet the various types of electricity loads that occur in any given hour, across any given day, in any given season. Reliability tended to be the most important planning consideration, followed closely by cost. Thus, generation planning strategies consisted of constructing and operating enough power plants to meet demand on a cost effective basis. In many instances, having the ability to meet sudden surges in demand entailed constructing and maintaining large capacity reserve margins that remained idle during large parts of the year.

Since load varies considerably across hour, day, and year, utilities have traditionally segmented their generation facilities into three classifications: base-load generation, intermediate or cycling generation, and peaking generation. Baseload generators are typically steam generation facilities used to service minimum system load, and as such are run at a continuous rate. While these units are the most efficient to operate, they are costly to start up from a cold shut down (designed for continuous combustion); therefore, they are usually run at a near-constant rate. Intermediate load plants are typically older steam units or combustion turbines brought on line during periods of forced or planned outage of baseload units. Intermediate units can also be thought of as units that bridge the dispatch of baseload and peaking units during periods of unusually high demand. These units can be older and less efficient than baseload units. Peaking units are typically combustion turbines that have the ability to generate electricity immediately, and serve temporary spikes in demand such as during a heat wave when residential and commercial air conditioning demands begin to surge.

In the past, electric utilities dispatched generating units to meet demand on a lowest-to-highest cost basis. This form of dispatch is commonly referred to as "economic dispatch." The marginal or incremental cost of dispatching units is traditionally the benchmark used to rank order available generators. These marginal costs, in the very short run, are typically associated with changes in fuel costs and other variable operating and maintenance (O&M) costs. Historically, baseload units, which are almost always large coal, hydro, or nuclear units, had the lowest incremental costs and were dispatched first to meet load. As load increased during the day, or across seasons, less efficient intermediate or cycling units, which generate electricity at slightly higher costs, were brought on line. Higher cost peaking units would be the last types of units brought on line, for example, during a heat wave with a resulting large demand for air conditioning. The cost of the last dispatched unit would therefore define the system marginal costs, often referred to as the system "lambda."

Given the importance and relative size of the electricity generation sector, shifts in the costs of constructing and operating electric power plants can have considerable influence on final rates of electricity for end users. Figure 1 shows the historic trend of real, or inflation-adjusted, electricity prices over time. Noticeable in the graph are the spikes that occurred in the early 1970s and again in the early 1980s, when utilities in the industry were faced with a number of almost insurmountable challenges leading to the undermining of their unique natural monopoly cost advantages.

The history of electricity generation planning can be broken into two distinct periods: one period proceeding, and one period following the energy crisis of 1973. Prior to 1973, electricity generation planning was a relatively straightforward endeavor. During this period, forecasted increases in load were met with the construction of new generation facilities. Utilities typically tried to meet this load with the most cost effective generation technology available at the time. As shown in Figure 2, the annual rate of electricity demand prior to 1973 grew at an annual average rate between 6 and 10 percent. This constant, significant growth placed many utilities in the position of having multiple construction projects ongoing at any given time.The period following the energy crisis of 1973 dramatically changed the generation planning process for utilities. During this time the industry was plagued by high inflation and interest rates, high fuel prices, financial risk, and regulatory uncertainty. These uncertainties increased costs, which in turn had a deleterious affect on electricity demand. Dramatic electricity price increases, resulting from the volatile operating environment of the post–1973 environment, stifled the growth of electricity demand and set strong incentives to end users to conserve electricity. As a result, utilities found themselves with considerable excess capacity that quickly became technologically and economically obsolete. This excess and uneconomic capacity, in combination with eventual emergence of new technologies and increased competition, resulted in an undermining of the natural monopoly justification for electric utility regulation.

THE ECONOMIC REGULATION OF POWER GENERATION

Historically, the electric power industry was characterized as being a natural monopoly. Natural monopolies typically occur in industries with very large fixed capital costs and relatively low operating costs. The cost characteristics of these industries tend to make them the most efficient producers in a given regional market. However, since these natural monopolies face no competition, they have the ability, if left unchecked, to charge prices that could be considerably above costs. Industries with large infrastructure requirements, such as telecommunications, water and wastewater, natural gas, and electric power, have historically been considered natural monopolies.

Many industrialized nations grapple with the unchecked power that infrastructure industries can have in any given market. In these instances, government has two public policy options. First, government can expropriate, or nationalize, these industries. Here the government takes over power generation ownership and operates the industry in the public interest by providing service at a reasonable (government determined) price.

Under the second policy option, the government can maintain private ownership and regulate firms operating in the public trust. This has been the unique policy option exercised within the United States for a greater part of the past century. Despite some municipal and federal government ownership of electricity generation facilities, much of electric generation capacity is investor-owned, privately controlled electric companies. Figure 3 shows the electricity generation capacity ownership percentages by type of entity.

Beginning in the 1920s, an extensive set of electric power industry regulation arose based upon the notion that this industry, like others, is a natural monopoly. An additional rationale for power industry regulation has been that electricity, like so many other regulated utility industries, is imbued with the public interest. Perhaps one of the greatest influences on power generation over the past half century has been the role of government and its public policies.

Since electric power moves within and between states, this regulation has roots in both federal and state jurisdictions. Federal intervention in electric power markets has its origins in the Federal Power Act, the Public Utility Holding Company Act, and the Rural Electrification Act. State regulation has evolved from state statutes, constitutions, and other legal precedents. At the federal level, electric power sales are regulated by the Federal Energy Regulatory Commission (FERC), while at the state level, regulation is directed by state Public Utility Commissions (PUCs).

Regulatory bodies at both the federal and state level attempt to ensure that electric power is provided economically, and in a safe and reliable manner. The primary method of electricity regulation has been rate of return, or cost-based, regulation. Here regulators set the rates utilities are allowed to charge their customers. This cost-based regulation allows utilities to recover their prudently incurred costs and also earn a reasonable rate of return on their investments. In return, utilities are granted exclusive franchises and monopoly service privileges

In the period from the 1930s to the early 1970s, regulation in the power industry was relatively uneventful. The energy crisis of the 1970s and early 1980s, however, dramatically changed the regulatory environment for electric power generation. During this period, state and federal government became exceptionally proactive in both generation planning and operation.

At the federal level, Congress passed the National Energy Act of 1978, which was composed of five different statutes: (1) the Public Utilities Regulatory Policy Act (PURPA), (2) the National Energy Tax Act, (3) the National Energy Conservation Policy Act, (4) the Power Plant and Industrial Fuels Act (PPIFA), and (5) the Natural Gas Policy Act. The general purpose of the National Energy Act was to ensure sustained economic growth during a period in which the availability and price of future energy resources was becoming increasingly uncertain. The two major themes of the legislation were to: (1) promote the use of conservation and renewable/alternative energy and (2) reduce the country's dependence on foreign oil.

While all aspects of the National Energy Act affected the electric power industry, PURPA was probably the most significant. PURPA was designed to encourage more efficient use of energy through industrial cogeneration. These cogenerators produce electricity through the capture of waste steam from their production processes. As a result of PURPA, a whole new class of electricity generation facilities emerged, commonly referred to as "qualifying facilities" or QFs. PURPA required utilities to interconnect and purchase power from any QF at a rate not to exceed the utility's avoided cost of generation. This legislation opened the door to competition in the generation portion of the industry by legitimizing and creating a market for non-utility generation.

State regulation during this period continued the trend of promoting nonutility sources of generation. While PURPA was passed by the federal government, it was the responsibility of state regulators to set the rates at which utilities were required to purchase cogenerated or QF power. In response to the energy crisis of the period, state regulators began to set overly generous rates for QF power to stimulate conservation and alternative sources of electricity in a period of uncertainty. As a result of the generous rates and guaranteed market for nonutility generated power, generating capacity from nonutilities increased from close to 2 percent in 1978 to over 8 percent a decade later.

Regulators also began to require utilities to subject themselves to competitive bidding when they had a need for additional capacity. In addition, regulators began to require utilities to investigate other alternatives to the construction of new generation facilities, including the evaluation of demand-side management, or energy conservation measures, as a means of meeting future load growth. As a result of both of these policies, the fundamental premise of utility regulation and generation planning came under fire as more and more cost-effective, reliable, and alternative means of meeting electricity needs began to emerge.

ELECTRICITY GENERATION AND POWER INDUSTRY RESTRUCTURING

The structural and institutional environment for electric generation began to change dramatically in the late 1980s and throughout the 1990s as more and more competitive providers of electricity began to emerge. By the early 1990s, policy makers were actively discussing the possibility of restructuring the industry by introducing competition into the generation portion of the business. Throughout the 1990s, the terms "restructuring," "deregulation," and "competition" became virtually synonymous.

The passage of the Energy Policy Act of 1992 (EPAct) is considered the watershed federal legislation opening the door to complete power generation competition. This legislation allowed the Federal Energy Regulatory Commission (FERC) to order utilities to "wheel" or transport power over their transmission lines on behalf of third parties on an open access and nondiscriminatory basis. In subsequent years, FERC passed Order 888 and Order 889, which established the rules and institutions under which interstate or wholesale competition would be allowed. This wholesale competition was restricted to customers that were bulk power customers buying on behalf of other customers such as municipal utilities, rural cooperatives, and other IOUs. Retail competition, that is, competition for residential, commercial, and industrial customers, soon followed.

The origin of retail competition has run almost parallel to wholesale restructuring initiatives. State restructuring initiatives began initially in California and were soon adopted in New England. Both regions of the country were suffering from exceptionally high retail rates that were, in some cases, double the national average. Ratepayers, typically industrial ratepayers, appealed to regulators to allow competitive forces, rather than continued regulation, to discipline electric power generation and power markets.

The advent of competition has virtually transformed the industry in every aspect, including its name. In the not too recent past, the industry was referred to as the "electric utility industry." Today, given its significantly wide and numerous participants, it is more appropriate to refer to the industry as the "electric power industry." This new power industry has new power generation and sales participants with names such as qualifying facilities, exempt wholesale generators, merchant facilities, small power production facilities, power marketers, and sales aggregators.

The Mechanics of the Restructuring Process

Restructuring is the process of completely reorganizing the electric power industry. The generation portion of the industry will become more competitive, while the transmission and distribution portion of the industry will remain under regulation. While many specific aspects of restructuring differ between different states, and between federal and state jurisdictions, there are three common transition procedures.

The first transition procedure requires vertically integrated, former electric utility companies to unbundle, or separate, their electric power generation and energy sales operations from other utility operations. This separation is required to prevent former utilities from using their monopoly transmission and distribution assets in an anticompetitive manner to benefit their generation and sales operations. This divestiture, or separation, can be either physical or functional. Under physical divestiture, deregulated utilities are required to sell either all or a portion of their generating assets; the assets are "physically" removed from the former utility's control. Under functional divestiture, utilities are simply required to establish separate corporate affiliates, with stringent rules of conduct between regulated and unregulated companies. Most states opt for functional divestiture.

The second transition procedure establishes independence for the transmission system. This procedure is also required to ensure that a monopoly asset, in this case transmission, is not used in an anticompetitive manner. Two institutional structures are currently being debated for this transmission independence: an Independent System Operator (ISO), or a Transmission Company (Transco). The ISO transmission governance structure is typically associated with a multiutility, nonprofit association. Transcos are typically associated with a single-utility, for-profit, governing board. At the end of the 1990s, the ISO was the more prevalent of the two governance structures, with the Transco proposals gaining in number and popularity.

The third transition procedure defines the rules under which competitive suppliers of electricity can compete for end users. There are two polar models that are often debated for power market organization: the direct access (or bilateral contracts) regime, and the Poolco regime. Under direct access, consumers enter into direct contracts with competitive suppliers of electricity, and competitive providers of electricity enter into contracts with, and pay an access fee to, the local (regulated) distribution company for the use of local power lines.

A Poolco regime is a centralized market structure consisting of an ISO and a competitive Power Exchange (PX), where the ISO handles the physical deliveries and coordination of power flows within a regional power system, and the PX handles all the transactional issues associated with system power sales. In the Poolco regime, regional power market competitors submit bid prices and capacity offers into the competitive PX. Load from local distribution companies, representing all electricity end users, are then aggregated by the Poolco. Hour-ahead bid prices are used to construct a least cost dispatched and an hourly supply curve, and an hourly market equilibrium price is determined at the point at which the PX-determined supply curve intersects total regional aggregated demand. Least cost dispatch information is then transmitted from the PX to the ISO that controls all system coordination and security issues.

Many states have debated the efficiency and equity of both the direct access and Poolco market structures. Like many other restructuring transition issues, final policy decisions tend to be some hybrid or amalgamation of both approaches. Alternatively, some states have moved forward with a more centralized process (i.e., Poolco), with gradual implementation of more disaggregated trading regimes (i.e., direct access) at a later date. Since restructuring rules and laws are promulgated at the state level, it is very likely that market structures will be evolving and moving targets well into the early part of the twenty-first century.

THE SHIFT IN TECHNOLOGICAL PARADIGMS

One of the most dynamic factors underlying changes in the power industry has been technology. From the early days of the industry, designing, constructing, and operating more efficient generating units has been a priority. For a good part of the early to mid-twentieth century, the electric power industry, like other major capital intensive manufacturing industries, was one of the leading sectors of the economy in terms of technical innovation and productivity growth.

The amount of heat input, measured in British thermal units (Btu's), needed to generate a kilowatt hour of electricity with steam turbines decreased by almost 40 percent between 1925 and 1945, and by 35 percent during the period 1945 to 1965. During this period, scale became an important factor in power generation planning. Bigger was clearly better, and remained the premier planning paradigm for the utility sector of the industry until the mid to late 1980s. Larger plants usually entailed larger thermal efficiencies, which in turn reduced costs. However, gains in thermal efficiencies tapered throughout the 1970s. As the gains disappeared, so too did the ability to offset the exogenous economic changes in costs that occurred during the energy crisis. The only nonfossil technology of promise during this period, nuclear power, fizzled under the pressure of cost acceleration and inflation, rapidly increasing safety regulations, imprudent management, and regulatory and financial uncertainty. The accident at Three Mile Island in 1979 all but assured the industry that it had run out of large-scale technological innovations in power generation.

However, out of the ashes of the technological failures of the 1970s and early 1980s came a new technological innovation that dramatically changed the nature of the power industry. The experiences of the decade showed that the industry needed a technology that was flexible, modular, could be constructed quickly, and had minimal environmental impacts. Advances in the aerospace industry made it possible to deliver combustion turbine technologies that met the requirements of a new power generation environment.

Ironically, throughout the early 1980s, it was the nonutility generation portion of the industry that began to aggressively adopt the new efficient combustion turbine and combined cycle applications of the new natural-gas fired technologies. Widespread nonutility deployment of these technologies was the direct result of PURPA and the guaranteed market for nonutility generated power. Combined cycle plants, in particular, were rapidly preferred technologies for onsite generation at large nonutility generation facilities throughout the United States. The rapid deployment of these small, modular, and highly efficient facilities was an underlying technological rationale for introducing competition into generation markets.

Combined-cycle plants were in many ways an extension to the idea of cogeneration. These plants were effectively natural gas-fired combustion turbines with additional waste heat recycling unit—thus, a combined cycle of electric generation. The first stage generates gas-fired electricity from a turbine, while the second stage captures the waste heat to run a second-stage electric generator. Clearly, market participants with small scale power generation construction experience, like industrial cogenerators, can develop and operate projects of this nature. With these technologies, utilities need not be the only party participating in power generation construction and operation.

The popularity of combined-cycle units has increased dramatically over the past several years in both the utility and nonutility generation of electricity. As shown in Figure 4, in the year 2000, 3 percent of total generating capacity consisted of combined cycle technology, while traditional steam generating capacity comprised 69 percent of total. By the year 2020, however, these percentages shift dramatically in favor of combined cycle technologies with over 20 percent of total generating capacity invested in this technology.

The widespread adoption of these combined cycle and combustion turbine units represents a technology paradigm shift from large central station generation to more modular, flexible generating units. Under the new planning paradigm, size is less important than flexibility, fuel availability (natural gas), and location to load center. While some scale is still presumed to have benefits under this new paradigm, it is not the foremost consideration that it was a decade before.

The newest paradigm in power industry is known as distributed generation (DG) or, more generally, distributed energy resources (DER). Here, small scale power generation and storage equipment is located at the distribution—not transmission—level of interconnection. DER/DG includes such technologies as reciprocating engines, micro-turbines, fuel cells, and small solar photovoltiac (PV) arrays. While many of these technologies are relatively expensive now, future deployment, as well as changes in competitive generation market conditions, can make a number of applications cost-effective. DER could usher in a new level of competition much like its predecessor, the combined cycle technology, did a decade earlier.

CONCLUSIONS

At the beginning of the 1990s, the power industry was considered an old and tired industry in the United States and global economy. However, changes stimulated by the forces of new technology, environmental consciousness, and public policies promoting competition have brought about a renaissance in the power generation portion of the electric power industry. Like other large-scale manufacturing industries, the power industry has restructured and retooled, taking advantage of informational, technological, and managerial innovations. Competition, choice, and changes in the way power is generated, delivered, and sold to end users should continue this trend well into the next century.

David E. Dismukes

See also: Cogeneration; Demand-Side Management; Engines; Hydroelectric Energy; Market Transformation; Supply and Demand and Energy Prices; Turbines, Gas; Turbines, Steam.

BIBLIOGRAPHY

Energy Information Administration. (1993). The Changing Structure of the Electric Power Industry, 1970–1991. Washington, DC: U.S. Department of Energy.

Utility Data Institute. (1994). Electric Utility Power Plant Construction Costs. Washington: DC: Utility Data Institute.

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