Electricity is a commodity that has captured the attention of Americans, from its creation to the present and onward to projections of the future. From an object of luxury to a mainstream "staff of life" and forward into the sophisticated world of tomorrow, electricity has become a critical necessity. The criteria have become: electricity on demand, reliably delivered, in sufficient quantities, and at the right price. At the heart of meeting this challenge is the utility planner.
Generating and delivering electricity requires a complicated infrastructure, significant funding, competitive markets, and adequate regulation. Broken into its simplest terms, utility planning is beginning with the most optimum operation of existing electrical facilities and foreseeing the future well enough to provide additional facility to "guarantee" an adequate supply of a reliable product (electricity) at an acceptable cost. Generation provides the product, transmission is the vehicle to deliver the product over long distances, and distribution is the functional method of providing the product to the individual customer.
Originally all facilities, financing, and decisions related to building an electrical system resided within a utility. In this simplistic approach, projections of load growth, established construction and planning criteria, and coordination of facilities remained within the single entity. In today's competitive unregulated marketplace, the planners, designers, generators, and transmission providers are within a complicated mix of organizational units; thereby providing a complicated network of system participants. The challenge for utility planning today is to coordinate all of the inputs for constructing and maintaining an electrical system that combines the economics efficiencies necessary for survival and the maintenance of a reliable network where generated power can be delivered to an ultimate customer on demand, in sufficient quantities, both today and in years to come.
The history of the interconnected high-voltage electric power system has roots in the early decades of the twentieth century. Moving power from generating plants remote from load centers began as utilities and customers realized that costs associated with many small generating entities placed strategically at concentrated load points would soon escalate to unacceptable values. Likewise, the many advantages of the new power source would be restricted to cities and other high-density areas. The efficiencies of larger generating units utilizing fuels of choice and availability soon became the economic choice for resources thus developed the need to "push" power across long distances.
There were many examples of early interconnected electric transmission systems extending across state territories and beyond state boundaries. Statements from a speech by Samuel Insull at Purdue University in 1924 indicated that Minneapolis, St. Paul, St. Louis, Louisville, and Cincinnati soon would be interconnected and that extension of these systems to Pittsburgh and across the Allegheny Mountains to the Atlantic Seaboard could be easily conceivable in a few years. This was but one example across the United States. To quote Insull, "It makes electric service available in new places for new purposes, so that aggregate demand for service is spread over more hours of day and night, and thus opens the way to utmost economy in production and distribution."
The interconnected power system grew and the load demand increased, over time, at varying rates and reached an average growth of some 10 percent, or a doubling every ten years. Utilities financed, constructed, and controlled the vast majority of the generation and transmission facilities in what was classified a "monopolistic society." In this environment, while the processes were complicated, the data necessary to plan these extensive projects were readily available.
One example of the complexity of the process was in load forecasting technology. By the 1960s and 1970s, utilities had developed processes to replicate the extensive electric power system for study purposes to include generation resources, transmission networks and individual points of load service to customers. The most complicated of these were the load forecast and load distribution techniques. No matter how fast technology developed, certain parameters of forecasting created significant challenges. Companies forecasted load as a composite for their territory, primarily using historical trends. Often, these forecasts were economically based, thus having boundaries driven by nontechnical issues. Load growth varied within areas of individual companies. New and increased industrial loads, which made up significant portions of the forecasts, diluted the forecast and often appeared on the system later (or earlier) than planned.
In the 1980s, as the complexity of forecasting became more challenging, utilities chose to augment their forecasting methodologies through the use of consultants who possessed sophisticated databases that included topography, diversity, trends, population growth and other intricate variables and impactors. These forecasts enabled a finer tuning of the process and in many cases a more efficient and economical forecast.
No matter how accurate the forecast, other planning techniques, while state of the art, introduced trending, estimating, and engineering judgment in the facility planning cycle. One such issue involved the time and expense to plan a project, budget the project, and place the project in service when required. Because of constraints, most planning studies considered only the estimated annual peak load for a company. This peak could occur in the summer or winter, depending on the region of the country. Obviously other variations on the annual load curve occurred, such as off-peaks (spring and fall seasons) and shoulder peaks (related to time of day). Normally these variations were trended or estimated or ignored in the interest of time, and an ultimate plan was developed. In the very early years of planning, utility planners assumed that planning for the peak load covered all other times of the year. History recorded it to be a valid theory.
In later years, studies involving variations of the peak load were initiated to answer specific questions. Generation maintenance schedules, which were initially developed to accommodate only peak load periods, were revised to protect extended off-peak periods of large energy usage. The components of generation and load include real power for load service and reactive power for voltage support. The effects of various load levels to voltage profiles were tested to plan economic generation reactive parameters and adequate capacitor levels, and to define optimum capacitor locations. In addition, off-peak voltage profiles were sensitive to generator outages and maintenance. Power transfer capabilities between entities had been routinely studied at peak load. As peak periods began to lengthen and as generation locations were more widely distributed, it became necessary to consider the impacts to transfers at load levels less than peak. The transfer capability issues have become of more specific importance with the move to greater open access and competition.
Transmission parameters for existing systems were translated into appropriate input data for calculation systems available at the time. During early periods of the twentieth century, calculations for expansion of the transmission network or grid were actually made by laborious longhand manual monotonous iterations. Fortunately, the areas of study were small or abbreviated sections not affecting other areas. In the 1940s, network analog calculators were introduced for use in modeling the power system. These calculators were large "black boxes" composed of resistors, capacitors, meters, controls, dials, plotting boards, etc., and often covered an entire room, usually at an area university.
The analog calculator employed a quantitative methodology. The engineer calculated the impedance (parameters) of a transmission line and physically dialed in the valve between points A and B. The calculator also included metering windows where various information could be readily observed. With this method an experienced planner could actually sense a "feel" of the system as the dials and data were manipulated. Likewise, the analog computer became a significant training tool for utility engineers.
By the late 1960s, digital computers began to replace the "black boxes." Despite forebodings of utility planning engineers regarding training of engineers and planning, adaptations to the new technology became commonplace.
The digital computer began as a mammoth blue or black giant mechanism hidden in some corporate information resource office. The planner's view of data processing was keypunching a "deck" of cards and dropping them into an open "hopper" to mysteriously disappear into the computer. Similarly, once the magic of the calculations was accomplished, white punched computer paper arrived from an output device with guaranteed solutions to difficult questions.
The process improved. Computers became smaller, and today it is rare for a planning engineer to be void of computer power available at his desk many times greater than the early corporate computer could muster. Computer tools of the future can only be envisioned as technology advances.
Generation data to complement the planning study were plentiful. As long as the utilities owned the physical facilities and were in control of future facility expansion, data were generally a nonissue. The parameters of generating plants were dialed into the calculations or computers, similar to transmission. Obviously, alternate locations for new plants could be evaluated, and oftentimes studies were finalized some ten years ahead of construction, with only limited analysis required as the in-service date approached.
Planning studies to identify the magnitude of generation required on a particular system for a specific time period were based on parameters such as loss of load probability (LOLP) or loss of load energy (LOLE). These studies modeled the system load curve throughout the year for projected years into the future and included existing generation resources. The purpose of the studies was to identify the probability statistics where the system could not serve its load requirement or to identify an amount of unserved energy. These data would be compared to specific criteria, and future generation requirements would be developed. The ability to obtain emergency or specific contracted generation resources from neighboring systems would normally be factored into the data. In addition, in many cases generation reserve sharing agreements were factored into the final determination of capacity required. Reserve sharing agreements were contractual arrangements, usually within power pools (groups of systems) or areas where each system involved factored in the pro rata share of neighboring generation available to that system. Both concepts of utilizing off-system resources as an integral part of a system's total resources involved risk, which had to be coordinated with economic advantages and reliability levels.
Given that there were numerous alternatives for the resources, including demand-side management, interruptible loads, and off-system purchases, many case studies were necessary. Each plan for service to future loads had to be tested for conformance with system and regional reliability criteria. The plans were further examined for cost, including losses, and examined for flexibility. Any acceptable plans had to be considered for ease of modification, should future load patterns differ from present projections.
Generation was normally modeled in system studies using economic dispatch schedules developed from individual unit fuel cost and heat-rate data. To serve a particular load level, the units would be "stacked" (added to the system) in order of priority based on cost and performance. Additional capacity options were available from off-system purchases or reserve sharing arrangements with neighboring systems. A system's ability to import power was a strong indicator of its territorial reserve requirements.
Prior to the 1990s, generation lead time was generally the critical factor in project planning. As smaller units, low run-time peaking plants, environmental issues, and more diversified fuel availability appeared, the lead time for transmission construction began to be of more concern than the generation construction period. In addition, line citing, environmental impact, and condemnation issues contributed to longer lead times for transmission projects.
The planning processes described herein were traditional in nature, with little variation from year to year. Growth was steady, equipment technology advancements were available for the conditions expected, and while utility facilities were capital-intensive, a regulated guaranteed return on investment resulted in adequate financing capital. The utility planner had a vision of the future with acceptable accuracy.
Many events signaled the beginning of a lengthy transition period for the utility industry in general, and more specifically, for the facility planning activity. The timeline in many instances was blurred, with some of the blurring attributable to a reluctance to change.
Perhaps the Public Utilities Regulatory Policies Act (PURPA) of 1978 was the initial formal driving force for change. The introduction of nonutility generators (NUGS) with qualified facilities and almost guaranteed sales opportunities was the first major nonutility resource activity. Whether the cause was the actual construction of these facilities or the resource atmosphere it stirred, transition was on the way. Independent power producers (IPPs) soon followed. These projects were introduced into the competitive resource market on an equal footing with utility-sponsored plants and could not be ignored by utility management.
In parallel with the new approaches to generating capacity additions, the utilities, with encouragement from regulators, introduced incentives during the 1980s for reducing load demand. Since the system peak hour load provided the inertia for capacity requirement definition, "shaving" of the peak became the focus of these incentives.
Enticements to involve the retail customer base, as well as the industrial sector, in the solutions desired became popular. Interruption of large commercial load, a provision by contract, had long been used to offset capacity shortages. Interest in this method mounted. In addition, retail customers were provided enticements to "cut load," either by manual participation or by automatic devices. These enticements will like continue into the future.
Further involvement by the typical industrial or commercial utility customer, both large and small, was stimulated by time-of-day price incentives. Encouragement was provided in the form of reduced rates if use of electricity was shifted from peak periods of the day to off-peak or shoulder-peak periods. Even the residential customer was invited to participate in load shifting with price incentives or rewards. A popular example of the day was encouraging the household laundry activity to be moved to late-night hours. This suggestion was met with varying enthusiasm.
Initially there were attempts to quantify and project magnitudes of power shifted and relief provided to the capacity resource requirements. Ultimately the shifting of load became embedded in the subsequent forecast and became harder to identify.
The impact of these tactics to augment capacity resources was successful to some degree. Currently, the values identified are marginal; however, much of the impact is unidentified and embedded in the load growth.
Industrial customers, early a driving force in the industry, began to react not only to local utility incentives but also to more competitive pricing opportunities in other systems and exerted significant pressure on regulators. Forces in Washington, D.C., following the industry trends, finally acted in 1992 with open access of the transmission system to the wholesale market, and more extensive competition resulted. Possibly this one act, more than any other, provided the stimulus for a major shift in the industry through deregulation, restructure, and more specifically, in the planning process of the bulk electric system.
With the opening of the transmission network to all resource suppliers, many marketing entities entered the game in the mid-1990s. Many of these marketers are subsidiaries of already established gas suppliers. Some have been created solely for the electric industry. Still others have been formed from the utilities themselves. All of these entities are competition-motivated. Facility planning and reliability issues, while important to their business, are left to other organizations.
The planning and construction of generation and transmission facilities by utilities came to a virtual halt. With no guaranteed market, no control over the use of their transmission networks, no assurance of stranded investment recovery, and no assurance of federal remedial treatment, the economic structure of utility planning and construction of generation facilities basically stopped in place.
The transition for utility planners has been difficult. Generation and transmission margins have deteriorated. Shortages have been noted. The number of transactions within and across systems has escalated to levels that not only test the reliability of a transmission network not designed for this level of activity but that also have challenged the ability to operate such a system with existing technology. Prices have reacted. Emergency disturbances have occurred. Basic questions regarding authority, planning, responsibility, and finances have been raised.
Several alternatives have been offered by the Federal Energy Regulatory Commission (FERC). Regional transmission groups (RTGs) were suggested. While the basic premise of these wide-area coordinating and planning organizations was sound, many of the questions involving economics and responsibility were left unanswered.
Systems of independent system operators (ISOs) were introduced as another alternative. Some have been implemented and many have been evaluated. Adoption of these systems has been slow, the same basic reasons as those affecting RTGs. The regional transmission organization (RTO) is the most current alternative being proposed and initial plans will be provided to FERC during 2000. All of these organizational arrangements are devised to segregate ownership, planning, construction, and operation in an appropriate manner to produce a nondiscriminatory, totally competitive marketplace for electricity. All of this activity will likely result in the complete deregulation of the industry, wholesale and retail. Restructuring of the electric business on all fronts is required to make deregulation complete.
The North American Electric Reliability Council (NERC), established in 1968, and its associated ten regional councils have been reliability monitors of the electric bulk power system. Their emphasis on compliance with reliability standards through peer pressure was effective in the past. NERC and the councils, with oversight from FERC, are engaged in a complete restructuring of the reliability organizations. This move will ultimately involve a move from peer pressure to mandatory compliance.
In the meantime, the utility planner struggles with how to approach the planning process in this changing environment. Perhaps these issues are more critical in the transition, since so many of the traditional parameters of planning have disappeared, and few new parameters have taken their place.
Future-generation location, timing, and ultimate customer designations are generally unknown. Transmission construction has become more of a patchwork activity. Power transactions across the various systems are at an all-time high, a condition the network was not designed to handle. System operators struggle with daily and weekly operational planning because of the volume of transactions. Many of these transactions are not identified beyond buyer and seller. The marketing of power continues to follow the traditional contractual-path power flow route from seller (source) to buyer (load), as opposed to the actual system flow path. The contract path is a predetermined contractual route from the source system to the load system, through any inter-connected intermediate system or systems. The contract assumes that all or a majority of the power will flow along this path. Only systems outlined in the contract are involved or compensated. In reality the power flows over the path of least resistance, as determined by the parameters (resistance) of the transmission lines involved. While there are economic considerations involved between the two alternatives, this is an issue of significant magnitude to the system planners and operators, who must know the path of actual power flow to properly address facility planning and operating security. In addition, many operating problems arise from the lack of automated software, a requirement for the volume of daily business being handled.
One alternative to planning in this environment of unknowns is called "scenario" planning. Utility planners in 2000 continue to estimate resource requirements for five to ten years into the future. These resources could be constructed indigenous to their systems or external to their systems, or purchased from off-system. By considering multiple alternatives for generation sources, the planner can simulate power transfers from within and outside each system. The results of these scenario analyses can be used to estimate where critical transmission might be constructed to be most effective for wide-area power transfer. Similarly, analyzing multiple transfers across a system can provide further justification for a new transmission path.
Other new planning processes are being considered to aid the transition. These include variations of probability analysis, optimum planning tools, and short-lead-time projects. None of these addresses all of the constraints discussed above. This should not, however, be construed as an impossible task.
As new generation is announced from all market segments, and as physical locations are determined, the planning picture will slowly evolve as well. It is also assumed that as retail access is introduced during the first decade of the twenty-first century, it will be controlled to some extent by contract terms long enough to provide practical development of demand forecasts. It is further assumed that future legislation and regulation also will assist in defining many aspects of the planning process. While the transition may be lengthy, the utility planner may be immersed in a full competitive environment without realizing that the transition has been completed.
The future of utility planning is uncertain. Good engineering judgment and technological advancements, however, will prevail as future system requirements are defined.
Major wholesale load shifts, unidentified transactions, dynamic scheduling (services provided by systems remote from the load served), unknown generation locations and timing, and retail wheeling will contribute to difficulty in planning for the future. The issues of planning, however, are likely to be easier to solve than the political issues that have a major impact on the health of the electrical infrastructure. The threats are many. An environment created by new deregulation legislation that fails to consider or impacts critical electrical phenomena and proper division of responsibility between the state and federal domains will be difficult to plan for. Environmental restrictions that curtail or impact generation resources or transmission availability will be costly to overcome and may lead to undesirable shortages. Retail customer access to systems remote from the host system will present future projection issues and change obligation-to-serve regulations. While stranded investment recovery will continue to be an economic issue, it may impact future planning in the restriction of alternative choices. Finally, mandatory compliance with reliability standards, while necessary to maintain a reliable system in a competitive marketplace, can become a constraint to good planning practices if the program becomes more bureaucratic than functional.
Based on history and the inherent unknowns related to planning, it is likely that full retail access and customer choice will present the utility planner with the most difficulty in future planning of the system. Since load demand is the principal driver of the facility developmental process, it has been necessary in the past to have a high degree of probability in the forecast. Without significant improvement in planning techniques for more accurate forecasts, planning for a changing (fluctuating) load demand in a given service area will be a significant challenge.
The various restructures of the industry are all planned to address these major issues. Wide-area planning, while undefined, may solve certain issues resulting from the unknown parameters. Divestiture of the industry into generation, transmission, and distribution companies will strengthen emphasis on the facilities involved. Many of these new structures will move the industry toward full competition; however, coordination of their activities could become more difficult.
Entry into a true competitive market suggests that the market will resolve all issues created by this move. Supply and demand will likely prevail. Full retail wheeling will introduce issues into utility planning never before addressed. Planning strategy for the future is difficult to envision based on history and current transition difficulties. It is assumed, however, that the need will create the solutions.
New technology, in both long-range planning and operational planning, will aid the entrance into a full competitive market. New tools and ideas will offset increased business and downsizing of manpower created by a more competitive environment. Each significant transition in the past was met with creative solutions. Utility planning expertise and experience will be major factors in the twenty-first-century electric industry. The goal, as always, is to continue the planning, construction, and operation of an economic and reliable electric power system.
James N. Maughn
See also: Capital Investment Decisions; Economically Efficient Energy Choices; Economic Growth and Energy Consumption; Electric Power, System Protection, Control, and Monitoring of; Energy Management Control Systems; Government Intervention in Energy Markets; Regulation and Rates for Electricity; Risk Assessment and Management; Subsidies and Energy Costs; Supply and Demand and Energy Prices.
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