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Amreica’s Enery Future: Technology and Transformation 9 Electricity Transmission and Distribution Electric power transmission and distribution (T&D) in the United States, the vital link between generating stations and customers, is in urgent need of expansion and upgrading. Growing loads and aging equipment are stressing the system and increasing the risk of widespread blackouts. Modern society depends on reliable and economic delivery of electricity. Recent concerns about T&D systems have stemmed from inadequate investment to meet growing demand, the limited ability of those systems to accommodate renewable-energy sources that generate electricity intermittently, and vulnerability to major blackouts involving cascading failures. Moreover, effective and significant utilization of intermittent renewable generation located away from major load centers cannot be accomplished without significant additions to the transmission system. In addition, distribution systems often are incompatible with demand-side options that might otherwise be economical. Modernization of electric T&D systems could alleviate all of these concerns. The U.S. T&D system has been called the world’s largest machine and part of the greatest engineering achievement of the 20th century (NAE, 2003). This massive system delivers power from the nearly 3000 power plants in the United States to virtually every building and facility in the nation. This chapter reviews the status of current T&D systems and discusses the potential for modernizing them (thus creating the “modern grid”). The focus is on the technologies involved—their potential performance, costs, and impacts—and potential barriers to such a deployment in the United States over the next several decades.
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Amreica’s Enery Future: Technology and Transformation BACKGROUND The Current Transmission and Distribution System T&D involves two distinct but connected systems (as shown in Figure 9.1): The high-voltage transmission system (or grid) transmits electric power from generation plants through 163,000 miles of high-voltage (230 kilovolts [kV] up to 765 kV) electrical conductors and more than 15,000 transmission substations. The transmission system is configured as a network, meaning that power has multiple paths to follow from the generator to the distribution substation.1 The distribution system contains millions of miles of lower-voltage electrical conductors that receive power from the grid at distribution substations. The power is then delivered to 131 million customers via the distribution system. In contrast to the transmission system, the distribution system usually is radial, meaning that there is only one path from the distribution substation to a given consumer. The U.S. T&D system includes a wide variety of organizational structures, technologies, economic drivers, and forms of regulatory oversight. Federal, state, and municipal governments and customer-owned cooperatives all own parts of these systems, but approximately 80 percent of power transactions occur on lines owned by investor-owned regulated utilities (IOUs). These fully integrated utilities own generating plants as well as the T&D systems that deliver the power to their customers. In the past, this was the dominant model, but deregulation in some states has transformed the industry. In deregulated areas, generation, transmission, and distribution may be handled by different entities. For example, independent power producers (IPPs) may sell power to distribution utilities, or even directly to end users, using the transmission system as a common carrier (as shown in Figure 9.2). The Federal Energy Regulatory Commission (FERC) has long had the authority to regulate financial aspects of the transmission of electricity in inter- 1 “Distribution substations” connect the high-voltage transmission system to the lower-voltage distribution system via transformers. The system includes 60,000 distribution substations. “Transmission substations” connect two or more transmission lines.
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.1 The current T&D system comprises two distinct but connected systems: transmission and distribution. Source: Courtesy of NETL Modern Grid Team. state commerce. The Energy Policy Act of 2005 expanded FERC’s mandate, giving it the authority to impose mandatory reliability standards on the bulk transmission system and to impose penalties on entities that manipulate electricity markets. As part of its new authority, FERC has in turn granted the North American Electric Reliability Corporation (NERC)—a private organization created by the utility industry in 1968 to advise on reliability—the authority to develop and enforce reliability standards. The National Institute of Standards and Technology also is involved in developing standards for the grid. In some areas, independent system operators/regional transmission operators (ISO/RTOs) are responsible for operating the transmission system reliably, including constantly dispatching power to balance demand with supply and monitoring the power flows over transmission lines owned by other public or private entities. The ISO/RTOs, with oversight by FERC and NERC, monitor their systems’ capac-
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.2 Key players in the T&D system. Power is produced by regulated investor-owned utilities (IOUs), which own the majority of the T&D systems, and in some areas by independent power producers (IPPs). IOUs typically provide electricity to end users through their own distribution systems, while IPPs sell to a utility or purchase transmission services to deliver electric power directly to an end user. There are also utilities that are federally or locally owned, such as municipal and rural co-ops. Most of these utilities own generating plants as well as T&D lines. Source: Courtesy of NETL Modern Grid Team. ities and conduct the wholesale market to clear short-term transactions.2 There are nine ISO/RTOs in North America, as shown in Figure 9.3. Seven of the nine come 2 Market-clearing transactions match the available supply of electric power at a clearing price that matches the demand.
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.3 Independent System Operators (ISO) and Regional Transmission Organizations (RTO) in North America. Regions in which the power industry has been restructured, such as Texas, the Northeast, the Upper Midwest, and much of California, are colored. In these areas, ISO/RTOs are responsible for operating the transmission system. In the white regions, where the industry has not been restructured, vertically integrated power utilities continue to operate the transmission system. Source: North American Electric Reliability Corporation. under FERC’s reliability oversight. The remaining two are subject to Canadian regulations. Operationally, the electric transmission systems of the United States and Canada are divided into four large regions known as “interconnections,” as shown in Figure 9.4: The Eastern Interconnection, which includes most of the United States and Canada from the Rocky Mountains to the Atlantic coast;
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.4 North American power interconnections. The Quebec Interconnection is shown as part of the Eastern Interconnection because operations are coordinated. Source: North American Electric Reliability Corporation. The Western Interconnection, which extends from the Pacific coast to the Rockies; The ERCOT Interconnection, which encompasses most of Texas; The Quebec Interconnection, which is shown in Figure 9.4 as part of the Eastern Interconnection because they are operated jointly. Within each interconnection, all generators operate in synchronism with each other. That is, the 60-Hertz alternating current (AC) is exactly in phase across the entire interconnection. While all interconnections operate at 60 Hz, no attempt is made to synchronize them with each other. Electricity is transmitted between interconnections, but that is done by converting to direct current (DC) and then back to AC.
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Amreica’s Enery Future: Technology and Transformation Controlling the dynamic behavior of this interconnected transmission system presents an engineering and operational challenge. Demand for electricity is constantly changing as millions of consumers turn on and off appliances and industrial equipment. The generation of and demand for electricity are balanced regionally by about 140 balancing authorities to ensure that voltage and frequency are maintained within narrow limits (typically 5 percent for voltage and 0.02 Hz for frequency). If more power is drawn from the grid than is being pumped into it, the frequency and voltage will decrease, and vice versa. If the voltage or frequency strays too far from its prescribed level, the resulting stresses can lead to system collapse and possibly damage to power system equipment. Problems with the Current System Most U.S. transmission lines and substations were constructed more than 40 years ago and are based on 1950s’ technology, but demands on the electric power system have increased significantly over the years. Since 1990, electricity generation has risen from about 3 trillion kilowatt-hours (kWh) to about 4 trillion in 2007. Long-distance transmission has grown even faster for reliability and economic reasons, including new competitive wholesale markets for electricity, but few new transmission lines have been built to handle this growth.3 Figure 9.5 shows transmission investment from 1975 to 2007. From 1985 through 1995, transmission investment was fairly stable at the level of about $4.5 billion per year. Although this was about $2 billion per year lower than during the previous decade, reserve margins4 were adequate because of prior over-building and slow growth in demand. However, in the late 1990s, the restructuring and re-regulation of the U.S. transmission system led to a decrease in invest- 3 The stress on the U.S. transmission system that was brought about by wholesale electric competition was described by Linn Draper, chairman and CEO of American Electric Power, during his testimony before the House Energy and Water Committee shortly after the August 14, 2003, blackout: “In the five-year period during which wholesale competition first gained momentum, the number of wholesale transactions in the U.S. went from 25,000 to 2 million—an 80-fold increase.” Another factor increasing demand for transmission is the difficulty of building generating facilities near load centers because of pubic opposition. Ironically, new transmission lines also are the object of considerable public opposition even while the need for them is increased by opposition to generating stations. 4 Reserve margin is the amount of transmission capacity available above the maximum power expected to be delivered over the system. Some margin is necessary to allow for unexpected loads or outages on the system.
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.5 Transmission investment by integrated and stand-alone transmission companies. The IOU data cover only 80 percent of the transmission system. All investment is shown in 2007 dollars. Data were adjusted as necessary using the Handy-Whitman index of Public Utility Construction Costs. Sources: 1975–2003 from EEI, 2005; 2000–2007 from Owens, 2008. ment. This decrease “was principally due to uncertainty in the rate of return on investment (and whether it would be modified or disallowed in future years) offered to transmission owners/investors” (EPRI, 2004). Transmission investment averaged about $3 billion per year from 1995 to 2000. The deficit of the late 1990s is still affecting reliability; it has contributed to transmission bottlenecks and other transmission deficiencies throughout North America, even with the more recent upward trend in transmission expenditures since 2000. According to NERC, the transmission system is being operated at or near its physical limits more of the time (Nevius, 2008). Stressed grids have less reserve margin for handling disturbances. Figure 9.6 shows the increase in transmission loading relief events. (TLR is a measure of when scheduled transmission requests could not be accommodated.5) Inadequate system maintenance and repair also have contributed to an 5 Transmission loading relief (TLR) is a sequence of actions taken to avoid or remedy potential reliability concerns associated with the transmission system. Calls for TLRs involve problems
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.6 Transmission loading relief (TLR) events. The number of TLR events is not an outage measure; it is the number of times a congestion limit is reached. Although this measure has been used to characterize transmission reliability, congestion limits can be reached purely for market reasons. Source: See www.nerc.com/docs/oc/scs/logs/trends.htm. increase in the likelihood of major transmission system failures (EPRI, 2004), and the number of such disturbances has in fact been increasing in recent years, as shown in Figure 9.7. Of greatest concern is the risk of these disturbances cascading over large portions of the T&D systems. The 2003 blackouts in the world’s two largest grids—the North American Eastern Interconnection and the West European Interconnection—resulted from such cascading failures (see Box 9.1). Each event affected 50 million people. Another result of diminished investment in transmission is that the manufacturing of associated equipment has largely disappeared from the United States, along with commercial research and development (R&D) for transmission equipment (including transformers, switchgear, and high-voltage DC [HVDC] technology). Today, essentially all large power-transmission equipment is imported from Europe and Japan. This could become a potentially that require intervention on the transmission system. These may or may not result in transmission outages or outages to customers.
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.7 Major transmission system disturbances reported to NERC. Disturbances include electric service interruptions, unusual occurrences, demand and voltage reductions, public appeals, fuel supply problems, and acts of sabotage that can affect the reliability of the bulk electric systems. Source: Compiled from data in NERC, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001, 2002, 2003, 2004, 2005, and 2006. serious problem, especially with long lead-time components, in case of major natural disaster or terrorist attack. Modernization is progressing much more rapidly abroad. For example, China and India are building 800 kV HVDC and 1000 kV AC transmission lines, along with the underlying high-power infrastructure. About 30 high-power HVDC projects are under construction in Europe, including many submarine cable connections to increase utilization of offshore wind power. Two-way metering is common in Europe because it helps to maximize the potential of rooftop photovoltaics, which are being heavily promoted in Germany and other countries. Although the United States has vast potential for wind and solar generation, there is no consensus or plan for how this power could be transmitted to load centers. While expenditures on the replacement and new construction of American T&D assets have increased recently (see Figure 9.5), grid assets are aging, and investments are still not keeping pace with the growing demand for electric power and power marketing. To meet these challenges, transmission
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Amreica’s Enery Future: Technology and Transformation BOX 9.1 The Northeast Blackout of August 14, 2003 A modern T&D system could have helped to avoid the circumstances that initiated the August 2003 Northeast blackout. Two major issues contributed to this blackout: first, the operators did not know the system was in trouble; and second, there was poor communication between the utilities operating the transmission lines—First Energy and American Electric Power—and also between these utilities and the ISO responsible for the area (the Midwest Independent System Operator). The U.S.-Canada Power System Outage Task Force (2004) noted that four major factors contributed to the blackout: Inadequate system understanding, Inadequate situational awareness, Inadequate tree trimming, Inadequate reactive power control diagnostic support. A modern T&D system could have provided better understanding of the state of the system, better communications, and, ultimately, better controls. Adequate monitoring, communication, and dynamic reactive power support during the initial voltage sag could have helped to prevent lines from overloading, heating up, and sagging excessively. Operators would have been better informed, and online real-time dynamic contingency analysis of potential system collapse would have helped operators stay aware of possible risks and actions to be taken in response. Finally, automatic actions could have been taken to island (isolate) portions of the system and prevent the ultimate cascading event (which spread the localized outage across much of the northeast United States and Canada). The system could also have been restored much more rapidly if a modern grid had been in place. systems must be modernized—a complex but vital undertaking.6 However, orders for modern transmission technologies remain low, largely because they are perceived to be risky and uneconomic,7 as discussed in more detail later in this chapter. Thus if business continues as usual, investment will focus on new construction to meet peak load growth, which is projected to increase 6 Modernization is defined here as the deployment of a suite of technologies (described in the coming sections) that will enable the T&D systems to meet a variety of challenges, particularly the seven characteristics (adapted from NETL, 2007d) discussed in more detail in the section titled “A Modern Electric T&D System.” 7 This view was presented repeatedly to the committee by industry representatives, including those representing Southern California Edison Co., Areva, ABB, and Siemens.
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Amreica’s Enery Future: Technology and Transformation third the core loss of transformers with grain-oriented steel. This material is made by running molten metal on a fast-moving belt, thereby solidifying it rapidly without producing grains in tape form. The market for amorphous steel transformers has been quite low, however—fewer than 10,000 units per year—mainly because of their higher cost. The U.S. Department of Energy (DOE) has established standards for distribution-transformer efficiency that will become effective in 2010 (DOE, 2007). The DOE estimates that the cost of the standard will be $463 million per year in increased equipment and installation costs, while the annualized benefits will be $602 million.4 This standard could help to make amorphous steel transformers, as well as advanced grain-oriented steel transformers, more competitive. Given the typical service lives of distribution transformers, it is expected that 5 percent of them will be replaced each year. Sensing and Measurements Understanding and acting on the current state of the T&D system require measuring their power characteristics at many points. The basic measurements that need to be made are the current (amperes) and voltage (volts) at every electrical connection and the status of all switches (on/off). The first two measures indicate the electrical condition of the electric T&D system—although the derived value of power flow (watts, VARs) is often preferred for monitoring. Whether the switches are on or off provides information on the connectivity of the T&D systems, such as which components are connected and which ones are switched out. These measurements, made at each substation, are used to drive controls and protective relays. In the early days, all the measurements and controls were hardwired within the substation, and a few—very few—of the measurements from high-voltage transmission substations were hardwired all the way back to a central control center. From the 1960s on, the control center was based on the digital computer’s supervisory control and data acquisition (SCADA) system, and the data from substations could be transmitted over slow communication channels, usually microwave, to the control center. Within the substation, the measured data could be sampled every few seconds and put into a remote terminal unit (RTU) that could be polled by the SCADA system over the microwave channel 4 A 7 percent discount rate is used in this calculation. Alternatively, using a 3 percent discount rate, the cost of the standard is $460 million per year and the benefits are $904 million per year.
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Amreica’s Enery Future: Technology and Transformation FIGURE 9.A.5 The SCADA at the control center collects real-time data from each substation remote terminal unit (RTU) every few seconds. (Figure 9.A.5). This configuration remains the architecture of most control centers in place today. More recently, most modern high-voltage substation control and protection systems are digital and the connectivity is through a local area network (LAN). Most of the recent and all future controllers and protection systems in the substation are based on digital processing. In fact, all the recording systems—for example, fault recorders and sequence of events recorders—are also based on digital processors. Given that the currents and voltages measured are all AC, the phase differences between these values reveal the stability of the power flow in the transmission system. Phase differences were not a problem to measure within one substation when the measurements were hardwired and continuous. However, the values sent to the control center were limited to current and voltage magnitudes, as there was no way to measure phase differences between values at widely separated substations. This situation has recently changed because of the availability of GPS signals, which can provide an absolute time reference to all substations on
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Amreica’s Enery Future: Technology and Transformation the continent. Thus both magnitudes and phase angles of AC currents and voltages can be measured and stored today, although the number of measurements taken that incorporate phase (phasor measurements) in the first place is still very low. However, the availability of digitized phasor measuring at high sampling rates raises the possibility of many new and fast control applications not previously available. The modern transmission system should have all of its high-voltage sub stations equipped with measurement systems that will be sampling critical data at rates of 30 to 120 times per second (and even faster for localized applications) with an absolute GPS time reference, allowing a more complete picture to be created of the current real-time state stability of the system. Although the hardware costs of these measurement units themselves are modest, they have to be retrofitted into the thousands of existing substations at significant cost. In this regard, developing countries such as China have an advantage over more established industrialized countries. They are able to leapfrog directly to the latest technologies for substation automation as they expand their electric grids. On the distribution side, there are about four times as many lower-voltage substations as there are transmission substations. Distribution systems can use measurement instrumentation with slower sampling rates than those needed for transmission systems, but the flood of data requires high-bandwidth communication to use these data for control. Also, synchronizing measurements by using GPS at the low-voltage substations is not yet considered cost-effective. With regard to end users, there is a move toward replacing the existing kilowatt-hour meters for billing with intelligent (i.e., microprocessor-based) meters that can provide the customer with new buying options, such as time-of-day pricing. These meters can also bring control signals from the power company directly into appliances and other equipment on the customer side. The ubiquity of more and faster measurements throughout the T&D system raises the issue of how to handle this proliferation of measurement data. Certainly they can be stored at the substations where they are collected and then used for various local engineering analyses as needed. However, a higher value of these real-time measurements is in helping to monitor and control the overall T&D system more efficiently and reliably. Such applications require the development of real-time data-handling software that can collect and move these data where they are needed.
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Amreica’s Enery Future: Technology and Transformation Integrated Communications The Eastern Interconnection has approximately 10,000 high-voltage (above 100 kV) substations, overseen by about 100 control centers. If fully instrumented, each substation could have about 100 measurement points (currents, voltages, powers, switch statuses), each of which may be sampled about 100 times per second. This arrangement would require each control center to process about a million data points per second. In addition, the center should be aware of what is going on in the neighboring parts of the T&D system and perhaps in the whole interconnection. The Eastern Interconnection also has about 10 second-level control centers, known as reliability coordinators, that supervise larger areas of the T&D systems; each of these facilities has to process data at rates that are an order of magnitude higher than those of the substations. But these data rates cannot be handled by the communication system used today between control centers and substations. A basic problem is that the existing communication channels between high-voltage substations and the control center, many dating from the 1960s, are slow. They are being replaced with high-bandwidth optical fiber. But even with the high bandwidth, the present architecture—wherein all data from substation RTUs are collected at the control center’s SCADA—cannot handle the expected proliferation of real-time measurement data. Moreover, it does not make sense to centralize this large amount of data. Automatic controllers need not be physically located in one place either but can be sited conveniently according to their input sources and output destinations. The actual data needs for particular applications to monitor and control the transmission network will vary widely. For example, there will always be control centers where human operators are monitoring a region of the system. The number of measurement data points needed at such a control center will be very large, but the sampling of the data can be as slow as once a second, as the human eye cannot follow much faster changes. However, the processing of these data for checking limits, warning, predicting, and visualization at the control center will be very large. And while an automatic control such as a special protection scheme for islanding a portion of the electric T&D system to keep a disturbance from cascading will require only a few measurements, they involve very high sampling rates and speeds. On the distribution side, the communication needs are localized to neighborhoods, but the sheer number of substations, feeders, and customers requires low-
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Amreica’s Enery Future: Technology and Transformation cost alternatives such as radio-frequency and power-line carrier systems. Smart meters, time-varying rates, the handling of customer generation, demand-side management, and other such applications require ubiquitous communications. Thus the communication system for both the transmission and the distribution system will need to be able to handle a wide range of speed and quantity requirements. Although such systems exist today—for example, cellular telephone networks—the communication needs of the power grid are unique; its software will thus have to be custom designed and developed. The cost of this communication infrastructure, which can begin to be deployed by 2020, is partly for the physical fiber-optic cables and switching computers, but mostly for the software. Costs of Modernizing an Electric T&D System The AEF Committee’s cost estimates are based on a study published by the Electric Power Research Institute (EPRI) in 2004 (EPRI, 2004). EPRI’s projected costs are summarized in Tables 9.A.1 and 9.A.2.5 The committee modified EPRI’s estimates to reflect its conclusion that superconducting cables, which account for $30 billion of the total in Table 9.A.1, are unlikely to be deployed during the next 20 years. If indeed they are not available, the costs of alternative technologies are likely to be higher than that amount and/or the benefits of modernizing the grid could be lower. The committee also considered the investment that would be required to meet load growth and replace aging equipment. The annual level of investment in transmission over the 20 years prior to 1985 averaged around $5 billion per year, but from 1985 to 1999 only about $3 billion per year was invested. That $30 billion shortfall meant that the transmission system failed to keep pace with load growth. EPRI assumes that load growth will continue in the future, as it has in recent decades, and that an investment of $5 billion per year continues to be needed to meet it. In addition, $1.5 billion per year for 20 years will be required to make up for the 1985–1999 investment shortfall. Thus EPRI estimates that $6.5 billion (in 2002 dollars) will annually be needed for transmission systems over the next 20 years simply to meet load growth and to correct deficiencies in the current system, in addition to implementing advanced technologies to modernize the transmission system. 5 EPRI’s cost estimates are in 2002 dollars.
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Amreica’s Enery Future: Technology and Transformation TABLE 9.A.1 EPRI Cost Estimates for Modernizing the Transmission System Technology Category Cost (billion 2002$) Communications and sensors 4 Hardware improvements to substations (includes transformers and other substation equipment) 5 Substation automation 10 Other equipment (power electronics, storage, HV lines and equipment, superconducting lines) 55 Emergency operation and restoration tools and equipment 12 IDSTa software 3 Dynamic thermal circuit rating 1 Predictive maintenance 20 Total 110 a IDST = Improved decision-support technology. Source: EPRI, 2004. TABLE 9.A.2 EPRI’s Cost Estimates for Modernizing Distribution Substations and Feeders Component Cost per Substation Feeder (2002$) Individual Cost per Substation Feeder (billion 2002$) Number to Be Upgraded Total Cost (billion 2002$) Upgrading distribution substations 600,000 40,000 24 Communications 75,000 Hardware improvements 350,000 Sensors and monitoring 75,000 Advanced controls and diagnostics 100,000 Upgrading distribution feeder circuits 540,000 320,000 173 Communications 60,000 Hardware improvements 170,000 Sensors and monitoring 100,000 Advanced controls and diagnostics 210,000 Integrating consumer systems with the grid 62 Total 259 Source: EPRI, 2004.
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Amreica’s Enery Future: Technology and Transformation As shown in Table 9.A.1, EPRI projects the cost to modernize the transmission system to be $110 billion over 20 years, or approximately $5.5 billion per year. Similarly, EPRI estimated the expenditures for the distribution system over 20 years to be $340 billion to meet load growth, $6 billion to correct deficiencies, and $259 billion to modernize the distribution system. Table 9.A.2 summarizes the costs to modernize distribution. Summing the T&D system expenditures needed to meet load growth and to correct deficiencies with the expenditure needed for the modern T&D system is likely to overestimate the total investment needed. When new lines are built (or rebuilt) to meet load growth, the additional investment to install modern technologies is less significant. In addition, technologies can meet multiple purposes. For example, dynamic thermal circuit rating can help to meet load growth by increasing the capacity of existing lines, but this is also an important part of a modern transmission system. Correcting for such overlaps (synergies), EPRI’s estimate of the total investment needed in the T&D system is shown in Table 9.A.3. It should be noted that in order to achieve the full benefits of synergies on the transmission side, equipment throughout the system would need to be deployed in an integrated way. This is unlikely to occur until after 2020. EPRI estimated the synergies for T&D to be $72 billion and $132 billion, respectively, over the 20-year time horizon of their study. The AEF Committee (as previously stated) dropped $30 billion from the $110 billion to modernize the transmission system (by eliminating superconducting cables), which also required dropping $30 billion from the transmission synergies. The net result was that the committee estimated $80 billion to modernize the transmission system, with synergies of $42 billion when incorporating the expenditures to meet load growth and to correct deficiencies. The elimination of superconducting cables was assumed to negate an equal benefit (synergies) in meeting load growth and correcting deficiencies. These details are shown in Table 9.A.3. In the committee’s analysis, EPRI’s cost estimates were escalated to 2007 dollars. The committee accounted for recent real escalation in materials and construction costs by using the national average T&D indexes.6 In 2007 dollars, the investment needed in the T&D systems over the next 20 years will be about $225 billion for transmission and $640 billion for distribution. These estimates 6 The national average transmission index increased by about 33 percent between 2002 and 2007. The national average distribution cost index has increased by about 40 percent during that same period (Brattle Group, 2007).
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Amreica’s Enery Future: Technology and Transformation TABLE 9.A.3 Costs to Implement Modern T&D Systems EPRIa Brattle Groupb AEF Committee Adjusted Transmission (billion 2002$) Distribution (billion 2002$) Transmission (billion 2007$) Distribution (billion 2007$) Transmission (billion 2007$) Distribution (billion 2007$) Investment to meet load growth 100 330 Investment to correct deficiencies 30 6 233 675 175c 470c Modern T&D systems 80 259 N/Ad N/Ad 105e 365e Total 210 595 233d 675d 280 835 Synergies 42 132 N/A N/A 55 195 Total minus synergies 168 463 N/A N/A 225 640 aEPRI, 2004. bBrattle Group, 2008. cEPRI’s estimates, originally in 2002 dollars, were escalated to 2007 dollars for the committee’s analysis. Recent real escalations in materials and construction costs were accounted for by using the national average T&D indexes (33 percent for transmission, 40 percent for distribution). dBrattle Group numbers include investments needed for the business-as-usual case but do not identify costs of deploying the modern T&D systems. eThe $30 billion (in 2002 dollars) that EPRI estimated for investment in superconducting cables has been removed from the total investment needed for the transmission system. This quantity has also been removed from the synergies calculation. include investments needed to meet load growth, to replace aging equipment, and, additionally, to implement modernization. Implementation of the modern T&D system alone makes up a small portion of this total, as shown in Table 9.A.3: $50 billion for transmission and $170 billion for distribution.7 The committee assumed that 40 percent of the transmission improvements involved in implementing the modern grid, meeting load growth, and correcting deficiencies would be made before 2020, while the remaining 60 percent would need to be implemented between 2020 and 2030. Thus an investment of $9 billion per year would be needed in the transmission system from 2010 to 2020 7 The $50 billion for transportation and $170 billion for distribution are the total costs for a modern T&D system, less the listed “synergies.”
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Amreica’s Enery Future: Technology and Transformation ($2 billion per year for modernizing the grid). From 2020 to 2030, approximately $13.5 billion per year would be needed ($3 billion for the modernization alone). On the distribution side, as with the transmission system, the committee has assumed that 40 percent of the improvements would be made by 2020 and the remaining 60 percent from 2020 to 2030. Thus an investment of $26 billion per year would be needed for the distribution system from 2010 to 2020 ($7 billion per year for modernization). From 2020 to 2030, approximately $38 billion per year would be needed ($10 billion for modernization), and an investment of $32 billion per year would be needed for the distribution system over the 20 years beyond 2030. Such an investment would be more than returned in the form of benefits from the improved system. References for Annex 9.A Bjelovuk, G. 2008. Presentation to the AEF Committee, Washington, D.C., February 21. Brattle Group. 2007. Rising Utility Construction Costs: Sources and Impacts. Prepared by M.W. Chupka and G. Basheda for the Edison Foundation. September. Available at www.edisonfoundation.net/Rising_Utility_Construction_Costs.pdf. Accessed July 2009. Brattle Group. 2008. Transforming America’s Power Industry: The Investment Challenge 2010-2030. Prepared by M.W. Chupka, R. Earle, P. Fox-Penner, and R. Hledik for the Edison Foundation. Available at www.edisonfoundation.net/Transforming_Americas_Power_Industry.pdf. Accessed July 2009. CECA (Consumer Energy Council of America). 2003. Positioning the Consumer for the Future: A Roadmap for an Optimal Electric Power System. Washington, D.C. Available at www.cecarf.org/publications/RestExecSummary.pdf. Accessed July 2009. DOE (U.S. Department of Energy). 2007. 10 CFR 431. Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards, Final Rule. Federal Register 72(197), October 12. Available at www1.eere.energy.gov/buildings/appliance-standards/commercial/pdfs/distribution-transformers_fr_101207.pdf. Accessed July 2009. EPRI (Electric Power Research Institute). 2004. Power Delivery System of the Future: A Preliminary Study of Costs and Benefits. Palo Alto, Calif. EPRI. 2008. Compressed Air Energy Storage Scoping Study for California. Prepared for the California Energy Commission. CEC-500-2008-069. Available at www.energy.ca.gov/2008publications/CEC-500-2008-069/CEC-500-2008-069.pdf. Accessed July 2009. EWIS (European Wind Integration Study). 2007. Towards a Successful Integration of Wind Power into European Electricity Grids. European Transmission System Operators. Brussels, Belgium.
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Amreica’s Enery Future: Technology and Transformation McDonald, John (General Electric Co.). 2008. Discussion of electric T&D technologies and costs. Presentation to the T&D Subgroup of the AEF Committee, April 24. NETL (National Energy Technology Laboratory). 2007a. A Systems View of the Modern Grid. Prepared for the U.S. Department of Energy. Available at www.netl.doe.gov/moderngrid/resources.html. Accessed July 2009. NETL. 2007b. A Systems View of the Modern Grid. Appendix A1: Self-Heals. Prepared for U.S. DOE. Available at www.netl.doe.gov/moderngrid/resources.html. Accessed July 2009. NETL. 2007c. A Systems View of the Modern Grid. Appendix A2: Motivates and Includes the Consumer. Prepared for U.S. DOE. Available at www.netl.doe.gov/moderngrid/resources.html. Accessed July 2009. NETL. 2007d. A Systems View of the Modern Grid. Appendix A6: Enables Markets. Prepared for U.S. DOE. Available at www.netl.doe.gov/moderngrid/resources.html. Accessed July 2009. NETL. 2007e. A Vision for the Modern Grid. Available at www.netl.doe.gov/moderngrid/docs/A%20Vision%20for%20the%20Modern%20Grid_Final_v1_0.pdf.resources.html. Accessed July 2009. NRC (National Research Council). 2002. Making the Nation Safer: The Role of Science and Technology in Countering Terrorism. Washington, D.C.: The National Academies Press. PNNL (Pacific Northwest National Laboratory). 2007. Testbed Demonstration Projects. Part II: Grid Friendly Appliance Project. October. Available at www.gridwise.pnl.gov/docs/gfa_project_final_report_pnnl17079.pdf. Accessed July 2009.
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