Appendices
Appendix A: How the Transmission/Distribution System Operates
Appendix B: Methodology / Limitations of this Report
Appendix C: Constraint Summaries
Section 1 - Transmission Constraints on PG&E's System
Section 2 - Transmission Constraints on SCE's System
Section 3 - Transmission Constraints on SDG&E's System
Section 4 - Economic Constraints Under the Control of The California ISO
Appendix D: Project Summaries
Appendix E: Electrical Glossary
Appendix A
HOW THE TRANSMISSION/DISTRIBUTION SYSTEM OPERATES
How the Transmission and Distribution System Operates
Most electric systems worldwide, including California's, generate and transmit Alternating Current (or AC), where current reverses flow many times a second.19 Large AC systems can be flexible and efficient, but they can become unusable or unstable if they are not carefully controlled. Loss of control of the system can lead to "cascading outages" and damage to equipment, such as the outage on October 10, 1996, which affected half of all electric customers in the West.
Electric power distributes itself over all available transmission lines, sometimes overloading lines or other equipment. In the short run, operators (and automated equipment) can respond to overloaded lines in a number of ways, including re-dispatching20 generation, shifting power to Direct Current (DC) lines, operating various kinds of special equipment (such as series capacitors and phase shifters), or dropping load. In the long run, system planners determine the capacity of existing equipment, so that operators can avoid "thermal" overloads and stability problems. In the long run, system planners determine how much power existing lines can carry, as well as the need for new lines.
Forecasting future power flows requires forecasting many other factors; making more extreme assumptions reduces the likelihood of outages, but also increases system costs.
Current planning studies (and this report) do not explicitly weigh the costs and benefits of transmission improvements; improved methodologies and data are not yet available. In some cases, PG&E uses a probabilistic cost-benefit analysis to evaluate its transmission project proposals. The ISO has undertaken an effort to institute a similar methodology for the utilities. A draft policy entitled "Methodology for the Application of Involuntary Planned Load Interruption" can be found on the ISO website.
Large AC Systems Can Be Flexible and Efficient
AC systems have a major advantage over DC: they can use transformers.21 Transformers connect power lines that operate at different voltages,22 converting the power from one voltage to another. Thus, an AC system can transmit power over high voltage, long-distance transmission lines, with minimal power losses, while efficiently converting that power to lower distribution voltages to serve customers. (Direct Current lines have even lower losses, but are much less flexible, and are generally economic only when large amounts of power must be moved long distances.) 23 Similarly, generators can supply power at various voltages. Moreover, generators and consumers can locate anywhere on the network, as long as the transmission system can handle the resulting power flows (see below).
As a result, alternating current systems can operate over very large distances. California's transmission system connects the state to the Pacific Northwest and the Desert Southwest (See Map 1). Thus, California's electric utilities are part of the Western Interconnection, which moves power between British Columbia and Alberta in the North, Baja Mexico in the South and just beyond Colorado in the East. Texas, Quebec, and the Eastern Interconnections cover the rest of the United States, Canada, and parts of Mexico. The interconnections are essentially electrically separate.24
Interconnected power systems have many advantages. First, to some extent, power plants can be located where generation costs and impacts are lowest, rather than being located at load centers. Second, because the system is large, the failure of any particular generator (or in many cases, transmission facilities) will have relatively less impact on the system as a whole. Third, different areas of the system are likely to have diverse demand patterns, so that a region where demand peaks in the winter (such as the Pacific Northwest), can supply summer power to summer peaking areas, and vice versa. Separate systems would have to build additional capacity that would remain unused much of the time; interconnected systems can build less generation capacity, and use that capacity much more intensively, reducing generation costs. Finally, large interconnected systems may facilitate increased competition, by expanding the number of power producers from which consumers may choose.
But AC Systems can Become Unstable if they are not Closely Controlled
AC systems require careful operation and planning, because power flows are governed by complex physical relationships. Some of these relationships make intuitive sense: for example, the total power injected into the system minus transmission and other losses, must equal total consumption at all times. Similarly, power flows will distribute themselves so that total flows into and out of any particular point on the transmission network must equal zero. Other relationships, such as the need for "reactive power" (described briefly below) are much less intuitive.25
In particular, all parts of interconnected AC systems must operate within tight frequency and voltage limits. Indeed, many of the motors and generators throughout the system must be synchronized,26 otherwise turbines and other components of the system can be badly damaged.27 Maintaining frequency and voltage takes constant adjustments, because electrical demand can change quickly between different hours of the day and between different seasons. A change in electric consumption can cause decreases or increases in both frequency and voltage, requiring increased or decreased generation, respectively. Operators, sensors at individual generators, and Automatic Generation Control (AGC) computers (with data links to power plants) all make such adjustments to some extent.
If load and generation are not adjusted properly, or if generation or transmission equipment fails suddenly, the system can become unstable, with voltage and frequency going out of control. Because such instability can seriously damage equipment (which can then be out of service for an extended period); for example, switches are set to disconnect equipment from the system when voltage and/or frequency vary too much beyond normal levels. In some cases, operation of protective equipment can rebalance the system (though sometimes at the cost of disconnecting some customers).
Another source of problems is sudden loss of a transmission line (e.g., when it contacts a tree and shorts out). When lines fail, power re-routes itself onto other lines, which may overload those lines, and cause them to disconnect from the system. The result is a "cascading" outage, which can affect wide areas.
Operators must also supply "reactive" power to compensate for motors and other inductive loads on the system. Insufficient supply of reactive power can cause voltage to "collapse" suddenly. Generators, capacitor banks,28 and other equipment can provide the reactive power and prevent such collapses.
In Particular Electric Power Distributes Itself over all Available Transmission Lines, Sometimes Overloading Lines or Other Equipment.
In most cases, operators can not directly control the routes over which AC power will flow. Rather, power flows take the path of least resistance29 through the transmission and distribution system. Thus under certain conditions, particularly in peak periods when demand for electricity is high, power flows can exceed the capacity of transmission lines, transformers, or other equipment. These problems are exacerbated when equipment fails suddenly, since power then reroutes itself instantaneously over remaining lines.
Loss of Control of the System can lead to "Cascading Outages" and Damage to Equipment, for Example, an Outage on October 10, 1996, Affected Half of all Electric Customers in the West.
Failure to manage the system properly can result in serious consequences. For example, on October 10, 1996, a west-wide heat wave drove power demand to very high levels across the Western Interconnection, resulting in much higher power flows than operators or planners expected. As a result, operators working for the Bonneville Power Administration (BPA) in the Pacific Northwest did not realize that several relatively minor transmission lines in their region were carrying major reactive power flows. BPA operators therefore paid little attention as three of these lines (which appeared to be lightly loaded) failed one-by-one.30 The failure of a fourth line caused power surges and overloads that quickly spread across the Western interconnection, activating automatic protective equipment and blacking out half of the interconnection's customers for several hours. Damage to equipment delayed restoration of full service for several days.
In the Short Run, Operators can Respond to Overloaded Lines in a Number of Ways, Including Rearranging Generation, Shifting Power to Direct Current (DC) Lines, Shutting Down AC Lines, Operating Various Kinds of Special Equipment (such as Series Capacitors and Phase Shifters), or Dropping Load.
The process that utilities use to satisfy electric demands as they vary during the day, without overloading transmission and distribution, begins with the control or "dispatch" of generation on the system. To oversimplify somewhat, the utility first tries to satisfy demand by using the cheapest generation available.31 Sometimes the system is able to handle resulting power flows with no problems; in that case, it is said to be "unconstrained." If transmission (or distribution) lines or equipment overload, however, the utility must reduce flows across them. The system is then said to be "constrained." The overloaded facilities are therefore specific constraints on the system. As discussed below, utilities can operate in the face of such constraints, but usually incur a cost for doing so.
The utility must reduce power flows over overloaded lines or equipment. Perhaps the simplest way to do so is to turn down generation down at the source of the power flow, and turn generation up at the other end of the line. Such generation adjustments can reduce power flows, but at a cost: since the utility initially started with the lowest-cost mix of generation, changes will generally increase operating costs.32
Under California's restructuring program, this process is initiated by scheduling coordinators33, who submit "schedules" to the Independent System Operator (a day in advance) showing the size and location of loads and generation. The scheduling coordinators also submit bids on increases or reductions in generation (or reductions and increases in load) in various locations; these bids are called "incs" and "decs," respectively. The ISO determines whether the system is constrained using computerized power flow models. Where overloads are projected, the ISO uses incs and decs to adjust generation, to prevent those overloads, paying the prices bid, and adjusting generation as needed. The cost of these adjustments are paid by scheduling coordinators whose bids are not accepted, and who therefore continue to use the congested path.
The ISO can also take other kinds of actions to relieve overloads, depending on the equipment available. For example, the ISO can request increased power flows over existing DC lines (for example, the DC line from the Pacific Northwest to the Los Angeles area), which can reduce flows over parallel AC lines (such as the three AC lines from Oregon to Northern California). The ISO can also shut down AC lines to force power to flow over different routes.
When necessary, the ISO can reduce generation at the source of the overload, while reducing load at the other end. First, the ISO will call on "non-firm" customers who have agreed to reduce consumption when needed, generally in return for a discount on electric rates.34 If additional load must be dropped to balance the system, the ISO will begin ordering "rotating outages," turning off power to "firm" customers by operating circuit breakers at distribution substations. Rotating outages are the last step the ISO can take to prevent the uncontrolled operation of automatic equipment and the possibility of cascading outages and damage to equipment. However, such rotating outages are expensive to customers and to society as a whole.
In the Long Run, System Planners Determine how much Power Existing Lines can Carry, as well as the need for New Lines.
Some capacity limits are "thermal." The ISO, utilities, and manufacturers set these limits on power throughput to prevent equipment from overheating. Overheated equipment can literally melt or explode. Overheated lines can sag and contact trees, causing an electrical fault (short circuit). Either event can put equipment out of service, in some cases, interrupting service to customers. Utilities calculate thermal limits based on the size, material, and design of the equipment, as well as assumptions about the ambient air temperature, windspeed, and other factors.35
"Stability" and security limits, on the other hand, keep the system running even if equipment fails suddenly. When equipment fails, power flows re-route themselves over remaining parts of the system, which can cause more thermal overloads. Further, such sudden changes can make the system unstable, causing voltage and frequency to oscillate wildly; if the system does not rebalance automatically, cascading outages and more damage can result.
Therefore, the Western Systems Coordinating Council (WSCC),36 the ISO, and the Utilities run computerized case studies of power flow patterns under "stressed" conditions (weather and generation patterns that would cause high power flows) under which system integrity and service reliability is most critical. Underlying each case study is a set of assumptions about demand and power production patterns, among other things. The studies determine what will happen if major parts of the system fail suddenly (such failures are called "contingencies"). 37 WSCC, the ISO, and the utilities set limits on power flows (also called "operating transfer capability) as high as possible without exposing the system to instability or other problems.
Because electricity routes itself over available transmission lines, such stability limits apply to one or more transmission "paths." Each path includes all lines that connect two regions of the electric system. WSCC assigns major paths a number; for example, Path 26 connects PG&E and Edison, and forms part of the electrical link between Northern and Southern California. In some cases, stability limits apply to one path. In other cases, limits apply to two or more paths simultaneously; for example, WSCC imposes a limit on California's total simultaneous imports from the Northwest and Southwest.
Forecasting Future Power Flows Requires Forecasting Many Other Factors; Making more Extreme Assumptions Reduces the Likelihood of Outages, but also Increases System Costs.
To forecast future power flows, planners must first forecast a many other factors. These include the amount, location, and price or cost of generation on the system (considering that owners will retire old power plants and build new ones), the amount and location of load, and the behavior of transmission equipment. In turn many of these factors depend on temperature and other weather conditions. All of these assumptions can affect the results of planning studies. The ISO specifies statewide values for some of these assumptions.
For example, under ISO planning criteria, the ISO and utilities assume that temperatures will reach 1-in-10 year levels in local planning areas, and 1-in-5 year levels across the service territory. Thus, temperatures are likely to exceed the assumed levels 10 or 20 percent of the time, respectively; it appears likely that some additional margin of error is built into the system, since most (though not all38) components of the system generally function satisfactorily on hotter days.
Making more stringent assumptions about future weather and other factors (or modeling more possible contingencies) causes studies to find more frequent and lengthy overloads, as well as more overloaded equipment. Planning based on more stringent assumptions will lead to more investment in the transmission system. Such investments may improve reliability but will also increase costs to consumers.
Current Planning Studies (and this report) do not Explicitly Weigh the Costs and Benefits of Transmission Improvements; Improved Methodologies and Data are not yet Available
Current reliability standards (and thus most transmission studies) are "deterministic:" planners do case studies of load flow patterns to see if equipment overloads or the system become unstable. At that point, under current criteria, either power flows must be reduced, or the transmission system must be modified to increase capacity.
This approach does not explicitly consider a number of factors that determine the cost-effectiveness of transmission improvements, including the probability of congestion, overloads, or instability, or the costs of those problems, either in terms of additional operating costs or the willingness of consumers to pay for avoiding outages on the system. In practice, WSCC grants exceptions from reliability standards where project costs clearly exceed benefits.39 Similarly, utilities simply don't propose projects that appear too expensive. However, with a few exceptions, such decisions are not well documented.
While both the Western States Coordinating Council (WSCC) and the ISO plan to develop "probabilistic" approaches that will consider costs and benefits explicitly, full data and methodologies are not yet ready and will take some time to complete.
Appendix B
METHODOLOGY / LIMITATIONS OF THIS REPORT
Methodology / Limitations of this Report
As part of this compilation and analysis, we looked for alternative solutions to constraints, especially where no projects were proposed.
Methodology
Because summer 2001 is only a few months away, in the interests of time, Energy Division used existing utility and ISO reports supplemented with information from data requests. Reports were reviewed to determine whether they were reasonable, but there was no confirmation of all details of the studies because they use large databases and many computer modeling runs.
Limitations
Both the utility studies and this reports fall short of the ideal because neither has a full cost/benefit study of proposals to address constraints. Available studies implement current reliability standards, which are deterministic - planners do case studies of load flow patterns to see if equipment overloads or the system become unstable. If such problems occur, either power flows must be reduced, or the transmission system must be modified to increase capacity. But the studies do not consider (1) the probability that the particular conditions in the case study will actually occur, (2) the size of resulting impacts on consumers, (3) the value consumers place on reliability,40 or (4) the cost of adding capacity to the system. 41 Nor do the studies consider the lost electricity sales that result from limits on transmission capacity, although in January 2001, the ISO released a preliminary study of the economics of expanding Path 15.
While both the Western States Coordinating Council (WSCC) and the ISO plan to develop probabilistic approaches that will explicitly consider all costs and benefits, full data and methodologies are not yet ready, and will take some time to complete. While utilities were asked to submit detailed cost-effectiveness information, they did not do so fully.
This report concentrates on transmission and distribution substations, but does not cover distribution systems below the substation level. There are thousands of circuits throughout the state, each with multiple transformers, lines and poles. Construction of a few new distribution substations is planned, however, since they will not be operating until after 2001, they are not examined in detail in this study. Utilities submitted no information on distribution equipment below the substation level, generally maintaining that improvements to such equipment are routine.
Because this report depends on deterministic planning studies, its conclusions are based on a number of assumptions:
· Demand forecasts are based on California Energy Commission demand forecasts and current trends. An unexpected slowdown in demand due to increased prices or a severe economic recession would reduce the need for many of the projects identified here.
· Weather - the ISO and utility studies assume 1-in-10 year or 1-in-5 year temperatures (see Appendix A). Therefore, there is a 10-20 percent chance that any particular year will be hotter than these studies assume. Because the system is generally designed conservatively, utilities will be able to squeeze by most of the time even if temperatures are higher. However, in near-record or record heat, outages may occur, particularly if unusual numbers of lines and generators are out of service at those times (such as occurred on June 14 in the Bay Area).
Appendix C
CONSTRAINT SUMMARIES
Section 1 - TRANSMISSION CONSTRAINTS ON PG&E's SYSTEM
19 California and the rest of the Western Interconnection operate at 60 cycles per second (as does the rest of the US). 20 Turning some generators up at one end of a power line and turning others down at the other end (see below). 21 Transformers work because changes in electric flow in one coil of the transformer induce changes in magnetic fields, which in turn induce changes in electric flow in the other coil of the transformer. Steady flows do not induce such changes. Thus a changing , alternating current is required. 22 Electrical voltage is analogous to the "pressure" in a water pipe. 23 Or when the object is to link two AC Systems and have them remain separate. Direct Current (DC) can carry power in only one direction between two specific points (that is, they cannot connect with loads or generators along the way). Further, they require expensive equipment at both termini. They are therefore economic only for very large power flows over long distances. Two such lines connect California to other states; one from Pacific Northwest, the other from the Intermountain Power Project in Utah. Both lines terminate near Los Angeles 24 Some "weak" power lines run between the different interconnections. Some are DC lines (see the previous footnote) which allow the systems to remain electrically separate since power flows can be controlled. Others are low-voltage, low-power AC lines. 25 For example, equations predicting the need for reactive power use the square root of -1, also called "i." That number does not exist in normal arithmetic, since there is no number that can be squared to yield a negative result. Mathematicians call "i" an "imaginary" number. 26 That is, they must operate at the same frequency. 27 In most power plants, turbines (driven by water, steam, or combusted gas) turn a drive shaft that turns the electric generator itself. The speed of the rotor determines the frequency of generated power. If the system frequency changes suddenly, the magnetic field in the generator will change the speed of the generator and drive shaft, while the turbines tend to stay at the same speed as before, due to mechanical inertia. This conflict can literally tear turbine blades apart. 28 Condensers and capacitors (in the simplest form, two parallel electrical plates separated by a non conductor) can, under the right circumstances, correct the divergence of frequency and voltage caused by coils (such as those in large motors). They are therefore a source of "reactive power." 29 Or more technically, impedance. 30 Due to heavy rains and hot weather, trees along transmission lines had grown unexpectedly high. Heavy power flows and high temperatures also caused transmission lines to sag enough to contact trees and create an electrical "short." Protective equipment at either end of the lines picked up the power surge, and shut the lines down automatically. 31 The utility chooses generation with the lowest marginal cost, in terms of price, operational cost, and/or the cost of alternatives. This calculation can be complicated; for example, while hydroelectric power generally has the lowest operating costs, its output can be adjusted very quickly and finely, and is often saved to meet peak loads. Because of this complexity, utilities typically use computers to dispatch generation. The ISO took over this function from PG&E, SDG&E, and Southern California Edison when it began operations in 1998. 32 When many generators are offering power at exactly equal prices, it may be possible to find alternative generation at the same cost. 33 Each scheduling coordinator is responsible for a group of customers, and must find generation to meet those customer's needs. Thus, schedules submitted to the ISO must balance demand and supply. Until recently, the Power Exchange acts as the exclusive scheduling coordinator for the three large distribution utilities, PG&E, SDG&E, and Southern California Edison. 34 California's distribution utilities, for example, offer discounted "interruptible" tariffs to large commercial and industrial customers who agree to curtail usage when power is in short.35 Wind cools equipment and increases capacity.
36 WSCC is the western affiliate of the North American Electric Reliability Council (NERC). Both organizations were formed in the 1960's after a major blackout affected most of the Northeastern United States. First composed of regulated electric utilities, the organizations have recently expanded their membership to include regulators, marketers, generators, and others; they also plan further changes in their governance structure. Under NERC's general framework, WSCC issue planning and operating criteria for use in the Western Interconnection. All criteria and rules were initially voluntary, with no enforcement system. In the past few years, with encouragement from the Federal Energy Regulatory Commission (FERC), WSCC has converted a number of its rules into a "mandatory" program which levies (arguably nominal) fee on violators; provided those violators have signed up for the program. 37 The system is assumed to be operating normally, when one or two (and sometimes more) contingencies occur. Thus, a single contingency is called "N-1" for "Normal minus one"; a double, simultaneous contingency is called "N-2"; etc. WSCC and ISO standards determine which contingencies utilities must model. 38 For example, on June 14, 2000, record high temperatures caused record demand in the Bay Area. In response to low voltages in the Bay Area, the ISO had to institute rotating outages to reduce Bay Area electricity demand by about 1 percent. 39 In practice, WSCC grants exceptions where project costs clearly exceed benefits. In some cases, WSSC allows more minor modifications (which, for example, reduce the probability that a problem will occur), or approves "remedial action schemes," generally automated equipment which drops load in response to the problem. 40 By CPUC order, California utilities survey customers who are asked one of three questions:- 1) what would you pay to avoid an outage? 2) What payment would you accept in order to accept an outage? 3) what are your direct financial losses when an outage occurs? In general, answers are lowest for question #1, highest for #3. Surveys specify the length and timing of the outage (e.g., a one-hour outage on a hot summer afternoon). Industrial and commercial customers generally value reliability higher than residential customers, but there are large variations even within those groups. Surveys specify the length and timing of outages (e.g., a one-hour outage on a hot summer afternoon).
- In some cases,WSSC allows more minor modifications (which, for example, reduce the probability that a problem will occur), or approves "remedial action schemes," generally automated equipment which drops load in response to a problem.
