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HomeMy WebLinkAboutAmerican Public Power Association Load Management est 1980LOAD MANAGEMENT BY GILBERT / COMMONWEALTH MANAGEMENT CONSULTING DIVISION IN ASSOCIATION WITH OSAGE MUNICIPAL UTILITIES OSAGE, IOWA AMERICAN PUBLIC POWER ASSOCIATION 2301 M STREET, NORTHWEST WASHINGTON, DC 20037 AMERICAN PUBLIC POWER ASSOCIATION TABLE OF CONTENTS EXHIBIT REFERENCE TABLE INTRODUCTION AND OVERVIEW I. 181 5 III. IV. VI. KEY BENEFITS OF LOAD CONTROL A. Production Capacity Cost Savings B. Energy Cost Savings Cc. Purchase Power and Wheeling Cost Savings D. Ancillary Benefits CONTROLLABLE LOADS BS Range of Controllable Loads Bs Characteristics of Controllable Loads Gs Projection of Controllable Load Estimates CONTROL STRATEGIES A. Data Requirements B. Procedures C. System Control vs. Substation Control LOAD CONTROL EQUIPMENT A. Generic Types B. Cost Estimate of Load Control Equipment BENEFIT COST ANALYSIS A. Benefit/Cost Methodology B. Payback Periods Cc. Sensitivity Analyses D. Customer Incentives CUSTOMER SENSITIVITIES CASE STUDIES vs Winter Peaking Urban Non-Generating Utility Die Winter Peaking Urban Generating Utility of Summer Peaking Urban Non-Generating Utility BIBLIOGRAPHY Gilbert /Commonwealth AMERICAN PUBLIC POWER ASSOCIATION EXHIBIT REFERENCE TABLE I. BENEFITS OF LOAD CONTROL I-l Comparison of Load Forecast with Available Capacity I-2 Base Case Forecast vs. Load Management Forecast I-3 Comparison of Capacity Requirements With and Without Load Control I-4 Two-Way Load Control System Ancillary Function Evaluation II. CONTROLLABLE LOADS II-1 Appliance Survey Form II-2 Approximate Average Water Use of Major Crops Irrigated E--3) Water Heater Diversified Demands - Winter Curves LI-4 Water Heater Diversified Demands - Typical Summer Curves TE-5 The Time Varying Nature of Diversified Demand II-6 Water Heater Restore Curves II-7 Central Air Conditioner Diversified Demand - Typical Summer Curves II-8 Central Air Conditioner Peak Day Load Curves II-9 Air Conditioner Demand vs. Temperature Curves II-10 Central Air Conditioner Load Control Test - Payback Period, LR AFB, September 2, 1975 II-11 Central Air Conditioner Load Control Test - Payback Period, Arkansas P&L, August 13, 1975 II-12 Space Heater Peak Day Load Curves III. CONTROL STRATEGIES III-1 Load Control Simulation - Water Heaters III-2 Load Control Simulation - Air Conditioners I1I-3 Substation vs. System Comparison of Peak Occurrences IV. CONTROL EQUIPMENT Iv-1 Typical Distribution System Makeup Iv-2 V.H.F. Radio Control Iv-3 V.H.F. Radio Control Components Iv-4 .F. Powerline Carrier Control Medium Voltage Injection Iv-5 Powerline Carrier Control Components IV-6 Powerline Carrier Control Transmission Voltage Injection IV-7 - Powerline Carrier Control Components Iv-8 - Powerline Carrier Control Line or Substation Injection Iv-9 Powerline Carrier Control Components AMERICAN PUBLIC POWER ASSOCIATION EXHIBIT REFERENCE TABLE — Page 2 = IV. CONTROL EQUIPMENT (Cont'd) IV-10 Hybrid Control Radio Plus H.F. Powerline Carrier IV-11 Hybrid Control Components IV-12 Telephone Address Control IV-13 Telephone Address Control Components V. BENEFIT/COST ANALYSIS Vat Benefit/Cost Analysis Flow Diagram Gilbert /Commonwealth INTRODUCTION AND OVERVIEW Over the past ten years the cost of operating a utility have risen dramatically. In response many utilities have begun to consider load management in addition to their conventional power supply. In a broad sense load management may be defined as any modification of loads and/or energy made to save money. In accordance with this broad definition, the sharp decline in load growth throughout the electric utility industry can clearly be considered as load management on the part of utility customers. Customers have become more energy conscious as a result of higher costs of electricity. For our purposes in discussing utility load management, however, we will consider only those modifications undertaken as a result of conscious programs by utility management. While it is true that one should consider the actual and potential effects of higher prices in general on electricity consumption and loads, to claim such effects as part of a conscious load management program is not appropriate. The term load management implies a deliberate act to bring about changes in loads. Few utility managers could claim to have raised rates over the last several years in order to reduce system load growth. There are two general types of load management activities which utilities can engage in: (1) passive load management and (2) active load management. Both types of load management have the same objective in general. However, the characteristics of each type of considerable different. Passive load management includes those activities which once set in motion depend primarily on the actions of customers in order to achieve the desired results. For instance, taking a cue from the change in load growth resulting from higher prices over the last several years, various forms of rates can result in passive load control. The more common forms of load management rates are seasonal rates and time-of-day rates. Another increasingly common form of passive load control includes consumer education Gilbert /Commonwealth of S| programs designed to encourage the purchase of energy efficient appliances and promote the efficient operation of existing appliances. Active load management, on the other hand, include activities which once taken, insure that certain reductions in system load or energy consumption take place. The most common form of active load management is the direct control of customer loads. Utility direct load control programs frequently include the control of residential water heaters, air conditioners and space heating. In some utility programs the control of agricultural irrigation pumping has proved very successful. Some forms of load management have some characteristics of both active and passive techniques. For example, interruptible loads while not usually controlled directly by utilities, are shed in response to utility requests. However, the typical response time required for load shedding is too long to be considered a controllable load from the system dispatcher operating viewpoint. Thus, interruptible loads may not play as valuable a role in day-to-day utility operations as that of directly controlled loads. Another example of a combined characteristic technique is that of demand subscription service. This technique typically allows each customer to choose his own maximum demand level. The level chosen establishes a portion of his monthly bill. A breaker installed at the customer's meter can be activated during peak load periods. If the load limit is exceeded while the breaker is activated, the entire household load is dropped. The customer must reduce his household load (i.e., turn off the dishwasher) and reset the breaker to continue service. While this technique is receiving interest it does require customer action to (1) choose a reduced load level and (2) take action as necessary to shed household load. OT The following table compares various characteristics of active and passive load management approaches in a qualitative manner. Characteristics of Load Management Approaches Passive Active 1. Effect on Load Depends on customer Ensured response 2. Time required to Generally, several 1-2 years produce significant years or longer results 3. Reliability for Difficult to predict Measurable planning purposes 4. Utility costs Negligible to high Medium to high The table indicates that, as its name implies, active load management produces more positive results. This does not mean to say, however, that passive load management techniques should not be utilized by utilities. It does mean that passive techniques should be viewed cautiously and depended on only in a secondary role. For this reason we will consider only direct load control in this load management course. There are two potential sources of savings from load management. First, energy costs savings may result from the reduction of energy consumption in periods during which the incremental costs for energy are high. The energy cost savings may be offset by the need to pay back all or a part of the energy which was avoided during the high cost hours. Presumably, the energy paid back can be purchased or produced at a lower cost than that which was deferred. Second, capacity cost savings may result from a reduction in system loads, particularly during peak load hours. The capacity cost savings may result from a reduction in the demand charges related to Gilbert /Commonwealth purchased power or a reduction in long run costs resulting from the delay in the addition of a new generating unit or a reduction in capacity added. These sources of savings will be examined in more detail later in the course. Many forms of active load management have been demonstrated to be technically feasible. Load management has been practiced in Europe and the United States for many years. The desirability to promote a load management program for a specific utility depends on two essential factors: (1) economics and (2) consumer satisfaction. Simply speaking, the economics of a load management program depend on the benefits of the program exceeding the costs of the program. Without a doubt, if a full scale load management program is shown to be uneconomic it should not be undertaken. On the other hand, even if a program can be shown to make good economic sense, it may not be feasible due to the customer satisfaction criterion. Direct load control means that electricity will be inhibited to certain customer loads in such a manner that they will operate differently than they would have otherwise. Under these circumstances it is extremely important that the customers' needs continue to be provided for in an adequate manner. Otherwise, the program will be rejected by the customers regardless of the economic justification for the program. Any utility considering load management programs must consider that the primary purpose for their operations is to satisfy the needs of their customers. There will be more discussion on these points during the course. A load management program is a complex process. It involves virtually all areas of utility operations and administration. Many utilities have opted to approach a load management program cautiously by establishing a pilot program initially. A pilot program can allow a utility to experience for itself some of the problems which would be encountered in a full scale program. Additionally, a pilot project, if designed appropriately, can provide a good measurement of the amount of diversified controllable load. The measurement of controllable load should not be the sole purpose of a pilot project, however, since in many cases, good estimated of controllable load can be obtained from the results of projects completed by other utilities. In fact, you may find that the accuracy of those estimates surpasses the accuracy of other critical elements of load management evaluation, such as the base load forecast, cost of future construction, interest rates and customer acceptance. Pilot projects cannot answer these key questions. Short of finding a crystal ball, these issues should be addressed by means of sensitivity analysis in the initial evaluation. This course was designed for both generating and non-generating utilities. The primary difference, of course, is the analysis of load management benefits. It is intended that upon completion of the course, participants will be familiar with all key aspects of load management feasibility studies. Po SECTION I KEY BENEFITS OF LOAD CONTROL The primary benefits of load control are: 1. Production Capacity Cost Savings Ve Energy Cost Savings 3. Purchase Power Cost Savings 4. Wheeling Cost Savings. Some utilities may be able to take advantage of all these potential benefits while others may be limited by source of supply or other factors. The basic distinction lies between generating and non-generating utilities. Production capacity cost savings and energy cost savings apply to generating utilities. Purchase power cost savings and wheeling cost savings apply primarily to non-generating utilities but could also apply to generating utilities who purchase power or use wheeling service. A. Production capacity cost savings can be earned by reducing peak demands, thereby reducing production capacity requirements. The emphasis is on peak demand, because control strategies dealing with existing appliances shift demand only a few hours on peak days. The reason for shifting demand only a few hours is that existing appliances are not designed for extended energy storage. As a result only a small demand shift can be imposed on customers without causing inconvenience and hardship... Therefore, load control applied to existing appliances can be used in the long term, in lieu of peaking capacity only. By the nature of control applied to existing appliances, the tolerable hours of load shifting are so few as to preclude the long term displacement of base load generating units. In the event that load control is used on a short term basis to delay the addition of a base loaded unit, the resulting impact of fuel costs must be considered. It is likely that older less efficient units would have to be used in place of the delayed unit, therefore increasing fuel costs. Only the net savings can properly be credited to load control. The first step in quantifying potential production capacity cost savings is to identify when future capacity additions will be required. Exhibit I-l is an example comparison of a peak load forecast with available capacity. It shows that in the short term there is ample capacity to meet peak demand plus reserves (capacity requirement). However, over the next decade load growth will outstrip available capacity such that a deficiency will exist in the early 1990's. As a result there can be no capacity cost savings until the early 1990's when the deficiency occurs. This is a basic, but nonetheless critical comparison to make when attempting to identify potential capacity cost savings from load control. It will essentially establish the time when fixed generating capacity costs can be reduced. The next step is to determine the impact of load control on the load forecast. To accomplish this, the base case forecast without load control is reduced to reflect controllable load for each year of the planning horizon. The base case forecast is critical to this analysis. Exhibit I-2 is a sample comparison of a base case forecast (without load control) and a forecast with load control. For both an equal percent reserve margin (15%) is applied to account for the total capacity requirement. Only the peak load forecast is considered at this point, as it is the primary determinant of system generating capacity requirements. Other factors, such as the projected load duration curve and fuel costs will have an impact on the generation mix, but not the amount of capacity required. Gilbert /Commonwealth I-2 EXHIBIT 1-1 COMPARISON OF WINTER FORECAST WITH AVAILABLE CAPACITY 2200 2100 2000 1900 1800 1700 1600 1500 FORECAST + 15% RESERVES~Z, 1400 AVAILABLE CAPACITY 1300 1200 1100 HUGO ADDED 1000 900 LOAD FORECAST 800 700 600 500 1980 81 82 83 84 85 86 87 88 89 90' 91 92 9394 95 96 97 98 99 EXH| 1-2 1900 — BASE CASE WINTER FORECAST VS LOAD MANAGEMENT FORECAST BOTH WITH 15% RESERVES 1700 1600 1500 BASE CASE FORECAST - 15% RESERVE 1400 1300 1200 1100 1000 900 800 700 600 500 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 YEAR The third step is the comparison of the forecast with and without load control to available capacity. Exhibit I-3 is a sample of such a comparison. The forecast with control requires less capacity to meet peak demand than the forecast without load control. In addition to the reduction in capacity requirements load control can also delay construction of the next generating unit. Therefore, the capacity related benefits of load control, as illustrated by Exhibit I-3, are twofold: 1. Long term reduction of total capacity requirement 2. Short term delay in construction of future generating units. Energy cost savings theoretically can be earned by dispatching load control, on a daily basis, to avoid start up and running high fuel cost generating units. This premise seems logical, provided there are fuel cost differentials between generating units and customers can tolerate daily control of their appliances. The retort to this premise is, that flattening the system load profile on a daily basis, will reduce system reliability as measured by loss of load probability (LOLP). As a result, the percent reserves necessary to maintain the same level of reliability will increase. The resolve of these issues will be unique to each utility. To assess these issues a production simulation model must be used. Ideally, the model should calculate monthly and annual system energy costs (ie. fuel and variable 0 & M) and LOLP. Required for input is a load forecast with and without load control, a capacity expansion plan for both forecasts, and generating unit data. Accurate simulation and subsequent energy costing of the generation system under any load control scheme, requires that detailed daily load representation and unit commitment scheduling be incorporated in the production simulation model. This requires a probabilistic production cost technique utilizing daily load profiles for typical weekday, T5) 2200 EXHIBIT 1-3 Zz 2100 Comparison Of Winter Capacity Requirements 2000 With And Without Load Control 1900 1800 1700 1600 1500 1400 1300 aad Heo CAPACITY REQUIRED 1980 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 weekend, and peak day load types for each month of the year to establish a unit priority start-up list and daily commitment schedule. It follows then that weekday, weekend and peak day load types have to be modified for load control and put in the production costing model. Finally two passes through the model are required, ie., a load control case and a no load control case. Comparing the results will indicate any energy cost savings as well as the impact on LOLP. Purchase power and wheeling cost savings can be realized depending on the magnitude of the controllable load, structure of the wholesale/ wheeling power rate and the demand charge built into the rate. The fact that wholesale/wheeling power rates are subject to periodic change cannot be overlooked. Therefore, to evaluate and assess the savings that may be expected from load control programs, it is important to understand the various factors that may affect the wholesale/wheeling power rates. These factors include: (1) the method by which the revenue requirement of the wholesale power supplier is established; (2) the billing determinants used to recover that revenue level; (3) the structure of the rate itself regarding capacity costs and energy costs; (4) the number, size and diversity of utilities served under that wholesale rate; (5) the timing of wholesale power rate increases relative to the initiation of the load control program; (6) the regulatory jurisdiction under which the load control program's wholesale power rate is established, if any; and (7) the general nature of the relationship between the power supplier and utility. 1. Revenue Requirements To obtain the pro rata share or proper revenue requirement associated with power supply, the causal relationship of power supply and costs must be examined. If, as a result of certain peak demands or reliability criteria, increased production and/or tranmission costs are incurred by a generation utility, these causal factors should be considered so that incremental costs are allocated to those customers responsible. Frequently, however, the method actually used to establish the revenue requirements for a wholesale/wheeling power rate is not totally consistent with the cost factors of the supplying utility. Be this as it may, if the rate is "cost-based", there should be some combination of demands and other allocation factors which are used to set the level of annual revenue requirements from wholesale/wheeling rates. The factors which determine this overall allocation must be considered in the load capacity strategy of the purchasing utility. Load control may not affect the capacity related revenue requirements of the supplying utility. However, such control will result in a reduction of overall revenue derived from the wholesale/wheeling of electricity and may prompt the supplier to adjust the rates in order to recover its sunk cost. In such case, the adjustment of wholesale/wheeling power rate may affect the amount of savings that a purchasing utility can expect from the load control program. If the rate adjustment is universally applied to all wholesale/ wheeling customers, a possible effect of load control programs is to shift a portion of the supplying utility's costs to its other customers not implementing load control. Here, one's perspective is important. If the purchasing utility's relative share of the supplying utility's total cost is small, certain constraints affecting revenue requirements such as timing, plant size and location, reliability, and other planning criteria may override the effect that the purchasing utility's load control program might otherwise have on planning and total costs. In such cases, wholesale/wheeling power costs to the purchasing utility may remain unaffected, and the long-term savings from load control program can be realized. The long term reduction of the purchaser's share of the supplier's revenue requirement can be assured by controlling load to reduce Gilbert /Commonwealth is capacity cost allocations. The allocation factors used to distribute capacity costs may not be the same as the demands used for billing purposes. For example, the billing determinate is set on the noncoincident peak of each delivery point, but capacity costs may be allocated on the single monthly coincident peak of the supplier's demand. There's no question that bills will be reduced over the long term by reducing billing requirements, however, the purchaser's share of the supplier's revenue requirement may not be correspondingly reduced. Therefore, to issue that the purchaser minimizes its long term costs, control will also have to be directed at capacity allocation factors used to establish the cost of service. Billing Determinants Normally, after revenue requirements have been determined, the next consideration is revenue recovery using a rate form geared to selected billing determinants. For the purchasing customer, these determinants are commonly in one of the following forms: monthly maximum demands at individual metering points, the coincident monthly maximum demands of all metering points of the purchasing utility, or even some combination of demands coincident with the supplying utility's peak demands. In addition, a ratchet form may be introduced to establish a minimum monthly demand at some percentage of the highest billing demand established in previous months. This ratchet may be as high as 100%. The interval of recorded demand, whether 15, 30, or 60 minutes, has little effect on load control strategies currently in use. Demand Charges and Billing Determinants Quite often in the structure of wholesale power rates, some portion of the total capacity costs are designed to be recovered in the energy charge. The greater the amount of capacity costs that are included in the capacity charge portion of the rate, the higher the $/kW and the greater is the savings that may be obtained from each kW controlled. In any case, that portion of total revenue requirements to be recovered through demand charges is divided by total demand billing determinants to establish the unit price per kW of demand. As discussed above, using load control to reduce the billing demands after the rate is established, will, of course, reduce the monthly wholesale/ wheeling power bill. If, as a result of load control, total class demands are less than the billing determinants used to establish unit price, a shortfall will result in meeting the supplying utility's revenue requirements. Consequently, although short term savings may accrue to the purchasing utility immplementing load control, such savings may be jeopardized in the next rate filing when the per-kW capacity costs are adjusted upward to reflect the decrease in billing determinants. This would generally be the case unless the impact of load control is insignificant with regard to a proportional reduction in the overall wholesale/ wheeling class revenue requirement. If the purchasing utility with load control is identified as a single customer class with an individual rate the situation indicated above will be even more pronounced. If load control strategy focuses only upon a reduction in billing units, and the demands and other factors impacting periodic determination or revenue requirements are not affected, savings will only result until the time when that individual rate is again brought under review, all other considerations remaining unchanged. With the revenue requirement unaffected and only the billing units reduced through load control, the per unit capacity charge will be increased and any further savings will be eliminated. Therefore, it is essential to direct control at factors which affect the allocation of revenue requirements to customer classes. 6. Impact of Ratchet Provision There are additional considerations regarding load control and billing demands. It may be assumed that in order to realize maximum savings when a ratchet is not in effect, demands in all months would have to be controlled (assuming potentially controllable loads exist in each month). However, when a ratchet provision is in effect, control might not be necessary in those months having an otherwise lower billing demand than the minimum billing demand based on the ratchet provision and established even after control is accomplished in peak month(s). Often the ratchet provision is seasonal, and the effect can only be determined after evaluating the specific rate. Metering Points, System Peak, and Distribution Peak To produce savings through control of specific demands requires that some means be available for anticipating when those demands would reach a "critical" level. This level would be set such that control will produce a savings. Total system load of the purchasing utility is generally, but not always, monitored; control decisions may have to be based on the coincident load of all metering points. In some cases the wholesale/wheeling power rate can only be achieved by controlling demand at the time of the supplying utility's peak, additional metering and cooperation between supplier and purchasing utility may be necessary. Frequency and Timing of Rate Adjustments As indicated previously, savings may be considerably reduced or even eliminated after a wholesale/wheeling rate is restructured. The timing of rate increases or rate reviews is therefore important in the short term perspective of the purchasing utility. Nation-wide, the frequency of rate filings and rate reviews has been increasing in recent years, and it is not uncommon to see Gilbert /Commonwealth I-i rate increases filed with the Federal Energy Regulatory Commission (FERC) every few years. D. Ancillary Benefits of Load Control l. Two-Way Control Systems Previous discussion has been devoted exclusively to load control and that in the context of one-way systems. It is inappropriate to compare one- and two-way systems without consideration of the additional benefits potentially afforded by a two-way control and communication device. State-of-the-art development of two-way systems presently provides capability with respect to at least the following functions in addition to direct load control: Remote Meter Reading Time-of-Day or Other Time Differentiated Metering Load Survey Capability. In addition to these customer related functions, the two-way communication links provided by systems of this type lend themselves to other system related functions such as: System Monitoring Dynamic Distribution Automation Fault Location Optimized Voltage and VAR Control Capacitor Bank Switching. Although these latter functions add an additional prespective in management's evaluation of alternative load control devices, such utilization is somewhat far afield from the direct emphasis of this course. It is appropriate, however, to consider potential future uses of a two-way control system when making such an evaluation even if only in an intangible manner. Such system ii 2. applications would permit a sharing of central facility costs which, particularly for a two-way system, impose a significant burden when measured only in terms of load control. For those customer related functions initially indicated, a prerequisite management decision or regulatory mandate would probably serve as the impetus to embark on any or all of the designated programs. The attractiveness of a two-way system is obviously enhanced by, for example, an actual or anticipated decision or order to adopt time-of-day rates, thus necessitating a multi-part metering capability. Obviously, if that requirement can be accomplished in conjunction with a system which also provides a means for direct load control, a potential mutual advantage exists. Benefit of Ancillary Functions A Benefit Cost analysis for a two-way system would necessarily include consideration of any of those additional functions presently necessitated or realistically anticipated. Two-way load control systems frequently have the capacity not only to read meters remotely, but to do so in a time structured mode separately identifying consumption in pre-designated peak, intermediate and off-peak periods. This capability permits the implementation of time differentiated rates, and the benefits could therefore be equated to the load management benefits attributable to time-of-day or other time structured rates. However, in the absence of full scale implementation or a comprehensive test, the degree of price elasticity and therefore the load management impact of time-of-use pricing is generally unknown. Given, however, a management decision or other mandate to implement time structured rates, the ancillary benefit accruing to a two-way system is equal, at least, to the cost of otherwise accomplishing multi-part metering. I-12 Similarly, for each function indicated and for any other function envisioned, an alternate means of accomplishment probably exists. Meters are presently being read on a regular basis by Meter Readers. Two or three dial conventional meters are on the market and would serve as a basis for evaluating time differential metering capability. Cartridge type load survey meters provide a means to measure on-site customer loads on a continuous basis. The least cost alternative means of accomplishing the same function may reasonably be assumed as the benefit of a two-way communication system insofar as that function is concerned. Care must be taken, however, to consider all costs of alternative means. Although no such direct development of costs is made in this Report, the following listing indicates the nature of items to be considered in measuring typical alternative costs for each of the ancillary functions indicated above: Conventional Meter Reading Costs Personnel Costs Meter Reader wages Supervisory salaries Fringes and Benefits Overhead costs Transportation Costs Use of company vehicles Reimbursement for use of personal vehicles Per diem allowances Miscellaneous Costs Office space and supplies Postcards and forms for "not-at-homes" Property damage and other liability insurance Postage Personal injury costs I-13 3. Other Labor-Related Functions Special field readings Off/on readings at customer's request Billing costs for incorrect reads Personnel time devoted to answering complaints and inquiries occasioned by estimated bills. Time Differentiated Metering (Conventional) Two or three dial meter costs(1) Operation and maintenance expense Incremental meter reading costs Load Survey Capability Conventional load survey meter costs Spare cassettes Personnel costs for tape changeout Transportation costs for tape changeout Maintenance costs In each case, benefits based on recognition of the above alternative costs would be in addition to that attributed to the two way system's direct load control capability. Evaluation of Ancillary Functions Certain of the ancillary functions indicated above may also be accomplished as extensions of the capability of at least some of the one way load control systems. For example, capacitor switching could be handled with radio control as could certain other Distribution Automation functions. Furthermore, caution should be exercised in the process of applying two-way high frequency power line carrier systems, to distribution control and surveillance functions. The use of the frequently coined term "distribution automation" has led to the common interpretation that two-way systems of this type are equivalent to or may be used Gilbert /Commonwealth I-14 for purposes similar to Supervisory Control and Data Acquisition Systems (SCADA) as they are presently available. In developing cost benefit figures, care must be exercised to define the actual practical uses of power line carrier facilities and to differentiate between these uses and the generally accepted uses of actual SCADA equipment. The basic difference in the two types of equipment is one of intelligence brought about by the achievable transmission speed of the available communication channel. This ranges from slow, as used for the power line carrier (30 bits per second) to relatively fast for SCADA systems utilizing leased telephone lines or microwave channels. Due to the requirements of message protocol, it is usual that such data gathering systems are deisgned to respond on demand only-such that remote data acquisition device with a message to send must await an interrogation command from central control. It is then apparent that the time resolution of data gathered is strictly a function of communication channel bandwidth (transmission speed), and the number of points scanned. These two factors control scanning speed or in other words, the number of interrogations of a single point in unit time. If it is accepted that the principal purpose of the two-way power line carrier is to control customer appliances and remotely read billing meters, then it must be apparent that its use for any purpose other than elementary system monitoring will either severely restrict the primary purpose or, alternatively result in extremely slow scanning speeds for interrogation. Time is not available for any other conclusion with the average message times. This in effect limits the usefulness of distribution automation functions to such slow speed actions as tap change control (possibly for system brownouts), capacitor switching, loss of voltage detection (fault identification) and other similar non-repetitive functions. Repetitive functions such as substation metering, switching, alarms and similar data collection which, to Gilbert /Commonwealth T+13 be useful, requires rapid and constant updating for presentation as a system mimic diagram is more properly the prerogative of the high speed, wide bandwidth data channels. For evaluation purposes, the individual benefits of the multiple functions of a two way system would be directly additive. From a cost standpoint, care must be taken to include any optional costs associated with the implementation of ancillary functions. With respect to the basic load control function, the benefit should be based not on potential future capacity cost savings but on the least cost alternative means of accomplishing load control as determined from application of the Benefit/Cost methodology. This concept is incorporated in the ancillary function evaluation procedure diagrammed in Exhibit I-4. 1-16 EXHIBIT 1-4 2-WAY LOAD CONTROL SYSTEM -— ANCILLARY FUNCTION EVALUATION LEAST COST TECHNICALLY FEASIBLE LOAD CONTROL SYSTEM THAT CAN ACCOMMODATE NECESSARY CONTROL STRATEGIES LOAD CONTROL IS LOAD CONTROL ITSELF FEASIBLE? (A Positive Net Benefit) COST OF A 2-WAY SYSTEM ANCILLARY FUNCTION "A" PROVIDES A QUANTIFIABLE SAVINGS RELATIVE TO PRESENT METHOD OF OPERATION ANCILLARY FUNCTION "Cc" IS REQUIRED COST OF SOME LEAST COST METHOD OF PERFORMING ANCILLARY FUNCTION "A" COST OF SOME LEAST COST METHOD OF PERFORMING ANCILLARY FUNCTION "C" IS TWO WAY COMMUNICATION SYSTEM LEAST COST ALTERNATIVE TO GET TOTAL SAVINGS FROM TWO WAY: Any Additional Differential Savings From Cost Two Other Ancillary Way is Less + Function avail. Than Sum From Two Way But Not Req'd. By That Utility (2) NOTES: (1) Im decision process above, a probability can be assigned to an ancillary function being required, if {t is considered possible (probability x cost). Otherwise, it should be considered a probability of zero for being required. (2) The benefits should be quantified as those accrued from having that ancillary function, and not any comparison with the cost of other equipment, etc, to perform that function. USE ONE WAY PLUS SEPARATE EQUIPMENT FOR ANY ANCILLARY FUNCTIONS WHICH ARE REQUIRED SECTION IIL CONTROLLABLE LOADS In order to estimate the load control potential; it is necessary to determine both the number of customers with controllable load and the associated diversified load characteristics of the loads controlled. The more knowledge available to the utility of the usage pattern and load characteristics of end-use equipment, the greater the confidence level that can be given to expected kW reductions that result from control. The highest confidence can be placed on in-house load research data. The next highest confidence can be placed on load research data from a nearby utility with similar customers. When in-house or neighboring utility data is not available, published data from industry sources is a suitable alternative. General criteria for any controllable load is that it can take advantage of some type of storage medium or be reschedulable to minimize customer inconvenience. For example water heaters use a storage tank to store heat; air conditioners can use the building as a storage medium. Storage capability is especially important when controlling residential loads. Commercial and industrial loads may be amenable to rescheduling and shifting of usage patterns. A. Range of Controllable Loads There are controllable loads in each of the major customer classes, ie, residential, commercial, industrial and agri-industrial. The residential class has been the primary source of controllable load. Agri-industry has also been a source of controllable load, of course it's only available in rural areas. Commercial and industrial loads are less likely to be controllable because control may adversely impact productivity. -1 1. Residential Appliances In general, temperature-sensitive residential appliances dictate the time and intensity of the peak periods of most municipal electric utilities because of the large number of such appliances and the low diversity of usage between appliances at times of temperature extremes. Significant results have been obtained by utilities effecting direct control of selected temperature-sensitive appliances of residential customers. Specifically, the existence of residential water heaters, air conditioners and electric space heating loads (singly or in combination) in the form of a deferrable kW demand has enabled many utilities to pursue full implementation plans of load control. (1) Some other household appliances may also have the end-use characteristics that would suggest load control application. Several concerns, however, may restrict the adaptability of highly visible appliances such as washers, dryers, or freezers to an acceptable control logic. Some examples of such concerns are: a. The requirements of a working couple for a fixed time of use. b. The high diversity in the collective use of those appliances by customers in the distribution system yields a relatively low deferrable kW demand per unit during potential control periods. c. Electrical wiring cost per appliance imposed on the utility. d. Legal implications facing the utility concerning liability in the event of appliance malfunction. To obtain the best possible result of load control, a survey of residential customers in the service area should be conducted to Gilbert /Commonwealth ii-2 determine appliance saturations, customer density on the distribution circuits, and customer acceptance to utility control. For many distribution utilities, a current estimate of these customer parameters is not readily available. A mailed survey questionnaire is an expedient and effective method for gathering the needed information. Exhibit II-1 is an example of a residential appliance survey form. The following paragraphs characterize controllable residential appliances and provide estimates of controllable load for each. Is Water Heater The storage characteristics of water heaters inherent in their design make control by the utility relatively easy to accomplish with little, if any, inconvenience to the customer. (2) For most winter peaking utilities and some summer peaking utilities, control of an electric water heater can represent a significant reduction in load. The quantification of kW of deferrable demand per water heater (deferrable at times of the utility's peak periods, for example) is dependent on several factors: 1. Capacity of the appliance (number of gallons) 2. Type and size of heating elements 3. Season of application 4. Climatic characteristics of the service area 5. Appliance load profile 6. Saturation of the appliance. Gilbert /Commonwealth II-3 EXHIBIT I1-1 SC3eus RESIDENTIAL APPLIANCE SURVEY wkeaKe Ke KR KR KR KR KKK KKK KK KK KKK KKK KK KKK KK KK KKK KK KKK KKK KK Resident Description: Please check the one which best describes your home: Single Family wR Mobile Home / / Apartment T/ Farm Home [7 Business and Residence Combined / / Other [7 Specify Number of people living in the home: Adults Q » Children under 18 eke RR KR KEKE KKK KEK KK KE KK KR KKK KK KEK KK KR KK KK KR KKK KEKE KKK KKK ELECTRIC APPLIANCE SECTION: Please check the box indicating each ELECTRICAL appliance or equipment found in your home. ie Electric Water Heater; tank size 40 gallons Electric Central Air Conditioning; ry ton capacity Electric Window Air Conditioner; number of each; size Electric Clothes Dryer QeOo’ Electric Space Heating: [7 Electric Forced Air Furnace, size [7 Electric Heat Pump; tons [7 Other Electric Heat; Specify Kae Ke KR KR KR KEKE KKK KK KK KEK KK KKK KK KKK KK KK KKK KEKE KK KKK KKK NON-ELECTRIC APPLIANCE SECTION: Please check the boxes in this section indicating each NON-ELECTRIC appliance or equipment found in your home. // Gas Water Heater /7 Other NON-ELECTRIC water heater, Specify fi] Gas Space Heating // Other NON-ELECTRIC Space Heating, Specify In the absence of actual test data, the following minimums may be applied in establishing a conservative estimate of controllable load for water heaters. Winter - 0.80 kW Summer a 0.60 kW Test data in the form of an hourly load profile is preferable to the use of these minimums. Typical water heater load profiles are included under the heading "Characteristics of Controllable Loads," which follows. Generally water heaters with less than a 30 gallon storage tank should not be controlled because they are not large enough to satisfy demand for hot water during control periods. During control period water heaters are turned off continuously as opposed to cycled off. Control periods of up to eight hours can be imposed on water heaters with greater than 30 gallon tanks without affecting the customer. Window Air Conditioners Window air conditioning units tend to be relatively small in size, more portable, and possibly greater in diversity during control periods when compared to central air conditioning units. In addition, electrical wiring problems are possible in cases where a window unit is being supplied power from an already heavily loaded house circuit. In the few tests of window air conditioner control, it has become clear that control can be easily defeated by the customer. It is obvious to the customer when his unit is being cntrolled and consequently complaints have been high. At this time, window units are too difficult to control effectively and should not be considered in estimates of controllable load. Gilbert /Commonwealth LI-3 Central Air Conditioning For summer peaking systems, the influence of central air conditioning during peak load hours makes it an obvious choice to consider for direct control. The major factors that may affect the potential load reduction from the control of central air conditioning units are: he Individual maximum kW demand per unit (or connected load) ym Climatic characteristics of the service area 3. Appliance load profile 4. Saturation of the appliance Se Length and frequency of the control periods. The findings of recent load research tests and direct load control programs indicate that a diversified demand per residential central air conditioner of over 4 kW can be expected for summer peaking conditions. This demand essentially represents the estimated average connected load. However, in order to minimize discomfort for the customer, a shared control cycle which utilizes the volume of the house as a cooling storage medium should be used. For example, if one-fourth of the central air units were controlled at any given time, the effective load reduction of a 4 kW average demand per central air conditioning unit would be 1 kW. In current load control programs the low voltage thermostat circuit is controlled to inhibit only the compressor; this Gilbert /Commonwealth II-6 4. allows the inside fan motor to continuously circulate air and thereby contribute to customer acceptance. One kW of demand reduction can be expected from central air conditioners. The "Characteristics of Controllable Load" section includes typical load profiles for central air conditioners. Space Heating Existing space heating has gained attention of winter peaking utilities seeking controllable load. Clearly only central heating systems are amenable to control. Baseboard heating or any "zoned" heating with thermostats distributed throughout the building would required significant rewiring to implement control. Therefore, control of existing space heating should be limited to central forced air type units. A recent study indicated that as much as 7 kW per electrically heated home could be deferred by controlling the existing central heating system during peak winter hours. Temperature drops inside the home average 1.75° F per hour of continuous off-time (no cycling). These results indicate that a control strategy, similar to the shared cycling scheme which has been quite successful with central air conditioners, will be effective in controlling central space heaters. One kW of demand reduction is a conservative estimate of what can be expected from control of central space heaters. The "Characteristics of Controllable Load" section contains typical load profiles for central space heaters. ti*7 The potential of controlling space heating load can be enhanced by the use of non-conventional types of heating systems such as the following two: Storage type space heating - This type of heating has been popular in Europe for many years. After an 8 to 12 hour charge (on-time) these system can normally supply enough heat for the remainder of the day. The on time is short enough such that these systems can be supplied completely off-peak, usually at night. One significant drawback to this charging cycle has become apparent in European domestic applications of such heating systems. The discharge of stored heat occurs in inverse proportion to its demand. The maximum heat is available in the hours immediately following completion of the charging cycle. However, the demand for heat throughout the morning hours is somewhat reduced when members of the household are absent because of routine daily activities. In the early evening hours as temperatures drop and households require more heat, the minimum is available from the storage system. These factors may limit the application of such storage systems in severe winter climates. There is currently limited use of storage heating in the U.S., and it is unlikely that the great majority of utility customers would be willing to make an investment in such a system until there are reasonable economic incentives coupled with a thorough consumer education program. Several northern utilities currently are offering incentive rates to promote storage heating. Perhaps in the next several years a significant number of storage space heaters will be available for centralized control in certain areas of the country. Gilbert /Commonwealth II-8 Dual-Fuel Systems - Specially modified heating systems have been developed to run on electricity during the utility's off-peak periods and then switch to an alternate fuel source during peak periods, thus moving the heating usage of electricity completely off-peak. These dual-fuel heating systems are becoming increasingly popular in some areas. A minimum investment is required for the conversion and fuel expenses can be significantly reduced.(7) Where low off-peak rates are offered, such a system could have a payback of as little as two years. (8) In summary, due to relationship of temperature to peak periods, the high kW of connected load at individual residences, of residential space heating is potentially a prime candidate for centralized load control by winter peaking utilities. In the short term, cycling of existing heating systems will provide a means of deferring load to off-peak periods. In the long term, storage heat systems and dual-fuel systems offer the highest potential for load deferral for winter peaking utilities. 2. Agri-Industry The most successful application of utility control of agricultural loads has been in the control of irrigation pumps. Certain types of irrigation systems (particularly the center-pivot and other sprinkler systems) incorporate watering techniques that, by design, would permit controlled operation. In addition, depending on the acceptable level of soil moisture depletion associated with various soil types and the crops grown, some irrigation systems may tolerate part-time operation. Significant progress has been made in refining the technology of applying irrigation control and in gaining acceptance by irrigators.(9) pee eee Gilbert /Commonwealth TeT9 De In Nebraska and northwest Kansas, several years of effort by public power districts, cooperative utilities, the Department of Agriculture, and local agricultural engineers have fostered irrigation control strategies for part-time operation, corresponding to the time of the peak requirements of the utility. Reports on the progress of these efforts indicate that, depending on soil conditions or crop requirements, not all irrigation systems will permit a part-time operation.(10) Flood watering techniques for example, may offer a potential for scheduled operation on a calendar day basis that would not allow for interruption of the flooding cycle. Quantification of the load reduction associated with the deferment of irrigation loads during peak periods of the utility requires substantial analyses. Some of the factors which should be considered in such an analysis include types of irrigation system, total irrigation horsepower, underground water supplies, crops, soils, rainfall, frequency and duration of peak loads requiring control, and customer acceptance. It is not necessarily true that every utility serving irrigation loads, even sprinkler systems, will find a sufficient amount of deferrable load from irrigation at the time of the peaks to offset the cost of instituting control. Since the peak water use of all crops does not occur at the same time, there is inherently a certain amount of diversity of demand associated with irrigation load. The amount of this diversity for a given utility will depend on the number of electrically powered irrigation pumps used for the various crops in its service area and the percentage of the utility's total load represented by such irrigation pumps. Some typical crop water use curves are provided in Exhibit II-2. Certain types of crops may have critical stages of growth. The possible reductions in yield caused by the inadequate supply of water during the critical growing period tend to limit the potential for load control. Gilbert /Commonwealth II-10 INCHES OF WATER EXHIBIT 11-2 APPROXIMATE AVERAGE WATER USE OF MAJOR CROPS IRRIGATED 0.4 0.3 WHEAT / 02 L / \ PEANUTS \e ALFALFA-PASTURE x. — x SORGHUM a NOV DEC Some knowledge of soil types is also an important factor in determining the load control potential. Control can be exercised more often in soils which can store moisture, particularly during periods of little rainfall. Clay and loam soils fall in this category, while sandy soils store much less moisture. The frequency and duration of load control on sandy soils is therefore more limited. The potential for load control also depends on the type of irrigation system. Center pivot systems offer the least problems to load control since such systems automatically resume irrigation following control. With a side roll system, the control cycle will not affect the total water applied, but the time required to irrigate will be increased. If gravity or surface systems are controlled during an irrigation set, excessive watering might occur in the upper field. Therefore, the control strategy for the gravity system must be limited to regularly scheduled intervals. The effects of load control can be offset by installing automatic restarting equipment to use the allotted time during peak water use periods. The specific load curves of irrigation loads should be examined relative to the total non-generating utility's load profiles for those periods when load control would likely be implemented. The most convenient method of obtaining such load curves would be from circuit feeders or substation readings. In addition, the load control program should probably be limited to the larger irrigation loads, in order to achieve the maximum benefit per control point. As a general rule, one horsepower of irrigation pumping could be equated to one kW of load at the control point because of electromechanical inefficiencies and line loss. Gilbert /Commonwealth II-12 The following points summarize the factors affecting the potential for control of irrigation load: Frequency and duration of control periods relative to peak irrigation loads. Irrigation system types. Soils and their moisture holding capability. Peak water use periods of crops. Amount of rainfall. Size of individual irrigation pumps. Ze Customer acceptance and understanding. Commercial and Other Industrial Loads Most of the utility direct load control has, so far, focused on selected residential loads. For industries, local logic devices have been utilized to balance equipment loadings for the purpose of lowering the maximum billing demands. Direct utility control of commercial and industrial end-use loads has not yet been implemented on a large scale. Although industrial customers in general are interested in exploring the possibility of direct utility control, how successful the application of control technology will be in industry remains to be seen. It is apparent that non-production loads can be controlled to the benefit of both the utility and industry without affecting production. On the other hand, if the industrial's power bill is only a small portion of total product cost, or if plant efficiency is reduced by load control, or if labor force Tr-ka restrictions are imposed because of load control, it is not likely that a load control program will be well received. Before the load control potential can be quantified, the utility must work closely with the industrial customer to analyze the load characteristics of equipment and processes and the effect of those loads on the utility's peaking requirements, and target potentially controllable loads for further study. As in the case of residential customers, economic (rate) incentives will likely be necessary to induce industries to accept direct utility control. Commercial customers are perhaps the customer group most sensitive to load control application. As in industry, a few major hotel chains and other types of commercial customers have installed local logic devices for load leveling to reduce billing demands. But a majority of the utility customers in this sector are extremely conscious of the comfort requirements of their own customers (from shopping centers and malls to office buildings and hospitals). Reducing costs and improving operating efficiencies are considered important only to the extent that they do not interfere with customer convenience or service standards. Other specific problem areas for load control in the commercial sector include the following: a. Leased space in commercial buildings where the wiring does not permit practical selective control, or master metering prevents a required rate incentive. b. Mobile home communities served as commercial customers, because of the nature of the load (where there is a master meter and the individual mobile home is not billed by the utility). However, since the largest loads of the commercial customers are the temperature sensitive appliances, potential does exist for control. As with industry, the utility will need to work closely with the commercial customer to inventory and analyze the equipment and appliances, and develop an acceptable interruption procedure. Characteristics of Controllable Loads In order to estimate the amount of deferrable load that can be expected from a system-wide application of load control, a knowledge of the load characteristics for both the targeted load for control and the system is necessary. The principle differences between the load pattern at a specific controlled customer and the load pattern at the supply levels involve two variables: (1) the natural diversity existing between individual customers which reflects the differences in time of use for the same appliance or load, and (2) system losses occurring during control periods at the various voltage levels in the distribution system. The nature of the average diversified demand of the target loads during the times of the system peak or other control periods, as well as the voltage level of service on the electric system, are major factors in determining the potential demand deferrable. Therefore, to assess the potential effect of direct utility load control and to determine the control strategy, it is first necessary to develop the utility's system daily load profiles and the corresponding diversified demand curves of the target appliances for the selected control periods. Ideally, the utility should develop a set of these load curves strictly applicable to its own system, service area, and customers. This Section provides some "typical" load profiles of appliances which have been controlled, and develops a general relationship for quantifying the maximum controllable load. Control strategy and limitations on the maximum controllable load are analyzed in Section III. Gilbert /Commonwealth LETS Load Profiles The amount of the controllable load associated with a particular appliance depends on the number of the appliances connected to the system, its usage pattern when considered as a group, and the maximum kW rating or connected load. The last two factors will determine the "diversified demand" of the appliance at any given point in time. On an aggregate basis, the diversified demand curve reflects the load characteristics of the appliance to be controlled. Two types of existing residential appliances were considered controllable in the Case Studies for this manual, they are, water heaters and central air conditioners. Separate diversified demand curves of these appliances are developed for winter peaking and summer peaking utilities. All load curves were derived from previously published utility test data, and they represent typical data of appliance loads imposed on utility systems. Water Heaters The diversified demand curve of water heaters depends on a number of factors which were discussed in the preceding section. A preliminary comparison of Exhibits II-3, II-4, and II-5 illustrate the time varying nature of the load due to these factors. The season and source of supply determine incoming water temperature. Thus more energy for water heaters is normally required in the winter. Washing and dining habits of the service area customers influence the daily load pattern. The design characteristics must also be considered. The older the water heater the lower the wattage of the heating elements. Before 1963 the NEMA standard for water heaters dictated that bottom heating elements could not exceed 20 watts/gallon and that top heating elements could not exceed 30 watts/gallon. Subsequent standards have increased the wattage to 4500 watts per element for a 40 gallon tank. The Case Gilbert /Commonwealth 31h Studies assume a standard 40 gallon capacity water heater with two interlocked 4500W heating elements (only one element is energized at any one time). Exhibit II-3 illustrates some winter daily load profiles for such a water heater. Note that the diversified demand can be as low as 0.03 kW or as high as 1.24 kW depending on the time of the day. The three curves illustrated show a familiar double peaking shape with the peaks occurring at mid-day and in the early evening. Note that one curve, Pioneer Rural Cooperative, shows the peak at noon while the others peak in the evening. Therefore, this exhibit also points out that difference in water heater demands do exist between utilities. For example, cooperative utilities have historically been less restrictive on heater sizing requirements; and generally the noon meal of rural residents is more often consumed at home than those living in a commercial or industrial environment. Exhibit II-4 illustrates some summer load profiles for water heaters. Note that for two of the three utilities shown, the peaks occur in the later morning hours. The diversified demand is lower in these curves compared to the winter curves, one principal reason being the higher incoming water temperature. In Exhibit II-4, the summer diversified demand ranges from 0.09 kW to 1.1 kW. Note how dissimilar the three curves are from each other compared to the winter curves. To further demonstrate the influence of season on water heater loads, Exhibit II-5 shows the diversified demand of water heaters for three hourly periods often being peak hours: 6 to 7 PM, 3 to 4 PM, 11 AM to noon, during the course of a year. This data is taken from a 1973 Western Massachusetts report. One of the most critical characteristics necessary to analyze water heater control is the "payback". Payback consists of the amount of diversified load that is seen by the system when the inhibits are removed from controlled loads. Test data indicates l= 17 DIVERSIFIED DEMAND PER WATER HEATER (KW) EXHIBIT 11-3 WATER HEATER DIVERSIFIED DEMANDS WINTER CURVES (WEEKDAY ) LEGEND -<——--— DETROIT EDISON, 1969 WESTERN MASS., 1973 PIONEER RURAL, 1973 COOP. ee ee eee) 7 9 10 11 «12 DIVERSIFIED DEMAND PER WATER HEATER (KW) EXHIBIT 11-4 WATER HEATER DIVERSIFIED DEMANDS TYPICAL SUMMER CURVES (WEEKDAY ) LEGEND CONSUMERS PWR, 1974 ——-—-—— CONSUMERS PWR, 1961 ei *°* DETROIT EDISON, 1966 1.0 UZ a2 1) 4) Pe 16) 24 Ol) bon) On taki LN) 2 Se a5) PG) 7a ce) ior On) Urania WEEKDAY DIVERSIFIED DEMAND PER WATER HEATER - KW EXHIBIT 11-5 THE TIME VARYING NATURE OF DIVERSIFIED DEMAND OEC JAN FEB MAR APR MAY JUN JUL AUG SEP oct NOV DEC i Ir T T THAR T it T T MIATA eit Pe = 6-7 PM 0.9 + 0.7 - Wie 0.9 3-4 PM ONT linn O25) eS al et 11AM-NOON O49) ig OT Far 0.5 1 1 ! 1 ! ! ! ! 1 A csepeneinionins vec JAN FEB WAR APR way JUN JUL Aue SEP oct Nov oEc that in the case of water heaters, the restored diversified demand varies rather directly with the length of the inhibit.(2) That is, the longer the inhibit, the higher the restore demand. Exhibit II-6 taken from Detroit Edison studies provides a graphic illustration. These studies show that if the inhibit existed for as much as four hours, the restored diversified demand was seen to be 4.1 times the diversified demand at the time of inhibit. The curves also show how the payback decays back to normal diversified demand rather quickly. These payback curves will be utilized in the Case Studies. The payback phenomenon requires that the controlled water heaters be divided into separate control groups. This allows the total water heater load to be restored to the system in staggered intervals, avoiding a secondary peak greater than the control target. Central Air Conditioners Air conditioners are subjects of load control in the summer season. Diversified demand curves of central air conditioners are shown in Exhibits II-7 and II-8. As shown in Exhibit II-7, the diversified demand of air conditioners can range from approximately 1.2 kW to 4.1 kW. Exhibit II-8 illustrates that the peak can occur over a wide range in the afternoon hours depending on temperature. Exhibit II-9 illustrates the high degree of correlation that exists between temperature and air conditioner load. It also shows the large proportion that air conditioning represents of the total service load in the summer. Exhibit's II-10 and II-11l provide a typical set of results (one residence) from the central air conditioning load control test performed by Arkansas Power and Light in the Little Rock area Gilbert /Commonwealth a EXHIBIT 11-6 WATER HEATER RESTORE CURVES ~ o ~ = o MULTIPLE OF INITIAL DEMAND HOURS OFF DIVERSIFIED DEMAND -— A/C (KW) “ 4.0 3.0 2.0 = 1.0 EXHIBIT I 1-7 CENTRAL AIR CONDITIONER DIVERSIFIED DEMAND TYPICAL SUMMER CURVE ha ee a a a ee SOURCE: GEORGIA POWER COMPANY, AIR CONDITIONING DEMAND CONTROL (ACDC) 1 23°4 5 6 7 AM TEST, JUNE—AUGUST 1975 8 9 We The 42 1 2 3 4 5 PERCENT OF DAILY PEAK 100 90 80 70 a o w ° > Ss 30 20 10 EXHIBIT 11-8 CENTRAL AIR CONDITIONER PEAK DAY LOAD CURVES (NORMALIZIED) “ LEGEND MK SAN DIEGO G&E ‘ . \ ’ — ——FREsNO —— + <= SOUTHERN CAL.EDISON at 2-3 4° 5. BF. © -9°E VU 1254-2) 8. 4S a Te ER. at AM PM SOURCE: STAFF REPORT ON LOAD MANAGEMENT STANDARDS, CALIFORNIA ENERGY COMMISSION, JUNE 1978, P.48 Mx — YSWOLSND Y3d GNVW3G 2b te ere 80 70 60 SOURCE: MONDAY AEIC DATA 1964-1965 TUESDAY WEEK OF MAXIMUM A C USE 1960 —- SOUTHERN MICHIGAN WEDNESDAY THURSDAY FRIDAY SATURDAY TOTAL SERVICE CENTRAL AIR CONDITIONING SUNDAY 90 80 70 60 do ~ JYNLVYIdW3L YOOALNO S3AUND JYNLWYAdWAL “SA ONVW30 YANOILIGNOD UYlV 6-11 LIGtHx3 EXHIBIT I 1-10 CENTRAL AIR CONDITIONER LOAD CONTROL TEST - PAYBACK PERIOD ARKANSAS POWER & LIGHT LITTLE ROCK AIR FORCE BASE, SEPT. 2, 1975 RETURN AIR TEMPERATURE 60° 70° 80° 90° 2AM 12 AM 10 PM PAYBACK PERIOD 8PM 6PM 4PM A/C’S INHIBITED TWICE/HOUR I i NOON 10 AM 8 AM 4° TO 9° RISE SOURCE, LOAD MANAGEMENT BY RADIO CONTROL, J.S. HOLTZINGER, APRIL 1976 (FIG.23) 4AM 2AM MIDNITE 10 PM 8 PM 6 PM 4PM 2PM NOON QQ ——————————————— SOURCE: LOAD MANAGEMENT BY RADIO CONTROL, J.S. HOLTZINGER EXHIBIT I 1-11 CENTRAL AIR CONDITIONER LOAD CONTROL TEST -— PAYBACK PERIOD AUGUST 13, 1975 ARKANSAS POWER & LIGHT RETURN AIR TEMPERATURE 60° PROJECTED UNCONTROLLED TEMPERATURE 5 PM MOTOROLA, APRIL 1976, FIG.20 2° TO 4° RISE PAYBACK PERIOD AYC'S SWITCHED OFF TWICE*HOUR in 1975. The exhibits are presented to show the effects of load control on the payback period. In Exhibit II-ll, the air conditioner was controlled from 1 p.m. to 5 p.m. The unit was switched off twice per hour from 5 to 9 minutes at each interval. Results showed that interrupting 22% of the air conditioners in the test area reduced circuit load by 5 to 10%. Exhibit LII-11 also shows that in one residence, the temperature rise was over 4° and payback lasted 5 hours. In Exhibit II-10 the inhibit interval was increased to 9 to 13 minutes (twice per hour). The temperature rise varied from 4° to 9° and the payback period increased to over 6 hours. The Case Studies rely heavily on this data for air conditioner payback assumptions. Space Heating The load characteristics of space heating are not as easily described as water heating and air conditioning. These latter two are more homogeneous. The various means of residential heating present different load and energy storage qualities, all of which affect load control. A home with electric baseboard heating exhibits a different load curve from one with an electric furnace with forced hot air. The European experience is dramatically different from the U.S. in their approach to home heating and load control. In Europe load control came before electric space heating became popular. In the U.S., the reverse was true. As a result European residences and businesses use the building's mass for heat storage in addition to normal insulating techniques. This allows for extended inhibit times even in cold climates. In the U.S., the average electric heating system is not designed to store heat. Exhibit III-12 illustrates the daily load curves of space heaters in four different areas of the country. The profiles show that Gilbert /Commonwealth II-28 PERCENT OF DAILY PEAK (DIVERSIFIED DEMAND) EXHIBIT 11-12 SPACE HEATER PEAK DAY LOAD CURVE (NORMALIZED) PEAK (NOT AVAILABLE) 100 7h = a . PEAK = 8.2 ida /: . ¢ 4a oF ae 90 win 7 vis “ : ¢ . oJ — = : ™N =_ : 80 f : = / PEAK = 4.5KW 70 60 + 50 |. 40 30 ——— SAN DIEGO (SOURCE: STAFF REPORT ON LOAD MANAGEMENT STANDARDS, CALIFORNIA ENERGY COMMISSION, JUNE 1978, P.48) — — — SOUTHERN ALABAMA 1-5-70 (CHART A-68) AEIC, 1972~1973 BBE ieee . NEW HAMPSHIRE, WINTER 61-62 7 (CHART CH-5 AEIC, 1961-1962) BALTIMORE, WINTER 61-62 (CHART A-7, AEIC 1963—1964) 12°12 3 4 5 6 7 8 9 W WW 12 1°23 4 5 6 7 8 9 0 1 12 space heating load has two peaks, one for a short interval in the early morning hours and for an extensive period in the early and late evening hours. One study in California, (12) states that space heater cycling would be used no more than 10 days a year. Space heaters were shown to have a lower coincidence factor at the system peak than air conditioners because of oversizing and the winter peak being less temperature sensitive than the summer peak in California. Of course caution should be exercised when extrapolating these results to other areas of the country. One report concluded that space heaters could be turned off for longer time intervals than air conditioners without affecting customer comfort.(12) this is somewhat contradicted in a study performed at Buckeye Power in 1975 where their report stated that they expected more favorable consumer acceptance of water heating control than control of electric heat.(1) Another study, by Potomac Edison, (5) referred to previously, demonstrated significant load deferments per customer (up to 10 kW). The test did provide interesting "payback" data. It took about 1.5 hours of continuous heating to bring temperatures back to normal after 4 hours continuous of control. Diversified demand was 50% higher than normal during the payback period. ai Current Estimates Potentially Controllable Load To estimate the total deferrable demand in kW, first identify each of the appliance types that are to be controlled. For each appliance, the deferrable load will depend on the following factors: 1. Total number of appliances. 2. Customer acceptance rate, which is a measure of the percentage of customers with the appliance who can be expected to participate in the load control program. eee ee 11-30 3. Load Control Equipment Success Rate. 4. The diversified demand of the appliance load coincident with the time of the system peak (or during other control periods). The above factors will determine the reduction in load at the customer level. To estimate the load reduction at the supply level, an additional factor should be taken into account, namely, the system loss factor. To illustrate the procedure of quantifying the effect of controlling water heaters or any other appliance, the value of the factors identified above is assumed as: a. Number of customers with water heaters 5,601 b. Customer acceptance rate 75% c. Diversified Demand at the Control -8 kW (Winter) Period -6 kW (Summer ) d. Load Control Equipment Success Rate 98% Based on the above, the potential load reduction at the customer level can be determined by: axbxcxd Therefore, during the winter period, the potentially controllable load is: 5,601 x .75 x .8 kW x .98 = 3,293 kW To determine the controllable load at the reference level of generation or purchased power delivery point, the loss factor has Gilbert /Commonwealth 11-31 to be taken into account. The potentially controllable load can be estimated by: a x b xc xd x Loss Factor Assuming the capacity loss of the system is 9%, then the loss factor is 1/.91 or 1.0989. Therefore, during the winter period, the potentially controllable load at the point of delivery is: 5,601 x .75 x .8 kW x 1.0989 = 3,619 kW Substituting the lower summer period diversified demand for that of the winter period, the potentially controllable load becomes: 5,601 x .75 x .6 kW x .98 x 1.0989 = 2,714 kW Projection of Controllable Load Estimates Estimates of controllable load must be projected through the useful like of load control hardware to facilitate matching of benefit and cost streams. The useful life or project planning horizon ranges from 15-20 years. The method of projecting controllable load should be consistent with the method of forecasting system demand. For example, if system demand is projected to grow at a constant rate controllable load should be projected on a consistent basis. Basic methods for projecting controllable load are: l. Constant percent growth rate 2. Constant percent of peak 3. Appliance saturation applied to customer projections. Gilbert /Commonwealth II-32 Constant percent growth rate - Under this method the same percent growth rate is applied to controllable load as is applied to system demand. This method implies that controllable load is added in the same proportion as total system load. This is perfectly acceptable if the system is made up of primarily residential customers. If large additions of load can be identified as other than residential, they should be back out of the forecast and the resultant growth rate applied to controllable load. For example, if a factory is expected come on line during the project planning horizon its load should be back out of the foreacast and a new growth rate calculated to project controllable load. This basic approach to projecting controllable load is attractive because it requires a minimum of input data and is completed quickly. As such, it is suited to utilities who not have a sophisticated method for load forecasting or to preliminary feasibility study. Constant percent of peak - The percentage of controllable load to peak demand for the base year is applied to the peak demand forecast for each year of the project planning horizon. This method also implies that controllable load will remain a constant proportion of controllable load. Major load additions identifiable as uncontrollable should be eliminated from the forecast before the controllable percentage is applied. This basic approach is similar to the "Constant percent growth rate" approach in that it requires minimum input data and it is suited to preliminary studies and where compatible with the demand forecast methodology. Gilbert /Commonwealth II-33 PO Appliance saturation applied to customer projections - Appliance saturation, either current or projected, are applied to class customer projections. For example, the current saturation of residential water heaters is applied to the projection of residential customers for the project planning horizon. It requires a customer projection by class for the project planning period. In addition, a current appliance saturation survey is required, or an appliance saturation forecast could also be used to match with customer projections. Clearly much more being is required for this type of project than is required for either of the previous two types. This method is suited for a more detailed type of study or where it is consistent with the demand forecasting methodology. Gilbert /Commonwealth ZEEE Ee II-34 SECTION II - Footnotes 1. Charlie F. Jack (Buckeye Power), "Peak Shaving a Way to Fight Rising Costs", 1975 Rural Electric Power Conference. Omaha, Nebrasks, April 27-29, 1975 (C75-310-8-IA). James B. Oliver (Detroit Edison), "Radio Control of Water Heaters and Distribution Station Voltage Regulators". 1969 IEEE Summer Power Meeting. Dallas, Texas June 22-27, 1969 (pp 666 - PWR). Paul E. Weatherby (Cobb EMC), "Load Management Report". 1977 Managers Conference. Kansas City, Missouri August 11, 1977 (#6a). Robert L. Roberts (Pioneer R.E.C.). "Load Factor Improvement Through Radio Controlled Diversity". 1973 Rural Electric Power Conference. Minneapolis, Minnesota April 30-May 1, 1973 (C73-906-51A). Arkansas Power and Light Company, "Peak Load Control Study, Summer of 1975". Distribution Standards Section. Arkansas Power and Light Company, October 6, 1975. Rev. January 12, 1976. Ibid. "Demand Controller Shaves Winter Peak", Electrical World, October 1, 1956, pp. 92, 93. Policy Bulletin No. 20-2.1, P.J.M. Electric Cooperative, Inc., Warren, Minnesota. August, 1978. Highline Notes, Cass County Electric Coop, Kindrad, North Dakota. August, 1977. Ibid. LE-35, 9. L. E. Stetson and Ivan D. Nelson, "Irrigation Scheduling to Control Electrical Demand". Nebraska Irrigation Short Course. January 20-21, 1975, pp. 1-6. 10. Ibid. ll. Staff Report on Load Management Standards, California Energy Commission, June 5, 1978 (DRAFT), pp. 48-50. 12. Ibid. Gilbert /Commonwealth TI-36 SECTION IIL CONTROL STRATEGY The objective of the control strategy is to achieve the control target without inconveniencing controlled customers. It is essential to model the control strategy before reaching any final conclusons regarding controllable load, reduction of load forecast and cost savings (benefits). The control strategy model must be sufficiently detailed to identify the hours of control and the maximum off time for controlled customers With the hours of control and maximum off times identified the impact on the customer can be assessed. If control times are intolerably long, the controlled load will have to be reduced and the control target adjusted upward. Another iteration of the control strategy will have to be made and customer off times reevaluated. This procedure must be repeated until a balance between customer off time and controllable load is reached, thereby establishing an achievable level of controllable load. System load and other power supply arrangements may require control in both the summer and winter, effectively reducing the controllable load per customer. This, in turn, may have a negative impact on the benefit/cost analysis. For example, assume that control is required in both peak seasons with water heaters and central air conditioners controlled in the summer, and water heaters and central space heaters controlled in the winter. The deferrable load is available per water heater all year round and is determined by the diversified demand. However, to obtain the same annual kW of deferrable demand from the central air conditioner (in the summer) and the central space heater (in the winter) twice as many control switches may be required. Thus the deferrable annual load per control switch is effectively reduced. In some cases, this requirement for additional control switches may neutralize the benefits of load control, even where dual function switches are used to minimize cost. Gilbert /Commonwealth Ei! DATA REQUIREMENTS A prerequiste for establishing a load control strategy is the development of a reliable data base. The data base would include: 1) the most current system peak day load profiles for all seasons in which control would be implemented, 2) identification of controllable loads, 3) controlled appliance diversified demand curves for all those periods, and 4) controlled appliance restore demand curves. Reference data is included throughout the various sections of this report. In-house data is preferable to borrowed data and should be the first choice when available. In some instances a load control pilot project may be necessary to collect data if suitable in-house data is not available or industry data does not fit a unique condition. PROCEDURES 1. Establishing Control Target - With the above mentioned data base established, a control target can be developed. The control target is the reduce peak load level which becomes the upper limit of the load profile during a control period. Priorities must be established when inhibiting controllable loads so the utility must analyze how the different appliance diversity curves interact. The largest interruptible loads should be considered as a base for load shedding. Irrigation loads exhibit this quality. Air conditioning, because of the sheer size of its load qualifies as a base, even though it is most vulnerable to causing customer inconvenience. Water heaters represent the most convenient deferable load because of their energy storage characteristics, but, in many systems they do not represent the majority of controllable loads. In this latter case, water heater load shedding is used to fine tune the control target when larger controllable loads cannot achieve the amount of load drop desired. In some utilities a relatively flat load curve forces long control times and appliance groups may have to cycle with other appliance Gilbert /Commonwealth I1lI-2 groups to avoid customer inconvenience. This type of problem lends itself to a linear programming solution. The objective function would consist of minimizing power costs. This would be balanced against imposed restraints of customer acceptance (appliance off-time) and avoidance of secondary peaks (appliance diversity and restore demand information). The ‘tactics’ involved in a load control strategy rely on responsiveness. They are developed below for the two principal types of controllable appliances. If the controllable load has been predetermined to be water heaters only, the straightforward procedure involves multiplying the total number of water heaters by 3 factors: 1) their load diversity at the time of the peaks or control periods, 2) the system loss factor to reflect the load referenced to the bulk power billing point, and 3) the control switch success rate to account for switch failures. The resultant maximum potential controllable load is then subtracted from the system peak demand to obtain the control target related to water heater control. If the controllable load has been predetermined to be central air conditioners only, a slightly different procedure is necessary. To minimize customer inconvenience, tests have shown that only 15 minutes off time is tolerable per central air conditioner in any one hour. (2) Therefore, the maximum potential controllable load, as calculated above for water heaters, must be divided by 4 to account for this restriction. (Further testing might alter this restriction for a specific utility.) For most summer peaking utilities, the maximum diversified demand of central air conditioners is in excess of 90% of the average air conditioner's connected load (implying that the air conditioning compressors are running almost continuously on the hottest days). Consequently, little diversity of air conditioner demand normally Gilbert /Commonwealth EPS occurs on the summer peak. Maximum diversified demand, during control, is reached approximately after two inhibit cycles and at an earlier time than would occur without control. Maximum diversified demand after a control period could actually be higher than normal demand because of restore demand effects. In any event it is, in many cases, very close to the connected load of all air conditioning at that time. When central air conditioners are controlled during periods when temperature is below maximum, where insulation standards are high or where thermostat settings may be relatively high, the increased diversity of air conditioning demands will substantially affect the control strategy. Tests conducted by both a midwestern(7) and western utility, (8) for example, show that with a natural diversity of 50% of the air conditioners being on at any one time, very little load was being shed as a result of cycled inhibits. In other words if the inhibit cycle causes a unit to be "off" 25% of the time and "on" 75% of the time, the average demand of the air conditioner will not be affected. The unit will still be allowed to run 50% of the time to satisfy the cooling requirements of the home. The net effect is to shift the "off" period of the unit. The Inhibit and Restore Sequence - With the control target established, the strategy next involves the inhibiting of loads as system demand approaches the control target so that the target is never exceeded. For this purpose, the controllable load is divided into a number of groups determined by the number of control channels available. As noted previously for air conditioners, the number must be such that approximately 25% can be controlled at any one time. The inhibit and restore sequence necessary to keep the system load below the control target is discussed below for water heaters and air conditioners. Gilbert /Commonwealth III-4 a. Water Heaters‘) - The system monitor observes the load increasing on a real time basis. At frequent intervals, this value is compared with the control target and the load profile that determined this control target. Based on this load profile's slope, the monitor initiates inhibit commands to a sufficient number of groups to stay below the control target until the time of the next sample. Group demand is a function of water heater diversity at the time of inhibit. It also must be adjusted by the loss factor and switch success rate previously mentioned. Because of the time varying nature of diversified demands, continuous monitoring during the initial inhibit sequence will probably be required. Generally, the initial inhibit sequence, i.e., the removal of all water heater load from the system, is completed within an hour or less. Total off time will depend on the system load profile. The width and slope of the system peak will determine off time and the initiation of restore. The restore sequence begins as soon as the system load profile decreases sufficiently below the control target. (6) In other words, the difference between the control target value and the actual demand must be at least as great as the first group's restore value. The first group inhibited must be the first group restored to satisfy the minimum off-time objective. The order of restore would then follow the order of inhibit. Restore values are calculated as follows: the diversified demand of each group at the time of inhibit is multiplied by the loss factor, switch success rate, and restore multiplier. The restore multiplier is the ratio of returning load to initial load. These ratios are statistical averages derived from several tests. This data also indicates the manner in which the restore values decay over time to normal values, i.e., the payback period. (See Exhibit II-6). To observe the effects of the first group's restored demand, the initial restore WEEE EE EEE EL Gilbert /Commonwealth LiI=5 value is added to the load curve with all water heaters off at the time of the restore command. The payback curve is drawn from this point, establishing a revised system load profile. When this revised load profile drops sufficiently below the control target, the next group may be restored. Then in the same manner as before, this payback curve is added to the first payback curve to establish another load profile. This sequence continues until all groups are restored. Note that depending on the slope of the load profile, it may be possible to restore more than one group at a time. Conversely, some time intervals may have to be skipped to allow for adequate load decay. Exhibit III-1 is an example of a control strategy for water heaters. Central Air Conditioners - For central air conditioners, the inhibit and restore sequences consist of group cycling. Groups can be inhibited only for short intervals (previous tests have used 7-1/2 minutes, no more than twice an hour) (7) to minimize customer discomfort. The inhibit sequence begins when the system monitor projects a load demand above the predetermined control target, as previously explained for water heaters. Group demand is determined from applicable diversity curves. Once the inhibit sequence is initiated, all groups are cycled in 7-1/2 minute intervals. It may become necessary to cycle two groups at a time as the system load increases rapidly. (Restricted by the fact that no group may have more than two 7-1/2 inhibit periods in any one hour.) After two inhibit cycles, it is assumed that each group requires the maximum diversified demand. Therefore, after the second cycle, the resultant load profile is established by adding 3/4 of the maximum diversified demand of the total central air conditioning load (times loss factor and switch success rate) to the load curve with central air conditioners removed. As LT IPE A IEA III-6 MEGAWATTS EXHIBIT [11-1 540 LOAD CONTROL SIMULATION WINTER PEAK DAY 520 WATER HEATERS AND PUMPS SYSTEM LOAD PROFILE BEFORE LOAD CONTROL 5 ° SYSTEM LOAD PROFILE WITHOUT OIL PUMPS 480 RESULTANT LOAD PROFILE AFTER LOAD CONTROL 460 NO, GROUPS INHIBITED LOAD CURVE 440 WITHOUT WH NO. GROUPS RESTORED KWH GAIN 420 GREEN ARROW = DEWAND INHIBITED RED ARROW = DEMAND RESTORED 400 380 360 WATER HEATER GROUP SWITCHING SCHEDULE ~ Grour OFF TIMES 9 Stalin tale ay 2:00 218 15 145 215 215 230 245 200 215 | OIL PUMPS SWITCHING SCHEDULE LOADS BEING CONTROLLED: 1, WATER HEATERS 2, OIL WELL PUMPS 1PM 2 3 4 5 6 1 8 9 10 N 12 1AM the revised load profile drops below the control target, central air conditioning load is restored by discontinuing the cycling sequence as soon as possible while still not exceeding the control target. The restore information on central air conditioners shows that payback period (the time necessary to satisfy the original thermostat setting) can be anywhere from 3 to 7 hours.(7) The maximum diversified demand extends through the length of the restore period. This means that the load curve after all central air conditioner groups have been restored is determined by adding the maximum diversified demand of the total central air conditioners to the base load curve with central air conditioning removed. This resultant load profile extends through the duration of the restore period. Exhibit III-2 is an example control strategy for central air conditioners. SYSTEM CONTROL VS. SUBSTATION CONTROL Some manufacturers of load control equipment have taken the position that deferring system peak demands through load control will result in reduced distribution plant investment and the associated costs. This assumption implies that the controlled demands at the time of the system peak are directly related to reduced peak demands on the distribution network. In other words, substation transformer and secondary transformer capacity can be reduced or system reinforcement postponed as a result of the control scheme designed to reduce system peak conditions. This assumption would be credible if substation maximum demands and localized peak conditions throughout the distribution network occurred coincidently with the system peak. In an attempt to assess the validity of this assumption, the time of the system peak and the times of the various substation peaks were compared for a large cooperative system (see Exhibit III-3). The comparison shows that less than 5% of the distribution substations peaked at the same hour as the system peak TET=7 etm | MEGA WATTS 560 KWH Loss SYSTEM PEAK DAY LOAD PROFILE A mh iN MSO LOAD CONTROL SIMULATION 540 “ ae See 34 Nee ome SUMMER PEAK DAY AIR CONDITIONERS NO. OF A/C GROUPS INHIBITED ua 500 480 460 F \ KWH GAIN qe LOAD PROFILE WITHOUT A/C ae 420 400 380 ALL GROUPS RESTORED 360 ‘TNE CYCLES cRUP A/C GROUP SWITCHING SCHEDULE | 30 55200 ' Ly LeeLee LL aL 6:15 2 2 LU LI i Lea a Ue ee 320 6:07 3 LT Lo hea UO a a a 300 & ie “| ; 4 US aft eae x “Le - ; sl UU J mons Ya 13 8 UU eg 6:22 aa ested ee sau a U LP Ue LU 5:62.12 10 ik Uae WU Ue ie 5:45 2 " ald We caer Co a a 54512 12 eso al eee Uo LU rod e180 13 Nee ECE are UL 5:15 4 ror UU tei UU Yue oY $45 2S ect Uecker AP Le ee ed 5:37 12 16 Loe UU ae EXHIBIT III-3 SUBSTATION AND SYSTEM PEAKS: COMPARISON OF PEAK OCCURENCES PEAKING IN PEAKING ON PEAKING AT THE SAME THE SAME THE SAME MONTH AS THE DAY AS THE TIME AS THE SUBSTATION SYSTEM SYSTEM SYSTEM x x 7 8 Total Substations Reviewed - 42 Source: Western Farmers Electric Cooperative, Hourly Substation Load Data, July 1978 This Exhibit summarizes a representative sample of the total 230 substations supplied from a common bulk power supplier. Hourly demand data was reviewed for each of the sample substations in order to determine the relationship between the overall system peak and individual substation peaks. It can be seen that the majority of substation peak demands would not be reduced by a control strategy designed to limit the overall system peak. Therefore, there would likely be little capacity savings in the distribution system if such a control strategy were employed. III-8 and only 14% peaked on the same day as the system peak. Based on these observations, approximately 5% of the substations reviewed would have reduced peak demand to some extent by controlling only at the time of the system peak, and 14% of the substations would have altered peak day load profiles as a result of a control scheme using system peak criteria. Another factor to consider is the frequency with which the substation's demand approaches its peak. Diversity of peak loads decreases as distance from the supply point increases. Consequently, the frequency of approaching a load peak is higher at the final distribution level than it is at the system level. This implies that more control periods would be necessary at the distribution level. In other words, to effectively limit the peak in the distribution network and create savings by deferral of investment, a substantial number of additional control periods would have to be imposed above those required for system peak control. In a few cases, individual substation peaks may, in fact, occur during a restore period under a system peak control scheme, increasing the problem of overloading the substation, rather than deferring distribution investment. Remote metering equipment would be required at each substation in order to detect the upcoming peaks. Ultimately, additional addressing capability would be imposed on the control system so individual feeders would be controlled independent of each other. The preceding analysis involving the relationship between the load restoration demand and numbers of channels required would also be greatly increased in complexity. Under these conditions the capability of the initially conceived peak load control system would be exceeded. The technical feasibility of such a sophisticated control scheme has not yet been demonstrated. Therefore, any benefits attributed to reduce demands on the distribution network must be considered premature until an adequate control strategy can be achieved and cost of this additional capability can be included in the cost-benefit analysis. III-9 ae CHAPTER III FOOTNOTES a) Peak Load Control Study - Summer of 1975, Arkansas Power and Light Company, p. 10. (2) tad. (3) Central Illinois Light Company Load Management Studies - Report to Illinois Commerce Commission, December 21, 1978. (4) E.T.K. Law, Pacific Gas & Electric Company's residential central air conditioning load control equipment. EPRI Workshop in "new modes of residential HVAC; economic incentives and barriers" January 14-17, 1979, Tampa, Florida. (5) Charlie F. Jack (Buckeye Power), "Peak Sharing - A Way to Fight Rising Costs". 1975 Rural Electric Power Conference. Omaha, Nebraska. April 27-29, 1975. (C75 310-8-IA) p. 4. (6) The "load profile" now consists of a base load curve with water heaters removed. (7) Peak Load Control Study - Summer of 1975, Arkansas Power and Light Company, p. 10. Gilbert /Commonwealth rz1—10 SECTION IV LOAD CONTROL EQUIPMENT Selecting Candidate Systems Once an analysis of the customers, loads and physical systems of the distribution utility has been obtained, a review of the available generic types of systems is necessary to select the suitable equipment alternatives. This phase of the selection process will indicate which systems will accomplish the required functions to meet the preset objectives, which systems may offer additional secondary functions, and how to construct the related cost of the systems selected. The communication and control systems are described as current design technology now exists. Existing systems specifications will undoubtedly be modified and improved over time and new systems are on the drawing board which will increase the spectrum of communication paths and equipment choices presently available for end use load control, systems functions and remote meter reading. In any event, the following section reviews only those generic types of utility control systems existing or expected to exist within 1 to 3 years. These include radio, low frequency power line carrier, high frequency power line carrier, hybrid-radio/power line carrier, telephonic and direct wire systems. In addition to the basic characteristics of each type, this section covers the direct vendor cost components and those components of indirect cost involved in the installation and initial setup of the equipment. A. Generic Types of Load Control Equipment The communication and control systems presently being marketed have inherent design differences that need to be recognized. Different communication paths are utilized with obvious characteristic differences in component equipment. The purpose of this portion of the Gilbert /Commonwealth Iv-1 task is to expose the potential strengths or weakness of each generic control system with regard to the parameters inherent in any specific utility system. For each generic type discussed, the following broad categories are addressed. a. Origin of system. b. Simplified system description. Ce Engineering application considerations and the influence of the power system network. d. Installation considerations for devices located at the customers location. e. Major cost factors. To further illustrate the application of each generic system to a typical distribution network, an idealized layout typical of the major apparatus and interconnections likely to be found in any average utility is shown in Exhibit IV-1. This network layout is subsequently modified for each communication system to illustrate the portions of the power network which are utilized for the communication channel, the point of major interface between the control system and the power system and the location of the major components. 1. VHF Radio Direct radio control of remote devices is a well established technique. Its application for the control of end-use customer loads involves little more than an adaption of existing hardware. Large-scale integrated circuit design has resulted in smaller, less costly and more reliable units capable of close frequency tolerances and suitable for bulk production. The radio system components are now available in quantity production. A number of Gilbert /Commonwealth LV =2 GENERATION AND TRANSMISSION ar CENTRAL —_—_— CONTROL BULK SUPPLY SUB A SUB B POINT DISTRIBUTION 1A | 2A 3A 1B 2B (3B LINE L. V. DISTRIBUTION TRANSFORMER oT ba i. — SERVICE CABLE TYPICAL DISTRIBUTION SYSTEM CUSTOMER'S MAKEUP WIRING ' if | LOAD LOAD EXHIBIT IV-- 1 utilities in the United States installed extensive radio systems for load control with excellent results. Radio transmitters operate on Federal Communication Commission administered frequency bands with frequencies being allocated for load control systems in specific locations. The possibility of a joint use of load control signals with a utility's existing VHF voice communication is permitted if required. Simple audio-tone frequency modulation can be used to activate the single-tone decoder at the end-use location. Block addressing is then possible by utilizing selected tones for individual commands to each group of receivers preset for a particular tone. As an alternative, coded tone signals may be used where multiple commands are required at each receiver location. The control of end-use loads is initiated by transmitting "off" commands that activate the remote radio switch and disconnect the equipment to be controlled. The receiver will restore the disconnected appliance after a preset delay if an additional transmitted signal is not received. Prolonged "off" cycles can be obtained by retransmitting the appropriate tone before the expiration of the time delay. Transmission within the frequency band allocated is generally immune from normal day and night variations in the signal path. Some compromise in the channel reliability can be expected at infrequent intervals by freak long distance reception of a remote transmitter due to sporadic ionization layers in the upper atmosphere. The probability of false operation due to the precise matching of the correct modulated tone signal is considered to be minimal. The use of frequency modulation and the design of the detector makes it possible to obtain a receiver characteristic which is largely immune from noise interference, either atmospheric or man-made. Gilbert /Commonwealth Iv-4 At this time, radio control systems are limited to one-way communication for the purpose of load control. Remote receiver/transmitters are being developed that may permit bi-directional radio system applications in the future. Significant parameters in the use of radio systems are: As a general rule, the land topography will influence the effective range of any given transmitter. The physical dimensions of the utility's service area will govern the number of transmitters required. Locations involving flat or rolling terrain will obtain the best coverage, while mountainous areas will be subject to valley locations which will be difficult to cover due to shielding from the radio signal. Applications involving urban areas will be subject to man-made radio frequency noise such as that generated by electrical appliances and motor vehicle ignition. It will be desirable to reduce the transmitter coverage area in these locations to compensate for the increased noise levels and the loss of signal strength due to building screening. Application of radio control to a given area is relatively simple. For most utilities already using VHF base station voice communication equipment, the major portion of the engineering work required is completed. The coverage experienced by the present voice communication system can be directly correlated with the expected performance of the load control system in a majority of locations. Where improvements are required in fringe areas, systems utilizing multiple transmitters can be arranged for a degree of "overlap" in the service area of two transmitters to cover these points. Omni-directional antennas are generally employed, however, coverage of specific portions of the Gilbert /Commonwealth Iv-5 system may be improved (and coverage of unwanted areas prevented) by the use of modified- antenna designs. In those cases requiring multiple transmitters for coverage of the distribution system area, the transmitters should be arranged for sequential keying to prevent mutual interference. Communication between the central control point and the transmitters may be by leased telephone lines, central control radio link or microwave system. The radio system is completely unrelated to the distribution system, and the mode of operation of the electrical system has no effect on the communication path. Communication is maintained regardless of network switching, abnormal operating routines or arrangement of bulk supply points. Load growth or extensions to the network will not require changes to the existing installed system for control provided such extensions are within the service area of the transmitter. Extensions outside of the transmitter's service area may require either an additional transmitter or the relocation of an existing unit. Location of the receiver on the customer's premises is relatively flexible and simple. Generally, receivers may be located at any convenient position, such as the incoming electric panel or at the end-use equipment location. However, some restrictions may apply in fringe areas where the signal strength is marginal and with certain types of building construction causing heavy screening. The receiver antenna, integral with the unit, is augmented by signal pickup on the power line connections and adequate signal strength is available at most locations. This factor also protects the receiver from deliberate screening as an attempt to prevent operation. Sea ee Iv-6 Receivers controlling more than one circuit are less flexible in the choice of location. Usually, receivers of this type should be installed at the incoming electric panel; otherwise, a modification to the building wiring will be required. The application of a radio control system to an idealized distribution system layout is demonstrated in Exhibit IV-2. As referred to earlier, no portion of the power system forms part of the communication channel and communication between the central control and the individual receivers is maintained regardless of the network configuration. Receivers may be located at any point on the distribution network that is within the service area of the transmitter. Exhibit IV-3 details the major components which are required to be added to an existing distribution network to provide for remote radio control. The major factors which will influence the cost requirements for a VHF radio system may be summarized as: 1) The effective coverage area for a given transmitter and antenna is largely controlled by the surrounding terrain. The load density within that service area will govern the number of controllable loads and therefore the total controlled kW demand per transmitter. Therefore, as the amount of controlled kW demand per transmitter decreases, the cost per controlled kW increases. 2) The physical dimensions of the utility's network and the effective service area of each transmitter will dictate the number of transmitters required. A long, narrow service area will be more costly to cover via radio than an equivalent service area which is more "square" or Gilbert /Commonwealth LV=7, GENERATION AND TRANSMISSION [\ Re is eran CONTROL BULK SUPPLY SUB B NO PORTION OF POINT POWER SYSTEM FORMS PART OF COMMUNICATION CHANNEL. DISTRIBUTION LINE NO PORTION OF POWER SYSTEM FORMS PART OF COMMUNICATION CHANNEL. L. V. DISTRIBUTION TRANSFORMER 7 a T ae SERVICE ss il V. H. F. RADIO CONTROL CUSTOMER'S — rf i [| lot LOAD LOAD EXHIBIT IV - 2 VHF TRANSMITTER) =) CENTRAL CONTROL REMOTE TRANSMITTER CONTROL MAY BE MICROWAVE OR LEASED TELEPHONE LINES Ore CONTROL RECEIVERS SCATTERED THROUGHOUT TRANSMITTER SERVICE AREA. V. H. F. RADIO CONTROL ira ae COMPONENTS. EXHIBIT IV - 3 more evenly proportioned. Similarly, a mountainous area will be more expensive to achieve a one hundred percent coverage with a radio communications system than a service area that is relatively flat. Typically, a 300 watt licensed power transmitter may be assumed to have an average service area of 15 mile radius from the antenna site. This may be increased up to about 25 miles for very flat locations in "quiet areas" but reduced in built-up areas containing large buildings, radiated interference and such considerations which suggest a low signal to noise ratio may be encountered. 3) The joint use of existing radio facility towers for load control transmitter antennas is sometimes possible and will reduce the overall cost. In addition, existing transmitter land lines or microwave systems may be available for joint use as a communication link from the control center to the load control transmitter. 4) The complexity of the communication link required between the control point and the transmitter is dependent on 2 major factors: (1) the number of transmitters controlled and (2) the distance from the control point to the furthest transmitter location. An evaluation must be made of the relative capital and operating costs of alternatives such as a master transmitter for controlling the remote transmitters via microwave link or leased telephone lines. 2: Power Line Carrier Control Using Low-Frequency Injection Low-frequency power line carrier control has been commonly utilized in overseas markets for many years. The hardware has Gilbert /Commonwealth Iv-10 been continually updated to incorporate new developments in circuitry and solid state devices and the application of new sophisticated electronics has enabled the development of complex signal codes. Equipment is now available with code formats which range between simple on-off rhythm keying and multibit binary pulse codes capable of significant intelligence. Regardless of the code format used, all systems employ the following basic techniques. The low frequency signal is in the low audio range, usually less than 1000 Hz and above the fundamental 60 Hz power frequency. This signal is generated by a low frequency oscillator and is keyed on-off in accordance with the signal code program. The resultant chopped, low-frequency carrier is injected into the power system in such a manner that it adds vectorially to the power system waveform and modulates the fundamental voltage wave. Injection may be accomplished in two ways: parallel and series, either line-to-line or line-to-ground. Parallel coupling involves injecting the signal via a line connected capacitor and a 60 Hz filter reactor. Series coupling is by means of a series boosting transformer. In either event, the coupling devices must be large enough to handle the injected kVA, which for estimating purposes may be assumed to be 0.1% of the maximum load on the system: Il1kVA per MVA of system load. The high injection power requirements to obtain a usable signal has, in part, been responsible for this system being restricted to a one way system. Return communication from the receiver to the substation (two-way system) is neither currently provided nor foreseen in the near-term. The receiver relays at customer terminals possess blocking filters for the fundamental frequency and accept the injection signal frequency. Detectors are pre-programmed to accept a signal code Gilbert /Commonwealth Iv-11 Se or codes according to the manufacturer's system design-typically between one and three codes. Significant parameters in the use of low-frequency powerline injection are as follows: a. Attenuation of the injected signal by the distribution system components will be lower as the signal frequency approaches the fundamental power frequency. This is due to the characteristics of the power system which are designed to transmit fundamental frequency power with a minimum loss. An injected frequency lower than power frequency will cause higher magnetizing currents (therefore, higher losses) in shunt-connected magnetic circuits (transformers). Frequencies higher than power frequencies will encounter higher reactance in series impedances (line reactance, series reactors), and lower shunt reactance due to line capacitance, both resulting in increased signal volt drops. Generally, frequencies below 1000 Hz are sufficiently close to the power frequency to permit normal transformer action in both power and distribution transformers. Injection at the subtransmission and medium voltage distribution levels is therefore feasible without involving an intolerable reduction in signal strength at the end-use terminals. The closer the signal frequency is to the power frequency, the better the distribution system will perform at the signal frequency. b. A second consideration is signal losses by mechanisms other than series attenuation. These include direct losses due to shunt connected loads such as power factor correction capacitors which are encountered commonly on distribution systems. Line capacitors are utilized as an integral part of the system for voltage control, and at the end-use terminal for power factor correction. In either event, capacitors exhibit a decreasing shunt reactance with an increasing Gilbert /Commonwealth Iv-12 signal frequency and absorb signal volt-amperes. In addition, as the signal frequency is increased, the lumped capacitive reactance drops while the series line inductive reactance is increased, giving rise to a potential divider effect. Dependent upon the network characteristics and the signal frequency adopted, switching lumped capacitors can cause an unexpected signal decrease or increase. The use of a signal frequency close to the power frequency to take advantage of the transmission path characteristics, incurs a penalty at the consumers terminal. Each terminal power frequency load also provides a load on the injection signal voltage proportional to the ratio of the signal voltage to the power frequency voltage. Generally, the final choice of signal frequency will be from discrete bands provided by individual manufacturers and will be based upon network characteristics, field tests and measurements and the proximity of other similar carrier current installations where interference may be a problem. Ge Selection of the signal frequency within the audio band considered (less than 1000 Hz) is subject to certain limitations. Although the lower end of the band may be preferred for minimum signal path attenuation and an increase in the area covered, this part of the frequency spectrum is rich in power frequency harmonics of significant magnitudes. Should such harmonics correspond to the signal frequency, the receivers will be saturated and will be inoperable. Not only must frequencies corresponding to both even and odd harmonics of 60 Hz be avoided (i.e., 120, 180, 240, 360 Hz, etc.), each of these frequencies must be given a clearancé margin to allow for harmonic generation under anticipated : “off normal" power system operation frequencies. It is particularly important to allow a safety band below the Gilbert /Commonwealth _| Iv-13 nominal harmonic frequencies as emergency load shedding may be required under abnormally low system frequency. In order to limit the effects of line noise, the bandwidth allowed by the injection and receiver filter circuits is narrow. With the low signal frequencies used, the effective band-width is limited to only a few Hertz. Consequently, the speed of signal transmission is slow, commonly in the range of 10 to 30 seconds per message. Depending upon the signal coding utilized, each message may contain one or several independent commands. Signal coding for specific types of equipment is available in each manufacturer's published literature and falls within two basic categories; repetitive and binary pulse. In each case, simple on-off transmitter keying is used, resulting in audio tone bursts of a finite length being injected into the system. In the repetitive system, tone bursts and spaces are of equal durations and are repeated in a rhythmic fashion to give a recognizable periodic time of the injected rhythm. By changing the period (i.e., the length of the tone signal and space cycle), different addresses are obtained. Receivers are provided with decoders which are preset for a particular periodic time and will operate if the transmitted period corresponds to this setting. Signals of different periodic times will inhibit the output, analogous to a simple pendulum. Only relatively few discrete addresses are possible at any one signal frequency. One major advantage is that a few of the injected pulses may be missed during the transmission period and the receiver will still obtain an identifiable signal. A dual pulse repetition rate signal may be transmitted sequentially to significantly increase the number of discrete commands available. This form of coding Gilbert /Commonwealth Iv-14 is particularly suitable for systems containing potentially high network noise bursts and where discrete address requirements are minimal. The binary pulse code configuration uses a multibit mark/space signal. The mark comprises a short duration tone burst of typically 0.5 second. Up to 50-bit signal trains are presently being used for utility application. The subdivision of the train into address and command fields can result in an impressive number of discrete signals (in the order of 20,000). It is important to emphasize that the receiver must detect the complete signal train in order to respond, thus it may be necessary to repeat the command more than once to achieve the same immunity from system noise obtainable with a repetetive type system, at a cost of much longer transmission times. Generation of illegal codes and injection into local wiring for the purpose of defeating the relay is difficult, giving good system security. By-passing the signal for the purpose of preventing operation would require technical knowledge not available to the majority of the population. Application of the low-frequency injection system requires an electrical engineering analysis of the distribution system. The major factors involved are network configuration, normal and abnormal switching arrangements, circuit impedances (or methods of construction), location and value of shunt capacitors and series reactors, load type and load distribution (geographical and magnitude). The controlling factor, however, will be the local system load at each point selected for injection. This factor determines the injection signal input kVA. Gilbert /Commonwealth Iv-15 The use of a few, large injection points to cover a distribution area may show a reduction in cost for both the equipment and the communication channel between the control point and the injection sites. However, the optimum rating of each site (and therefore the number required) may be limited by load considerations. Too large a unit looking into a high system impedance may cause an objectional voltage flicker during signal injection, particularly if too great a differential exists between the impedance to the nearest and to the most remote end-use terminal. Injection may be at either the medium (distribution) or high (transmission) voltage level of the system. The choice will depend largely on the network configuration and area to be covered. Due to the high injection power involved, frequency conversion and coupling equipment is physically large and space must be available either inside the substation building or outside (depending upon the manufacturer's equipment type). In either event, the complexity rises with increasing voltage level of injection as at the higher voltages, a fully protected feeder bay must be used for connection to the bus. Also, an adequate house service electrical supply must be made available. The location of receiver relays is relatively flexible and simple. The injected signal is available throughout the customer's wiring system. As a result, the relay may be located either at the incoming control panel or at the controlled appliance, whichever is convenient. Relays possessing facilities for controlling more than one circuit are somewhat less flexible in location. If not installed at the incoming panel, some modification to the building wiring will be required. Gilbert /Commonwealth eee eee | Iv-16 Two possible alternatives in the application of low frequency powerline carrier control to an idealized distribution system layout are shown in Exhibit IV-4 and IV-5. The former diagram shows a typical radially connected network with injection taking place at each bulk supply point's medium voltage busbar. The latter demonstrates the possibility of injection at the high voltage level in order to cover more than one bulk supply point with a single set of injection equipment, but also indicates the vulnerability of the communication path to switching at the transmission system voltage level. This deficiency is particularly serious where the transmission system is not owned and operated by the distribution authority. Receivers may be located at any point on the system where a low voltage supply is available. Exhibits IV-6 and IV-7 detail the major components required to be added to an existing distribution network. Although it is apparent that the required equipment has much in common between the two alternatives, it must be recognized that in the latter case, the injection point equipment is larger, is rated for the higher voltages and requires a significant addition to the high voltage substation in the form of a completely protected feeder bay. Factors which will influence the cost requirements for a low-frequency powerline injection system are summarized as: 1) The demands imposed on the system governs the injection equipment rating. Conversely, the amount of controllable load tied to the injection equipment has no effect on the rating of that equipment. This implies that for any given system, the greater the ratio of controlled load to total load, the lower will be the total cost of the system per controlled kW. Iv-17 GENERATION AND TRANSMISSION INJECTION CONTROL CENTER AND INJECTION TUNING AND ae TUNING DISTRIBUTION POWER SYSTEM FORMING LINE PART OF COMMUNICATIONS CHANNEL. L. V. DISTRIBUTION TRANSFORMER EACH RADIAL SYSTEM IS INDEPENDENT OF TRANSMISSION SERVICE SWITCHING. CABLE OMER’S P WIRING FS ">> LF. POWERLINE CARRIER CONTROL &® $@® ~ MEDIUM VOLTAGE INJECTION LOAD LOAD EXHIBIT IV - 4 GENERATION AND TRANSMISSION (INJECTION AND = CENTRAL SS CONTROL BULK SUPPLY SUB B POINT POWER SYSTEM FORMING ns Tae 1B 2B 3B ee SIGNAL AT SUB A DEPENDENT UPON TRANSMISSION SWITCHING L. V. DISTRIBUTION TRANSFORMER T i. SERVICE CABLE ca ao L. F. POWERLINE CARRIER CONTROL i | | | @ TRANSMISSION VOLTAGE INJECTION LOAD LOAD EXHIBIT IV - 5 LEASED TELEPHONE LINES CONTROL CENTER INJECTION POINT COMPRISES: 1) FULLY RATED AND PROTECTED CIRCUIT BREAKER OR FUSE 2) SYSTEM VOLTAGE CAPACITOR INJECTION AND TUNING INJECTION AND TUNING LF. CARRIER RECEIVER 3) TUNING REACTOR RELAYS FOR SYSTEM CONTROL 4) ISOLATION TRANSFORMER CAN BE LOCATED THROUGHOUT 5) FREQUENCY GENERATOR/CONVERTER SYSTEM. L.F. POWERLINE CARRIER CONTROL rane COMPONENTS. EXHIBIT IV - 6 LEASED TELEPHONE LINES a ae. . CONTROL CENTER INJECTION POINT COMPRISES: (— INJECTION 1) FULLY RATED AND PROTECTED AND CIRCUIT BREAKER TUNING 2) SYSTEM VOLTAGE CAPACITOR 3) TUNING REACTOR 4) ISOLATION TRANSFORMER 5) FREQUENCY GENERATOR/CONVERTER. L.F. CARRIER RECEIVER RELAYS FOR SYSTEM CONTROL CAN BE LOCATED THROUGHOUT SYSTEM. L.F. POWERLINE CARRIER CONTROL LF. CARRIER RECEIVER ® COMPONENTS RELAYS FOR LOAD CONTROL. EXHIBIT IV - 7 Network changes (whether extension of the system, increasing load densities or changes in network switching arrangements) affect the required capacity of injection equipment and tuning. Similarly, projected load additions close to the injection station must be factored into the initial design as these may limit the maximum allowable injection power due to possible voltage flicker problems. A cost comparison of transmission versus distribution level injection should be made for distribution systems having the option of high voltage injection. The cost requirement per injection point increases significantly at higher system voltages. At the same time, the number of injection sites for a given area may decrease. The comparison must also include the cost the required communication channels to each site. The analysis should recognize any additional maintenance charges incurred as well as inherent intangibles (such as expense of visits to the number of sites involved, availability of substation space and additional rate costs incurred by the failure of one injection point). Power Line Carrier Using High-Frequency Injection Historically, high frequency injection into power lines has been restricted to applications using open-wire, high-voltage primary transmission lines for the purpose of voice communication, supervisory control and/or protective relay systems. These installations performed well, but were generally bulky and used vacuum tube techniques. Little application was seen on distribution systems due to the large power requirements, cost, and regular maintenance required on both transmitters and receivers. Operating frequencies were generally in the range of 150 to 500 kHz. Iv-22 fT Development of solid state components has reduced the size, power, cost and maintenance requirements. As a result, the equipment has become more attractive for use on lower voltage systems. Such equipment is now in advanced, post-development testing phase and is expected to be available as a commercial product in the near future.(1) studies have indicated that noise generation on low and medium voltage lines is at a minimum at frequencies somewhat lower than those previously used. The band between 5 and 200 kHz has been selected for this application. The signal is generated by a stable solid state oscillator and keyed either on-off or frequency shift in accordance with a preselected multibit binary pulse code. The resultant modulated carrier may be injected into the power system by parallel or series injection to modify the power frequency voltage wave. Injection may be either line-to-neutral or neutral-to-ground via a line-connected coupling capacitor and the necessary protective fuses and isolating switches. A high-frequency current transformer may be used for signal injection if applicable. Injection power requirements are low (normally in the order of a few watts), but rise with a decrease in frequency. Low power requirements encourage the use of this system for two-way communication. Such systems are being perfected for the purpose of remote meter reading and other remote data retrieval functions, in addition to load control. The receivers at the customer terminals are provided with input filters for the carrier Frequency. Detector-decoders have been designed for the appropriate signal address and operate function. For remote meter reading, the receivers have an "on-demand", retransmit capability from integral information storage registers. Gilbert /Commonwealth Iv-23 Significant parameters in the use of high-frequency power line injection are: a. Attenuation of the injected signal by the distribution system components is relatively high. This is due to the high reactance of system series inductance and low reactance of shunt capacitance at these Frequencies. The effective range of the signal is somewhat less than an equivalent lower frequency system and injection is usually limited to the medium voltage distribution system. Adequate signal strength can be obtained to handle the attenuation across medium to low voltage distribution transformers without the use of signal bypass facilities. A wide spread, low-load density medium voltage system may require signal repeaters to achieve adequate signal strength at the remote, low voltage end-use terminals. b. Signal losses not attributable to power distribution system series attenuation occur principally at shunt connected capacitors which possess a low reactance at the signal frequency. These capacitors may be either voltage correction system capacitors or customer terminal power factor correction capacitors. The former should be provided with signal frequency blocking filters but the latter may be trapped on an "as needed" basis (depending upon the signal conditions prevailing at that particular location). The use of a signal frequency higher than the power system frequency reduces the signal loss in the power frequency load equipment. Sufficient inductance is usually present in the load equipment to severely limit loading of the signal source. ce. Selection of the signal frequency may be either controlled by the equipment vendor or chosen from within an available band, Gilbert /Commonwealth Iv-24 depending upon equipment type. Precise selection of a frequency in this high band is relatively unimportant. Only a nominal amount of power system generated interference (in the form of harmonics) is present and only wide-band impulse noise is a consideration. There are some advantages to be gained at the lower end of the band: 1) less distribution system signal attenuation and, 2) a minimum interference with the intermediate frequency stages of broadcast band AM radio receivers (conventionally 455 kHz). Disadvantages are higher injection power and increased signal loss in power frequency system loads, At the signal frequencies used, the band width is sufficient to allow for a moderate transmission speed resulting in short message transmission times using multibit codes. This factor enables the channel to be available for multiple message commands without excessive delays. Typically, up to 150 bit signal trains are used providing the capability for individual address of each meter point in addition to common addresses for group functions. Security of the system is relatively good. Generation of illegal commands would be difficult while bypassing the signal for the purpose of preventing operation may be partially prevented with the practice of obtaining the signal on the line side of the meter, placing the meter inductance between any bypass tap and the receiver. In addition, if the system was used for remote meter reading, any such bypass would be readily detected. Application of the high-frequency injection system requires a minimum of information about the distribution system concerned. The information needed is limited to such factors as network configuration, normal and abnormal switching arrangements and location of power factor correction Gilbert /Commonwealth Iv-25 capacitors. For load control systems of this type which permit selection of signal frequencies, the type of construction of the distribution system (overhead, underground) would be needed. Several factors result in a requirement for a minimum amount of application engineering: 1) Each of the systems is predicated upon the use, or facilities for use, of remote meter reading. As such, the distribution system is divided into sectors. Each sector reports to an individual sector control unit for signal processing. This is necessary in order to avoid "bottlenecks" in the information channel (where large amounts of data have to be transmitted). 2) Each sector injection unit contains the necessary high frequency equipment. Due to the low transmitted power, such equipment is comparatively small, simple and inexpensive and may be located at a substation or elsewhere on the distribution system. 3) Distribution system impedances at high signal frequencies are unpredictable; therefore, emperical determination of injection points is more expedient. If trouble areas are located during test, it is relatively simple to relocate the injection point or provide repeaters. 4) The restriction in signal range due to attenuation, plus the use of individual sectors, usually results in injection at the medium or low voltage distribution levels thus rendering the system insensitive to variations that may occur on the high voltage system. Gilbert /Commonwealth IV-26 Location of the receiver in the customer's building is, typically, at the metering point. This avoids the signal loss due to the customers wiring and noise generated by end-use devices. The positioning of the receiver (or transponder) at the meter will be necessary if meter information reading is required (present or future). This will also enable the receiver power supply requirements to be obtained from the unmetered line. Some modification or addition to the building wiring will be required for load control purposes (usually low voltage wiring to an interposing relay). The application of a high frequency power line carrier control system to an idealized distribution system layout is demonstrated in Exhibit IV-8. Injection is normally at the medium voltage level and although line connected units of low power ouput are shown, an alternative higher power substation unit is available with some systems. Injection units may use either individual telephone grade lines to connect to the central control equipment or share party lines, depending upon equipment type. Receivers may be located at any point on the system where a low voltage supply is available. Potential for the use of receivers for system control purposes is enhanced by the retransmit capability and the facility for a unique address for each receiver. Exhibit IV-9 details the major components required to be added to an existing distribution network. By virtue of injection being at the medium voltage level, coupling to the power system can usually be via a simple fused disconnect. Gilbert /Commonwealth LVS27, Hors the : oa f we J ee Site, = Renee ea, et tr GENERATION AND TRANSMISSION BULK SUPPLY POINT DISTRIBUTION LINE CV, DISTRIBUTION PART OF COMMUNICATION ae RIBUTION TRANSFORMER 7 a T 7 CHANNEL. coor LE ee (M) (M) (M) (M) O® x) i 2 H. F. POWERLINE CARRIER CONTROL | If ''! | LINE OR SUBSTATION INJECTION LOAD LOAD EXHIBIT IV - 8 LEASED TELEPHONE LINES CENTRAL CONTROL SEVERAL LINE INJECTION UNITS MAY BE FED BY ONE LEASED LINE SECTOR INJECTION UNITS COMPRISE: H.F. CARRIER RECEIVE/TRANSMIT 1) SYSTEM VOLTAGE LINE FUSE UNITS FOR SYSTEM CONTROL 2) COUPLING CAPACITOR CAN BE LOCATED THROUGHOUT 3) H.F. GENERATOR SYSTEM. 4) RECEIVER (FOR RETURN SIGNALS) 5) TRANSMIT/RECEIVE LOGIC NUMBER OF UNITS GOVERNED BY NUMBER OF METER UNITS WITHIN RANGE. ® ® IF. CARRIER METER UNITS H.F. POWERLINE CARRIER CONTROL READING AND LOAD CONTROL. COMPONENTS. EXHIBIT IV - 9 The factors which influence the cost requirements for a high-frequency powerline carrier system may be summarized as: 1) 2) 3) For practical purposes, the signal transmitted power is largely independent of the system connected or the controlled system load. Line attenuation or the maximum number of addressable receivers per injection point is normally the limiting factor. Network changes, by virtue of 1 (above), have a minimum effect on an installed system. Increasing load densities, if not accompanied by additional metering points, will not significantly change the signal quality. An existing sector may have to be sub-divided and an additional injection point installed if the total number of meters increases over the maximum address capacity of the existing injection point. The use of multiple injection points involves the use of multiple communication channels between the control center and the injection points. This may be in the form of leased or dial telephone lines. On systems which permit several injection points to employ shared lines, this requirement is reduced. Nevertheless, the lines comprise a significant percentage of the operating cost of the system. 4. Hybrid System The hybrid system is an amalgamation of two generic systems; VHF radio and high frequency power line carrier, the two being combined to accentuate the strong points of each. From both an engineering and operation standpoint, the strength of the radio system undoubtedly lies in its complete independence Gilbert /Commonwealth Iv-30 from the power system configuration and in consequence, the ability to communicate throughout the area regardless of the supply source arrangements, network configuration, modifications and "off normal" operating modes. A disadvantage is that for multiple functions at the end use customer location, separate receivers must be provided or, alternatively, single receivers with multiple functions must be installed. This latter will involve significant modification to the customers wiring with the attendant problems of compliance with the National Electric Code for older installations, expense, complaints and liability, both financial and legal. High frequency power line carrier systems, while being less dependent upon system configuration than the low frequency versions, are still sensitive to abnormal system operation, noise and system induced attenuation of signal strength. At the customer's location however, the injected signal is available at any point in his installation and comparatively simple receivers are possible at each controlled appliance location. In the hybrid system, communication via the VHF radio channel is between the central control and VHF receivers located at each low voltage transformer's secondary connection. In practice, only those transformers feeding a controlled customer would be so fitted. The VHF receiver contains a small, low power, high frequency oscillator and this tone coded signal is injected into the low voltage wiring upon receipt of an appropriately addressed radio signal. The carrier current signal is available throughout the low voltage wiring connected to the transformer secondary. The signal frequency is sufficiently high, typically about 200 kHz, that the severe attenuation across the transformer winding prohibits interference between two adjacent LV transformers and permits unique addresses to be used. Gilbert /Commonwealth Iv-31 Significant parameters in the use of hybrid systems are: The radio portion of the system may be either a VHF transmitter dedicated for use with the control scheme or may be the utility's existing VHF voice base station transmitter. The tone-coded control signal is compatible for use on a voice channel although small but usually insignificant delays of the control signal may be experienced on a heavy traffic channel. Installation of a separate radio channel for the system will follow generally those considerations already described for VHF radio systems with respect to land topography, proximity of urban areas, voice communication experience, requirement for multiple transmitters, and the like. Location of the VHF receiver/carrier retransmitter may be varied according to usage. Injection may be made anywhere on the low voltage transformer's secondary wiring. For overhead line construction, it is usually convenient to locate the receiver on the transformer pole and connect it directly to the transformer secondary terminals. Where pad mounted transformers or underground construction is encountered, receivers are available for pad mounted transformer use or alternatively for use at the meter location of any customer fed from the transformer. Regardless of the receiver location, all customers connected to the low voltage wiring associated with that transformer will receive a usable carrier signal. The coding system presently available will allow up to eight separate commands per transformer secondary and up to thirty-two groups of addressable receivers at the VHF signal level. It may be necessary to separate the commands for Gilbert /Commonwealth I¥-32 similar end-use loads on one transformer secondary to permit sequential load restoration and prevent overloading due to loss of diversity. This will result in an effective number of commands less than the full eight individual commands per VHF receiver. d. This system can be used to trigger changes in meter registers to accumulate kWh usage by time zones. Depending on the number of commands occupied for load control or metering requirements, spare commands may be available for fire calls or other ancilliary service functions. The application of hybrid radio/high frequency powerline carrier control to an idealized distribution system layout is shown in Exhibit IV-10. With only the low voltage distribution wiring forming part of the communication channel, the system is to all practical purposes immune to distribution network considerations. The VHF receiver/carrier current retransmitters may be connected to any low voltage transformer secondary winding circuits which are located within the transmitter service area. Carrier current receivers are located at the controlled equipment in the customer's building. The use of hybrid receivers for the control of network apparatus is possible but would have no benefits over a simple radio receiver. Exhibit IV-1l details the major components required to be added to an existing distribution network. The VHF transmitter may be for the sole use of the control system or alternatively, may be joint use of an existing base station. Factors which can influence cost for the hybrid system may be ‘ . summarized as: 1) Joint use of the existing VHF voice communication system and the hybrid load control system can effect substantial savings Gilbert /Commonwealth IV-33 | Z| | GENERATION AND “ TRANSMISSION f\ ee CENTRAL ——— CONTROL BULK SUPPLY SUB A POINT POWER SYSTEM NOT FORMING PART OF COMMUNICATION CHANNEL DISTRIBUTION 1A 2A 3A LINE L. V. DISTRIBUTION To? To! &R) Toi LOW VOLTAGE POWER SYSTEM SERVICE FORMING PART OF COMMUNICATION CABLE CHANNEL @) (Ni) CUSTOMER'S Ww) HYBRID CONTROL WIRING i RADIO PLUS H. F. POWERLINE CARRIER LOAD EXHIBIT IV - 10 ma VHF TRANSMITTER \—_—_—_ | CONTROL CENTER REMOTE TRANSMITTER CONTROL MAY BE MICROWAVE OR LEASED TELEPHONE LINES V.H.F. RADIO RECEIVERS CONVERT V.H.F. RADIO RECEIVERS LOCATED ON SIGNAL TO H.F. POWERLINE CARRIER EACH L. V. DISTRIBUTION TRANSFORMER FOR ONWARD TRANSMISSION TO SECONDARY FEEDING A CONTROLLED CUSTOMER'S RECEIVER. “- H.F. CARRIER RECEIVER HYBRID CONTROL FOR METERING FUNCTION COM PONENTS @® wr.canmenrecevess © FOR LOAD CONTROL EXHIBIT IV - 11 2) 3) in procurement, operation and maintenance of the radio portion of the link. However, this saving is at the expense of possible delays in control signal transmission for heavy traffic radio channels. If a separate radio channel is used cost sensitivities are similar to those discussed under the VHF radio control system. The hybrid system's major economic justification hinges on the number of controlled end-use loads being fed from the secondary of each low voltage transformer. As each end-use customer being controlled must share the transformer receiver/retransmitter cost, the economics are quite sensitive to the number of controlled customers per transformer. Each customer is allocated the cost of the carrier current receiver plus the appropriate proportion of the VHF receiver. This sensitivity suggests that the hybrid system is more suited to urban/suburban areas. This system, however, is quite compatible with the radio system. As a result, a combination system approach may be very attractive to the utility serving a mixed urban and rural service area. By applying the hybrid receiver/retransmitters to the urban transformers with a sufficient number of controllable loads, and radio receivers directly to the balance of end-use loads to control, the combination system could optimize both the functional utility and cost of the control system. Network changes have a minimum effect on an installed system. For all practical purposes, the communication channel is independent of the configuration of power system. The exception is that portion of the system which utilizes the low voltage transformer secondary connections (however, this is so insignificant that it may be neglected). By similar reasoning, power system faults can only incapacitate small portions of the control system. Gilbert /Commonwealth IV-36 Le 4) Location of the carrier current receivers within the customer's building is simple because the signal is available at all power outlets. The receivers may be installed directly at the location of the end-use appliance with only a minimum wiring modification involved. Df Telephonic and Direct Wire Systems Direct wire supervisory control systems have been used for a number of years for utility and industrial applications with much success. Systems using this form of communication have ranged from simple DC "on/off" switching or polarity change detectors for distribution system control to sophisticated high-speed, digital-coded signal systems for complete system control, indication and metering. The communication path used was commonly privately-owned overhead lines, multiconductor cables or for the high speed systems, leased telephone lines. Where telephone lines were used for the DC type systems, care had to be taken to ensure such routes contained all metallic circuits. One common characteristic of these systems is that they are limited to a few discrete terminals by virtue of the cost of providing unique circuits to each location from the control point. It follows, therefore, that the installation of direct wire lines for control of end-use utility customers' electrical loads would be uneconomic. However, the presence of the local telephone company's system does provide an equivalent facility which should not be ignored. This network presents an available, reliable and high quality communication channel which enters the vast majority of end-use customers' property. The telephone network can be extended to cover additional locations within the telephone service area at a minimum cost to the utility. Load control schemes using such telephone circuits on a shared basis are in the pilot project/test stage.! Such schemes have characteristics compatible with the general purpose automatic dial telephone system. These systems are available for use as one-way or two-way channels for automatic remote meter reading as well as control of end-use customer loads. In general, these systems share a common feature with other two-way systems; a dependence upon the central control to initiate an information interchange. End-use transponders may independently accumulate data, but cannot transmit this information except in response to an interrogation signal. This places the sole address capability at the telephone switching office equipment. It also greatly simplifies the end-use terminal. Message priority is the sole prerogative of the initiating terminal. Both circuit impedance modification and tone-coded, frequency-shift signals are used according to the system type. It should be noted that only the latter possesses the capability of transmission through a carrier link. Scanners for line interrogation are located at the telephone switching office. In some locations, existing equipment installed for routine telephone functions may be utilized. Although sufficient installations are not available to detect any trend at this time, it is quite possible that such equipment will remain under the control of the telephone company. For one-way load control use, the instruction is received by the end-use receiver and converted to an "on/off" function for the control circuitry. For a two-way system, in addition to receiving the load control signal, the unit will respond upon demand, and transmit to the central control, information fed to it by the meter encoders (or other sensors as applicable). One-way meter reading encoders are only capable of conveying information back to the control centers. Gilbert /Commonwealth Iv-38 Significant parameters in the use of telephone systems are as follows: CORLL Tee aC Ue These systems are completely immune from any effects of the operation of the electric distribution system. Although power is required for some customer use terminal receivers or transponders, built-in carryover batteries can be provided to preserve its function. Monitoring the supply status (i.e., on AC or DC power), can be used to retransmit signals to the central control indicating the geographical extent of power outages. Choice of communication system is limited in part, by the telephone company line equipment. DC signaling and line impedance modification type systems both require circuits suitable for the transmission of DC current and as such can only be used on continuous metallic circuits from the exchange main frame to the customer's terminal. Such circuits may contain loading coils but must be free of transformer coupling and similar isolation devices. Any use of carrier circuits or other multiplex links will render these systems inoperable. Tone-coded signals are compatible with all types of equipment commonly found on telephone networks. This coded format also enables individual customer addressing on multi-terminal shared lines. Should the present experience in trial installations of telephone control systems persist in the future, the predominate cost may be expected to be on a per line interrogation charge basis (analogous to the telephone per call charge). The implication of this is to encourage the development of hardware capable of reducing the number of calls required to achieve an end function. Generally, the higher the per call charge, the more the incentives will be to restrict the number of control signals sent, the bottom LV =39 line being a cost trade off between the call charge and the price of the logic hardware required to restrict the number of calls. An example of this is shown for two common types of controlled load. End-use appliances containing sufficient storage time may be switched directly for both the "off" and "on" inhibit function, thereby restricting the time off to the period of maximum benefit. Loads which require cycling during periods of control will force cost penalties as the multiple commands per control period would involve multiple charges for the use of the communication channel. To reduce costs, such cycled appliances may be provided with a local logic pretimed program activated once per day when demand control is required. After receipt of such a signal, the device reverts to the preset sequence of "off/on" cycles for a fixed elapsed time period, or possibly, as monitored by outside temperature, as may be appropriate. The use of this control procedure, while reducing cost, will result in longer outage periods (more hours of control) and possibly more customer complaints. Service is available only where connection can be made to a telephone line. It is expected that a small percentage of electric service customers will not have a telephone communication. In those instances the cost of telephone service installation must be added to the control system cost if the connected load warrants control (or if remote meter reading is required). Similar considerations apply when the control system is extended to cover the monitoring and/or control of distribution equipment such as capacitors or voltage regulators. In this instance, telephone line connection would be required at each control or monitored location. Gilbert /Commonwealth Iv-40 e. Although not classified as a load control system, a one-way remote meter reading facility using the telephone network may be a valuable addition to a load control scheme. The combination of a scheme to report back to the control center plus a one way control system may provide a versitile, low cost combination for areas where a fully automatic two-way system may not be justified. f. The location of equipment in the customer's property is flexible in that the meter encoders may be remote wired to the transponder. Similar remote wiring will be needed between the unit and the controlled end-use load. Encoders for one-way remote metering are located on the meter to be read and are wired to the telephone line incoming termination. All wiring within the property is exposed to customer interference. While the load control function may be defeated relatively easily, interference with the meter reading function will be readily detected. The application of a telephone address control system to an idealized distribution system layout is demonstrated in Exhibit IV-12. As no portion of the power system forms part of the communication channel, communication between the control center and the individual receivers is maintained regardless of network switching or abnormal operating routines. Receivers may be connected at any at any location serviced by the telephone company without further addition to the telephone distribution system. Exhibit IV-13 details the major components required for telephone control. Except for the customer located receivers, no additions or modifications are required to the distribution network, all Gilbert /Commonwealth Iv-41 GENERATION AND TRANSMISSION Jean CONTROL pene BULK "BULK SUPPLY 1 SUB B NO PORTION OF POINT = + POWER SYSTEM FORMS PART OF COMMUNICATION CHANNEL. DISTRIBUTION 1B 3B TELEPHONE CO. LINE CENTRAL OC OFFICE ey L. V. DISTRIBUTION _TRANSFORMER _ 7 Yr a ~ SERIE 3s o =o CABLE __ An) (M) ~ CUSTOMER'S — WIRING ry ag TELEPHONE ADDRESS CONTROL &, LOAD EXHIBIT IV - 12 at a CONTROL CENTER ADDITIONAL TELEPHONE LINES REQUIRED FOR POWER LINE MOUNTED EQUIPMENT TELEPHONE CO. CENTRAL &®) | OFFICE TELEPHONE CO. DISTRIBUTION SYSTEM 45 ae CENTRAL OFFICE COMPRISES: 1) CONTROL UNIT 2) CENTRAL OFFICE SELECTOR 3) DATE TERMINAL (R) REDEIVERS AM/OR TELEPHONE ADDRESS CONTROL Fo cusTonens COMPONENTS. EXHIBIT IV - 13 equipment being located at the control center and the telephone company's central office. Factors which influence the cost requirements for a telephone type system are difficult to summarize as the responsiblities shared between the various interested parties may vary widely. No firm trends are yet established but the following possible alternatives are examined. 1) The most capital-intensive alternative for the electric distribution utility will occur where the electric system provides all end-use customer equipment, the control center equipment and the telephone office data terminal. It is regarded as unlikely that the telephone company would permit outside ownership of office-installed test selectors or similar line scanning devices connected directly to the exchange main-frames. Another possibility is that the telephone company will provide all the central station equipment, including the central controller, line selectors and data terminal. In this case, the electric distribution utility would provide end-use customer equipment and installation. The telephone company would also provide interconnection facilities for the utility's billing computer (to read from the central office data terminal) and such other access facilities needed for load and distribution system control. Capital charges would be minimal with correspondingly higher per call rate charges. Responsibility for utilizing any additional capacity (such as reading water or gas meters) would be a joint effort of all parties concerned with the unavoidable coordination problems. Iv-44 1. 3) The most simple variation would be for the telephone company to own, install and operate the entire system, including end-use customers' equipment. The control of the system, as to when a meter was read, when a load was disconnected, would naturally be at the sole discretion of the utility. This approach is uncommon by today's methods of load control and system operation, but it cannot be dismissed without study. Should the system be so organized, the telephone company would sell a complete service not limited to the electric power utility, but including the gas department, water authority, security services, and any other customer for which this communication channel could perform a function, up to the limit of the capacity of the equipment. Charges in the form of a usage charge would predominate (with perhaps an initial connection charge) and all could benefit from the diverse use of the system. Capital charges incurred by the utility would be minimal, limited to a central controller, any required telemetering and perhaps the contactors necessary for controlling full-voltage end-use equipment. B. Cost Estimate of Load Control Equipment Direct Vendor Cost Components by Generic Type In considering the wide range of sizes and types of communication and control equipment to categorize, associated costs are difficult to quote in any generalized manner. Some components of a certain system may have become standardized, while other hardware is still in the development process. Some vendors provided hard, list price quotations, but others were less firm on price quotes because of either the cost sensitivity of matching the system components to a utility system configuration or the competitive nature of the load control market. Gilbert /Commonwealth Iv-45 In addition, certain costs were given as currently available while others were target priced for future full-production costs and for some systems, sufficient cost information was not provided to render a fair cost range. In short, load control system hardware costs were not found to be stable enough to provide firm quotes on component prices at this time. New entries into the market, as well as the demand for such systems, will continue to influence the market price. To preserve the usefulness of this section, the major components which make up each generic system type are listed so the reader may seek current vendor quotes on components required to meet his needs. The components listed should correspond to any vendor-proposed system make up. In order to provide a benchmark set of cost comparisons for the various generic systems, refer to the case studies. a. VHF Radio 1.0 Central control unit - The central control unit cost is a function of the utility's control philosophy (i.e., required flexibility in cycling control periods relative to appliances controlled). For a completely automated system, the central control unit must have the capability to monitor load conditions throughout the system and initiate a control period at a predetermined load level. Less expensive and manually initiated units are also available primarily for small installations. 2.0 Radio transmitters - The maximum rating of radio transmitters for this use allowed by the FCC is 300 watts. These transmitters are of standard vintage. 3.0 Radio receiver switch - The common, single-function audio tone receiver is available from several manufacturers. Multifunction units are also available Gilbert /Commonwealth Iv-46 at smaller production levels. Coded tone receivers are available at higher costs but have more versatile functions and address capabilities. One receiver per controlled appliance is normally required, however, the multifunction receiver can control several appliances per location. b. Power Line Carrier Using Low-Frequency Injection 1.0 Central control unit - The central control unit cost is a function of the utility's control philosophy (i.e. required flexibility in cycling control periods relative to appliance types), and the total number of appliances controlled. For a completely automated system, the central control unit must have the capability to 1) monitor load conditions throughout the system 2) initiate a control period at a predetermined load level. Less expensive and manually initiated units are also available primarily for small installations. Signal injection equipment - Costs for injection equipment are a function of the power line voltage at the point of injection. Signal injection at high voltage levels is significantly more costly than signal injection at low voltage levels. Consideration must be given to the number of injection stations as well (high voltage injection requires fewer injection stations versus low voltage injection which generally requires numerous injection stations). To summarize cost trade offs of this function, high voltage injection requires few injection stations at high costs per station versus low voltage injection requiring several injection stations at lower cost per station. Iv-47 OB 3.0 Receiver and control relay - Both functions are considered jointly as they are performed by a single piece of hardware. There are two distinct types of receiver switches: 1) electro-mechanical, 2) solid state. Electro-mechanical relays have been standard in overseas installation for three decades. Such production processes have been refined and reflect low costs per unit. Solid state receiver switches are relatively new with higher production costs per unit. Multi-function receivers are available at increased costs. Cc. Power Line Carrier Using High Frequency Injection 1.0 Central control unit - The incorporation of meter reading capability into the system places additional requirements of flexibility and capacity on the central control unit. A manual central control unit could not meet such requirements, the solution is a fully automated unit of significant cost. 2.0 Sector signal injection equipment - For practical purposes, the power of the transmitted signal is largely independent of the connected or the controlled system load. Line attenuation or the maximum number of addressable receivers per injection point is normally the limiting factor. Network changes, by virtue of (2) above, have a minimum effect on an installed system. Increasing load densities, if not accompanied by additional metering points, will not significantly change the signal quality. If the total number of meters increases over the maximum capacity of the existing injection point, an Gilbert /Commonwealth Iv-48 d. 3.0 4.0 5.0 existing sector may have to be sub-divided and an additional injection point installed. Customer's receiver, control relay, encoded message transmitter - These functions are generally incorporated into a single piece of hardware. Solid state construction is utilized, and is anticipated to keep costs down at full production levels. Each receiver is capable of controlling more than one appliance, however, an additional control relay may be required for each new appliance. Customer's meter reading encoder - The methods for encoding the consumers kWh usage vary among vendors; however, the costs per unit are similar because of the competition between vendors. Sector encoded message receiver - This function may be incorporated into a common unit with the sector signal injection equipment and will reflect similar cost sensitivities. Hybrid-Radio/Power Line Carrier 1.0 2.0 Central control unit - This unit comprises the master controller for tone-code generation and a mini computer for telemetered bulk supply point information and readout. Prices of the master controller depend upon the facilities required. The mini computer prices depend on the number of remote telemetering points as well as the degree of automation in issuing system commands. Radio channel - Compatibility of the control system with a regular VHF two-way voice system permits the use of Gilbert /Commonwealth Iv-49 existing radio facilities for this portion and no additional charges are involved if this option is taken. The widespread use of land mobile communications may reduce the need to provide a separate transmitter purely for load control purposes due to such considerations as traffic density or security. 3.0 Radio receiver, power line carrier retransmitter - These functions are performed by one device. The units may be pole mounted for overhead distribution system or mounted on a customer's meter base to cover underground systems. One unit will receive a transmitted signal and retransmit to all customers served by one transformer. 4.0 Power line carrier receiver, control relay - These receivers are suitable for the control of a single appliance. A variation of this device is available with customer override facilities at an additional charge. e. Telephonic and Direct Wire Control 1.0 Telephone Office Equipment - This equipment consists of a central control unit (to act as the interface between the electricity personnel and the telephone system), the central office selector (for originating the calls) and the data terminal (for receiving and storing the transmitted information from the customer's meters and subsequent retransmission to the utility's billing center). This set of equipment would be, in all probability the responsibility of the telephone office. Costs are expected to vary from office to office according to the availability of existing suitable equipment. Costs would appear not as direct costs to the system but as SSS Iv-50 2. call charges on an ongoing basis. In trial installation tests, a flat fee has been charged similar to the per circuit installation charge levied for the connection of leased circuits. Customer's Installation - This hardware consists of the meter encoders, transponder and the necessary contactor equipment for full voltage controls. Indirect Non-Vendor Cost Components by Generic Type In addition to those vendor quoted items listed in previous pages, the investigation surfaced a set of less obvious, but additional costs to be borne by the utility, associated with each generic type of load control system. Non-vendor costs include installation and support equipment costs which may make up a significant portion of the total system costs. as VHF Radio 1.0 2.0 « Support equipment - Supply point telemetering is required on a sufficient sample of the total load so as to enable an accurate estimate of system demand. Communication links: 2.1 Remote RF transmitters - There are several communication channels which can be adapted to this function. Telephone, microwave, and VHF radio are all possible alternatives. Existing telephone lines are easily adapted to form this communication link. Direct costs are minimal. However, the costs of leasing lines may account for Iv-51 2.2 a large percentage of the ongoing operating expenses. Microwave and VHF radio communication links require substantial direct costs with a minimum of ongoing expenses. Supply point telemetering - Generally, the most economic method of interconnection for the telemetering system (substation to control center) will be by means of leased telephone lines. 3.0 Installation and Maintenance: Beil Central control and telemetering installation and maintenance - The magnitude of the work involved in the installation of the central control equipment will depend upon the complexity of the control to be used. Actual installation costs of the major pieces of equipment should not vary significantly as these will be received as self-contained, freestanding units. Interconnection costs will vary with the amount of external devices, control points, remote alarms, telemetering, etc. Installation of telemetering transmitters at the bulk supply points will vary between the extremes of adding transducers to existing potential and current transformer wiring and the procurement and installation of complete metering units where suitable existing facilities are not available. Maintenance of this equipment is limited to periodic cleaning and inspection. Trouble diagnosis and repair requirements should be Gilbert /Commonwealth LV 2 infrequent and are expected to be relatively straightforward. Transmitter installation and maintenance - As the use of VHF two-way voice communications by electric utilities is now almost universal, it is assumed that a transmitter site, housing and antenna tower is available for the installation of the load control transmitter and the antenna. Installation charges would be therefore limited to man-hour charges incurred in placing the transmitter cabinets, wiring power supply and control circuits, antenna erection and running the antenna co-axial feeder. Experience with similar voice transmitters has shown startup and adjustment requirements to be minimal. The only remaining initial charges are those associated with the FCC licensing application preparation. Maintenance charges are minimal, the manhour requirements are on the order of one visit per month for cleaning, inspection and possible minor adjustments. End-use receivers - The receiver switch installation costs will vary with each placement. Locating the switch at the service entrance panel board requires some rewiring. This may require the hiring of contract electricians to meet the minimum standards prescribed by the National Electric Code. However, where installation is adjacent to the controlled appliance, the use of utility personnel will lower the total costs. The maintenance of receiver switches is affected in a similar manner to meters. A faulty receiver is generally changed Iv-53 out and replaced with a new unit. Tests are performed on selected components which are easily replaceable if found to be defective, otherwise the unit would be discarded. 4.0 Initial Test and Debugging This function would comprise initial transmitter setup adjustments, modulation and loading adjustments, and verification that the transmitter is operating within the limits imposed by the FCC station license. Initial tests are required to calibrate the telemetering equipment. A check of the operation of the central control equipment for correct operation codes for each command is also necessary. Where multiple transmitters are utilized, sequential operation should be verified to ensure that no mutual interference is present. It is not anticipated that extensive field strength measurements would be required or that customer installation tests would require more than a few random samples. b. Power Line Carrier Using Low-Frequency Injection 1.0 Support Equipment: 1.1 Supply point telemetering is required on a sufficient sample of the total load so as to enable an accurate estimate of system demand. Injection equipment - In addition to the electronic portions of the injection station (i.e. tone generators, signal processors etc.), the injection equipment includes the power line coupling IV-54 components, the isolation transformers, capacitors, tuning inductors, circuit connection devices and protective systems. The two latter devices are not included as part of the purchased load control equipment. According to the voltage at the point of injection, these connection devices may range from a fuse disconnect to a fully protected feeder bay at a major switchyard and comprising the required bus bars, circuit breaker, disconnects, protective relays, etc. Connection from the system to the injection equipment may involve overhead jumpers or, more commonly, insulated cables running from the system connection device location (breaker, fuse) to the location of the injection equipment. According to the manufacturer's design specification, the injection equipment may be suitable for either indoor or outdoor installation. If the equipment is of the indoor type, building space must be available or constructed. If the outdoor type is required, the associated mounting slabs and support structures will have to be provided. 2.0 Communication Links: 2.1 Remote injection stations - There are several communication channels which can be adapted to this function. Telephone, microwave, and VHF radio are all possible alternatives. Existing telephone lines are easily adapted to form the communication link. While direct costs are minimal, the costs of leasing lines may account for EV=55 2.2 a large percentage of the ongoing operating expenses. Microwave and VHF radio communciation links require substantial direct costs with a minimum of ongoing operating expenses. Supply point telemetering - Generally, the most economic method of interconnection for the telemetering system (substation-to-control center) will be by means of leased telephone lines. 3.0 Installation and Maintenance: 3.1 Central control and telemetering, installation and maintenance - The magnitude of the work involved in the installation of the central control equipment will depend upon the complexity of the control to be used. Actual installation costs of the major pieces of equipment should not vary significantly as these will be received as self-contained, freestanding units. Interconnection costs will vary in relation to the amount of external devices, control points, remote alarms, telemetering, etc. Installation of telemetering transmitters at the bulk supply points will vary between the extremes of adding transducers to existing potential and current transformer wiring and the procurement and installation of complete metering units where suitable existing facilities are not available. Maintenance of this equipment is limited to periodic cleaning and inspection. Trouble diagnosis and repair requirements should be infrequent and are expected to be relatively Gilbert /Commonwealth IV-56 3.2 3.3 straightforward, with the possible exception of the more complex multi-command coded equipment. Injection equipment - This equipment includes the installation of support equipment, the injection equipment and provision of a station auxiliary power supply adequate for the required injected power (in the order of 500 kVA for a 500 MW controlled system). Maintenance charges would be comparable with normal power system maintenance requirements for equivalent size equipment. End-use receivers - Receiver switch installation costs are a function of placement (i.e. at the service entrance panel board or adjacent to the controlled appliance). Installation at the service entrance panel board, almost mandatory for multi-function receiver switches, requires rewiring of the supply circuit to the end-use appliance. This policy may require the hiring of contract electricians to meet the minimum standards prescribed by the National Electric Code. Installation adjacent to the controlled appliance may be effected by utility personnel at a lower cost. Maintenance costs at this stage of development of domestic projects are largely indeterminate. Due to domestic labor rates, it is anticipated that receiver switches would be handled in much the same manner as existing customer meter practice. Gilbert /Commonwealth Iv-57 4.0 Initial Test and Debugging: Initial testing comprises checking the operation of the injection equipment and adjusting the tuning inductors for the required signal level with the distribution network in the normal operating configuration. Initial tests are required to calibrate the telemetering equipment and check the central control equipment for correct operation codes for each command. Signal strength measurements are normally limited to a few sample points on each system fed by an injection point, concentrating on feeder ends or locations downstream from line capacitors or installations of large power factor capacitors. Areas where high line noise is detected should be examined for adequate signal strength or correction of the noise problem. Individual testing at each customer installation is not considered necessary. Cs Power Line Carrier Using High-Frequency Injection 1.0 Support Equipment: 1.1 Supply point telemetering is required on a sufficient sample of the total load so as to enable an accurate estimate of the system demand. 1.2 Connection equipment required for each unit is a function of the location of the installation. The appropriate equipment is detailed in the installation section. Gilbert /Commonwealth IV-58 2.1 2.2 2.0 Communication Links: Sector injection equipment - The use of multiple injection stations involves the use of multiple communication channels between the control center and the injection stations. This may be in the form of leased or dial telephone lines. On systems which permit several injection points to employ shared lines, this requirement is reduced. While direct costs of such communication links are minimal, associated ongoing costs may account for a significant portion of total operating costs. Due to the large number of injection stations, microwave radio would not seem to be an economical solution for this function. VHF radio may be an economical answer, noting the direct costs of such a system are significant and operating costs are minimal. Supply point telemetering - Generally, the most economic method of interconnection for the telemetering equipment (substation-to- control-center) is by means of leased telephone lines. If two-way meter reading facilities are provided by the control system, then the telemetered bulk supply point quantities may be transmitted over the remote meter reading channel, providing sufficient time is available in the meter reading program for the repetitive interrogations required for this function. Gilbert /Commonwealth Iv-59 3.1 3.0 Installation and Maintenance: Central control and telemetering, installation and maintenance - Should the high-frequency power line carrier equipment be used for load control purposes only, the installation costs of the central control equipment would vary according to the complexity of the control desired. However, the variance should be in the same order of magnitude as other one-way systems. Such variations would be minimized due to the major pieces of equipment being supplied as self contained units. The difference is due to the variations in the number of interconnections to external devices. If, on the other hand, a full two-way, remote meter reading and control system was involved, the installation costs would rise sharply. These costs would include not only the remote telemetering cabinets but the computer required for the meter reading program, address capability, retrieval of the meter reading and subsequent processing prior to transferring the information to the appropriate billing computer. Installation costs for the telemetering transmitters at the bulk supply points will vary between adding transducers to existing potential and current transformer wiring and the procurement and installation of complete metering units where suitable existing facilities are not available. Maintenance of the equipment is limited mainly to cleaning and inspection. Trouble diagnosis and repair requirements should be infrequent with a one-way control system but significantly increasing Gilbert /Commonwealth Iv-60 in frequency and complexity with the two-way system. Injection equipment - Due to the limited range of the high-frequency signal, the majority of applications will result in the injection point being located on the medium voltage system and covering one or at the most, a few feeders from one distribution substation. Two basic injection locations must be considered, at the substation bus bar or on a feeder remote from the substation. Where the equipment is installed within a distribution substation, space must be provided together with the required system connection equipment (circuit breakers, fuses, etc. as necessary). The installation, must be designed in such a manner that the control equipment does not hazard the substation bus. The fault interrupting duty at this location will often dictate the use of protective devices in excess of the rating needed for the injection equipment. However, equipment in this location will frequently service a large number of end-use receivers. Problem areas discovered after installation due to line attenuation, capacitors, and similar causes of poor signal strength, should be cured at the individual trouble spots by repeaters, traps, etc. because of the costly alternative of moving an injection point. Feeder-mounted equipment generally covers fewer end-use receivers per injection point. This equipment is small and installed simply on an Iv-61 existing line pole. Coupling to the line, with a fuse and surge arrestor, is inexpensive and the existing feeder protection may be used as backup without hazarding an appreciable portion of the power system. The somewhat unpredictable performance of the power system at the signal frequencies is less of a potential problem as the pole location of the injection unit may be easily and inexpensively changed if trouble is encountered. Not all equipment available may be suitable for line installation. End-use receivers - The use of power line carrier permits the receiver to be located at any point on the customer's wiring. The signal is present wherever electric service is available. However, the use of the receiver unit for retransmitting the local meter reading requires that the unit be installed at the customer's meter location. Current designs are compatible with the single phase house service meter socket. The units are fitted as an extension of the plug-in meter base. Connections from the meter position to the end-use load location are required in the form of low voltage "thermostat" wiring. Additional contactors are required where full voltage end-use load are to be controlled. This wiring technique will reduce the total installation costs by minimizing changes to the customers' wiring. Maintenance for receivers would be handled in a similar manner to the existing house service meters (i.e. a changeout program). Charges would be due to time, transport and the provision of suitable repair facilities. Faulty meter encoders for the IV-62 two-way system could be changed in the field, but it is questionable if this action would be advisable. Injection units installed in substations would be subjected to periodic maintenance and local repair at that location is possible. Pole-mounted units would be replaced by a spare and the faulty unit would be returned to the service facility for repair. Initial Test and Debugging Initial testing comprises initial injection equipment setup and adjustments would be minimal. Tests are required for each command for one-way systems to verify the correct operation of end-use receivers and spot field measurements would be required at selected points covered by each injection unit. Systems with two-way facilities would require extensive initial software verification followed by an individual address signal and reply to ensure correct response and processing. Any receiver failing to respond would require site investigation at the end-use location or the injection unit. Telemetering calibration would be required on each circuit provided from the bulk supply points. d. Hybrid Radio/Power Line Carrier 1.0 Support Equipment Supply point telemetering is required on a sufficient sample of the total load so as to enable an accurate estimate of the system demand. Iv-63 2.0 Communication links; Remote RF transmitter 2.1 There are several communication channels which can be adapted to this function. Telephone, microwave, and VHF radio are all possible alternatives. Existing telephone lines are easily adapted to form this communication link. While direct costs are minimal, the costs of leasing lines may account for a large percentage of the ongoing operating expenses. Supply point telemetering - Generally the most economic method of interconnection for the telemetering system (substation to control center) will be by means of leased telephone lines. 3.0 Installation and Maintenance: 3.1 Central control and telemetering, installation and maintenance - The magnitude of the work involved in the installation of the central control equipment will depend upon the complexity of the control to be used. Actual installation costs of the major pieces of equipment should not vary significantly as these will be received as self-contained, freestanding units. Interconnection costs will vary in relation to the amount of external devices, control points, remote alarms, telemetering, etc. Installation of telemetering transmitters at the bulk supply points will vary between adding transducers to existing potential and current transformer wiring and the procurement and installation of complete metering units where suitable existing facilities are not available. IvV-64 Maintenance of this equipment is limited to periodic cleaning and inspection. Trouble diagnosis and repair requirements should be infrequent. Transmitter installation and maintenance - as the use of VHF two-way voice communications by electrical utilities is now almost universal, it is assumed that a transmitter site, housing and antenna tower is available for the installation of the load control transmitter and the antenna. Installation charges would be limited to man-hour charges incurred in placing the transmitter cabinets, wiring power supply and control circuits, antenna erection and running the antenna coaxial feeder. Experience with similar transmitters has shown startup adjustment requirements to be minimal. The only remaining initial charges are those associated with the FCC licensing application preparation. Maintenance charges are small. Manhour requirements are on the order of one visit per month for cleaning inspection and possible minor adjustments. It should be noted that, none of these transmitter related costs are applicable if the existing radio communications facilities is utilized for the radio portion of the hybrid scheme. End-use receivers - Receiver installation costs are low due to the facility for location adjacent to the controlled apparatus. Such installations may be performed by utility personnel. Iv-65 e. Installation of the VHF receivers will involve the use of a service line crew for pole-mounted units. Maintenance of both end-use and VHF receivers is assumed to be on a change-out basis, where the malfunctioning unit is replaced by a spare unit. Tests are performed on selected components which are easily replaceable if found defective, otherwise the unit would be discarded. 4.0 Initial Test and Debugging These tests would be similar to those for a radio system with respect to the radio transmitter, control, telemetering and field strength measurements. Verification that the VHF receiver is retransmitting the command over the low voltage transformer secondary wiring is required. A portable, low-power VHF test set is available to test for code injection and check of the customer's receiver function. A single test per VHF receiver should be sufficient unless trouble is encountered. Telephonic and Direct Wire Non-Vendors costs are largely indeterminate at this time. These non-vendor costs are subject to numerous and significant variables. While the end-use customer installation charges may be on the same order of magnitude as other load control systems, the low capital cost of this system is compensated for by usage charges. Trials to date have resulted in a variation of charges based upon a per line interrogation for each meter reading command Gilbert /Commonwealth IV-66 or each load control signal. No meaningful estimate of the charges can be made at this time because of the variation in charges according to location and the difference in equipment supplied by the telephone company (ranging from the central office selector only to the complete equipment, including the customer's installation). An estimate of the actual charges must be made for each specific location. Maintenance charges should be restricted to those incurred by a customer's equipment changeout program and return of the faulty units for inspection and repair. Should the telephone company operate the entire system on a lease basis, maintenance charges would be included in the rate charge. IV-67 SECTION IV - FOOTNOTE J. A. Serfass, R. K. Adams, H. M. Long, "Field Demonstrations of Communications Systems for Distribution Automation". IEEE 1978 Region Six Conference Record. Electronics in Resources Management, Algamogordo, New Mexico. IEEE Catalog No. 78CH1316-9 Reg. 6, p. 36-42. Gilbert /Commonwealth IV-68 SECTION V BENEFIT/COST ANALYSiS For an individual utility, the merit of load control hinges upon a favorable balance of potential benefits over inherent costs. Further, the relative merit of alternative types of load control systems is a function of the relationship between their respective benefits and costs. Obviously, if all systems produce the same benefit for the same period of time, the least costly system (considering all elements of current and future cost) is the best economic choice, all other things being equal. There are a number of economic measures of project merit. Among these, the following will be treated in this discussion: te Net Present Value 25 Benefit/Cost Ratio a Payback Period Each of the first two methods is dependent upon present worthing procedures. That is, they recognize the time value of money. Net present value (NPV) is established as the difference between the respective present worths of project benefits and costs, or conversely the present worth of annual differences between benefits and costs. Some analysts prefer the NPV method of project evaluation because it explicitly defines the magnitude of potential savings or other net benefits. This is particularly useful where project benefits vary appreciably between alternative programs. Since, in the instant case, the principal benefit of load control is considered to be the capacity cost savings in generating plant or purchased power expense, direct load control benefits are the same for any system capable of accomplishing the prerequisite load control. As a consequence, the Benefit/Cost Ratio method serves as a more direct indicator of economic feasibility. The Benefit/Cost Ratio is a relatively easy test to make and is a reliable measure of economic priority, particularly where benefits are generally static as between alternative load control systems. The suggested methodology which follows relates to the development of the Benefit/Cost Ratio. The Payback Period application will also be treated subsequently. Benefit/Cost Ratio Methodology It would appear obvious that if the benefits to be derived from a course of action exceed the costs of achieving those benefits, the undertaking is a worthy one, all other things being equal. The Benefit/Cost (B/C) Ratio is an economic measure based on the ratio of Benefits to Costs. In its strictest sense, a ratio better than unity is indicative of project worthiness. On the other hand, relative B/C ratios are not necessarily a realistic criterion for evaluation between alternative projects. For an exaggerated (but legitimate) example, an investment of $100,000 to produce a $200,000 benefit may very well be considered to have priority over a $1,000 investment to achieve a $3,000 benefit, even though the B/C ratio of 3:1 in the latter case is greater than the 2:1 ratio produced by the former. The virtues of the Net Present Value approach may be seen from this application. However, for the evaluation of load control systems, at least for one-way systems, the compelling benefit for utilities is in every case the same--the potential reduction of capacity costs. In this specific context, the B/C ratio therefore serves as a valid measure of the relative merit of alternative solutions. In order to properly compare costs and benefits, they must, of course, be stated on a comparable basis. Load Control Systems represent a sizeable “up front" investment to provide benefits that will hopefully prevail throughout the lifetime of the apparatus installed. Consequently, equalization of timing differences is of primary importance in equating benefits and costs. The Levelized Annual Equivalent basis proposed in this application equalizes these factors. 1. Development of Levelized Annual Costs Determine Alternative Investment Costs - The criteria for developing total load control system installed costs have been described in Section IV of this Report. As indicated, different components make up the alternative systems under review and variances in operating procedures produce differences in costs of installation and similar other factors as well. Establish Fixed Charge Rate - To express load control system costs in terms of a single initial cost would, from the ratepayer's viewpoint be a misstatement of the fact. For a non-profit municipal or cooperative electric system, the debt vehicle is generally either Municipal Bonds or REA type loans. Since, generally, no stockholder costs are involved, the cost of money relates solely to debt service and, of course, income taxes are not incurred. In addition to the above annual costs, property taxes may be assessed by local authorities. Insurance or other similar costs may be considered desirable. All of these factors may be most conveniently expressed in a Fixed Charge Rate which when applied to the total investment yields the levelized annual system costs exclusive of operation and maintenance expenses. The Fixed Charge Rate then consists of: Cost of Capital Depreciation Property Taxes Property Insurance if applicable Other Annual Costs if applicable The Cost of Capital is simply the annual interest rate for current debt vehicles or, for stock companies, the weighted average current cost of all components of capitalization in a desired mix. The Cost of Capital thus established may generally be assumed as the minimum acceptable rate of return and consequently, establishes the discount rate to be used in all present worth determinations. In the context of a Fixed Charge Rate, depreciation is expressed as the annual Sinking Fund factor. This factor when applied to investment cost, yields the levelized annual deposit which, at a compound interest rate equivalent to the cost of capital, will produce an amount equal to the original investment over the service life assumed for the load control system. For even discount rates, this factor may generally. be found in compound interest tables. In the case of other discount rates, the factor may be determined from the following formula: Depreciation i Factor ae ee? where i = interest (discount) rate Cy =? and n = average service life Together, the Cost of Capital and the Depreciation Factor constitute the Capital Recovery Factor. Gilbert /Commonwealth vV-4 Ce Generally, property taxes, property insurance, etc. are already levelized in that they represent fixed annual amounts which may be expressed as a percent of investment. Consequently, this established percentage relationship may be directly incorporated into the Fixed Charge Rate. Where variation in future levels may be reasonably anticipated, annual charges over the life assumed must be present worthed to current levels and converted to annual equivalents by means of an annuity factor. Where it applies, Income Tax is the most complex component of the Fixed Charge Rate. Treatment varies by tax source and because of specific options adopted in individual applications. In keeping with the other components of the Fixed Charge Rate, income taxes are expressed as the annual equivalent of the present worth of income tax obligations over the life of the investment. Because of this complexity, many companies employ a computer program to develop annual fixed charges and a levelized fixed charge rate. Apply Fixed Charge Rate to Investment Costs - Since the Fixed Charge Rate has been established on a levelized basis, the annual equivalent fixed investment costs for comparative purposes result directly from application of this rate to installed costs as previously determined. Determine Levelized Annual Equivalent Operation & Maintenance Expenses - In addition, annual operation and maintenance expenses associated with the various systems must be recognized in the total cost stream. The basis for the estimation of O&M expenses has been previously detailed in Section IV. In connection with the economic analysis, it is appropriate to recognize future escalation of O&M expenses as developed at present cost levels. Finally, levelized annual operation and maintenance expenses are represented as the annual equivalent of the present worth of escalated expenses over the life of the investment. For illustrative purposes, consider this example of constructing levelized annual O&M expenses for one of the generic load control systems: O&M Present Worth Expense Factor Amount O&M Expenses As Developed: $15,354 -917431 $ 14,086 Anticipated Expenses at 7% Annual Escalation: 16,429 -841680 13,825 17,579 .772183 13,574 18,810 ~ 708425 13,325 20,127 649931 13,081 21,535 596267 12,841 23,043 -547034 12,605 24,656 501866 12,374 9 26, 382 -460428 12,147 10 28,229 -422411 11,924 1l 30,204 387533 11,705 12 32,319 355535 11,491 13 34,581 326179 11,280 14 37,002 299246 11,073 15 39,592 274538 10,870 Total $186,204 Annual Annuity Factor 124059 Annual Equivalent $ 23,100 In this illustration, a discount rate of 9% was assumed. For even, or other commonly used discount rates, both present worth and annuity factors may be determined directly from compound interest tables. In other cases, the following formulae may be applied: V-6 eee discount rate Present Worth Factor = (i+i)™ year and: Annunity Factor = » where i = discount rate 1-V vie present worth factor in final year. Summarize Levelized Annual Costs - Total costs, for analysis purposes, are the summation of levelized annual fixed costs and operating expenses associated with load control systems. Development of Levelized Annual Benefits For any utility, the overwhelming benefit of load control is the potential savings in capacity cost either in generating plant and/or purchased power expense. This is not to imply that other benefits may not accrue, but it would appear that basic justification must reside with this factor. Consequently, this illustrative Benefit/Cost Methodology is predicated on the potential benefit of capacity cost savings. Determine Potential Current Capacity Cost Savings - Having defined appliances to be controlled, their potential diversified demand and a load control strategy to achieve maximum cost advantage, total controlled load in each month of the year may be determined. In order to translate the respective control levels into potential capacity charge savings, present or prospective bills for electricity are calculated on a month by month basis both before and after adjustment of billing demands to reflect load control. To the extent that carryover ratchets are imposed, the full impact of load control may be somewhat restricted until the second year of operation, and seasonal demand fluctuations may impose ratchet limitations even thereafter. Annual net savings representing the difference in calculated billings with and without load control should be reflected for each year throughout the projected life of the load control hardware. Since it appears reasonable to assume that bulk power billing rates will undergo continuing upward adjustments, it is likely that annual net savings will escalate over the forecasted period. In order to quantify generating plant capacity cost savings, a comparison must be made of capacity required to meet the demand forecast with and without load control. Of course, a prerequisite for this comparison is a capacity expansion plan for both forecasts. The method for developing the capacity expansion plan will vary with each utility. In some cases a detailed capacity expansion plan will already be in place and in other cases no plans for future capacity additions will exist. This report does not attempt to describe how capacity expansion plans are developed. But, there are key issues to be considered when modifying or developing a capacity expansion to incorporate load control. These key issues are: a) Load control of existing appliances can generally not displace base load capacity without increasing fuel costs. Load control of existing appliances is essentially equal (in value) to peaking capacity. Load control cannot alter fixed capacity costs which are in place or committed. vV-8 d) Load control can defer capacity costs which are not fixed or committed. Convert Potential Future Savings to Levelized Annual Equivalents - Once again, in order to express all terms on a comparable basis, future capacity cost savings are converted to levelized annual equivalent amounts through the application of present worthing techniques. The capacity cost saving in each future year is reduced to its present worth under the discount rate applicable. The cumulative present worth of savings in all years is converted to a levelized annual equivalent amount by means of the annuity factor previously defined. Summarizing Costs and Benefits for Comparative Analysis Comparative costs and benefits are conventionally measured in terms of a Benefit/Cost Ratio. Since the ratio is developed by dividing project benefits by project costs (expressed throughout this procedure in terms of annual equivalents) a ratio in excess of unity is indicative of a favorable evaluation status, all other things being equal. A flow diagram tracing each step of the Benefit/Cost Ratio methodology is included as Exhibit V-l. B. Payback Periods As a further measure of project acceptability, individual payback periods may readily be determined. The Payback Period is defined as the number of years required to recover original investment from net returns before depreciation but after taxes (if applicable). EXHIBIT V-1 BENEFIT/COST ANALYSIS FLOW DIAGRAM SURVEY NUMBER AND LOCATION OF POTENTIALLY CONTROLLABLE LOADS 2. veveLor CONTROL STRATEGY costs a BENEFITS * a IDENTIFY CONTROL DEVELOP DIVERSIFIED SYSTEMS COMPATIBLE DEMAND ESTIMATE WITH LOAD D1STRIBUT! ON PER CONTROL POINT x x SCREEN IDENTIFI srsites ron Perarisiuity SALAS COAL MONTHLY LOAD REDUCTION WITH LOAD CONTROL STRATEGY Gesture cade AND REGULATORY CONSTRAINTS ws x ESTIMATE ANNUAL CALCULATE DIRECT COSTS ADJUST ACTUAL MONTHLY OPERATING EXPENSE FOR CANDIDATE SYSTEMS BILLING DEMANDS TO INCLUDING COMMUNICATION BASED ON MUNBER AND REFLECT REQUCT!ON LINK cOsTS LOCATION OF CONTROL POINTS DUE TO LOAD CONTROL ¥ ¥ x ESTIMATE ANNUAL auntitee ames DeveLor CALCULATE CAPACITY COSTS "ictus Lainie NOK-VENOOR WITH ADJUSTED DEMANDS Coiba Flues costs UNDER PURCHASED PONER RATE ¥ | ¥ a aural GIES CURRENT SAVING EQUALS DIFFERENCE IN CAPACITY OM EXPENSE INSTALLED OBST). £O8 COSTS WITH AND WITHOUT CANDIDATE SYSTEMS fis GonitaL a7 ¥ ¥ APPLY ESCALATION FACTOR DeveLor APPLY ESCALATION FACTOR TO DEVELOP PROJECTED FIXED CHARGE TO DEVELOP PROJECTED ANNUAL O&M EXPENSE RATE ANNUAL CAPACITY COST SAVINGS cz + ¥ APPLY PRESENT WORTH APPLY FIXED CHARGE APPLY PRESENT WORTH FACTORS TO DEVELOP RATE TO DEVELOP LEVELIZEO FACTORS TO DEVELOP Pw OF FUTURE OtM ANMUAL FIXED. CHARGES PH OF FUTURE SAVINGS x + + APPLY ANNUITY FACTOR LEVEL IZEO APPLY ANNUITY FACTOR TO LEVELIZE PH -—— ANNUAL TO LEVELIZE Pu OF FUTURE OLM ORM EXPENSE OF FUTURE SAVINGS x _¥ it jaa LEVELIZED ANNUAL LEVELIZED LEVELIZED meets ee, Pe ILLARY ANNUAL COST ANWUAL BENEFITS Fencriens (THO WAY SYSTEMS) = BENEFIT COST RATIO FoR EACH CANDIOATE SYSTEM ¥ EVALUATION OF LOAD CONTROL FEASIBILITY AND ALTERNATIVE SYSTEMS By definition, the payback period is completed in that year when cumulative net savings equal or exceed the original installed cost of the system under analysis. Sensitivity Analyses Inevitably, some assumptions must be made in the course of economic analysis. Although based on the best available information, they may, if in error, bias an investment decision. In order to measure the impact of certain pivotal estimates or assumptions, the analysis results should be redefined in terms of alternate determinants. In the Case Studies, project benefits and costs have been uniformly developed on the basis of a 100% acceptance rate; that is, agreement by all customers with potentially controllable loads to accept load control. Obviously, this may very well overstate the actual circumstance. In order to measure the impact of varying acceptance rates, control system costs are segregated into fixed and variable components. The fixed component covers certain central system costs which are inherent in the system and therefore apply at all acceptance levels. On the other hand, certain other costs are directly proportional to the number of installations, and the total cost at any acceptance level is a combination of the fixed cost and the cumulative variable costs for that number of installations. Since capacity cost savings vary directly with the amount of controlled load, benefits are linear from zero to that level established at the 100% acceptance rate. In combination, relative costs and benefits may be determined at any acceptance rate, and critical acceptance levels may be defined. As a further test of sensitivity, estimated project costs may be adjusted either upward or downward by a fixed percentage. The effect of escalation may be readily determined by restating the analysis v-10 without consideration of inflation, particularly that reflected in future capacity cost savings. Customer Incentives On an economic break-even basis, the maximum dollar incentive than can be provided to the customer can be derived given the annual equivalent costs and benefits for each generic type of communications and control equipment and specific control strategies for a given level of customer participation. Dividing the net benefits by 12 for conversion to a monthly time frame, the customer incentive becomes: (By - ¢)) 12N, = Monthly customer incentive = Annual equivalent cost for generic type 1 at Nj = Annual equivalent benefits for generic type 1 at Nj = Participation level of customers at CI), Note that because of the interrelationships of these parameters, no independent variable exists. Comprehensive customer surveys are thus necessary to identify to what extent customer participation is affected by perceived benefits and/or incentives. In a more general sense, a load control program is viable if the incentive (both long term and short term) required by the average participating customer is less than or equal to the possible customer incentive for the number of customers participating. (The possible incentive level is provided in the above equation). In this regard, all benefits should be viewed from the perspective of the customer. This assures that a valid cost/benefit analysis is conducted in examining the feasibility of load control. If communication of all costs and benefits is adequate, the average customer's decision is an economic one, even if implicit. Therefore, V-11 if benefits are diluted by not specifically identifying savings returned to the customer as being derived through load management, or by distributing them to all customers rather than participating customers, a distortion of this economic decision is created, confusing a clear evaluation of the program. To illustrate how the customer incentive variables interrelate, consider the following: If the fixed costs of a load control system are relatively high in relation to the variable costs and the number of customers participating is relatively low, then the cost per customer will obviously be high. If the net benefits per customer (savings less load control program costs per customer) controlled are not significant enough, the possible customer incentive may not be sufficient to be acceptable to the average customer over a long period. Furthermore, if the subsequent customer participation is too low, net benefits cannot be sustained. Finally, if benefits do not remain clearly greater than costs, the program will obviously be infeasible. As noted above, the threshold incentive level at which customers will reject a specific load control program as not worth the interruption of certain appliances, can only be ascertained by a comprehensive survey over several years. Ideally, this should be performed in conjunction with a pilot load control program. Gilbert /Commonwealth V-12 SECTION VI CUSTOMER SENSITIVITIES This Section describes the experience of Osage Municipal Utilities, an APPA member, with its load management program and customer sensitivities. SIGN UP INCENTIVES The Osage Load Management program was instigated in 1979, the first such program in Iowa. As such it required trial and error and much educating of the public on a subject unfamiliar to it. Osage was fortunate in that many newspapers, radio, and TV stations gave publicity to this new idea of cutting off power for hot water and air conditioning. It was considered important enough by the Iowa Energy Policy Council that a letter from the Governor was sent to the residents of Osage urging them to cooperate in the program. A survey was first made by the Osage Municipal Utilities personnel to determine who had central air conditioning and electric water heaters so these could be contacted and an estimate of the load management equipment requirements could be determined. The program was kicked off with news releases and talks to all service clubs. After explanation of the program at service club meetings, sign up sheets were passed around with a request for signatures. This was very effective because the majority of the businessmen were contacted first. They willingly signed up and even the hesitant ones signed because of peer pressure at these meetings. This was a good beginning for the program. This was followed by a newsletter with the 10 most asked questions and their answers. A return postage paid card was sent and the response was excellent, but we were soon at a plateau and getting few volunteers. Offering a monetary incentive was seriously considered but we hoped to avoid this if at all possible. Gilbert /Commonwealth VI-1 The answer to the final push for signatures was handled by the office girls who had been thoroughly instructed in the workings of the program. It was their suggestion that each of the monthly bills of customers who had central air conditioners or electric water heaters and had yet to sign up be marked. Since a large number of these use our drive up window for payment, the girls were able to contact and sign up a couple hundred new people. When asked to sign up the customer usually had a doubt or question in his mind which was immediately answered by one of the girls. Again peer pressure or "the thing to do" entered in and when people found "everyone" was signing up including their neighbor it became easier. We did find that through misunderstanding or misinformation quite a number who had gas water heaters signed up and some with window air conditioners. This reduced our numbers somewhat, but we estimate we have 70 to 75% signed up. More could have signed up with personal contact. Some were lost by "“bad-mouthing" of one of the electricians installing the devices. When this was discovered we asked that he be removed from this job. At Sanborn, Iowa (700 meters) 350 switches were installed in 1982 with 90% response. Since this is a smaller community, they had no service clubs to talk to but the Chamber of Commerce banquet was utilized, and they had a 60% sign up on the first drive. This was done with brochures mailed to every customer and good newspaper cooperation. Contact by phone or in person brought the remaining customers into the program. The management agrees the biggest problem in load management is public education. Every community will have a few negative people who will tear down any new program and disseminate misinformation. The smaller towns probably have the easiest job of education because of community pride and peer pressure. Two other small communities Alton and Roland both with about 1000 population were successful in getting 90% signed up. Orange City with 2180 meters, about the same as Osage, signed up 600 on their program in 1981. They used an education program similar to Osage, had good news coverage, used ads in the newspaper and a letter of explanation to each customer with a return card. This was quite effective. Gilbert /Commonwealth VI-2 REASONS FOR PARTICIPATING In each community mentioned above the principal reasons for participating in the program were community pride, peer pressure and the hope for long term rate benefits. Statements have been made by some who are unwilling to start a load management program that people are unwilling to allow their utility to shut off appliances, that they will not voluntarily allow this to happen to them or if they allow it at all they expect a hand out. None of us agree with this; we have found that people are willing to be a part of the solution if they just know what the problem is. For this reason it is imperative that the people be completely informed about load management and all questions answered truthfully. A good education program is vital. We found also that a guarantee to each cooperator of removal of the equipment at no cost to him if he were dissatisfied was important. In addition, promot response to any service calls even when not related to the load management equipment but suspected to be so by the customer was necessary to keep the program going. Along with this was the education of all plumbers and electricians in the area. It becomes easy to blame problems on something new and some made improper diagnosis--much to their later embarrassment. REACTIONS TO LOAD CONTROL Those of us with load management in Iowa have found an insignificant number of negative reactions. We have removed two or three controls and for good reason. People have been surprised to find they were not inconvenienced after all. Again it is important that a good service program be continued so there are no unhappy customers. We have paid for a number of service calls unrelated to load management, but they were necessary to prove to the customer there was no problem with the controls. Gilbert /Commonwealth VI-3 It can be expected that the water heater element that burns out or the fuse that blows or the air conditioner bearings that need to be replaced are sometimes going to be blamed on load management controls. This is when good public relations and honest answers are important. We avoided some potential problems by operating the controls several times prior to the announced start up date. Those who complained (and there were very few who did) were asked when they first noticed their problem. If it wasn't two weeks prior to announced start up we had little problem proving our point. Plumbers are recommending to new air conditioner customers that a control be added and have normally had favorable response. We've had customers contact us and ask why they don't have a control on their appliance after it was replaced. A city ordinance could be considered requiring all new air conditioners or water heaters to be installed with load control. We feel that a well planned, informative program will be of benefit to the utility and the customer. A good program will impress upon the customer that the utility really is attempting to hold down rates, that it is concerned about him. People want to see innovative programs designed to save them money and are willing to cooperate without any other incentive. There may be exceptions to this in the metropolitan areas; if so, then a program with a rate incentive might be appropriate. However, some large utilities have successfully run programs without rate reductions. One of the more successful programs was conducted by PG & E, one of the largest utilities in the country. Their experiment was community oriented, using three similar sized communities and resulting in a 5.1% to 13.7% reduction in peak. According to an article in Electrical World of August, 1982: The major premises of the community-based program include: (1) Customers identify with and are loyal to their community, and thus may respond to a community incentive; (2) local communities contain many individuals with imagination, leadership talent, and creative and Gilbert /Commonwealth VI-4 innovative ability who are willing to contribute their time and effort in a program for their community's benefit; and (3) despite adversarial relationships that may exist between a utility and its customers, the utility can rely on the maturity and good sense of its customers in building a working relationship to further common interests. This is especially true where that relationship is a genuine partnership that engenders mutual respect. The above is proof that load management does not have to be confined to small communities because the three they worked with had populations of 20,000 to 25,000. Albany, Georgia was also very successful. This is a city of 100,000 with a municipal electric system. It would appear that any city with incentive can make load management work. Gilbert /Commonwealth Vi=5)