CHAPTER 10. NATIONAL IMPACT ANALYSIS

TABLE OF CONTENTS 10.1 INTRODUCTION

.................................................. 10-1 10.1.1 National Impact Analysis Spreadsheet Flowchart

..................... 10-2 10.2 NATIONAL ENERGY SAVINGS

..................................... 10-5 10.2.1 National Energy Savings Overview

................................ 10-5 10.2.2 National Energy Savings Inputs

.................................. 10-6 10.2.2.1 Size Scaling of Losses and Costs

........................ 10-7 10.2.2.2 Mapping Life-Cycle Cost Design Line Data to Product Classes

.. 10-8 10.2.2.3 Root Mean Square Loading

........................... 10-10 10.2.2.4 Load Growth

....................................... 10-10 10.2.2.5 Affected Stock

..................................... 10-11 10.2.2.6 Unit Energy Consumption

............................. 10-12 10.2.2.7 Electricity Site-to-Source Conversion

.................... 10-13 10.3 NET PRESENT VALUE

............................................ 10-14 10.3.1 Net Present Value Overview

.................................... 10-15 10.3.2 Net Present Value Inputs

...................................... 10-17 10.3.2.1 First Cost

......................................... 10-17 10.3.2.2 Operating Cost

..................................... 10-18 10.3.2.3 Peak Responsibility Factor

............................. 10-19 10.3.2.4 Initial Peak Load

.................................... 10-20 10.3.2.5 Electricity Price Forecast Scalar

......................... 10-20 10.3.2.6 Marginal Electricity Costs

............................. 10-20 10.3.2.7 Discount Rate

...................................... 10-21 10.4 RESULTS

....................................................... 10-22 10.4.1 National Energy Savings and Net Present Value from Trial Standard Levels

......................................... 10-22

Table 10.2.1 Mapping of Desi gn Line to Product Class

........................... 10-9

Table 10.3.2 Fi rst Cost of Distribution Transformers by Trial Standard Level and Product Class (2006$/kVA, TSL A through TSL D)

................. 10-18 Table 10.3.1 Fi rst Cost of Distribution Transformers by Trial Standard Level and Product Class (2006$/kVA, TSL 1 through TSL 6)

.................. 10-18 Table 10.2.2 Average Site-to-Source Conversion Factors for No-Load Losses and Load Losses

................................................ 10-13 10.4.1.1 Liquid-Immersed Results

............................. 10-22 10.4.1.3 Discounted Cumulative Energy Impacts

................... 10-26

LIST OF TABLES

10-iTable 10.3.3 Peak Responsibility Factors by Product Class

....................... 10-20 Table 10.3.4 Initial Peak Loading by Product Class

............................. 10-20 Table 10.3.5 Marginal Energy and Demand Costs by Product Class

................ 10-21 Table 10.4.1 Summ ary of Cumulative National Energy Savings (2010–2038) and Net Present Value (2010–2073) Impact

........................... 10-22 Table 10.4.2 Summ ary of Cumulative National Energy Savings (2010–2038) and Net Present Value (2010–2073) Impact for Liquid-Immersed Transformers

............................................... 10-23 Table 10.4.3 Cum ulative Primary Energy Savings During 2010–2038: Dry-Type Transformers by Product Class

.................................. 10-24 Table 10.4.4 Ne t Present Value During 2010–2073: Dry-Type Transformers by Product Class

............................................... 10-25 Table 10.4.5 Discounted Cumulative Energy Impacts, Liquid-Immersed and Dry-Type, Medium-Voltage Transformers

.................................. 10-27

LIST OF FIGURES Figure 10.1.1 National Impact Analysis Flowchart

............................... 10-3 Figure 10.4.1 Liquid-Immersed Distribution Transformers: National Energy Savings and Net Present Value Impacts

..................................... 10-23 Figure 10.4.2 Dry-Ty pe Distribution Transformers: National Energy Savings and Net Present Value Impacts

..................................... 10-26

10-iiCHAPTER 10: NATIONAL IMPACT ANALYSIS

10.1 INTRODUCTION The Energy Policy and Conservation Act (EPCA) states that any new or amended st andard must be chosen so as to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. In determining whether economic justification exists, the Department of Energy (DOE) must determine that the benefits of the trial standard level exceed its burdens. Key factors in this decision are: the total projected amount of energy savings likely to result directly from the imposition of the standard, and the savings in operating costs throughout the life of the covered product in the type (or class) compared to any increase in the price of, or in the initial charges for or maintenance expenses of, the covered products which are likely to result from the promulgation of the standard. To satisfy this EPCA requirement and to more fully understand the national impact of pot ential efficiency regulations for distribution transformers, DOE conducted a national impact analysis. This analysis assessed future national energy savings (NES) from transformer energy conservation standards as well as the national economic impact using the net present value (NPV) metric. The NES is the cumulative incremental energy savings from a transformer efficiency standard, relati ve to a base case scenario of no national standard, over a forecast period. DOE calculated NES for each trial standard level in units of quadrillion British thermal units (Btus), or quads, for standards that it assumed will be implemented in the year 2010. The NPV is the net present value of the incremental economic impact on consumers from a trial standard level. DOE calculated the NPV using a method similar to the NES calculation, except that it estimated incremental costs and benefits instead of energy, and discounted the net benefits rather than calculating them as an un-discounted sum. DOE discounted purchases, expenses, and operating costs for transformers using a national average discount factor. It calculated the NPV impact from transformers that are purchased from 2010 through 2038 to calculate the total NPV impact from purchases during the forecast period. DOE developed a Microsoft Excel spreadsheet, the national impact spreadsheet, to implement the calculations described above. The spreadsheet calculates capacity and operating cost savings associated with each of the trial standard levels. The NES analysis considers cumulative energy savings through the year 2038, while the NPV considers capacity and operating cost savings through the year 2073 afor transformers purchased in the period 2010 to

a DOEmaintainsthe same time period for NPV as it did in the advance notice of proposed rulemaking (ANOPR) and notice of proposed rulemaking (NOPR). 10-12038. By taking the annual difference between the base case scenario and trial standard levels and summing the discounted annual results, the spreadsheet calculates an NPV for each trial standard level relative to the base case. 10.1.1 National Impact Analysis Spreadsheet Flowchart Figure 10.1.1 presents a graphical flow diagram of the distribution transformer national impactanalysis (NES and NPV) model and spreadsheet. In the diagram, the arrows show the direction of information flow of the calculation. The information begins with inputs (shown as parallelograms). As information flows from these inputs, it may be integrated into intermediate results (shown as rectangles) or through integrating sums or differences (shown as circles) into major outputs (shown as boxes with curved bottom edges). Note that the shipments model portion of the flow diagram (shaded) is discussed in Chapter 9.

10-2Figure 10.1.1 National Impact Analysis Flowchart The calculation started with the shipments model (described in Chapter 9), which i ntegrated the inputs of 2001 shipments estimates from DOE’s contractor, 1 the U.S. Bureau of

10-3Economic Analysis (BEA) transformer quantity index, 2electricity market shares from DOE’s Energy Information Administration (EIA), 3, 4and equipment price estimates from DOE’s life-cycle cost (LCC) analysis, to produce a backcast and a forecast of total shipments. DOE used the total shipments and a retirement function to produce an accounting of in-service transformers (stocks), enabling DOE to estimate the stock that is affected by trial standards and transformer retirements. After the shipments calculation, the NES and NPV calculations begin. Key inputs from the LCC analysis are the average rated losses for both no-load and load losses, and the cost of transformers, including installation. DOE adjusted the losses and the equipment costs for transformer size and product class, to convert the data from representative design lines to average product class information. Additional inputs on average and peak losses—including root mean square (RMS) loading, peak loading, and peak responsibility factor—allowed DOE to convert rated losses into actual losses. At this point, the information flow for the NES and NPV calculation split into two paths. On one path, the NES calculation sums the watt-hours of energy consumed by the affected stock, and takes the difference between the base case and standards scenario to calculate site energy savings. Marginal heat rates from the National Energy Modeling System (NEMS) 5then convert the site energy savings to energy savings at the source (i.e., at the power plant). The marginal heat rates from NEMS include the transmission and distribution losses. (DOE performed a sensitivity analysis to analyze an improvement in the heat rate as a result of the efficiency improvement in the standards scenario; the impact was not significant.) The sum of annual energy savings for the forecast period through 2038 then provides the final NES result. On the other path, the NPV calculation brings in marginal price inputs from the LCC analysis forboth energy costs and capacity costs and for both load losses and no-load losses. The marginal prices, when combined with the actual peak and average losses, provide the estimate of the operating cost. Meanwhile, the adjusted equipment installed cost times the annual shipments provide the estimate of the total annual equipment costs. DOE calculated three differences to calculate the net impact of the trial standard. The first difference was between the trial standards scenario equipment costs and the base case equipment costs, to obtain the net equipment cost increase from a trial standard. The second difference was between the base case scenario operating cost and the trial standards scenario operating cost, to obtain the net operating cost savings from a trial standard. The third difference was between the net operating cost savings and the net equipment cost increase, to get the net expense/savings for each year. DOE then discounted the net expenses/savings to 2007 and summed them over the years 2010–2073 for transformers purchased during or before 2038, to provide the NPV impact of a trial standard. Chapter 9 of this TSD provides a detailed technical description of the shipments model; si

milar descriptions of the other two models are provided below—the NES model in section 10.2, and the NPV model in section 10.3. Each technical description begins with a summary of the model. It then provides a descriptive overview of how DOE performed each model’s calculations, and follows with a summary of the inputs. The final subsections of each technical

10-4description describe each of the major inputs and computation steps in detail and with equations, when appropriate. After the technical model descriptions, this chapter presents the results of the national impact analysis calculations.

10.2 NATIONAL ENERGY SAVINGS DOE developed the NES model to estimate the total national energy savings using the resu lts from the shipments model, combined with information from the LCC on energy savings. The savings shown in the NES reflect decreased energy losses resulting from the installation of new, more efficient transformer units nationwide, in comparison to a base case with no national standards. Positive values of NES correspond to net energy savings, i.e., a decrease in energy consumption with standards in comparison to the energy consumption in the base case scenario. 10.2.1 National Energy Savings Overview DOE calculated the cumulative incremental energy savings from atransformer efficiency standard, relati ve to a base case scenario of no standard, over the forecast period. It calculated NES for each trial standard level, in units of quads, for standards that it assumed will be implemented in the year 2010. The NES calculation started with estimates of transformer shipments and stocks (in-service transformers), which are outputs of the shipments model (Chapter 9). DOE then obtained estimates of transformer losses from the LCC analysis (Chapter 8), and calculated the total energy use by the stock of transformers for each year, for both a base case and a standards case. Over time, in the standards case, more-efficient transformers gradually replace less-efficient ones. Thus, the energy per unit capacity used by the stock of transformers gradually decreases in the standards case relative to the base case. DOE converted energy used by the transformers into the amount of energy consumed at the source of electricity generation (the source energy) with a site-to-source conversion factor. The site-to-source factor accounts for transmission, distribution, and generation losses. For each year analyzed, the difference in source energy use between the base case and the standards scenario is the annual energy savings. DOE summed the annual energy savings from 2010 through 2038 to calculate the total NES for the forecast period. In calculating the NES, DOE did not assume any trends in transformer name-plate eff iciency besides the incremental efficiency improvement indicated by the LCC calculation. DOE examined proprietary shipments data provided by the transformer industry and found that the data lacked conclusive trends in efficiency improvement. Therefore, DOE felt that future efficiency trends were generally indeterminate and chose to use a fixed baseline efficiency. DOE also assumed that the efficiency of transformers does not degrade over time. This means the annual energy savings can be described in terms of an affected stock (see Equation 10.1), as described in section 9.3.11 in the shipments chapter: Eq. 10.1

10-5where: AES(y) = the annual energy savings in year y, UEC Base = the site unit energy consumption for the base case, UEC Std = the site unit energy consumption for the standards case, and Aff_Stock(y) = stock of transformers of all vintages that are operational in year y . Then, given the annual energy savings, the NES can be calculated as a simple sum: Eq. 10.2 where: Std_year = the year standards come into effect, SiteToSource(y)= the site-to-source conversion factor in year y, and AEC = the annual energy consumption. Once the shipments model provides the estimate for the affected stock, the key to the NES calculation is in calculating UEC Base and UEC Std, using the input from the LCC analysis and including the site-to-source conversion factor. The next section summarizes the inputs necessary for the NES calculation and then presents them individually. 10.2.2 National Energy Savings Inputs The NES model inputs fall into three broad categories: (1) those that help convert the dat a from the LCC into data for the product classes and transformer size distributions used in the NES; (2) those that help calculate the unit energy consumption; and (3) the site-to-source conversion factor, which enables the calculation of source energy consumption from site energy use. The specific list of NES model inputs is as follows: 1. Size scaling of losses and costs 2. Mapping of LCC design line data to product classes 3. Root mean square loading 4. Load growth 5. Affected stock 6. Effective date of standard 7. Unit energy consumption 8. Electricity site-to-source conversion

10-610.2.2.1 Size Scaling of Losses and Costs DOE used a scaling relationship, or equation, to project the economic results from one transform er design line to similar transformers of different sizes. This relationship is a key element in adjusting losses and costs from a representative transformer in the LCC to a distribution of transformer sizes represented in the NES calculation. To be consistent across trial standard levels, DOE used the same scaling for the National Electrical Manufacturers Association (NEMA)’s TP1 standard level as it did for the other levels. NEMA’s scaling was apparently based on a different set of representative units than DOE used. As a result, for transformers other than the representative units, which were keyed to NEMA TP1 efficiencies, there is a slight difference in efficiency level between NEMA’s TP 1 and DOE's TP 1, as used to calculate national impacts. As described in the engineering analysis, DOE applied the 0.75 power scaling rule (the “0.75 scal ing rule”) for projecting losses and costs from one design line to transformers of other sizes. In the NES analysis, DOE calculated shipments in terms of installed capacity. It estimated the losses associated with a stock of transformers, and the costs associated with a capacity shipped, by multiplying the relevant capacity times the average losses, or costs per unit capacity. Before applying the 0.75 scaling rule, DOE calculated the losses and costs per unit of installed capacity within a given engineering design line. Then it calculated an adjustment factor using the 0.75scaling rule to account for the fact that the representative design line unit used in the engi neering analysis is not exactly the “average” transformer size for the set of transformers that the design line represents. This adjustment factor is given by the following equation: Eq. 10.3 where: AdjFactor = adjustment factor that gives the shipment-weighted losses or costs per transformer when multiplied by the design line losses or costs, Shipi = shipments in the i-th si ze category, Cap i = the rated capacity for the transformers in the i-th size category, and CapDL = the rated capacity of the representative unit of the design line. DOE also used the shipment-weighted average size of transformers represented by a particular design line to calculate the average loss per capacity ( AvgLossPerCap DL), as described in the following equation: Eq. 10.4
where:

10-7Cap LossPerCapDL = the loss, or cost per unit capacity, for the design line unit from the LCC analysis, and

avg = the shipment-weighted average size of transformers represented by a particular design line. Once the losses and costs from the LCC represented the correct size distribution, they needed a f urther adjustment so that they represented the appropriate product classes, as described in the next section. 10.2.2.2 Mapping Life-Cycle Cost Design Line Data to Product Classes The NES and NPV calculations use the LCC calculations as the source of most input data. DOEperformed the LCC calculations by design line, whereas any eventual standard would be promulgated by product class. As a first step, therefore, the NES calculation aggregates the LCC design line data into product classes. This design-line-to-product-class aggregation was the process by which DOE took the results from an economic analysis of engineering design lines and combined them to provide estimates of economic impact by product class. To represent the variety of designs in some product classes, DOE analyzed up to three dif ferent design lines per product class. Specifically, product class 1 (single-phase, medium-voltage, liquid-immersed transformers) is represented by three design lines, and product class 2 (three-phase, medium-voltage, liquid-immersed transformers) is represented by two design lines. DOE did not specifically examine single-phase, dry-type design lines. For single-phase product classes 5 and 9, DOE used the appropriate three-phase design lines divided by three. Table 10.2.1 presents the mapping of design line (DL) to product class (PC).

10-8Table 10.2.1 Mapping of Design Line to Product Class
Product Class BIL* kV ** Capacity kVA *** PC 1, Liquid-Immersed, MV, †Single-Phase Any 10-833 PC 2, Liquid-Immersed, MV, Three-Phase Any 15-2500 PC 5, Dry-Type, MV, Single-Phase 20-45 15-833 PC 6, Dry-Type, MV, Three-Phase 20-45 15-2500 PC 7, Dry-Type, MV, Single-Phase 46-95 15-833 PC 8, Dry-Type, MV, Three-Phase 46-95 15-2500 PC 9, Dry-Type, MV, Single-Phase $ 96 75-833 PC 10, Dry-Type, MV, Three-Phase $ 96 225-2500 Mapping
DL 1 + DL 2 + DL 3 DL 4 + DL 5 (DL 9 ÷ 3) + (DL 10 ÷ 3) DL 9 + DL 10 (DL 11 ÷ 3) + (DL 12 ÷ 3) DL 11 + DL 12 DL 13 ÷ 3

DL 13

* BIL = Ba sic impulse insulation level ** kV = kilov olt *** kVA = k ilovolt-ampere † MV = mediu m-voltageTo aggregate losses from more than one design line, DOE took a shipments-capacityweighted average of the per-kilovolt-ampere (kVA) transformer characteristics from the economic analysis of the design lines and applied the average per-capacity values to the estimated capacity shipped for each product class. DOE’s contractor 1 provided the capacity shipped for each design line (and each product class), the LCC analysis provided the economic results for each design line, and DOE used the 0.75 scaling rule to estimate the re-scaled cost and loss estimates for each size category represented by each design line. Equation 10.5 provides the average loss per unit capacity of product class ( AvgLossPerCap PC), as derived from the average loss per unit capacity for a design line: Eq. 10.5 where: AvgLossPerCap DL = the average loss per unit capacity for the design line, and MS DL = the capacity market share of the design line. Equation 10.5 sums those design lines that constitute a product class. The AvgLossPerCap PC

represents the average loss per unit capacity of the transformer load. For no-load losses, no more adjustment is needed; for load losses, however, the losses at rated load need to be converted to losses at actual loading. The RMS loading is a key factor in estimating load losses at actual loading. The next section describes the RMS loading input.

10-910.2.2.3 Root Mean Square Loading Energy losses in transformers follow the RMS load, not the arithmetic average load. DOE calculated the RMS loading as the root mean square of the transformer load, divided by the transformer rated capacity, times the power factor. (As explained in Chapter 6, while DOE’s method for analysis can derive results for varying power factors, for the analysis presented here DOE set the power factor to the value of one.) DOE used the average national RMS loading for each design line as calculated in the LCC analysis. These values range between 30.1 percent and 47.7percent for the different design lines. 10.2.2.4 Load Growth The fractional load growth is the fraction by which the load has increased since a transformer was installed. DOE investigated load growth as a sensitivity. Load growth occurs when new equipment, new appliances, or additional activities increase the energy loads on the circuits served by distribution transformers. Load growth has the impact of increasing the load losses relative to the losses that DOE estimated to have occurred during the first year of installation. DOE calculated the fractional load growth from an estimated load growth rate that it used as a n input to the LCC analysis. There is a maximum load growth, LGRMax, which DOE set at 50 percent for liquid-immersed transformers. The 50 percent value represents the approximate amount of growth in load that can occur without overloading the transformer beyond a reasonable point. When overloading does occur, the transformer is assumed to be relocated and installed in a new location with the same initial peak loading as when originally installed. 6See Institute of Electrical and Electronics Engineers, Inc. (IEEE) Std C57.91-1995 7for details on permissible overloading of mineral-oil immersed transformers. Since IEEE does not report data on permissible overloading of dry-type units, DOE used the same values for both liquid-immersed and dry-type transformers. The age of the transformer at which the load switches to initial peak load is given by Equation 10.6: Eq. 10.6

where:
age Max = the maximum age of transformer after which time the load switches to initial peak load (years), and LGR = the annual load growth rate (%).

10-10Thus, the equation for the load growth as a function of the age of the transformer is as follows: Eq. 10.7 for age < age Max , and Eq. 10.8
for age >= age Max where: LGrwth(age) = the fractional load growth, and age = the a ge of the transformer (years). DOE then used the load growth to adjust the RMS loading estimate for the affected stock. The mathem atical equation for this adjustment is as follows:
Eq. 10.9

where LAdjust(y) is the load adjustment factor in year y . All other variables have been defined in previous equations. DOE used a load adjustment factor to calculate an adjusted RMS loading that in

corporates load growth into the unit energy consumption, as described in section 10.2.2.6. 10.2.2.5 Affected Stock The affected stock is an output of the shipments model (Chapter 9) and a key input for the NES and NPV cal culations. The affected stock represents that portion of the transformer stock that is potentially impacted by a standard. It therefore consists of those transformers in the stock that are purchased in or after the year the standard has taken effect, as described by the following equation:
Eq. 10.10

where:

10-11Aff_Stock(y) = stock of affected transformers of all vintages that are operational in year y, Ship(y) = shipment of new transformers in year y, Std_year = year the standard becomes effective, and Stock(age) = age in years of the stock of transformers.

10.2.2.6 Unit Energy Consumption One of the final quantities DOE calculated for the NES estimate was the unit energy co nsumption for affected stock. The unit energy consumption times the capacity shipped and the site-to-source conversion factor equals the annual energy consumption from which DOE derived total NES. Annual unit energy consumption ( UEC(y) ) for aff ected stock is the annual energy consumption per unit capacity for transformers shipped after the effective date of a standard. DOE calculated the losses per transformer as the sum of no-load losses plus the load losses. It calculated the load losses as the rated load loss times the square of RMS loading, adjusted for load growth. Average energy consumed per unit capacity for affected stock varies from year to year due to load growth effects. The annual unit energy consumption for affected stock of distribution transformers is giv en by Equation 10.11: Eq. 10.11
where:
E NL = rated no-load losses per kVA capacity, E

LL = rated load losses per kVA capacity, RMS = root mean square, and Ladjust(y) = loading adjustment factor for year y . Once DOE defined the unit energy consumption for affected stock, only one more input was necessary to complete the NES calculation: the site-to-source conversion factor. 10.2.2.7 Electricity Site-to-Source Conversion The site-to-source conversion factor for electricity is the factor by which site energy (in kilowatt-hours (kWh)) is multiplied to obtain primary (source) energy (in Btu). Since the NES estimates the change in energy use of the resource (e.g., the power plant), this conversion factor is necessary to account for losses in generation, transmission, and distribution. After calculating energy consumption at the site of its use (i.e., the installed transformer), DOE multiplied it by the
10-12conversion factor to obtain primary energy consumption, expressed in quads. This conversion permitted comparison across (source) fuels by taking into account the heat content of different fuels and the efficiency of different energy conversion processes. The annual values are the U.S. average conversion factors for electricity generation for both peak and base load reduction. DOE used marginal heat rates corresponding to base load for no-load losses (or core losses) and marginal heat rates corresponding to peak load for load losses (or coil losses). It used these different rates because load losses are higher during transformer peak loads while no-load losses occur at all times. DOE obtained these conversion factors using a variant of the NEMS, called NEMS-BT. aTable 10.2.2 presents the average annual conversion factors DOE used. Table 10.2.2 Average Site-to-Source Conversion Factors for No-Load Losses and Load Losses Year For No-Load Losses For Load Losses 2010 2.901 2.872 2011 2.784 2.696 2012 2.696 2.608 2013 2.696 2.550 2014 2.550 2.491 2015 2.491 2.403 2016 2.403 2.345 2017 2.345 2.257 2018 2.257 2.110 2019–2038 2.198 1.993 DOE used a time-series projection of conversion factors, changing from year to year, which it calculated as follows: 1. Start with an integrated projection of electricity supply and demand (e.g., the Annual Energy Outlook (

AEO2006) reference case)4and extract the source energy consumption. 2. Estimate projected energy savings due to possible standards for each year (e.g., using the NES spreadsheet model).

aFor m ore information on NEMS, refer to DOE’s EIA documentation. A useful summary is National Energ y ModelingSystem: An Overview 2003

. 5DOE/EIA appr oves use of the name NEMS to describe only an official version of

the model without any modification to code or data. Because this analysis entailedsome minor code modifications and the model isrun under policy scenarios that are variations on DOE/EIA assumptions, the name NEMS-BT refers tothe model as used here (BT is DOE’s Building Technologies Program, under whoseaegis this work was performed). 10-133. Feed these energy savings back to the NEMS-BT model as a new scenario, specifically a devi ation from the reference case, to obtain the corresponding source energy consumption. 4. Obtain the difference in source energy consumption between this trial standard level scenari o and the reference case. 5. Divide the source energy savings, in Btu, adjusted for load-specific transmission and distribution losses, by the site energy savings, in kWh, to provide the time series of conversion factors in Btu per kWh. The conversion factors change over time and account for the displacement of generating sources. The NES spreadsheet model includes the conversion factors for each year of the projection. DOE and stakeholders can examine the effects of alternative assumptions by revising this column of numbers. The conversion of site energy savings to source energy savings and the summation of energy savings over the forecast period complete the NES calculations. The next section of the chapter (section 10.3) describes the technical details of the NPV calculation. The results section (section 10.4) presents the NES and NPV results from the national impact spreadsheet.

10.3 NET PRESENT VALUE DOE estimated the national financial impact on consumers from the imposition of new energy efficiency standards using a national NPV accounting component in the national impact spreadsheet. DOE combined output of the shipments model with energy savings and financial data from the LCC to calculate an annual stream of costs and benefits resulting from trial distribution transformer energy efficiency standards. It discounted this time series to the year 2007 and summed the result, yielding the national NPV. 10.3.1 Net Present Value Overview The NPV is the present value of the incremental economic impact of a trial standard level. Like the NES, the NPV calculation started with transformer shipments and transformer stocks, estimates of which are outputs from the shipments model. DOE then obtained estimates of transformer first costs, losses, and average marginal electricity costs from the LCC analysis. It calculated the amount spent on transformer purchases and installation, and then calculated the corresponding operating costs by applying the marginal prices to the energy (both energy and electricity system capacity) used by the stock of transformers for each year, for both a base case and a standards case. Over time in the standards case, more-expensive, but more-efficient transformers gradually replace less-efficient transformers. Thus, the operating cost per unit capacity used by the stock of transformers gradually decreases in the standards case relative to the base case, while the equipment costs increase.

10-14DOE discounted purchases, expenses, and operating costs for transformers using a simple national average discount factor. The discount factor converts a future expense or benefit to a present value. The difference in present value of all expenses and benefits between the base case and standards scenario is the national NPV impact. DOE calculated the NPV impact from transformers that were purchased between the effective date of the standard and 2038, inclusive, to calculate the total NPV impact from purchases during the forecast period. Mathematically, NPV is the value in the present time of a time series of costs and savings, des cribed by the equation: Eq. 10.12
where: PVS = the present value of electricity savings, and PVC = the present value of equipment costs including installation. PVS and PVC are det ermined according to the following expressions:
Eq. 10.13

where: OC Base /Cap(y) = operating cost per unit capacity of transformer for the base case in year y, Aff_Stock(y) = stock of transformers of all vintages that are operational in year y, y = the year (from effective date of the trial standard to the year when units purchased in 2038 retire), and Discount Factor(y) = discount factor for the year y, defi ned in Eq. 10.14. Eq. 10.14

where: reference year = year 2007, and discount rate = the rate of discount as described in section 10.3.2.7.

10-15Eq. 10.15

where: FC Std

/Cap (y) = first cost of the transformer per unit of capacity for a trial standard level S td in year y. First cost is defined in Eq. 10.16and described in section 10.3.2.1. Std_year = the year standards come into effect, and Ship (y) = shipments of transformers in year yfor the standards case. DOE calculated NPV using its projections of national expenditures for distribution tra nsformers, including purchase price (equipment and installation price) and operating costs (electricity and maintenance costs). It calculated costs and savings as the difference between a trial standards case and a base case scenario without national standards. It discounted future costs and savings to the present. DOE calculated a discount factor from the discount rate and the number of years between the year to which the sum is being discounted (2007) and the year in which the costs and savings occur. The NPV is the sum over time (2010–2073) of the discounted net financial savings. The following sections describe the inputs specific to the NPV calculation. 10.3.2 Net Present Value Inputs The NPV model inputs include cost inputs, inputs important for detailing electricity capaci ty costs, and several of the inputs used by the NES calculation. This section provides details on those inputs that have not yet been described as part of the NES and shipments models. The specific list of inputs for the NPV is as follows: 1. First cost 2. Operating cost 3. Peak responsibility factor 4. Initial peak load 5. Electricity price forecast scalar 6. Marginal electricity costs 7. Discount rate

10-1610.3.2.1 First Cost The first cost includes all of the initial costs that are incurred with the installation of a transform er. DOE expresses first cost in terms of cost per unit capacity. Specifically, it defines the first cost of acquiring a transformer with the following equation: FC/Cap = (P + Install)/Cap Eq. 10.16 where: FC = the f irst cost, Cap = the rated capacity of the transformer, P = the price of the transformer including shipping and taxes, and Install = the installation cost of the transformer. In the NPV calculation, these values are obtained from the LCC calculation as the averages for specific design lines. DOE applied an adjustment factor to convert the first cost of a representative design to an estimated average first cost for a distribution of sizes within aparticular product class. The adjustment incorporates the 0.75 scaling rule and the design-line-toproduct-class mapping. This adjustment factor is explained in detail in sections 10.2.2.1 and 10.2.2.2. The costs are expressed in units of 2006$ per kVA of rated transformer capacity. Tables 10.3.1 and 10.3.2 show the resulting mean first costs per kVA for distribution transform ers by trial standard level (TSL) and product class. Note that for the liquid-immersed transformers, DOE examined two sets of TSLs: TSLs 1 through 6 are those levels DOE investigated in the notice of proposed rulemaking (NOPR), while for this final rule DOE labeled recombinations of these TSLs that maintained consistency between single-phase and three-phase efficiency as TSLs A through D. Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Level and Product Class (2006$/kVA, TSL 1 through TSL 6) Product Class Base TSL 1* (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 PC 1, Liquid-Immersed, MV, Single-Phase 63.82 65.04 65.27 65.23 66.31 73.56 116.98 PC 2, Liquid-Immersed, MV, Three-Phase 22.75 23.77 25.05 26.94 27.44 41.04 43.30 PC 5, Dry-Type, MV, Single-Phase 29.34 30.42 31.75 33.85 38.84 52.84 52.84 PC 6, Dry-Type, MV, Three-Phase 23.75 25.20 26.62 28.40 31.35 42.72 42.72 PC 7, Dry-Type, MV, Single-Phase 35.60 36.74 37.81 39.75 43.50 55.11 55.11 PC 8, Dry-Type, MV, Three-Phase 25.72 26.31 26.96 28.00 30.47 43.35 43.35 PC 9, Dry-Type, MV, Single-Phase 31.71 31.96 33.23 34.65 40.98 57.18 57.18 PC 10, Dry-Type, MV, Three-Phase 24.64 24.83 25.82 26.93 31.85 44.43 44.43
10-17*TSL = T rial Standa rd Level

Table 10.3.2 First Cost of Distribution Transformers by Trial Standard Level and Product Class (2006$/kVA, TSL A through TSL D) Product Class Base TSL A TSL B TSL C TSL D PC 1, Liquid-Immersed, MV, Single-Phase 63.82 76.07 69.41 69.38 66.15 PC 2, Liquid-Immersed, MV, Three-Phase 22.75 29.73 25.91 25.41 25.41 *TSL = T rial Standa rd Level

10.3.2.2 Operating Cost Transformer operating cost is the annual cost of transformer losses. Operating costs are a com plex, yet essential, part of calculating the national economic impact of a distribution transformer standard. DOE used distinct costs to calculate value of different types of losses and peak capacity savings. Potential load growth also requires a load growth adjustment factor. Peak loading, peak load coincidence, and average loading require additional factors to characterize load losses. Finally, DOE used an electricity price forecast scalar to characterize future trends in electricity prices consistent with the AEO2007 forecast. DOE assumed zero incremental maintenance cost in calculating the transformer operating costs. It calculated annual operating costs using the following formula to capture the diversity of potential factors that can affect these costs: OC/Cap = EPFS(y) × (ENL× (NLLMCC + 8760 × NLLMEC) + E LL× (LAdjust(y)) 2 × (PRF × PL 2× LLMCC + 8760 × RMS 2× LLMEC))/Cap Eq. 10.17 where:

E E OC = the ope rating cost, Cap = the rated capacity of the transformer, EPFS(y) = the electricity price forecast scalar for year y,

NL = the no-load losses at rated load, NLLMCC = the no-load loss marginal cost of capacity, NLLMEC = the no-load loss marginal energy cost,

LL = the load losses at rated load, LAdjust(y) = the load growth adjustment factor in year y, PRF = the peak responsibility factor, PL = the initial peak load, LLMCC = the load loss marginal cost of capacity, RMS = the root mean square loading of the transformer, and LLMEC = the load loss marginal energy cost.
10-18DOE expressed the operating costs in units of 2006$ per kVA of rated capacity. As in the NES calculation (see sections 10.2.2.1 and 10.2.2.2), DOE also applied an adjustment factor to incorporate the 0.75 scaling rule to E NLand E LL , to convert from design line data to product class estimates. The following four sections explain the inputs of the operating cost equation that are not ex plained in the NES section. 10.3.2.3 Peak Responsibility Factor The transformer peak responsibility factor (PRF) is the fraction of the transformer peak that is coincident with the system peak, calculated by taking the square of the ratio of the transformer load at the time of the customer peak load to the transformer peak load. In combination with the initial peak loading, the PRF is necessary for estimating the capacity cost impacts of transformer load losses. DOE used the average PRF from the hourly and monthly load analysis for the liquid-immersed and dry-type transformers, respectively, as reported in the LCC analysis. Table 10.3.3 presents the PRFs used in the analysis for the 8 product classes. Table 10.3.3 Peak ResponsibilityFactors by Product Class PC 1 PC 2 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 PRF 0.34 0.50 0.52 0.53 0.52 0.53 0.54 0.54
10.3.2.4 Initial Peak Load The initial peak loading is the annual per-unit peak load on the transformer during the first year of operation. This factor, in combination with the PRF, is necessary for calculating capacity cost impacts from transformer load losses. The initial peak load is estimated as a percentage of the rated peak load of the transformer. The IEEE’s Draft Guide for Distribution Transformer Loss Evaluation 6defines a similar but different measure of peak transformer loading called an “Equivalent Annual Peak Load” that accounts for changes in peak load over the life of the transformer. Rather than use the equivalent annual peak load method, DOE characterized a range of possible initial peak loads by defining a distribution of initial peak loads. Chapter 6, sections 6.2.3.3and 6.3.3.3, provide further description of DOE’s method. Table 10.3.4 presents the in

itial peak loadings used in the analysis for the 8 product classes. Table 10.3.4 Initial Peak Loadin g by Product Class PC 1 PC 2 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 Initial Peak Loading 0.86 0.86 0.75 0.75 0.75 0.75 0.75 0.75

10-1910.3.2.5 Electricity Price Forecast Scalar The electricity price forecast scalar converts current electricity costs into forecasted costs f or the period 2004–2073. The electricity price forecast scalar is the ratio of the unit cost of electricity in real dollars in a given year to the real cost of electricity in the year 2006. DOE used AEO20074forecasts to obtain the electricity price forecast scalar. For the period beyond 2025, DOE used the BEA real dollar price trend from 2015 to 2025 to extrapolate the electricity price scalar. 10.3.2.6 Marginal Electricity Costs The characterization of four distinct marginal electricity costs was necessary to calculate the ope rating costs of transformers and the financial impact of transformer efficiency standards. The four types of marginal costs are: no-load loss marginal capacity cost (NLLMCC), load loss marginal capacity cost ( LLMCC), no-load loss marginal energy cost ( NLLMEC ), and load loss marginal energy cost ( LLMEC ). In an electricity system, there are both energy costs and capacity costs. Depending on the load shape of a particular load, the average value of capacity costs and energy costs are different. Since no-load losses and load losses have distinct load shapes, and since different customers have different load shapes, costs vary both by loss type and by the product class of the transformer. DOE therefore used distinct marginal energy and capacity costs for no-load losses and load losses for each transformer product class. No transformer size scalingis necessary for the marginal costs, although DOE needed to apply the design-line-to-productclass mapping described in section 10.2.2.2 to convert the design line output from the LCC to product class information for the NPV calculation. DOE calculated capacity costs in units of 2006$/kW/year, and energy costs in units of 2006$/kWh. Table 10.3.5 summarizes the four marginal costs for the 8 product classes. Table 10.3.5 Marginal Energy andDemand Costs by Product Class Marginal Energy Cost by Product Class ($/kWh) PC 1 PC 2 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 NLL 0.032 0.031 0.054 0.054 0.054 0.054 0.054 0.054 LL 0.042 0.049 0.057 0.056 0.057 0.056 0.056 0.056 Marginal Demand Cost by Product Class ($/kW/year) PC 1 PC 2 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 NLL 103.82 119.56 97.75 98.97 97.94 99.21 99.62 99.62 LL 55.80 62.28 74.88 76.70 75.18 77.04 78.47 78.47

10-2010.3.2.7 Discount Rate The discount rate expresses the time value of money and is the final input to the NPV cal culation. DOE used real discount rates of three and seven percent, as established by the U.S. Office of Management and Budget (OMB) guidelines on regulatory analysis. 8In selecting the discount rate corresponding to a public investment, OMB directs agencies to use "the real Treasury borrowing rate on marketable securities of comparable maturity to the period of analysis." Office of Management and Budget (OMB) Circular No. A-94, "Guidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs," dated October 29, 1992, section 8.c.1. The discount rates DOE used in the LCC are distinct from those it used in the NPV calculations, in that the NPV discount rates represent the societal rate of return on capital, whereas LCC discount rates reflect the owner cost of capital and the financial environment of electric utilities and commercial and industrial entities. To address comments received in response to the NOPR, DOE also reports results for the 4.2percent discount rate in Appendix 10A of this TSD.

10-2110.4 RESULTS 10.4.1 National Energy Savings and Net Present Value from Trial Standard Levels Table 10.4.1 presents the NES and NPV results from the NES spreadsheet model for TS L 1 through TSL 6 and TSL A through TSL D. It should be reiterated that, currently, the NES spreadsheet model uses discrete point-values rather than a distribution of values for all inputs. Savings for the dry-type units are substantially different from the estimates in the advance notice of proposed rulemaking (ANOPR) analyses. 9The difference in savings originates predominantly from the exclusion of dry-type, low-voltage transformers from the later analyses, since these types of transformers were regulated by the Energy Policy Act of 2005, enacted on August 8, 2005. 42 U.S.C. 6295(y) Table 10.4.1 Summar y of Cumulative National Energy Savings (2010–2038) and Net Present Value (2010–2073) Impact Trial Standard Level Discount Distribution Transformers

Liquid- Imm ersed

Dry-Type Rate % TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL A TSL B TSL C TSL D NES quads 1.38 1.94 2.76 3.00 5.07 7.37 4.07 2.75 2.61 2.18
NPV billion 2006$ 3 5.57 7.06 9.17 9.33 1.40 -26.1 4.47 7.26 6.95 7.56 7 1.68 1.95 2.37 2.13 -4.89 -23.3 -1.89 1.11 1.11 1.91 NES quads 0.06 0.13 0.19 0.27 0.40 0.40
NPV billion 2006$ 3 0.47 0.85 1.18 1.55 1.02 1.02 7 0.16 0.28 0.38 0.45 -0.08 -0.08 Analysis

10.4.1.1 Liquid-Immersed Results Table 10.4.2 presents the NES and NPV results for liquid-immersed transformers by product class. Figure 10.4.1 illustrates the typical pattern of primary energy savings and costs resulting from standards for liquid-immersed transformers over time. The figure shows the nature of net savings for all ten TSLs relative to the base case. In this figure, the levels are ordered fromlowest to highest energy savings. The levels with letter names have consistency between singlephase and three-phase design lines. The constraint created by such consistency lowers the NPV for these levels.

10-22Table 10.4.2 Summary of Cumulative National Energy Savings (2010–2038) and Net Present Value (2010–2073) Impact for Liquid-Immersed Transformers
Distribution Transformers Analysis Discount Rate

% Trial Standard Level TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL A TSL B TSL C TSL D
LiquidNES quads 0.81 0.90 0.94 1.05 1.72 3.97 1.88 1.45 1.45 1.02 Immersed Singl e-Phase NPV billion 2006$ 3 3.15 3.42 3.74 3.60 1.02 -24.5 -0.31 2.98 2.97 3.58 7 0.98 1.04 1.17 0.93 -1.33 -18.5 -2.28 0.14 0.14 0.94
LiquidNES quads 0.57 1.04 1.82 1.96 3.36 3.41 2.19 1.30 1.16 1.16 Immersed Thr ee-Phase NPV billion 2006$ 3 2.42 3.64 5.42 5.72 0.38 -1.58 4.78 4.28 3.98 3.98 7 0.71 0.91 1.20 1.21 -3.56 -4.75 0.38 0.97 0.96 0.96

Figure 10.4.1 Liquid-Immersed Distribution Transformers: National Energy Savings and Net Present Value Impacts

10-2310.4.1.2 Dry-Type Results Tables 10.4.3 and 10.4.4 present NES and NPV results for dry-type transformers by prod uct class. Figure 10.4.2 shows the typical pattern of national savings and costs resulting from standards for dry-type transformers over time. Again, the figure shows the nature of net savings for six dry-type transformer TSLs relative to the base case. Table 10.4.3 Cumulative Primary Energy Savings During 2010–2038: Dry-Type Transformers by Product Class

Product Class Cumulative Primary Energy Savings quads TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 5. Dry-Type, MV, Single-Phase, 20-45 kV BIL 0.0003 0.0005 0.0008 0.0011 0.0014 0.0014 6. Dry-Type, MV, Three-Phase, 20-45 kV BIL 0.015 0.028 0.040 0.052 0.068 0.068 7. Dry-Type, MV, Single-Phase, 46-95 kV BIL 0.0004 0.0007 0.0009 0.0013 0.0016 0.0016 8. Dry-Type, MV, Three-Phase, 46-95 kV BIL 0.045 0.096 0.134 0.196 0.301 0.301 9. Dry-Type, MV, Single-Phase, > 96 kV BIL 0.00001 0.00006 0.00011 0.00018 0.00025 0.00025 10. Dry -Type, MV, Three-Phase, > 96 kV BIL 0.0010 0.0064 0.0115 0.0199 0.0267 0.0267 Total 0.062 0.1131 0.187 0.270 0.399 0.399

10-24Table 10.4.4 Net Present Value During 2010–2073: Dry-Type Transformers by Product Class Net Present Value
Product Class $billion Discount Rate: 3% Discount Rate: 7% TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 5. Dry-Type, MV, 0.002 0.003 0.005 0.006 0.004 0.004 0.001 0.001 0.002 0.002 0.000 0.000 Single-Phase, 20-45 kV BIL 6. Dry-Type, MV, 0.108 0.166 0.233 0.276 0.192 0.192 0.035 0.052 0.070 0.075 -0.002 -0.002 Three-Phase, 20-45 kV BIL 7. Dry-Type, MV, 0.003 0.005 0.006 0.008 0.006 0.006 0.001 0.002 0.002 0.002 0.001 0.001 Single-Phase, 46-95 kV BIL 8. Dry-Type, MV, 0.346 0.639 0.868 1.160 0.777 0.777 0.119 0.217 0.283 0.344 -0.058 -0.058 Three-Phase, 46-95 kV BIL 9. Dry-Type, MV, 0.000 0.000 0.001 0.001 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Single-Phase, > 96 kV BIL 10. Dry-Ty pe, MV, 0.007 0.037 0.067 0.095 0.037 0.037 0.002 0.012 0.022 0.022 -0.023 -0.023 Three-Phase, > 96 kV BIL Total 0.466 0.851 1.182 1.546 1.018 1.018 0.159 0.283 0.379 0.445 -0.085 -0.085

10-25Figure 10.4.2 Dry-Type Distribution Transformers: National Energy Savings and Net Present Value Impacts The national impact spreadsheet is available as an Excel file on the DOE website: http ://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers. html. Instructions for using the spreadsheet are in Appendix 10A of this TSD. 10.4.1.3 Discounted Cumulative Energy Impacts In the ANOPR, DOE stated that, for its NOPR analysis, it would calculate discounted values for future national energy savings. DOE used the same discount rates that it used in calculating the NPV (seven percent and three percent real) to calculate discounted cumulative NES. As described in section 10.3.2.7, it used the seven-percent and three-percent real discount rates in accordance with the OMB guidelines on regulatory analysis. 8Table 10.4.5 shows the discounted national energy savings for both liquid-immersed and dry-type, medium-voltage transformers. The seven-percent and three-percent real discount rate values are meant to capture the present value of costs and benefits associated with projects facing an average degree of risk. Other discount rates may be more applicable for discounting costs and benefits associated with projects facing different risks and uncertainties. Risk adjustment theory suggests that lower discount rates may be called for to calculate the present value of future energy consumption or saving.

10-26Table 10.4.5 Discounted Cumulative Energy Impacts, Liquid-Immersed and Dry-Type, Medium-Voltage Transformers Liquid-Immersed Dry-Type, Medium-Voltage Cumulative Cumulative Cumulative Cumulative 2010-2038 2010-2038 2010-2038 2010-2038 3% discount 7% discount 3% discount 7% discount TSL1 quads 0.768 0.391 0.034 0.018 TSL2 quads 1.080 0.550 0.073 0.037 TSL3 quads 1.534 0.780 0.104 0.053 TSL4 quads 1.672 0.851 0.199 0.099 TSL5 quads 2.824 1.439 0.222 0.113 TSL6 quads 4.105 2.093 0.222 0.113 TSLA quads 2.267 1.154 TSLB quads 1.531 0.780 TSLC quads 1.450 0.738 TSLD quads 1.213 0.618

10-27REFERENCES

1. HVOLT Consultants Inc., P. Hopkinson, and J. Puri. Distribution Transformer Market Shipment Estimates for 2001. February 17, 2003. 370 4 High Ridge Road, Charlotte, NC, 28270, tel: (704) 846-3290, e-mail: P.Hopkinson@hotmail.com. Prepared for Navigant Consulting, Inc., Washington DC. 2. U.S. Department of Commerce - Bureau of Economic Analysis. Industr y Economic Accounts Information Guide. Annual Industry Accounts. Gross Domestic Product (GDP) by Industry. 2005. (Last accessed May 11, 2005.) This material is available in Docket #86. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <For download page, see http://www.bea.gov/bea/dn2/iedguide.htm#gpo . For 1977-1997 data, go to http://bea.gov/bea/pn/GDPbyInd_SHIP_SIC.xls . For 1998-2003 data, go to http://bea.gov/bea/pn/GDPbyInd_SHIP_NAICS.xls .>> 3. U.S. Department of Energy-Energy Information Administration. Annual Energy Review 2003, Chapter 8: Electricity, Table 8.9 Electricity End Use, 1949-2003. 2004. (Last accessed May 9, 2005.) This material is available in Docket #86. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <http://www.eia.doe.gov/emeu/aer/txt/stb0809.xls> 4. U.S. Department of Energy - Energy Information Administration. Annual Energy Outlook 2005: With Projections Through 2025. Ja nuary, 2005. Washington, DC. Report No. DOE/EIA-0383(2005). <http://www.eia.doe.gov/oiaf/aeo/index.html> 5. U.S. Department of Energy-Energy Information Administration. National Energy Modeling System: An Overview 2003. 2003. R eport No. DOE/EIA-0581(2003). <http://www.eia.doe.gov/oiaf/aeo/overview/index.html> 6. Institute of Electrical and Electronics Engineers Inc. Draft Guide for Distribution Transformer Loss Evaluation. October, 2001. 345 E ast 47th Street, New York, NY. Report No. IEEE PC57.12.33/D8. 7. Institute of Electrical and Electronics Engineers Inc. Guide For Loading Mineral OilImmersed Transformers. 1995. 345 East 47th Street, New York, NY. Report No. IEEE Std C57.91-1995. Transformer Committee of the IEEE Power Engineering Society. 8. U.S. Office of Management and Budget. Cir cular A-4: Regulatory Analysis. 2003. (Last accessed March 25, 2005.) This material is available in Docket #86. Contact Ms. Brenda

10-28Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202)586-2945 for more information. <http://www.whitehouse.gov/omb/circulars/a004/a4.pdf> 9. U.S. Department of Energy-Office of Building Technologies. Technical Support Document: Energy Conservation Program for Commercial and Industrial Equipment: Electrical Distribution Transformers - ANOPR Version. 2004. U.S. Department of Energy. Washington, DC. Report No. LBNL-53985. <http://www.eere.energy.gov/buildings/appliance_standards/commercial/dist_trans_tsd_0 61404.html>

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