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CHAPTER 10. NATIONAL IMPACT ANALYSIS

TABLE OF CONTENTS

10.1 INTRODUCTION ......................................................................................................... 10-1

10.2 NATIONAL ENERGY SAVINGS ............................................................................... 10-4

10.2.1 Overview........................................................................................................................ 10-5

10.2.2 Inputs.............................................................................................................................. 10-6

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

10.2.2.2 Mapping Design Line Data to Equipment Classes...................................... 10-8

10.2.2.3 Mapping Draft Efficiency Level to Draft Trial Standard Level ................ 10-10

10.2.2.4 Root Mean Square Load ............................................................................ 10-11

10.2.2.5 Load Growth .............................................................................................. 10-11

10.2.2.6 Affected Stock ........................................................................................... 10-12

10.2.2.7 Unit Energy Consumption ......................................................................... 10-13

10.2.2.8 Site-to-Source Electricity Conversion ....................................................... 10-13

10.3 NET PRESENT VALUE............................................................................................. 10-15

10.3.1 Overview...................................................................................................................... 10-15

10.3.2 Inputs............................................................................................................................ 10-17

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

10.3.2.2 Operating Costs.......................................................................................... 10-18

10.3.2.3 Peak Responsibility Factor ........................................................................ 10-19

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

10.3.2.5 Scalar for Electricity Price Forecasts......................................................... 10-20

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

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

10.3.2.8 Projection of Future Product Prices........................................................... 10-21

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

10.4.1 National Energy Savings and Net Present Value for Draft Trial Standard Levels...... 10-21

10.4.1.2 Results for Liquid-Immersed Transformers............................................... 10-22

10.4.1.3 Results for Low-Voltage Dry-Type Transformers .................................... 10-23

10.4.1.4 Results for Medium-Voltage Dry-Type Transformers.............................. 10-24

LIST OF TABLES

Table 10.2.1 Mapping of Design Line to Equipment Class.................................................... 10-9

Table 10.2.2 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Liquid-Immersed Transformers....................................................................... 10-10

Table 10.2.3 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Low-Voltage Dry-Type Transformers............................................................. 10-10

Table 10.2.4 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Medium-Voltage Dry-Type Transformers....................................................... 10-11
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Table 10.2.5 Average Site-to-Source Conversion Factors for No-Load Losses and Load 

Losses............................................................................................................... 10-14

Table 10.3.1 First Cost of Distribution Transformers by Draft Trial Standard Level and 

Equipment Class (2010$/kVA)........................................................................ 10-18

Table 10.3.2 Peak Responsibility Factors by Equipment Class............................................ 10-19

Table 10.3.3 Initial Peak Loading by Equipment Class........................................................ 10-20

Table 10.3.4 Marginal Energy and Capacity Costs by Equipment Class............................. 10-20

Table 10.4.1 Results of Calculating Cumulative National Energy Savings (2016–2045) 

and Net Present Value (2016–2104)................................................................ 10-22

LIST OF FIGURES

Figure 10.1.1 Flowchart of National Impact Analysis............................................................. 10-3

Figure 10.4.1 Liquid-Immersed Distribution Transformers: Impacts of Standards on 

National Energy Savings and Net Present Value............................................. 10-23

Figure 10.4.2 Low-Voltage Dry-Type Distribution Transformers: Impacts of Standards 

on National Energy Savings and Net Present Value........................................ 10-24

Figure 10.4.3 Medium-Voltage Dry-Type Distribution Transformers: Impacts of 

Standards on National Energy Savings and Net Present Value....................... 10-25
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CHAPTER 10. NATIONAL IMPACT ANALYSIS

10.1 INTRODUCTION

The Energy Policy and Conservation Act (EPCA) of 1975, as amended, states that any 

new or amended energy efficiency standard must be selected to achieve the maximum 

improvement in energy efficiency that is both technologically feasible and economically 

justified. In determining whether a standard is economically justified, the U.S. Department of 

Energy (DOE) must determine whether the benefits of the potential standard outweigh 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 equipment compared to any increase in its price, or in its initial charges or 

maintenance, that are likely to result from promulgation of the standard.

To satisfy this EPCA requirement and to more fully understand the overall impact of 

potential efficiency standards for distribution transformers, DOE conducted a national impact 

analysis (NIA). The NIA assessed future national energy savings (NES) from energy 

conservation standards for transformers and the national economic impact using the net present 

value (NPV). This chapter describes the method DOE used to estimate the national impacts of 

draft trial standard levels for medium-voltage liquid-immersed and low- and medium-voltage 

dry-type distribution transformers. The analyses that preceded the shipments analysis in chapter 

9 (e.g., the engineering analysis [chapter 5] and the life-cycle cost analysis [chapter 8] examined

transformers by design line, accounting for the 14 distinct design options found in transformers.

For the NIA, DOE must examine impacts as they relate to equipment classes, because the final 

standards will apply to equipment classes, not design lines. DOE evaluated the following 

impacts: (1) NES attributable to each potential standard, (2) monetary value of the NES to 

purchasers of the considered equipment, (3) increased total installed cost of the equipment

because of standards, and (4) NPV of energy savings (the difference between the operating cost 

savings and increased total installed cost). 

To conduct its NIA, DOE determined both the NES and NPV for each draft trial standard

level being considered for distribution transformers. DOE performed all calculations for each 

considered equipment class using a Microsoft Excel spreadsheet model. The national impact 

spreadsheet is available as an Excel file on the DOE website: 

www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html. 

The spreadsheets combine the calculations for determining the NES and NPV for each 

considered equipment class with input from the appropriate shipments model that DOE used to 

forecast future purchases of transformers. Chapter 9 provides a detailed description of the 

shipments model, including customers’ sensitivities to total installed cost, operating cost, and 

income, and how DOE captured those sensitivities within the model. The NES and NPV together 

constitute the NIA model. Additional details, along with instructions for using the NIA 

spreadsheet, are provided in appendix 10A of this technical support document.
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Figure 10.1.1 presents a flow diagram of the model and spreadsheets used to perform the 

NIA (NES and NPV) for distribution transformers. In the diagram, arrows show the direction 

that information flows when the calculation is performed. The process begins with inputs (shown 

as parallelograms). As information flows from the inputs, it may be integrated into intermediate 

results (shown as rectangles) or, via integrating sums or differences (shown as circles), into 

major outputs (shown as boxes having wavy bottom edges). 

The NIA calculation starts with the shipments model (chapter 9), which is shaded in the 

flow diagram. For transformers, the model integrated the inputs of estimates of 2001 and 2009

shipments from DOE’s contractor,

1,2 the U.S. Bureau of Economic Analysis (BEA) transformer 

quantity index,

3 electricity market shares from DOE’s Energy Information Administration 

(EIA),

4,5 and equipment price estimates from DOE’s life-cycle cost (LCC) analysis. The model

produced both 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 would be affected by draft trial standard levels and transformer 

retirements. 

DOE used a scaling factor (described in section 10.2.2.1) to estimate the national impacts 

of new standards for all the equipment classes considered in this rulemaking. The scaling factor 

is applied to the equipment cost and annual energy consumption of each representative 

transformer size so they can describe all sizes within that equipment class.
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Figure 10.1.1 Flowchart of National Impact Analysis 

Following the calculation of shipments, the calculations of NES and NPV begin. For both 

calculations, key inputs from the LCC analysis are the average rated no-load and load losses and 

the cost of transformers, including installation. DOE adjusted the losses and equipment costs for 

transformer size and type to convert the applicability of the data from representative design lines 

to average equipment classes. Additional inputs on average and peak losses—including root 

mean square (RMS) loading, peak loading, and peak responsibility factor—enabled DOE to
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convert rated losses into actual losses. At this point, the information flow for the NES and NPV 

calculation splits into two paths.

On one path, the NES calculation sums the kilowatt-hours of energy consumed by the 

affected stock, taking the difference between the base-case and standards scenario to calculate 

site energy savings. DOE converted site energy savings to energy savings at the source (i.e., at 

the power plant), using average heat rates for base load and peak load generation from DOE’s 

National Energy Modeling System (NEMS).

6 The average heat rates from NEMS include 

transmission and distribution losses. Summing the annual energy savings for the forecast period, 

which extends from 2016 through 2045, provides the final NES result.

On the other path, the NPV calculation starts with marginal price inputs from the LCC 

analysis for both energy and capacity costs and for both load and no-load losses. The marginal 

prices, combined with the actual peak and average losses, provide estimates of operating costs. 

Meanwhile, the adjusted cost of installed equipment times the annual shipments provides the 

estimate of the total annual equipment costs. DOE calculated three differences to assess the net 

impact of each draft trial standard level (dTSL). The first difference was between equipment 

costs in each dTSL scenario and the base case to obtain the net increase in equipment cost 

attributable to the dTSL. The second difference was between operating costs under the base-case 

scenario and each dTSL to obtain the net operating cost savings from the dTSL. The third 

difference was between the net operating cost savings and the net increase in equipment cost, 

which provides the net expense or savings for each year. To obtain the NPV impact of a dTSL, 

DOE discounted the net expenses or savings to 2010$ and summed them for 2016–2104a for 

transformers purchased during 2016–2045.

The two models that comprise the NIA are described below—the NES model in section 

10.2, and the NPV model in section 10.3. Each description begins with a summary of the model, 

followed by an overview of how DOE performed that model’s calculations. Then model inputs 

are summarized. The final subsections of the two sections describe each of the major inputs and 

computational steps in detail and with equations when appropriate. After the technical 

descriptions of the models, this chapter presents the results of the NIA calculations.

10.2 NATIONAL ENERGY SAVINGS

DOE developed the national energy savings (NES) model to estimate the total NES using 

results 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 in which there are

no national standards. Positive values of NES correspond to net energy savings, specifically a 

decrease in energy consumption after implementation of a standard, in comparison to the energy 

consumption in the base-case scenario.

 a The analysis period for NPV is based on the cumulative operating cost savings of the last unit shipped (2045 + 

maximum transformer life -1).
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10.2.1 Overview

DOE calculated the cumulative incremental energy savings from each potential 

transformer efficiency standard relative to a base-case scenario of no standard. It calculated NES, 

in units of quads, throughout the forecast period for standards that it assumed will be effective in 

2016. The NES calculation started with estimates of transformer shipments and stocks (inservice transformers), which are outputs of the shipments model (chapter 9). DOE then obtained 

estimates of transformer energy 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. In each standards case, as more efficient transformers replace less efficient ones that retire 

from service, the energy per unit capacity used by the stock of transformers gradually decreases 

relative to the base case. DOE used a site-to-source conversion factor to convert the amount of 

energy used by the transformers into the amount of energy consumed at the source of electricity 

generation (the source energy). The site-to-source conversion 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 2016 through 2045 to calculate the total NES for the forecast period. 

In calculating the NES, DOE did not assume any trends in transformer name-plate 

efficiency besides the incremental improvement indicated by the LCC calculation. In examining

proprietary shipments data provided by the transformer industry, DOE found that the data 

revealed no conclusive trends in improved efficiency. Deciding that future efficiency trends 

generally are indeterminate, DOE chose to use fixed baseline efficiency. DOE also assumed that 

the efficiency of transformers does not degrade over time. Therefore the annual energy savings 

can be described in terms of an affected stock, as described in section 9.3.11 of the shipments 

chapter. Annual energy savings therefore are described by the following equation.

AES(y) = (UECBase − UECStd) × Aff_Stock(y) 

Where:

AES(y) = the annual energy savings in year y,

UECBase = the site unit energy consumption for the base case,

UECStd = the site unit energy consumption for the standards case, and

Aff_Stock(y) = the stock of transformers of all vintages that are operational in year y.

Given the annual energy savings, the cumulative NES can then be calculated as a simple 

sum.

NES= ∑ SiteToSource(y) × AEC(y) 2045

y=Stdyear

Where:

Stdyear = the year standards come into effect,

SiteToSource(y) = the site-to-source conversion factor in year y, and

AEC = the annual energy consumption.
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After the shipments model provides the estimate of affected stock, the NES calculates

UECBase and UECStd using the output from the LCC analysis and including the site-to-source 

conversion factor. The following section summarizes the inputs necessary for the NES 

calculation and then describes each input individually.

10.2.2 Inputs 

Inputs to the NES model fall into three broad categories: (1) those that help convert the

data from the LCC into data relevant to the equipment classes and transformer size distributions 

used in the NES; (2) those that help calculate the unit energy consumption; and (3) the site-tosource conversion factor, which enables the calculation of source energy consumption from site 

energy use. The specific NES model inputs are:

1. size scaling of losses and costs,

2. mapping of LCC design line data to equipment classes,

3. root mean square loading,

4. load growth,

5. affected stock,

6. effective date of standard,

7. unit energy consumption, and

8. electricity site-to-source conversion.

Each input is described further below.

10.2.2.1 Size Scaling of Losses and Costs

Transformers are produced over a broad range of capacities, only a few of which are 

modeled explicitly in this analysis. The modeled designs are referred to as representative units. 

Any given equipment type includes 2-4 representative units at different capacity, or kVA values. 

DOE used a scaling relationship, or equation, to project the economic results from a given 

transformer 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 the 

distribution of transformer sizes incorporated in the calculation of NES and subject to potential 

standards. The Department uses the 0.75 scaling rule to scale the cost and efficiency results for 

the modeled kVA values to the full capacity range for each type, the 0.75 scaling rule is 

discussed in greater detail in chapter 5. This rule assumes that both the physical and cost 

characteristics are determined by the quantity of material required to build the transformer, and is 

approximately true. In practice, if the kVA-range over which cost and efficiency data are to be 

scaled is large, the 0.75 rule is less accurate. This manifests as kinks or angles in the curve of 

efficiency as a function of capacity for a given equipment type.

The Department has implemented a correction to the 0.75 scaling rule to produce 

smoother curves of efficiency vs. capacity. This correction adjusts the value of the exponent (the 

0.75 of the scaling rule) so that the curve extrapolates correctly between any two representative 

units. Mathematically, the efficiency of a transformer is equal to the ratio:
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Eff = Load

(Load + Losses) �

Where:

Eff = transformer efficiency

Load = the load on the transformer

Losses = the transformer’s combined no-load and load losses.

Load is proportional to capacity kVA, and if the 0.75 scaling rule is valid, losses are 

proportional to (kVA)

0.75. This expression can thus be written as,

Eff = 1

(1 + Constant × (kVA)−0.25) �

Defining the loss function as 

Losses = 1

Eff − 1 � ,

Losses = Constant × (kVA)−0.25

For two representative units labeled 1 and 2, 

Log �

Losses1

Losses2

� = −0.25 Log �

kVA1

kVA2

�

The validity of the 0.75 scaling rule can thus be tested by evaluating the ratio,

x =

−Log �

Losses1

Losses2 � �

Log �

kVA1

kVA2 � �

The Department uses the exponent x calculated through the above equation, instead of the 

value -0.25 implied by the scaling rule, to interpolate the efficiency between any two 

representative units. The Department uses the unmodified scaling rule to extrapolate efficiency 

values to capacities below the minimum representative unit, or above the maximum 

representative unit.

The Department calculated an adjustment factor using the exponent x to account for the 

fact that the representative design line unit used in the engineering analysis is not the “average” 

size for the set of transformers that the design line represents. This adjustment factor is given by 

the following equation.
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AdjFactor = ∑ [Shipi × Capi i 1+X]/(CapDL1+X × ∑i Shipi)

Where:

AdjFactor = the adjustment factor that, when multiplied by the design line losses or 

costs, gives the shipment-weighted losses or costs per transformer;

Shipi = the shipments in the i-th size category;

Capi = the rated capacity of 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 (AvgLossPerCapDL), as described

by:

AvgLossPerCapDL = LossPerCapDL × AdjFactor × CapDL / Capavg.

Where:

LossPerCapDL = the loss, or cost per unit capacity, for the design line unit from the

LCC analysis, and

Capavg = the shipment-weighted average size of transformers represented by a 

particular design line.

After the losses and costs from the LCC were adjusted to represent the correct size 

distribution, they needed a further adjustment to represent the appropriate equipment classes, as 

described in the following section.

10.2.2.2 Mapping Design Line Data to Equipment Classes

The calculations of NES and NPV use the LCC calculations (chapter 8) as the source of 

most input data. DOE performed the LCC calculations by design line, whereas any standard will 

be promulgated by equipment class. As a first step, therefore, the NES calculation aggregates the

LCC design line data into equipment classes. DOE used this aggregation method to prepare for 

estimating economic impacts by equipment class.

To represent the range of designs in some equipment classes, DOE often analyzed several

design lines per equipment class. For example, equipment class 1 (single-phase, mediumvoltage, liquid-immersed transformers) is represented by three design lines, and equipment class 

2 (three-phase, medium-voltage, liquid-immersed transformers) is represented by two design 

lines. DOE did not specifically examine single-phase, medium-voltage, dry-type design lines. 

For single-phase equipment classes 5, 7, and 9, DOE used factors for the appropriate three-phase

design lines divided by three. Table 10.2.1 presents the mapping of design line (DL) to 

equipment class (EC).
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Table 10.2.1 Mapping of Design Line to Equipment Class

Equipment Class BIL* 

kV

Capacity 

kVA

Mapping

1 Liquid-immersed, medium-voltage, single-phase Any 10–833 DL1 + DL2 + DL3

2 Liquid-immersed, medium-voltage, three-phase Any 15–2,500 DL4 + DL5

3 Dry-type, low-voltage, single-phase ≤ 10 15–333 DL6

4 Dry-type, low-voltage, three-phase ≤ 10 15–1,000 DL7+DL8

5 Dry-type, medium-voltage, single-phase 20–45 15–833 (DL9 + DL10)/3

6 Dry-type, medium-voltage, three-phase 20–45 15-2,500 DL9 + DL10

7 Dry-type, medium-voltage, single-phase 46–95 15–833 (DL11 + DL12)/3

8 Dry-type, medium-voltage, three-phase 46–95 15–2,500 DL11 + DL12

9 Dry-type, medium-voltage, single-phase > 95 75–833 (DL13A + DL13B)/3

10 Dry-type, medium-voltage, three-phase > 95 225–2,500 DL13A + DL13B

* BIL = basic impulse insulation level in kilovolts (kV).

To aggregate losses from more than one design line, DOE applied the average of 

shipments weighted by capacity of the per-kilovolt-ampere (kVA) transformer characteristics

from the economic analysis of the design lines to the estimated capacity shipped for each 

equipment class. DOE’s contractor1,2 provided the capacity shipped for each design line (and 

each equipment class). The LCC analysis provided the economic results for each design line, and 

DOE used the scaling method described in section 10.2.2.1 to estimate the scaled cost and loss 

estimates for each size category represented by each design line. The following equation 

provides the average loss per unit capacity for an equipment class (AvgLossPerCapEC) as derived 

from the average loss per unit capacity for a design line. The equation sums those design lines 

that constitute an equipment class.

AvgLossPerCapEC = ∑ [AvgLossPerCapDL × MSDL DL ]

∑DL MSDL � .

Where:

AvgLossPerCapDL = the average loss per unit capacity for the design line, and

MSDL = the design line’s market share by capacity.

The AvgLossPerCapEC represents the average loss per unit capacity of the transformer

load. No further adjustment is needed for no-load losses. For load losses, however, the losses at

rated load must be converted to losses at actual loading. Root mean square (RMS) loading is a 

key factor used in estimating load losses at actual loading. The following section describes the 

RMS loading input to the NES.
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10.2.2.3 Mapping Draft Efficiency Level to Draft Trial Standard Level 

The Department conducted the LCC analysis for up to seven alternate efficiency levels, 

i.e., draft efficiency levels (dELs), for each representative unit in the 14 design lines. The 

Department selected the dEL efficiency levels for each design line by applying a set of common 

economic criteria to intermediate LCC analyses as discussed in chapter 5, resulting in unique sets 

of dEL efficiencies for each design line. It mapped these LCC analysis results to draft trial 

standard levels (dTSLs) for the 10 product classes. 

For liquid-immersed and medium-voltage dry-type (MVDT) transformers DOE selected 

five dTSLs. For dTSLs 1 through 4 DOE directly mapped dTSLs to their corresponding dEL for 

smaller capacity design lines; while larger capacity design lines were mapped to next higher dEL

than their smaller capacity counterparts. Max-tech is mapped to dTSL 5. For low-voltage drytype (LVDT) design lines DOE selected six dTSLs. Similar to the liquid-immersed and MVDT,

smaller capacity LVDT design lines dTSLs were mapped to their correspondingly higher dELs 

for dTSLs 1, 3, 4 and 5; while larger capacity design lines were mapped to next higher dEL than 

their smaller capacity counterparts.. The dELs that represent NEMA’s voluntary efficiency 

standard NEMA Premium were mapped to dTSL 2 and max-tech was mapped to dTSL 6.

Table 10.2.2 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Liquid-Immersed Transformers

Design Line dTSL1 dTSL2 dTSL3 dTSL4 dTSL5

1 Liquid-Immersed, 50kVA, single-phase dEL1 dEL2 dEL3 dEL4 dEL7

2 Liquid-Immersed, 25kVA, single-phase dEL1 dEL2 dEL3 dEL4 dEL7

3 Liquid-Immersed, 500kVA, single-phase dEL2 dEL3 dEL4 dEL5 dEL7

4 Liquid-Immersed, 150kVA, three-phase dEL1 dEL2 dEL3 dEL4 dEL7

5 Liquid-Immersed, 1500kVA, three-phase dEL2 dEL3 dEL4 dEL5 dEL7

Table 10.2.3 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Low-Voltage Dry-Type Transformers

Design Line dTSL1 dTSL2* dTSL3 dTSL4 dTSL5 dTSL6

6 LVDT, 25kVA, single-phase dEL2 dEL3* dEL3 dEL4 dEL5 dEL7

7 LVDT, 75kVA, three-phase dEL2 dEL3* dEL3 dEL4 dEL5 dEL7

8 LVDT, 300kVA, three-phase dEL3 dEL2* dEL4 dEL5 dEL6 dEL7

*NEMA Premium
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Table 10.2.4 Mapping of Draft Efficiency Levels to Draft Trial Standard Levels for 

Medium-Voltage Dry-Type Transformers

Design Line dTSL1 dTSL2 dTSL3 dTSL4 dTSL5

9 MVDT, 300kVA, three-phase, 45kV BIL dEL1 dEL2 dEL3 dEL4 dEL7

10 MVDT, 1500kVA, three-phase, 45kV BIL dEL2 dEL3 dEL4 dEL5 dEL7

11 MVDT, 300kVA, three-phase, 95kV BIL dEL1 dEL2 dEL3 dEL4 dEL7

12 MVDT, 1500kVA, three-phase, 95kV BIL dEL2 dEL3 dEL4 dEL5 dEL7

13A MVDT, 300kVA, three-phase, 125kV BIL dEL1 dEL2 dEL3 dEL4 dEL7

13B MVDT, 2000kVA, three-phase, 125kV BIL dEL2 dEL3 dEL4 dEL5 dEL7

10.2.2.4 Root Mean Square Load

Energy losses in transformers follow the RMS load, not the arithmetic average load. DOE 

calculated the RMS load as the RMS of the transformer load divided by the transformer rated 

capacity, then multiplied by the power factor. (As explained in chapter 6, although DOE’s

analytical method can derive results for varying power factors, for the analysis presented here

DOE set the power factor to a value of one.) DOE used the average national RMS load for each 

design line as calculated for the LCC analysis. Those values range from 26.2 percent to 41.9

percent for the various design lines.

10.2.2.5 Load Growth

The load growth is the fraction by which the load increases after a transformer is 

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 increases the load losses relative to those 

estimated to have occurred during the first year of installation.

DOE calculated the fractional load growth from an estimated rate that it used as an 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 occurs, DOE assumed that the transformer would be installed in a new 

location where the initial peak loading would be the same as when originally installed.7 See

Institute of Electrical and Electronics Engineers, Inc. (IEEE) Std C57.91-19958 for details on

permissible overloading of mineral-oil-immersed transformers. Because IEEE does not report 

data on permissible overloading of dry-type units, DOE used the same values for both liquidimmersed and dry-type transformers. The age at which a transformer load switches back to initial 

peak load is given by the following equation.

ageMax = ln (1 + LGRMax)

l n(1 + LGR) . �
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Where:

ageMax = the maximum age of the transformer after which time the load switches back 

to initial peak load (years), and

LGR = the annual load growth rate (%).

Thus, the equation for the load growth as a function of the age of the transformer is:

LGrwth(age) = (1 − LGR)(age) − 1

for age < ageMax, and

LGrwth(age) = (1 − LGR)(age−ageMax) − 1

for age >= ageMax.

Where:

LGrwth (age) = the fractional load growth, and

age = the age of the transformer (years).

DOE then used the load growth to adjust the estimate of RMS load for the affected stock.

The mathematical equation for this adjustment is:

LAdjust(y) = � � [Stock(y, age) × (1 + LGrwth(age))2]

y−Std_year

age=1

/Aff_Stock(y),

where LAdjust(y) is the load adjustment factor in year y. All other variables were defined for

previous equations. DOE applied a load adjustment factor to RMS loading to incorporate load 

growth into the unit energy consumption, as described in section 10.2.2.7.

10.2.2.6 Affected Stock

The affected stock, an output of the shipments model (chapter 9), is a key input for the 

NES and NPV calculations. The affected stock represents that part of the transformer stock that 

would be impacted by a standard. It consists of those transformers purchased in or after the year 

the standard takes effect, as described by the following equation.

AffStock(y) = Ship(y) + ∑ Stock(age) y−Stdyear

age=1 .

Where:

Aff_Stock(y) = stock of affected transformers of all vintages that are operational in

year y,
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10-13

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.

10.2.2.7 Unit Energy Consumption

One of the final quantities DOE calculated to estimate the NES was the unit energy

consumption for affected stock. The unit energy consumption multiplied by the capacity shipped 

and the site-to-source conversion factor equals the annual site energy consumption from which 

DOE derived total NES.

Annual unit energy consumption (UEC(y)) for affected 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 load losses. It

calculated the load losses as the rated load loss times the square of the RMS load, adjusted for

load growth. Average energy consumed per unit capacity for affected stock varies from year to

year because of load growth effects. The annual unit energy consumption for affected stock of 

distribution transformers is given by the following equation.

UEC(y) = ENL + ELL × [RMS × LAdjust(y)]2

.

Where:

ENL = rated no-load losses per kVA capacity,

ELL = rated load losses per kVA capacity,

RMS = root mean square, and

LAdjust(y) = load adjustment factor for year y.

After 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.

10.2.2.8 Site-to-Source Electricity 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 quadrillion British

thermal units [quads]). Because the NES estimates the change in energy use of the resource (e.g.,

at 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 use—the 

installed transformer—DOE multiplied the site energy consumption by the conversion factor to 

obtain primary energy consumption, expressed in quads. This conversion permitted comparison 

across (source) fuels by taking into account the heat content of various fuels and the efficiency of 

various energy conversion processes. The annual conversion factors are the United States

averages for generating electricity for both peak and base loads. DOE used average heat rates 

corresponding to base load for no-load losses (or core losses), and average heat rates 

corresponding to peak load for load losses (or coil losses). It used different rates because load 

losses are higher during transformer peak loads, whereas no-load losses occur at all times. DOE 
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10-14

developed conversion factors using a variant of the NEMS5 called NEMS-BT.b Table 10.2.3

presents the average annual conversion factors DOE used.

Table 10.2.5 Average Site-to-Source Conversion Factors for No-Load Losses and Load

Losses

Year No-Load Losses Load Losses

2015 1.890 2.443

2016 1.888 2.446

2017 1.885 2.444

2018 1.883 2.443

2019 1.883 2.444

2020 1.886 2.446

2021 1.896 2.452

2022 1.900 2.450

2023 1.907 2.447

2024 1.915 2.448

2025 1.915 2.439

2026 1.916 2.425

2027 1.920 2.414

2028 1.921 2.395

2029 1.920 2.377

2030 1.919 2.355

2031 1.920 2.345

2032 1.920 2.330

2033 1.919 2.308

2034 1.920 2.294

2035 1.923 2.289

2036–2045 1.923 2.289

The conversion factors change over time to account for the changes in electricitygenerating 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 the conversion factors in the NES spreadsheet.

The conversion of site energy savings to source energy savings and the summation of

energy savings throughout the forecast period complete the calculations needed to estimate the

NES. The next section (section 10.3) describes the technical details of the NPV calculation. 

Section 10.4 presents the NES and NPV results from the NIA spreadsheet model.

 b DOE/EIA approves use of the name NEMS to describe only an official version of the model without any 

modification to code or data. Because this analysis entailed some minor code modifications and the model is run 

under policy scenarios that are variations on DOE/EIA assumptions, the name NEMS-BT refers to the model as 

used here (BT is DOE’s Building Technologies Program, under whose aegis this work was performed).
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10.3 NET PRESENT VALUE

DOE used a national net present value (NPV) accounting component in the NIA 

spreadsheet to estimate the national financial impact on customers from the imposition of 

potential energy efficiency standards. DOE combined the output of the shipments model with 

energy savings and financial data from the LCC analysis to calculate an annual stream of costs 

and benefits resulting from draft trial standard levels (dTSLs) for distribution transformers. It 

discounted this time series to 2010 and summed the result for 2016–2104 (the year the last unit 

shipped in 2045 retires from service), yielding the national NPV.

10.3.1 Overview

The NPV is the present value of the incremental economic impact of a dTSL. Like the 

NES, the NPV calculation started with transformer shipments and stocks, estimates of which are 

outputs of the shipments model. DOE then obtained estimates of transformer first costs, losses, 

and average marginal electricity costs from the LCC analysis. It calculated the costs of

transformer purchases and installation, then the corresponding operating costs for both a base 

case and a standards case, by applying marginal prices to the energy (both energy and electricity

system capacity) used by the stock of transformers for each year. In the standards case, more

expensive, but more efficient, transformers gradually replace less efficient units. Thus, the 

operating cost per unit capacity for the stock of transformers gradually decreases in the standards 

case relative to the base case, while equipment costs increase.

DOE used a simple national average discount factor to discount purchases, expenses, and 

operating costs for transformers. 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 represents the impact on national NPV. DOE calculated the NPV impact 

for transformers purchased during the forecast period (between the effective date of the standard 

and 2104, inclusive). Mathematically, NPV is the value in the present of a time series of costs

and savings, described by the equation:

NPV = PVS – PVC.

Where:

PVS = the present value of electricity savings, and

PVC = the present value of equipment costs including installation.

PVS and PVC are determined according to the following three equations.

PVS = ∑ �

OCBase

Cap � (y) × OCStdCap � (y)� × AffStock(y) × Discount Factor(y). 2104

y=Std_year
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10-16

Where:

OCBase/Cap(y) = operating cost in year y per unit capacity of transformer for the 

base case,

Aff_Stock(y) = stock of transformers of all vintages that are operational in year 

y,

y = the year (from effective date of the standard to the year when

units purchased in 2045 retire [in 2104]), and

Discount Factor(y) = discount factor for year y, defined in the next equation.

Discount Factor(y) = 1

(1 + Discount Rate) � (y−reference year)

Where:

reference year = 2016, and

discount rate = the discount rate, as described in section 10.3.2.7.

PVC is determined as follows.

PVC = � �

FCstd

Cap � (y) − FCBaseCap � (y)�

2104

Std_year

× Ship(y) × DiscountFactor(y).

Where:

FCStd/Cap (y) = first cost of the transformer per unit of capacity for a dEL Std in year 

y (first cost is described in section 10.3.2.1);

Std_year = the year the standard comes into effect, and

Ship(y) = shipments of transformers in year y for the standards case.

DOE calculated NPV using its projections of national expenditures for distribution

transformers, including purchase price (equipment and installation price) and operating costs

(electricity and maintenance costs). It calculated costs and savings as the difference between a

dTSL and a base case lacking national standards. It discounted future costs and savings to the 

present (2010$). DOE calculated a discount factor from the discount rate and the number of 

years between the year to which the sum is being discounted (2010) and the year in which the 

costs and savings occur. The NPV is the sum over time (2016–2104) of the discounted net

financial savings.

The following sections describe inputs to the NPV calculation that are not described 

elsewhere.
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10.3.2 Inputs

Inputs to the NPV model include cost inputs, inputs important for detailing electricity

capacity costs, and several of the inputs used by the NES calculation. This section provides

details on those inputs that were not described for the NES or shipments models. The specific

inputs for the NPV are:

1. first cost,

2. operating cost,

3. peak responsibility factor,

4. initial peak load,

5. scalar for electricity price forecast,

6. marginal electricity costs, and

7. discount rate.

Each input is described in detail below.

10.3.2.1 First Cost

The first cost includes all the initial costs incurred with the installation of a distribution 

transformer. 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.

Where:

FC = first cost;

Cap = rated capacity of the transformer;

P = price of the transformer including shipping, and taxes; and

Install = installation cost of the transformer.

The above values were obtained from the LCC calculation as the averages for individual

design lines. DOE converted the first cost of a representative design to an estimated average first 

cost for a distribution of sizes within a particular equipment class. The adjustment incorporates 

the 0.75 scaling rule and the mapping of design line to equipment class discussed in sections 

10.2.2.1 and 10.2.2.2. Costs are expressed in units of 2010$ per kVA of rated transformer 

capacity. Table 10.3.1 shows the resulting mean first costs per kVA for distribution transformers 

by dEL and equipment class. 
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10-18

Table 10.3.1 First Costc

Equipment Class

of Distribution Transformers by Draft Trial Standard Level 

and Equipment Class (2010$/kVA)

Base dTSL

1

dTSL

2

dTSL

3

dTSL

4

dTSL

5

dTSL

6

Liquid-immersed, medium-voltage, single-phase 101.58 112.68 116.08 115.92 117.97 154.76

Liquid-immersed, medium-voltage, three-phase 28.33 32.61 34.56 33.61 34.13 49.71

Dry-type, low-voltage, single-phase 67.25 52.67 51.16 53.36 55.88 90.81 142.08

Dry-type, low-voltage, three-phase 49.79 33.48 31.60 35.17 33.57 66.40 102.82

Dry-type, medium-voltage, single-phase 35.39 28.67 29.93 32.64 30.83 73.31

Dry-type, medium-voltage, three-phase 28.71 28.97 33.38 34.51 35.93 55.17

Dry-type, medium-voltage, single-phase 44.97 37.02 38.23 41.71 38.62 89.48

Dry-type, medium-voltage, three-phase 32.85 33.53 36.33 41.05 42.57 62.55

Dry-type, medium-voltage, single-phase 44.45 39.74 40.08 42.83 51.44 127.59

Dry-type, medium-voltage, three-phase 34.39 35.54 37.54 41.04 44.92 71.55

10.3.2.2 Operating Costs

Transformer operating costs are the annual cost of transformer losses. Operating costs are 

a complex, yet essential, part of calculating the national economic impact of a standard. DOE 

used distinct costs to calculate the value of various types of losses and peak capacity savings. 

Potential load growth also requires an adjustment factor. Peak loading, peak load coincidence, 

and average loading require additional factors to characterize load losses. Finally, DOE used a

scalar for the electricity price forecast to characterize future trends in electricity prices consistent 

with the EIA’s AEO2010 forecast.

4

In calculating transformer operating costs, DOE assumed zero incremental maintenance 

costs. It used the following formula to capture the diversity of factors that can affect annual 

operating costs.

OC/Cap = EPFS(y) × (ENL × (NLLMCC + 8760 × NLLMEC) + ELL × (LAdjust(y))2

× (PRF × PL2 × LLMCC + 8760 × RMS2 × LLMEC))/Cap.

Where:

OC = the operating cost,

Cap = the rated capacity of the transformer,

EPFS(y) = the scalar for the electricity price forecast for year y,

ENL = the no-load losses at rated load,

NLLMCC = the marginal cost of capacity for no-load losses,

 c First cost includes installation cost.
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10-19

NLLMEC = the marginal cost of energy for no-load losses,

ELL = 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 marginal cost of capacity for load losses,

RMS = the root mean square loading of the transformer, and

LLMEC = the marginal cost of energy for load losses.

DOE expressed the operating costs in 2010$ per kVA of rated capacity. As when 

calculating the NES (sections 10.2.2.1 and 10.2.2.2), DOE also used an adjustment factor to 

scale to ENL and ELL in order to convert from design line data to equipment class estimates.

10.3.2.3 Peak Responsibility Factor

The transformer peak responsibility factor (PRF) is the fraction of the transformer peak 

load 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 load, the PRF is necessary for estimating impacts on capacity 

costs of transformer load losses. DOE used the average PRF from the hourly and the monthly

load analyses for liquid-immersed and dry-type transformers, respectively, as reported in the

LCC analysis. Table 10.3.2 presents the PRFs used in the analysis of the 10 equipment classes

(ECs).

Table 10.3.2 Peak Responsibility Factors by Equipment Class

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

PRF 0.43 0.62 0.23 0.23 0.48 0.48 0.48 0.48 0.48 0.48

10.3.2.4 Initial Peak Load

The initial peak load 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 impacts 

on capacity costs from transformer load losses. The initial peak load is estimated as a percentage 

of the rated peak load of the transformer. The IEEE (2001)7 defines a similar, but different,

measure of peak transformer load called an “Equivalent Annual Peak Load” that accounts for 

changes in peak load during the life of the transformer. Rather than use the equivalent annual 

peak load, DOE used a distribution to characterize a range of initial peak loads. Chapter 6, 

sections 6.2.3.3 and 6.3.3.3, further describe DOE’s method. Table 10.3.3 presents the initial 

peak loads used in the NPV analysis for the 10 equipment classes.
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10-20

Table 10.3.3 Initial Peak Loading by Equipment Class

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

Initial Peak Load 0.88 0.88 0.80 0.79 0.85 0.85 0.81 0.80 0.80 0.80

10.3.2.5 Scalar for Electricity Price Forecasts

The scalar for forecasting electricity prices converts current electricity costs into 

forecasted costs for 2010 through 2104. The scalar is the ratio of the unit cost of electricity in 

real dollars in a given year to the real cost of electricity in 2010. DOE used forecasts from

AEO20114 to obtain the scalar for electricity price forecasts. For the period beyond 2035, DOE 

extrapolated the scalar based on the EIA real dollar price trend for 2025–2035.

10.3.2.6 Marginal Electricity Costs

DOE needed to characterize four distinct marginal electricity costs in order to calculate 

the operating costs of transformers and the financial impact of potential efficiency standards. The 

four marginal costs are: the marginal capacity cost for no-load losses, (the marginal capacity cost 

for load losses, the marginal energy cost for no-load losses, and the marginal energy cost for load 

losses. An electricity system has both energy costs and capacity costs. Depending on the shape of 

a particular load, the average value of capacity costs may differ from those of energy costs. 

Because no-load losses and load losses have distinct load shapes, and because different 

customers experience different load shapes, costs vary both by loss type and by the equipment 

class of a transformer. DOE therefore used distinct marginal energy and capacity costs for noload losses and load losses for each transformer equipment class. No transformer size scaling is 

necessary for the marginal costs, although DOE needed to map design lines to equipment classes 

(as described in section 10.2.2.2) to convert the design line output from the LCC to equipment 

class information for calculating the NPV. DOE calculated capacity costs in units of 

2010$/kilowatt (kW)/year, and energy costs in units of 2010$/kWh. Table 10.3.4 summarizes the 

four marginal costs for the 10 equipment classes.

Table 10.3.4 Marginal Energy and Capacity Costs by Equipment Class

Marginal Energy Cost by Equipment Class $/kWh

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

NLL 0.067 0.049 0.060 0.060 0.060 0.060 0.060 0.060 0.060 0.060

LL 0.073 0.054 0.059 0.059 0.059 0.059 0.059 0.059 0.059 0.059

Marginal Capacity Cost by Equipment Class $/kW/year

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

NLL 498.59 498.59 142.62 142.62 142.62 142.62 142.62 142.62 142.62 142.62

LL 197.66 197.66 104.25 104.68 104.25 104.25 104.25 104.25 104.25 104.25

10.3.2.7 Discount Rate

The discount rate, which is the final input to the NPV calculation, expresses the time 

value of money. DOE used real discount rates of 3 percent and 7 percent, as established by the 

Office of Management and Budget guidelines on regulatory analysis.9 The discount rates DOE 

used in the LCC differ from those used in the NPV calculations, in that the NPV discount rates 
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10-21

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.

10.3.2.8 Projection of Future Product Prices

For reasons discussed in chapter 8 (Section 8.2.1.1), DOE used a constant price 

assumption for the default forecast in the NIA. In order to investigate the impact of different 

product price forecasts on the consumer net present value (NPV) for the considered dTSLs for 

medium electric motors, DOE also considered two alternative price trends. Both of these trends 

are based on a power-law fit on the deflated producer price index for electric power and specialty 

transformer manufacturing. Details on how these alternative price trends were developed are in 

appendix 10B, which also presents the results of the sensitivity analysis.

10.4 RESULTS

The following sections summarize the results of the NES and NPV calculations

performed for the NIA.

10.4.1 National Energy Savings and Net Present Value for Draft Trial Standard Levels

Table 10.4.1 presents the NES and NPV results from the spreadsheet model for dTSLs 1–

5 for medium-voltage liquid-immersed and dry-type transformers and dTSLs 1–6 for lowvoltage dry-type transformers. It should be reiterated that the NES spreadsheet model uses

discrete point values rather than a distribution of values for all inputs.
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Table 10.4.1 Results of Calculating Cumulative National Energy Savings (2016–2045) 

and Net Present Value (2016–2104) 

Discount 

Rate 

(%)

Draft Trial Standard Level

1 2 3 4 5 6

Liquid-Immersed

Cumulative Source Savings 2044 (Quads) 0.70 1.03 1.16 1.47 2.43

Net Present Value (B 2010$) 3 3.29 5.48 8.00 11.32 -0.11

7 -0.33 -0.13 0.76 1.47 -7.49

Low-Voltage Dry-Type

Cumulative Source Savings 2044 (Quads) 1.15 1.22 1.23 1.49 0.94 1.54

Net Present Value (B 2010$) 3 16.23 17.56 16.43 19.30 2.94 -3.91

7 6.26 6.81 6.21 7.22 -0.19 -4.79

Medium-Voltage Dry-Type

Cumulative Source Savings 2044 (Quads) 0.20 0.26 0.31 0.37 0.41

Net Present Value (B 2010$) 3 1.55 1.77 1.74 2.08 -0.14

7 0.48 0.48 0.37 0.44 -0.76

*B2010 = billion dollars in 2010 value.

10.4.1.2 Results for Liquid-Immersed Transformers

Figure 10.4.1 illustrates the typical pattern of source energy savings and costs resulting 

from standards for liquid-immersed transformers. The figure shows the nature of net savings for 

all six dTSLs relative to the base case. The figure also shows the NPV at both a 3-percent and a 

7-percent discount rate. In this figure, the dTSLs are ordered from lowest to highest energy

savings. 
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10-23

Figure 10.4.1 Liquid-Immersed Distribution Transformers: 

Impacts of Standards on National Energy Savings 

and Net Present Value 

Figure 10.4.1 shows that, although the savings in energy (quads) are greatest at dTSLs 5 

(max tech), the associated financial savings decrease dramatically at either the 3 percent or 7 

percent discount rate. At a discount rate of 3 percent, the NPV of cumulative source savings for 

liquid-immersed transformers are highest at dTSL 4. At a discount rate of 7 percent, the NPV is 

highest at dTSL 4.

10.4.1.3 Results for Low-Voltage Dry-Type Transformers

Figure 10.4.2 shows the pattern of source energy savings and costs resulting from 

potential standards for low-voltage dry-type transformers. The figure shows the nature of net 

savings for the six dTSLs relative to the base case. The figure also shows the NPV at both a 3-

percent and a 7-percent discount rate.

-10.0

-5.0

0.0

5.0

10.0

15.0

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1 2 3 4 5

Net Present Value (Billion US$)

Cumulative Source Energy Savings (Quads)

Trial Standard Levels

Cumulative Source Energy Savings and NPV for Liquid-Immersed Units

Cumulative Source Savings 2045 (Quads) Net Present Value at 3% Discount Rate ($Billions) 

Net Present Value at 7% Discount Rate ($Billions) 
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10-24

Figure 10.4.2 Low-Voltage Dry-Type Distribution Transformers: 

Impacts of Standards on National Energy Savings 

and Net Present Value 

Figure 10.4.2 shows that, although the cumulative savings in energy (quads) are highest 

under dTSLs 4 and 6, the associated financial savings decrease dramatically at either discount 

rate. The reduction of cumulative energy savings at dTSL 5 can be attributed to higher than 

expected load losses. The efficiency level dTSL 5 represents a complete the shift from grain 

oriented steels to amorphous steel for transformer cores for low-voltage dry-type transformers. 

The high efficiency of amorphous steel enables transformers to meet dTSL 5 with lower 

efficiency winding materials, it is the influence of these inefficient windings that increase the 

load-losses and reduce the overall cumulative source savings. At a discount rate of 3 percent, the 

NPV of cumulative source savings for dry-type transformers are highest under dTSL4. At a 

discount rate of 7 percent, the savings are highest under dTSL 4.

10.4.1.4 Results for Medium-Voltage Dry-Type Transformers

Figure 10.4.3 illustrates the typical pattern of source energy savings and costs resulting 

from standards for medium-voltage dry-type transformers. The figure shows the nature of net 

savings for all five dTSLs relative to the base case. The figure also shows the NPV at both a 3-

percent and a 7-percent discount rate. In this figure, the dTSLs are ordered from lowest to 

highest energy savings. 

-10.0

-5.0

0.0

5.0

10.0

15.0

20.0

25.0

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

1 2 3 4 5 6

Net Present Value (Billion US$)

Cumulative Source Energy Savings (Quads)

Trial Standard Levels

Cumulative Source Energy Savings and NPV for Low-Voltage Dry-Type Units

Cumulative Source Savings 2045 (Quads) Net Present Value at 3% Discount Rate ($Billions) 

Net Present Value at 7% Discount Rate ($Billions) 
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10-25

Figure 10.4.3 Medium-Voltage Dry-Type Distribution 

Transformers: Impacts of Standards on National 

Energy Savings and Net Present Value 

Figure 10.4.3 shows that, although the savings in energy (quads) are greatest at dTSLs 5 

(max tech), the associated financial savings decrease dramatically at either the 3 percent or 7 

percent discount rate. At a discount rate of 3 percent, the NPV of cumulative source savings for 

medium-voltage dry-type transformers are highest at dTSL 4. At a discount rate of 7 percent, the 

NPV is highest at dTSL 4.

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1 2 3 4 5

Net Present Value (Billion US$)

Cumulative Source Energy Savings (Quads)

Trial Standard Levels

Cumulative Source Energy Savings and NPV for Medium-Voltage Dry-Type Units

Cumulative Source Savings 2045 (Quads) Net Present Value at 3% Discount Rate ($Billions) 

Net Present Value at 7% Discount Rate ($Billions) 
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REFERENCES

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(HVOLT Consultants Inc.: Washington DC, 2003).

2. Hopkinson, P. & Puri, J. Distribution Transformer Market Shipment Estimates for 2009. 

(HVOLT Consultants Inc.: Washington DC, 2010).

3. U.S Department of Commerce-Bureau of Economic Analysis Industry Economic Accounts 

Information Guide. Annual industry accounts: gross domestic product (GDP) by industry. 

(2010).

4. U.S. Energy Information Administration Annual Energy Outlook 2011, With Projections to 

2036. (U.S. Department of Energy: Washington DC, 2011).

5. U.S. Department of Energy-Energy Information Administration Annual Energy Review 2009, 

Chapter 8: Electricity, Table 8.9 Electricity End Use, 1949-2009. (U.S. Department of 

Energy: Washington DC, 2010).

6. Energy Information Administration - Office of Integrated Analysis and Forecasting The 

National Energy Modeling System (NEMS): An Overview. (U.S. Department of Energy: 

Washington DC, 2009).

7. Institute of Electrical and Electronic Engineers (IEEE) Draft Guide for Distribution 

Transfomer Loss Evaluation. (IEEE: 2001).

8. Institute of Electrical and Electronic Engineers (IEEE) Guide for Loading Mineral OilImmersed Transformers. (Transformer Committee of the IEEE Power Engineering Society: 

1995).

9. U.S. Office of Management and Budget Circular A-4: Guidelines and Discount Rates for 

Benefit-Cost Analysis of Federal Programs. (2003).