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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 ......................... 10-8

10.2.2.2 Mapping Life-Cycle Cost Design Line Data to Product Classes . . 10-9

10.2.2.3 Mapping of Candidate Standard Levels to Trial Standard Levels 10-11

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

10.2.2.5 Load Growth ........................................ 10-12

10.2.2.6 Affected Stock ....................................... 10-13

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

10.2.2.8 Electricity Site-to-Source Conversion ..................... 10-14

10.3 NET PRESENT VALUE CALCULATION ............................... 10-16

10.3.1 Net Present Value Overview ............................... 10-16

10.3.2 Net Present Value Inputs .................................. 10-18

10.3.2.1 First Cost ........................................... 10-19

10.3.2.2 Operating Cost ....................................... 10-20

10.3.2.3 Peak Responsibility Factor .............................. 10-21

10.3.2.4 Initial Peak Load ..................................... 10-22

10.3.2.5 Electricity Price Forecast Scalar ......................... 10-22

10.3.2.6 Marginal Electricity Costs .............................. 10-22

10.3.2.7 Discount Rate ........................................ 10-23

10.4 RESULTS ......................................................... 10-23

10.4.1 National Energy Savings and Net Present Value from Trial

 Standard Levels ......................................... 10-23

10.4.1.1 Liquid-Immersed Results ............................... 10-24

10.4.1.2 Dry-Type Results ..................................... 10-26

LIST OF TABLES

Table 10.2.1 Mapping of Design Line to Product Class ........................... 10-10

Table 10.2.2 Mapping of Candidate Standard Level to Trial Standard Level .......... 10-11

Table 10.2.3 Average Site-to-Source Conversion Factors for No-Load Losses and 

Load Losses .................................................. 10-15

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Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Levels and Product

Class (2004$/kVA) ............................................ 10-20

Table 10.3.2 Peak Responsibility Factors by Product Class ........................ 10-21

Table 10.3.3 Initial Peak Loading by Product Class .............................. 10-22

Table 10.3.4 Marginal Energy and Demand Costs by Product Class ................. 10-23

Table 10.4.1 Summary of Cumulative National Energy Savings (2010-2038) 

and Net Present Value (2010-2073) Impact .......................... 10-24

Table 10.4.2 Cumulative Primary Energy Savings During 2010-2038: Liquid-Immersed

Transformers by Product Class ................................... 10-24

Table 10.4.3 Net Present Value During 2010-2073: Liquid-Immersed Transformers

 by Product Class .............................................. 10-25

Table 10.4.4 Cumulative Primary Energy Savings During 2010-2038: Dry-Type 

Transformers by Product Class ................................... 10-26

Table 10.4.5 Net Present Value During 2010-2073: Dry-Type Transformers

 by Product Class .............................................. 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 Values Impacts ...................................... 10-25

Figure 10.4.2 Dry-Type Distribution Transformers: Net Energy Savings and Net Present 

Value Impacts ................................................ 10-28

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CHAPTER 10: NATIONAL IMPACT ANALYSIS

10.1 INTRODUCTION

The Energy Policy and Conservation Act (EPCA) states that any new or amended

standard 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 to the greatest extent practicable. 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 estimated average 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

imposition of the standard.

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

potential efficiency regulations for distribution transformers, the Department conducted a

national impact analysis. This analysis assessed future national energy savings (NES) from trial

transformer 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 relative to a base case scenario of no national standard over a forecast period. The

Department calculated NES for each trial standard level in units of quadrillion Btus (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. The Department calculated the NPV using a method similar to the NES,

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. The Department discounted

purchases, expenses, and operating costs for transformers using a national average discount

factor. The Department calculated the NPV impact from transformers that were purchased

between 2010 through 2038 to calculate the total NPV impact from purchases during the forecast

period.

The Department 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

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and operating cost savings through the year 2073a for transformers purchased in the period 2010

to 2038. 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

impact analysis (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 that are

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 that are shown as boxes with curved bottom edges. Note that the

shipments model portion of the flow diagram (shaded) is discussed in Chapter 9.

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Total Shipments

Retirement Function

New Capacity

Shipments

Stock Accounting

Affected Stock

Marginal

Energy Prices

Source Energy

Savings

NPV NES

Total

Shipments -

Retirements

Marginal Heat

Rates from

NEMS

Discount

Rate

Peak

Responsibility

Factor

Initial Peak

Loading

HVOLT

2001Shipments

BEA Quality

Index

EIA Electricity

Market Share

First Cost

Elasticity

Retirements

First Cost by

Design Line

First Cost by

Product Class

Rated Losses

by Product

Class

Rated

Losses by

Design Line

Design Line to

Product Class

Conversion

Σ

Fractional

Load Growth

RMS Loading

from LCC

Site Energy

Savings

Annual Equipment

Costs

Actual Electricity

Use: Peak & Average

Electricity

Price

Forecast

Scalar

Σ

Annual Operating

Cost Savings

Figure 10.1.1 National Impact Analysis Flowchart

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The calculation starts with the shipments model (described in Chapter 9) which integrates

the inputs of 2001 shipments estimates from the Department’s contractor,1 the U.S. Bureau of

Economic Analysis (BEA) transformer quantity index,2 electricity market shares from the DOE’s

Energy Information Administration (EIA),3, 4 and equipment price estimates from the life-cycle

cost analysis (LCC) to produce a backcast and a forecast of total shipments. The total shipments

and a retirement function feed an accounting of in-service transformers (stocks) to produce

estimates of the stock that is affected by trial standards and transformer retirements. When

subtracted from total shipments, the transformer retirements produce new capacity shipments,

which are those transformers made to supply new electrical capacity.

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. The losses and the equipment costs then go through a

transformer size and product class adjustment that converts the data from representative design

lines to average product class information. Additional inputs regarding average and peak losses

—including root mean square (RMS) loading, peak loading, and peak responsibility

factor—allow a conversion from 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 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)5

then convert the site energy savings to energy savings at the source (i.e., at the power plant). The

marginal heat rates from NEMS includes the transmission and distribution losses. The

Department 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 number.

On the other path, the NPV calculation brings in marginal price inputs from the LCC

analysis for both 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

provides the estimate of the total annual equipment costs. The Department took 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

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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. The

Department then discounted the net expenses/savings to 2004 and summed them over the years

2010-2073 for transformers purchased during or before 2038, to provide the NPV impact of a

trial standard.

Given this overview, the Department provides detailed technical descriptions of the three

models below: the shipments model in Chapter 9, 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 the Department performs each model’s calculations, and

follows with a summary of the inputs. The final subsections of each technical description

describe each of the major input and computation steps in detail and with equations, when

appropriate. After the technical model descriptions, the Department presents the results of the

national impact analysis calculations.

10.2 NATIONAL ENERGY SAVINGS

The Department developed the NES model to estimate the total national energy savings

using the results from the shipments model, combined with information from the LCC on energy

savings. The savings shown in the NES reflect decreased losses from the installation of new,

more efficient transformer units nationwide in comparison to a base case with no national

standards. The NES predicts the energy savings for each of several trial standard levels. 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

The Department calculated the cumulative incremental energy savings from a trial

transformer efficiency standard relative to a base case scenario of no standard over the forecast

period. The Department 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 transformer shipments and stocks (in-service transformers), estimates of which are outputs

of the shipments model (Chapter 9). The Department then obtained estimates of transformer

losses from the LCC analysis (Chapter 8). The Department proceeded to calculate the total

energy use by the stock of transformers for each year for both a base case and 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. The Department 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

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transmission, distribution, and generation losses. For each year analyzed, the difference in source

energy use between the base case and standards scenario is the annual energy savings. The

Department summed the annual energy savings from 2010 through 2038 to calculate the total

NES for the forecast period. 

In calculating the NES, the Department did not assume any trends in transformer nameplate efficiency besides the incremental efficiency improvement indicated by the LCC

calculation. The Department is aware that some states have adopted efficiency standards for

low-voltage, dry-type transformers that are equal to TP 1 and that more states may follow in the

future. Countering that trend are uncertainties in purchased efficiencies of distribution

transformers driven by the uncertainty of utility deregulation. With these counter trends, the

Department felt that future efficiency trends were generally indeterminate and therefore chose to

use a fixed baseline efficiency. The Department also assumed that the efficiency of transformers

did not degrade over time. This means that the annual energy savings can be written in terms of

an affected stock described in section 9.3.10 in the shipments chapter:

AES y UEC Eq. 10.1 Base 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) = 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:

NES SiteToSource y AEC y Eq. 10.2 

y Std year

= ×

=

∑ ( ) ( )

_

2038

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 UECBase and UECStd, given the input from the LCC and

including the site-to-source conversion factor that translates site energy into energy consumed at

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the power plant. In the next section, the inputs necessary for the NES calculation are

summarized and then presented individually with complete technical detail. 

10.2.2 National Energy Savings Inputs 

The NES model inputs fall into three broad categories: (1) some inputs help convert the

data from the LCC into data for the product classes and transformer size distributions used in the

NES; (2) some inputs help calculate the unit energy consumption; and (3) the site-to-source

factor then enable 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. Mapping of Candidate Standard Levels to Trial Standard Levels 

4. Root Mean Square Loading

5. Load Growth

6. Affected Stock

7. Effective Date of Standard

8. Unit Energy Consumption

9. Electricity Site-to-Source Conversion

The size scaling of losses and costs adjusts LCC representative design line data so it can

represent the size distribution of transformers that are in a particular product class. The mapping

of LCC design line data to product classes provides the proper inter-design line averaging or

adjustments for representation of the product classes (i.e., the design line-to-product class

relationship is a many-to-many relationship so the mapping needs to be carefully specified). The

mapping of candidate standard levels to trial standard levels aggregates standard levels from

design line to product class. The root mean square (RMS) loading is a key factor in estimating

actual load losses given the load losses at rated load for a transformer. Load growth over the

lifetime of the transformer can modify the average RMS loading that is seen by an affected stock

of transformers. The effective date of the standard affects the definition of the affected stock. 

The unit energy consumption is the energy per unit capacity of an affected stock of transformers

and depends on all of the first four inputs. Finally, the electricity site-to-source conversion

provides the estimate of energy consumption at the power plant given the site energy use of the

transformer. 

The next section begins the detailed discussion of NES inputs with a description of the

size-scaling method that adjusts transformer losses and costs from a representative LCC design

line to the distribution of sizes in a transformer product class. 

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10.2.2.1 Size Scaling of Losses and Costs 

The size scaling of losses and costs is the scaling relationship or equation that the

Department used to project the economic results from one transformer design line to similar

transformers of different sizes. It 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, the Department used the same

scaling for the TP1 level as it did for the other levels. As a result, for transformers other than the

representative unit, there is a slight difference in efficiency level between the National Electrical

Manufacturers Association's TP 1 and the Department's TP 1, as used to calculate national

impacts.

As described in the engineering analysis, the Department applied the 0.75 power scaling

rule (the “0.75 scaling rule”) for projecting losses and costs from one design line to transformers

of other sizes. In the NES calculation, shipments are calculated in terms of installed capacity. 

The losses associated with a stock of transformers, and the costs associated with a capacity

shipped, are estimated by multiplying the relevant capacity times the average losses, or costs per

unit capacity. Before applying the 0.75 scaling rule, the Department calculated the losses and

costs per unit of installed capacity within a given engineering design line. Then the Department

calculated an adjustment factor using the 0.75 rule to account for the fact that the representative

design line unit used in the engineering analysis is not exactly the “average” transformer size for

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

following equation:

Eq. 10.3 AdjFactor [Shipi i Cap Cap ] Ship

i

DL i

i

= × ×









 ∑ ∑ 

0 75 . 0 75 .

/

where: 

AdjFactor = adjustment factor that gives the shipments-weighted losses or costs

per transformer when multiplied by the design line losses or costs, 

Shipi = shipments in the i-th size category, 

Capi = the rated capacity for the transformers in the i-th size category, and

CapDL = the rated capacity of representative unit of the design line.

The Department 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 in the following equation:

AvgLossPerCapDL LossPerCapDL AdjFactor CapDL Cap Eq. 10.4 = × × / avg

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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.

Once the losses and costs from the LCC represent the correct size distribution, they need

a further adjustment so that they represent 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. The LCC calculations are performed 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 to product classes. Design line-to-product class aggregation is the process

by which the Department 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, the Department analyzed up

to three different 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. The Department did not specifically examine single-phase, dry-type design lines. 

For single-phase product classes 5, 7, and 9, the Department used the appropriate three-phase

design lines divided by 3. Table 10.2.1 presents the mapping of design line (DL) to product class

(PC).

Table 10.2.1 Mapping of Design Line to Product Class

Product Class BIL* 

kV**

Capacity

kVA***

Mapping

PC 1, Liquid-Immersed, MV,† Single-Phase Any 10-833 DL 1 + DL 2 + DL 3

PC 2, Liquid-Immersed, MV, Three-Phase Any 15-2500 DL 4 + DL 5

PC 3, Dry-Type, LV,‡ Single-Phase # 10 15-333 DL 6

PC 4, Dry-Type, LV, Three-Phase # 10 15-1000 DL 7 + D L8

PC 5, Dry-Type, MV, Single-Phase 20-45 15-833 (DL 9 ÷ 3) + (DL 10 ÷ 3)

PC 6, Dry-Type, MV, Three-Phase 20-45 15-2500 DL 9 + DL 10

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PC 7, Dry-Type, MV, Single-Phase 46-95 15-833 (DL 11 ÷ 3) + (DL 12 ÷ 3)

PC 8, Dry-Type, MV, Three-Phase 46-95 15-2500 DL 11 + DL 12

PC 9, Dry-Type, MV, Single-Phase $ 95 75-833 DL 13 ÷ 3

PC 10, Dry-Type, MV, Three-Phase $ 95 225-2500 DL 13

* BIL = Basic Impulse insulation Level

** kV = kilovolt

*** kVA = kilovolt-ampere

† MV = medium-voltage

‡ LV = low-voltage

To aggregate losses from more than one design line, the Department took a

shipments-capacity-weighted average of the per 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. The Department’s contractor1 provided the

capacity shipped for each design line (and each product class), the LCC analysis provided the

economic results for each design, and the 0.75 rule provided the re-scaled cost and loss estimates

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

average loss per unit capacity of product class (AvgLossPerCapPC), as derived from the average

loss per unit capacity for a design line:

AvgLossPerCapPC [ AvgLossPerCapDL DL MS MS ] Eq. 10.5

DL

DL

DL

= ∑ × / ∑

where: 

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

MSDL = the capacity market share of the design line.

The summation in Eq. 10.5 is over those design lines that constitute a product class. 

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

load. For no-load losses no more adjustment is needed, but for load losses, 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.

10.2.2.3 Mapping of Candidate Standard Level to Trial Standard Level

The Department conducted the LCC analysis for six alternate efficiency levels, i.e.,

candidate standard levels (CSLs), for each representative unit in the 13 design lines. The

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

economic criteria to intermediate LCC analyses as discussed in Chapter 8, resulting in unique

sets of CSL efficiencies for each design line. DOE mapped these LCC analysis results to trial

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standard levels (TSLs) for the 10 product classes. All CSLs directly map to their corresponding

TSLs with the exception of design lines 1 and 4. Due to the close size proximity between design

lines 1 and 2 representative units and constraints on material selection combinations within

product classes, the Department mapped CSL results for design line 1 and design line 4 to TSLs

as shown in Table 10.2.2.

Table 10.2.2 Mapping of Candidate Standard Levels to Trial Standard Levels

DL1 DL2 DL3 DL4 DL5 DL6 DL7 DL8 DL9 DL10 DL11 DL12 DL13

TSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1

TSL2 CSL1 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2

TSL3 CSL1 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3

TSL4 CSL2 CSL4 CSL4 CSL3 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4

TSL5 CSL3 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5

TSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6

10.2.2.4 Root Mean Square Loading 

The RMS loading is the root mean square of the hourly transformer loading relative to the

transformer capacity. Energy losses in transformers follow the RMS load, not the arithmetic

average load. The Department 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 the Department’s method for analysis can derive results for varying

power factors, for the analysis presented here the Department set the power factor to the value of

one.) The Department used the average national RMS loading for each design line as calculated

in the LCC analysis. These values range between 30.5 percent and 59.1 percent for the different

design lines. 

10.2.2.5 Load Growth

The fractional load growth is the fraction by which the load has increased since a

transformer was installed. Load growth occurs when new equipment, new appliances, or

additional activities occur on the circuits served by distribution transformers. Load growth has

the impact of increasing the load losses relative to the losses that the Department estimated

during the first year of installation.

The Department calculated the fractional load growth from an estimated load growth rate

that it used as an input to the LCC analysis. There is a maximum load growth, LGRMax, which

is set by the Department at 50 percent for liquid-immersed transformers. The 50 percent value

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represents the approximate amount of growth in load that can occur without overloading the

transformer beyond a reasonable point, at which time the transformer is assumed to be relocated

and reinstalled with the initial peak loading.6 See Institute of Electrical and Electronics

Engineers, Inc. (IEEE) Std C57.91-19957 for details on permissible overloading of mineral-oil

immersed transformers. Since IEEE does not report data on permissible overloading of dry-type

units, the Department used the same values for both liquid-immersed and dry-type transformers. 

The age of the transformer at which this point is reached is given by:

Eq. 10.6 ( )

( ) age

ln 1 LGRMax

ln 1 LGR Max =

+

+

where:

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

follows:

LGrwth age LGR Eq. 10.7 age ( ) ( )( )= − 1 − 1

for age < ageMax , and

LGrwth( ) ( ) age = − 1 LGR (age−ageMax )− 1 Eq. 10.8

for age >= ageMax

where:

LGrwth (age) = the fractional load growth, and 

age = the age of the transformer (years).

The load growth is then used to adjust the RMS loading estimate for the affected stock. 

The mathematical equation for this adjustment is as follows:

Eq. 10.9 LAdjust y [Stock y age LGrwth age ] Aff Stock y

age

y Std year

( ) ( , ) ( ( )) / _ ( )

_

= × +

=

−

∑ 1

2

1

where LAdjust(y) is the load adjustment factor in year y and all other variables have been defined

previously. 

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The Department used a load adjustment factor to calculate an adjusted RMS loading that

incorporates load growth into the unit energy consumption as described in the next section.

10.2.2.6 Affected Stock

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

NES and NPV calculations. The affected stock consists of that portion of the transformer stock

that is potentially impacted by a trial standard. It therefore consists of those transformers in the

stock that are purchased in or after the year the trial standard has taken effect, as described by the

following equation:

Aff Stock y Ship y Stock age Eq. 10.10

age

y Std year

_ ( ) ( ) ( )

_

= +

=

−

∑

1

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

10.2.2.7 Unit Energy Consumption

One of the final quantities that the Department calculated for the NES estimate is the unit

energy consumption 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 the

total national energy savings is derived.

Annual unit energy consumption (UEC(y)) for affected stock, or energy per unit capacity,

is the annual energy consumption per unit capacity for transformers shipped after the effective

date of a standard. This energy consumption is a function of load losses and no-load losses. The

Department calculated the losses per transformer as the sum of no-load losses plus the load

losses. The Department 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 distribution transformers for affected stock is

given by the following equation:

UEC Eq. 10.11 y E E RMS LAdjust y NL LL ( ) = + × × [ ( )]2

where:

ENL = rated no-load losses per kVA capacity, 

ELL = rated load losses per kVA capacity,

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a

 For more information on NEMS, refer to the Department’s EIA documentation. A useful summary is National Energy

Modeling System: An Overview 2003.

5

 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 the analysis entails 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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RMS = root mean square, and

Ladjust(y) = loading adjustment factor for year y.

Once the unit energy consumption for affected stock is defined, only one more input is

necessary to complete the NES calculation: the site-to-source conversion factor.

10.2.2.8 Electricity Site-to-Source Conversion

The source conversion factor for electricity is the factor by which site energy (in 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), the source conversion factor is necessary to

account for losses in generation, transmission, and distribution. After calculating energy

consumption at the site, the Department multiplied it by the conversion factor to obtain primary

energy consumption, expressed in quads. This conversion permits 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. The Department 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. The

Department obtained these conversion factors using a variant of the NEMS, called NEMS-BT.a

Table 10.2.3 presents the average annual conversion factors used by the Department. 

Table 10.2.3 Average Site-to-Source Conversion Factors for No-Load Losses and Load

Losses 

Year For No-Load Losses For Load Losses

2010 2.699 2.931

2011 2.699 2.931

2012 2.699 2.931

2013 2.568 2.809

2014 2.390 2.578

2015 2.390 2.458

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2016 2.390 2.345

2017 2.390 2.283

2018 2.390 2.222

2019–38 2.390 2.180

The Department 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’s (AEO2005) reference case)4 and extract the source energy

consumption.

2. Estimate projected energy savings due to possible standards for each year (e.g., using the

NES spreadsheet model).

3. Feed these energy savings back to the NEMS-BT model as a new scenario, specifically a

deviation from the reference case, to obtain the corresponding source energy

consumption. 

4. Obtain the difference in source energy consumption between this trial standard level

scenario 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. Furthermore, the NES spreadsheet model includes conversion factors for each year of

the projection. The Department 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 results section

(section 10.4) presents the output from the NES model. The next section describes the technical

details of the NPV calculation.

10.3 NET PRESENT VALUE CALCULATION 

The Department estimated the national financial impact on consumers from the

imposition of new energy-efficiency standards with a national NPV accounting component in the

national impact spreadsheet. The Department combined output of the shipments model with

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

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benefits resulting from trial distribution transformer energy efficiency standards. The

Department discounted this time series to the year 2004 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. The Department then obtained

estimates of transformer first costs, losses, and average marginal electricity costs from the LCC

analysis. The Department proceeded to calculate the amount spent on transformer purchases and

installation. It 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 standards case. Over time in the standards case, moreexpensive, 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. The Department

discounted purchases and 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 for that expense or benefit. The difference in present value of all expenses and benefits

between the base case and standards scenario is the national NPV impact. The Department

calculated the NPV impact from transformers that were purchased between the effective date of

standards 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, described by the equation:

NPV PVS PVC 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 determined according to the following expressions:

PVS Eq. 10.13

OC

Cap

y

OC

Cap

y Aff Stock y Discount Factor y

Base Std

y Std year

= −











 × ×

=

∑ ( ) ( ) _ ( ) ( )

_

2073

where:

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OCBase/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 is defined in Eq. 10-14.

Discount Factor y Eq. 10.14

Discount Rate y reference year ( )( )

( ) =

+

−

1

1

where:

reference year = year 2004, and

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

PVC Eq. 10.15 FC

Cap

y

FC

Cap

y Ship y Discount Factor y

Std Base

y Std year

= −











 × ×

=

∑ ( ) ( ) ( ) ( )

_

2073

where:

FCStd/Cap (y) = first cost of the transformer per unit of capacity for a trial

standard level Std in year y. First cost is defined in Eq.

10.16 and described in section 10.3.2.1.

Std_year = the year standards come into effect, and

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

The Department calculated NPV from the projections of national expenditures for

distribution transformers, including purchase price (equipment and installation price) and

operating costs (electricity and maintenance costs). The Department 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.

The Department calculated a discount factor from the discount rate and the number of

years between the year to which the sum is being discounted (2004) 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 in detail.

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10.3.2 Net Present Value Inputs

The NPV model inputs include cost inputs, selected inputs that are important for detailing

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

details 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

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

transformer. Generally, first cost increases with the increased efficiency that may be required by

a trial standard level. Operating cost includes the annual costs of operating a transformer. In this

analysis, operating cost includes both energy and capacity costs for supplying both no-load and

load losses. The peak responsibility factor is a necessary input for estimating the capacity costs

incurred from load losses at the initial peak load. The electricity price forecast scalar provides

the forecasted increase or decrease in electricity prices over the cost accounting period that

ranges from 2004 to the year 2073. Marginal electricity costs convert physical transformer loss

estimates into financial economic impacts. The discount rate represents the time value of money

and allows the Department to estimate the present value of a future monetary cost or benefit.

The next section begins the detailed discussion of NPV inputs with a description of the

transformer first cost that the Department used. 

10.3.2.1 First Cost

The Department expresses first cost in terms of cost per unit capacity. Specifically, the

Department defines the first cost of acquiring a transformer with the following equation:

FC/Cap = (P + Install)/Cap Eq. 10.16

where: 

FC = the first 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. 

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In the NPV calculation, these values are obtained from the LCC calculation as the

averages for specific design lines. The Department applied an adjustment factor to convert the

first cost of a representative design to an estimated average cost for a distribution of sizes within

a particular product class. The adjustment incorporates the 0.75 scaling rule and the design lineto-product 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 2004 dollars per kVA of rated transformer capacity.

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

product class and trial standard level.

Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Levels and

Product Class (2004$/kVA)

Product Class Base TSL 1*

(TP 1)

TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

PC 1, Liquid-Immersed, MV, Single-Phase 61.85 62.46 62.67 62.85 63.79 69.43 106.66

PC 2, Liquid-Immersed, MV, Three-Phase 20.48 21.04 22.12 24.37 24.99 35.82 37.87

PC 3, Dry-Type, LV, Single-Phase 47.41 52.94 54.22 58.69 63.56 77.84 77.85

PC 4, Dry-Type, LV, Three-Phase 31.74 33.30 35.17 37.75 42.98 53.42 53.42

PC 5, Dry-Type, MV, Single-Phase 27.58 28.24 28.82 30.15 33.70 44.65 44.64

PC 6, Dry-Type, MV, Three-Phase 22.36 23.18 23.72 24.79 26.79 35.37 35.36

PC 7, Dry-Type, MV, Single-Phase 32.61 33.36 33.97 35.31 38.12 47.16 47.17

PC 8, Dry-Type, MV, Three-Phase 23.43 23.80 24.05 24.65 26.41 36.30 36.31

PC 9, Dry-Type, MV, Single-Phase 28.90 29.10 29.50 30.37 34.92 47.60 47.61

PC 10, Dry-Type, MV, Three-Phase 22.46 22.62 22.92 23.60 27.14 36.99 36.99

*TSL = Trial Standard Level

The next section presents the operating costs, which are substantially more complex than

the transformer first costs.

10.3.2.2 Operating Cost

Operating costs are an essential, yet complex, part of calculating the national economic

impact of a trial distribution transformer standard. The Department used eleven distinct inputs to

calculate operating costs. This large number of inputs is necessary because transformers have

both no-load and load losses, and because electricity has both energy and capacity costs. The

combination of distinct losses and distinct capacity and energy costs creates the necessity for four

price and two loss coefficients. Potential load growth requires a load growth adjustment factor. 

Peak loading, peak load coincidence, and average loading require three additional factors to

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characterize load losses. Finally, the Department used an electricity price forecast scalar to

characterize future trends in electricity prices consistent with the AEO2005 forecast.

Transformer operating cost is the annual cost of transformer losses. The Department

assumed zero maintenance cost in calculating the transformer operating cost. The Department

calculated annual operating cost using the following formula to capture the diversity of potential

factors that can affect transformer operating costs:

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

 × (PRF × PL2 × LLMCC + 8760 × RMS2 × LLMEC))/Cap Eq. 10.17

where: 

OC = the operating cost, 

Cap = the rated capacity of the transformer, 

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

ENL = the no-load losses at rated load,

NLLMCC = the no-load loss marginal cost of capacity, 

NLLMEC = the no-load loss marginal energy cost,

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 load loss marginal cost of capacity, 

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

LLMEC = the load loss marginal energy cost.

The Department expressed the costs in units of 2004 dollars per kVA of rated capacity. 

One additional complexity in the operating cost equation that is shared with the NES calculation

is that the Department applied an adjustment factor to incorporate the 0.75 scaling rule to ENL and

ELL, as explained in sections 10.2.2.1 and 10.2.2.2, 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

explained in the NES section. 

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10.3.2.3 Peak Responsibility Factor

The peak responsibility factor (PRF), in combination with the initial peak loading, is

necessary for estimating the capacity cost impacts of transformer load losses. The transformer

PRF is the square of the ratio of the transformer load at the time of the customer peak load to the

transformer peak load. The Department 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 10.3.2 presents the PRFs used in the analysis for the ten product classes.

Table 10.3.2 Peak Responsibility Factors by Product Class

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

PRF 0.35 0.61 0.46 0.49 0.52 0.53 0.53 0.54 0.54 0.54

10.3.2.4 Initial Peak Load 

The initial peak loading, in combination with the PRF, is necessary for calculating

capacity cost impacts from transformer load losses. The initial peak loading is the annual perunit peak load on the transformer during the first year of operation. 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 Evaluation6 defines 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,

the Department characterized a range of possible initial peak loads by defining a distribution of

initial peak loads. Chapter 6, section 6.3.4, provides further description. Table 10.3.3 presents

the initial peak loadings used in the analysis for the ten product classes.

Table 10.3.3 Initial Peak Loading by Product Class

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

Initial Peak Loading 0.87 0.86 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75

10.3.2.5 Electricity Price Forecast Scalar

The electricity price forecast scalar converts current electricity costs for forecasted costs

for the period 2004 to 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 2004. The

Department used AEO20054 forecasts to obtain the electricity price forecast scalar. For the

period beyond 2025, the Department used the real price trend from 2015 to 2025 to extrapolate

the electricity price scalar.

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10.3.2.6 Marginal Electricity Costs

The characterization of four distinct marginal electricity costs is necessary to calculate the

operating costs of transformers and the financial impact of transformer efficiency standards. 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 compared to each other and since

different customers have different load shapes, such costs vary by loss type and by the product

class of the transformer. The Department therefore used distinct marginal energy and capacity

costs for no-load losses and load losses for each transformer product class. No transformer size

scaling is necessary for the marginal costs, although the design line-to-product class mapping

described in section 10.2.2.2 needs to be applied to convert the design line output from the LCC

to product class information for the NPV calculation. The Department calculated capacity costs

in units of 2004$/kW/year, while energy costs are in units of 2004$/kWh. The names for the four

types of marginal cost 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). Table 10.3.4 summarizes the four marginal costs for the ten product

classes.

Table 10.3.4 Marginal Energy and Demand Costs by Product Class

Marginal Energy Cost by Product Class ($/kWh)

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

NLL 0.027 0.026 0.057 0.054 0.051 0.051 0.051 0.051 0.050 0.050

LL 0.037 0.034 0.059 0.056 0.054 0.053 0.054 0.053 0.053 0.053

Marginal Demand Cost by Product Class ($/kW/year)

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

NLL 103.05 106.42 77.45 85.45 92.19 93.50 92.06 93.32 93.99 93.99

LL 55.72 56.80 54.10 61.82 70.62 72.44 70.66 72.47 74.10 74.10

10.3.2.7 Discount Rate

The discount rate expresses the time value of money and is the final input to the NPV

calculation. The Department used real discount rates of 3.0 and 7.0 percent as established by the

Office of Management and Budget (OMB) in Circular A-94, Regulatory Analysis.8 The discount

rates that the Department used in the LCC are distinct from those it used in the NPV calculations,

in that the NPV discount rate is 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.

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10.4 RESULTS

10.4.1 National Energy Savings and Net Present Value from Trial Standard Levels

 The NES and NPV results from the NES spreadsheet model for TSL 1 through TSL 6 are

shown in Table 10.4.1. 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 significantly higher than what was estimated in the ANOPR analysis.9 The increase in

savings originate predominantly from engineering design changes in DL 6, DL 7, and DL 8,

which results in a significant increase in load losses in the base case.

Table 10.4.1 Summary of Cumulative National Energy Savings (2010-2038) and Net

Present Value (2010-2073) Impact

Distribution

Transformers Analysis

Discount

Rate

%

Trial Standard Level

TSL 1

(TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

Liquid-Immersed

NES

quads 1.70 2.28 2.99 3.38 6.51 9.38

NPV

billion

2004$

3 7.02 8.78 9.20 9.83 9.94 -10.31

7 2.02 2.31 2.01 1.92 -1.14 -14.10

Dry-Type

NES

quads 6.83 7.82 9.02 10.28 11.17 11.17

NPV

billion

2004$

3 45.64 51.42 58.87 65.30 65.06 65.06

7 14.82 16.53 18.70 20.24 18.87 18.87

10.4.1.1 Liquid-Immersed Results 

Tables 10.4.2 and 10.4.3 present NES and NPV results for liquid-immersed transformers

by product class. Figures 10.4.1 and 10.4.2 illustrate the typical pattern of primary energy 

savings and costs resulting from standards for liquid-immersed transformers over time. The

figures show the nature of net savings for all six trial standard levels relative to the base case. 

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Table 10.4.2 Cumulative Primary Energy Savings During 2010-2038: Liquid-Immersed

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

 1. Liquid-Immersed, MV, Single-Phase 0.81 0.86 0.90 1.06 1.77 4.49

 2. Liquid-Immersed, MV, Three-Phase 0.90 1.42 2.10 2.32 4.74 4.88

Total 1.70 2.28 2.99 3.38 6.51 9.38

Table 10.4.3 Net Present Value During 2010-2073: Liquid-Immersed Transformers by

Product Class

Product Class

Net Present Value

$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

 1. LiquidImmersed, MV,

Single-Phase

2.95 3.03 3.13 3.31 2.14 -16.91 0.87 0.86 0.85 0.75 -0.59 -12.76

 2. LiquidImmersed, MV,

Three-Phase

4.07 5.76 6.08 6.52 7.80 6.60 1.16 1.46 1.16 1.18 -0.55 -1.34

Total 7.02 8.78 9.20 9.83 9.94 -10.31 2.02 2.31 2.01 1.92 -1.14 -14.10

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0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

One Two Three Four Five Six

Trial Standard Levels

Cumulative Source Savings 

(quads)

-20.00

-15.00

-10.00

-5.00

0.00

5.00

10.00

15.00

NPV (billion US$)

National Energy Savings NPV at 7% discount rate

NPV at 3% discount rate

Figure 10.4.1 Liquid-Immersed Distribution Transformers: National

Energy Savings and Net Present Values Impacts

10.4.1.2 Dry-Type Results

Tables 10.4.4 and 10.4.5 present NES and NPV results for dry-type transformers by

product class. Figures 10.4.3 and 10.4.4 show the typical pattern of national savings and costs

resulting from standards for dry-type transformers over time. Again, the figures show the nature

of net savings for all six trial standard levels relative to the base case.

Table 10.4.4 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

 3. Dry-Type, LV, Single-Phase 0.411 0.458 0.498 0.529 0.565 0.565

 4. Dry-Type, LV, Three-Phase 6.352 7.252 8.364 9.506 10.214 10.214

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 5. Dry-Type, MV, Single-Phase, 20-45 kV BIL 0.000 0.000 0.001 0.001 0.001 0.001

 6. Dry-Type, MV, Three-Phase, 20-45 kV BIL 0.016 0.024 0.035 0.047 0.065 0.065

 7. Dry-Type, MV, Single-Phase, 46-95 kV BIL 0.000 0.001 0.001 0.001 0.002 0.002

 8. Dry-Type, MV, Three-Phase, 46-95 kV BIL 0.053 0.082 0.117 0.179 0.298 0.298

 9. Dry-Type, MV, Single-Phase, >96 kV BIL 0.000 0.000 0.000 0.000 0.000 0.000

10. Dry-Type, MV, Three-Phase, >96 kV BIL 0.001 0.005 0.009 0.018 0.026 0.026

Total 6.83 7.82 9.02 10.28 11.17 11.17

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Table 10.4.5 Net Present Value During 2010-2073: Dry-Type Transformers by Product

Class

Product Class

Net Present Value

$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

 3. Dry-Type, LV,

Single-Phase

2.82 3.18 3.40 3.53 3.45 3.44 0.90 1.01 1.07 1.09 0.99 0.99

 4. Dry-Type, LV,

Three-Phase

42.39 47.56 54.51 60.47 60.56 60.56 13.79 15.31 17.35 18.81 17.84 17.84

 5. Dry-Type, MV,

Single-Phase,

20-45 kV BIL

0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 6. Dry-Type, MV,

Three-Phase,

20-45 kV BIL

0.10 0.14 0.19 0.24 0.20 0.20 0.03 0.04 0.06 0.06 0.02 0.02

 7. Dry-Type, MV,

Single-Phase,

46-95 kV BIL

0.00 0.00 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 8. Dry-Type, MV,

Three-Phase,

46-95 kV BIL

0.33 0.51 0.69 0.96 0.80 0.80 0.10 0.16 0.20 0.26 0.03 0.03

 9. Dry-Type, MV,

Single-Phase,

>96 kV BIL

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

10. Dry-Type, MV,

Three-Phase,

>96 kV BIL

0.01 0.03 0.05 0.08 0.04 0.04 0.00 0.01 0.02 0.02 -0.01 -0.01

Total 45.64 51.42 58.87 65.30 65.06 65.06 14.82 16.53 18.70 20.24 18.87 18.87

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0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

One Two Three Four Five Six

Trial Standard Levels

Cumulative Source Savings 

(quads)

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

NPV (billion US$)

National Energy Savings NPV at 7% discount rate

NPV at 3% discount rate

Figure 10.4.2 Dry-Type Distribution Transformers: Net Energy Savings and

Net Present Value Impacts

The national impact spreadsheet is available as a 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. 

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REFERENCES

1. HVOLT Consultants Inc., P. Hopkinson, and J. Puri. Distribution Transformer Market

Shipment Estimates for 2001. February 17, 2003. 3704 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. Industry 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

#83. 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 #83. 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. January, 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. Report 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 East 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. 

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8. U.S. Office of Management and Budget. Circular No. A-94. Appendix C. 2002. (Last

accessed November, 2002.) This material is available in Docket #83. 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.whitehouse.gov/omb/circulars/a094/a94_appx-c.html>

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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