CHAPTER 10. NATIONAL IMPACT ANALYSIS 

TABLE OF CONTENTS 

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


10.1.1 National Impact Analysis Spreadsheet Flowchart ..................... 10-2


10.2 NATIONAL ENERGY SAVINGS ..................................... 10-5


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


10.2.2 National Energy Savings Inputs .................................. 10-6


10.2.2.1
 Size Scaling of Losses and Costs ........................ 10-7


10.2.2.2
 Mapping Life-Cycle Cost Design Line Data to Product Classes .. 10-8


10.2.2.3
 Root Mean Square Loading ........................... 10-10


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


10.2.2.5
 Affected Stock ..................................... 10-11


10.2.2.6
 Unit Energy Consumption ............................. 10-12


10.2.2.7
 Electricity Site-to-Source Conversion .................... 10-13


10.3 NET PRESENT VALUE ............................................ 10-14


10.3.1 Net Present Value Overview .................................... 10-15


10.3.2 Net Present Value Inputs ...................................... 10-17


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


10.3.2.2
 Operating Cost ..................................... 10-18


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


10.3.2.4
 Initial Peak Load .................................... 10-20


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


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


10.3.2.7
 Discount Rate ...................................... 10-21


10.4 RESULTS ....................................................... 10-22


10.4.1 National Energy Savings and Net Present Value from 

Trial Standard Levels ......................................... 10-22


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


Table 10.3.2
 First Cost of Distribution Transformers by Trial Standard Level and 


Product Class (2006$/kVA, TSL A through TSL D) ................. 10-18


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


Product Class (2006$/kVA, TSL 1 through TSL 6) .................. 10-18


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


Load Losses ................................................ 10-13


10.4.1.1 Liquid-Immersed Results ............................. 10-22


10.4.1.3 Discounted Cumulative Energy Impacts ................... 10-26


LIST OF TABLES 

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Table 10.3.3 Peak Responsibility Factors by Product Class ....................... 10-20


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


Table 10.3.5 Marginal Energy and Demand Costs by Product Class ................ 10-21


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


Net Present Value (2010–2073) Impact ........................... 10-22


Table 10.4.2 Summary of Cumulative National Energy Savings (2010–2038) and 


Net Present Value (2010–2073) Impact for Liquid-Immersed 

Transformers ............................................... 10-23


Table 10.4.3 Cumulative Primary Energy Savings During 2010–2038: Dry-Type 


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


Table 10.4.4 Net Present Value During 2010–2073: Dry-Type Transformers by 


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


Table 10.4.5 Discounted Cumulative Energy Impacts, Liquid-Immersed and Dry-Type,


Medium-Voltage Transformers .................................. 10-27


LIST OF FIGURES 

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


Figure 10.4.1 Liquid-Immersed Distribution Transformers: National Energy Savings and 


Net Present Value Impacts ..................................... 10-23


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


Net Present Value Impacts ..................................... 10-26


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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. Key factors in this decision are: the total projected amount of energy 

savings likely to result directly from the imposition of the standard, and the savings in operating 

costs throughout the life of the covered product in the type (or class) compared to any increase in 

the price of, or in the initial charges for or maintenance expenses of, the covered products which 

are likely to result from the promulgation of the standard. 

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

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

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

conservation standards as well as the national economic impact using the net present value (NPV) 

metric. 

The NES is the cumulative incremental energy savings from a transformer efficiency 

standard, relative to a base case scenario of no national standard, over a forecast period. DOE 

calculated NES for each trial standard level in units of quadrillion British thermal units (Btus), or 

quads, for standards that it assumed will be implemented in the year 2010. 

The NPV is the net present value of the incremental economic impact on consumers from 

a trial standard level. DOE calculated the NPV using a method similar to the NES calculation, 

except that it estimated incremental costs and benefits instead of energy, and discounted the net 

benefits rather than calculating them as an un-discounted sum. DOE discounted purchases, 

expenses, and operating costs for transformers using a national average discount factor. It 

calculated the NPV impact from transformers that are purchased from 2010 through 2038 to 

calculate the total NPV impact from purchases during the forecast period. 

DOE developed a Microsoft Excel spreadsheet, the national impact spreadsheet, to 

implement the calculations described above. The spreadsheet calculates capacity and operating 

cost savings associated with each of the trial standard levels. The NES analysis considers 

cumulative energy savings through the year 2038, while the NPV considers capacity and 

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

a

 DOE maintains the same time period for NPV as it did in the advance notice of proposed rulemaking (ANOPR) and 

notice of proposed rulemaking (NOPR). 

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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 (shown as 

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

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

major outputs (shown as boxes with curved bottom edges). Note that the shipments model 

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

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Figure 10.1.1 National Impact Analysis Flowchart 

The calculation started with the shipments model (described in Chapter 9), which 

integrated the inputs of 2001 shipments estimates from DOE’s contractor,1

 the U.S. Bureau of 

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Economic Analysis (BEA) transformer quantity index,2

 electricity market shares from DOE’s 

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

cost (LCC) analysis, to produce a backcast and a forecast of total shipments. DOE used the total 

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

enabling DOE to estimate the stock that is affected by trial standards and transformer retirements. 

After the shipments calculation, the NES and NPV calculations begin. Key inputs from 

the LCC analysis are the average rated losses for both no-load and load losses, and the cost of 

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

transformer size and product class, to convert the data from representative design lines to average 

product class information. Additional inputs on average and peak losses—including root mean 

square (RMS) loading, peak loading, and peak responsibility factor—allowed DOE to convert 

rated losses into actual losses. At this point, the information flow for the NES and NPV 

calculation split into two paths. 

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

stock, and takes the difference between the base case and standards scenario to calculate site 

energy savings. Marginal heat rates from the National Energy Modeling System (NEMS)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 include the transmission and distribution losses. (DOE 

performed a sensitivity analysis to analyze an improvement in the heat rate as a result of the 

efficiency improvement in the standards scenario; the impact was not significant.) The sum of 

annual energy savings for the forecast period through 2038 then provides the final NES result. 

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

analysis 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 

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

calculate the net impact of the trial standard. The first difference was between the trial standards 

scenario equipment costs and the base case equipment costs, to obtain the net equipment cost 

increase from a trial standard. The second difference was between the base case scenario 

operating cost and the trial standards scenario operating cost, to obtain the net operating cost 

savings from a trial standard. The third difference was between the net operating cost savings and 

the net equipment cost increase, to get the net expense/savings for each year. DOE then 

discounted the net expenses/savings to 2007 and summed them over the years 2010–2073 for 

transformers purchased during or before 2038, to provide the NPV impact of a trial standard. 

Chapter 9 of this TSD provides a detailed technical description of the shipments model; 

similar descriptions of the other two models are provided below—the NES model in section 10.2, 

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

model. It then provides a descriptive overview of how DOE performed each model’s 

calculations, and follows with a summary of the inputs. The final subsections of each technical 

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description describe each of the major inputs and computation steps in detail and with equations, 

when appropriate. After the technical model descriptions, this chapter presents the results of the 

national impact analysis calculations. 

10.2 NATIONAL ENERGY SAVINGS 

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

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 with no national 

standards. Positive values of NES correspond to net energy savings, i.e., a decrease in energy 

consumption with standards in comparison to the energy consumption in the base case scenario. 

10.2.1 National Energy Savings Overview 

DOE calculated the cumulative incremental energy savings from atransformer efficiency 

standard, relative to a base case scenario of no standard, over the forecast period. It calculated 

NES for each trial standard level, in units of quads, for standards that it assumed will be 

implemented in the year 2010. The NES calculation started with estimates of transformer 

shipments and stocks (in-service transformers), which are outputs of the shipments model 

(Chapter 9). DOE then obtained estimates of transformer losses from the LCC analysis (Chapter 

8), and calculated the total energy use by the stock of transformers for each year, for both a base 

case and a standards case. Over time, in the standards case, more-efficient transformers gradually 

replace less-efficient ones. Thus, the energy per unit capacity used by the stock of transformers 

gradually decreases in the standards case relative to the base case. DOE converted energy used 

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

(the source energy) with a site-to-source conversion factor. The site-to-source factor accounts 

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

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

DOE summed the annual energy savings from 2010 through 2038 to calculate the total NES for 

the forecast period. 

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

efficiency besides the incremental efficiency improvement indicated by the LCC calculation. DOE 

examined proprietary shipments data provided by the transformer industry and found that the data 

lacked conclusive trends in efficiency improvement. Therefore, DOE felt that future efficiency 

trends were generally indeterminate and chose to use a fixed baseline efficiency. DOE also 

assumed that the efficiency of transformers does not degrade over time. This means the annual 

energy savings can be described in terms of an affected stock (see Equation 10.1), as described in 

section 9.3.11 in the shipments chapter: 

Eq. 10.1 

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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: 

Eq. 10.2 

where: 

Std_year = the year standards come into effect, 

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

AEC = the annual energy consumption. 

Once the shipments model provides the estimate for the affected stock, the key to the NES 

calculation is in calculating UECBase and UECStd, using the input from the LCC analysis and 

including the site-to-source conversion factor. The next section summarizes the inputs necessary 

for the NES calculation and then presents them individually. 

10.2.2 National Energy Savings Inputs 

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

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

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

conversion factor, which enables the calculation of source energy consumption from site energy 

use. The specific list of NES model inputs is as follows: 

1. Size scaling of losses and costs 

2. Mapping of LCC design line data to product classes 

3. Root mean square loading 

4. Load growth 

5. Affected stock 

6. Effective date of standard 

7. Unit energy consumption 

8. Electricity site-to-source conversion 

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10.2.2.1 Size Scaling of Losses and Costs 

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

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 a 

distribution of transformer sizes represented in the NES calculation. To be consistent across trial 

standard levels, DOE used the same scaling for the National Electrical Manufacturers Association 

(NEMA)’s TP1 standard level as it did for the other levels. NEMA’s scaling was apparently 

based on a different set of representative units than DOE used. As a result, for transformers other 

than the representative units, which were keyed to NEMA TP1 efficiencies, there is a slight 

difference in efficiency level between NEMA’s TP 1 and DOE's TP 1, as used to calculate 

national impacts. 

As described in the engineering analysis, DOE applied the 0.75 power scaling rule (the 

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

sizes. In the NES analysis, DOE calculated shipments in terms of installed capacity. It estimated 

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

shipped, by multiplying the relevant capacity times the average losses, or costs per unit capacity. 

Before applying the 0.75 scaling rule, DOE calculated the losses and costs per unit of installed 

capacity within a given engineering design line. Then it calculated an adjustment factor using the 

0.75 scaling 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 

the design line represents. This adjustment factor is given by the following equation: 

Eq. 10.3 

where: 

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

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

Shipi = shipments in the i-th size category, 

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

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

DOE also used the shipment-weighted average size of transformers represented by a 

particular design line to calculate the average loss per capacity (AvgLossPerCapDL), as described 

in the following equation: 

Eq. 10.4 

where: 

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Cap

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

LCC analysis, and 

avg = the shipment-weighted average size of transformers represented by 

a particular design line. 

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

needed a further adjustment so that they represented the appropriate product classes, as described 

in the next section. 

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

The NES and NPV calculations use the LCC calculations as the source of most input data. 

DOE performed the LCC calculations by design line, whereas any eventual standard would be 

promulgated by product class. As a first step, therefore, the NES calculation aggregates the LCC 

design line data into product classes. This design-line-to-product-class aggregation was the 

process by which DOE took the results from an economic analysis of engineering design lines and 

combined them to provide estimates of economic impact by product class. 

To represent the variety of designs in some product classes, DOE analyzed up to three 

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

product classes 5 and 9, DOE used the appropriate three-phase design lines divided by three. 

Table 10.2.1 presents the mapping of design line (DL) to product class (PC). 

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Table 10.2.1 Mapping of Design Line to Product Class 

Product Class BIL* 

kV** 

Capacity 

kVA*** 

PC 1, Liquid-Immersed, MV,† Single-Phase Any 10-833 

PC 2, Liquid-Immersed, MV, Three-Phase Any 15-2500 

PC 5, Dry-Type, MV, Single-Phase 20-45 15-833 

PC 6, Dry-Type, MV, Three-Phase 20-45 15-2500 

PC 7, Dry-Type, MV, Single-Phase 46-95 15-833 

PC 8, Dry-Type, MV, Three-Phase 46-95 15-2500 

PC 9, Dry-Type, MV, Single-Phase $ 96 75-833 

PC 10, Dry-Type, MV, Three-Phase $ 96 225-2500 

Mapping 

DL 1 + DL 2 + DL 3 

DL 4 + DL 5 

(DL 9 ÷ 3) + (DL 10 ÷ 3) 

DL 9 + DL 10 

(DL 11 ÷ 3) + (DL 12 ÷ 3) 

DL 11 + DL 12 

DL 13 ÷ 3 

DL 13 

* BIL = Ba sic impulse insulation level 

** kV = kilov olt 

*** kVA = k ilovolt-ampere 

† MV = mediu m-voltage 

To aggregate losses from more than one design line, DOE took a shipments-capacityweighted average of the per-kilovolt-ampere (kVA) transformer characteristics from the 

economic analysis of the design lines and applied the average per-capacity values to the estimated 

capacity shipped for each product class. DOE’s contractor1

 provided the capacity shipped for 

each design line (and each product class), the LCC analysis provided the economic results for 

each design line, and DOE used the 0.75 scaling rule to estimate the re-scaled cost and loss 

estimates for each size category represented by each design line. Equation 10.5 provides the 

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

loss per unit capacity for a design line: 

Eq. 10.5 

where: 

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

MSDL = the capacity market share of the design line. 

Equation 10.5 sums 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; for load losses, however, the losses at 

rated load need to be converted to losses at actual loading. The RMS loading is a key factor in 

estimating load losses at actual loading. The next section describes the RMS loading input. 

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10.2.2.3 Root Mean Square Loading 

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

calculated the RMS loading as the root mean square of the transformer load, divided by the 

transformer rated capacity, times the power factor. (As explained in Chapter 6, while DOE’s 

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

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

each design line as calculated in the LCC analysis. These values range between 30.1 percent and 

47.7 percent for the different design lines. 

10.2.2.4 Load Growth 

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

transformer was installed. DOE investigated load growth as a sensitivity. Load growth occurs 

when new equipment, new appliances, or additional activities increase the energy loads on the 

circuits served by distribution transformers. Load growth has the impact of increasing the load 

losses relative to the losses that DOE estimated to have occurred during the first year of 

installation. 

DOE calculated the fractional load growth from an estimated load growth rate that it used 

as 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 does occur, the transformer is assumed to be relocated and installed in a 

new location with the same initial peak loading as when originally installed.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, DOE used the same values for both liquid-immersed 

and dry-type transformers. The age of the transformer at which the load switches to initial peak 

load is given by Equation 10.6: 

Eq. 10.6 

where: 

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

peak load (years), and 

LGR = the annual load growth rate (%). 

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

follows: 

Eq. 10.7 

for age < ageMax , and 

Eq. 10.8 

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 RMS loading estimate for the affected stock. 

The mathematical equation for this adjustment is as follows: 

Eq. 10.9 

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

previous equations. 

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

incorporates load growth into the unit energy consumption, as described in section 10.2.2.6. 

10.2.2.5 Affected Stock 

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

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

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

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

equation: 

Eq. 10.10 

where: 

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

year y, 

Ship(y) = shipment of new transformers in year y, 

Std_year = year the standard becomes effective, and 

Stock(age) = age in years of the stock of transformers. 

10.2.2.6 Unit Energy Consumption 

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

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 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 the load losses. It 

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

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

year due to load growth effects. 

The annual unit energy consumption for affected stock of distribution transformers is 

given by Equation 10.11: 

Eq. 10.11 

where: 

ENL = rated no-load losses per kVA capacity, 

ELL = rated load losses per kVA capacity, 

RMS = root mean square, and 

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

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

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

10.2.2.7 Electricity Site-to-Source Conversion 

The site-to-source conversion factor for electricity is the factor by which site energy (in 

kilowatt-hours (kWh)) is multiplied to obtain primary (source) energy (in Btu). Since the NES 

estimates the change in energy use of the resource (e.g., the power plant), this conversion factor is 

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

energy consumption at the site of its use (i.e., the installed transformer), DOE multiplied it by the 

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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 different 

fuels and the efficiency of different energy conversion processes. The annual values are the U.S. 

average conversion factors for electricity generation for both peak and base load reduction. DOE 

used marginal heat rates corresponding to base load for no-load losses (or core losses) and 

marginal heat rates corresponding to peak load for load losses (or coil losses). It used these 

different rates because load losses are higher during transformer peak loads while no-load losses 

occur at all times. DOE obtained these conversion factors using a variant of the NEMS, called 

NEMS-BT.a Table 10.2.2 presents the average annual conversion factors DOE used. 

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

Losses 

Year For No-Load Losses For Load Losses 

2010 2.901 2.872 

2011 2.784 2.696 

2012 2.696 2.608 

2013 2.696 2.550 

2014 2.550 2.491 

2015 2.491 2.403 

2016 2.403 2.345 

2017 2.345 2.257 

2018 2.257 2.110 

2019–2038 2.198 1.993 

DOE used a time-series projection of conversion factors, changing from year to year, 

which it calculated as follows: 

1.	 Start with an integrated projection of electricity supply and demand (e.g., the Annual 

Energy Outlook (AEO2006) reference case)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). 

a

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

Modeling System: An Overview 2003.

5

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

of the model without any modification to code or data. Because this analysis 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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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. The NES spreadsheet model includes the conversion factors for each year of the 

projection. DOE and stakeholders can examine the effects of alternative assumptions by revising 

this column of numbers. 

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

energy savings over the forecast period complete the NES calculations. The next section of the 

chapter (section 10.3) describes the technical details of the NPV calculation. The results section 

(section 10.4) presents the NES and NPV results from the national impact spreadsheet. 

10.3	 NET PRESENT VALUE 

DOE estimated the national financial impact on consumers from the imposition of new 

energy efficiency standards using a national NPV accounting component in the national impact 

spreadsheet. DOE combined output of the shipments model with energy savings and financial 

data from the LCC to calculate an annual stream of costs and benefits resulting from trial 

distribution transformer energy efficiency standards. It discounted this time series to the year 

2007 and summed the result, yielding the national NPV. 

10.3.1 Net Present Value Overview 

The NPV is the present value of the incremental economic impact of a trial standard level. 

Like the NES, the NPV calculation started with transformer shipments and transformer stocks, 

estimates of which are outputs from the shipments model. DOE then obtained estimates of 

transformer first costs, losses, and average marginal electricity costs from the LCC analysis. It 

calculated the amount spent on transformer purchases and installation, and then calculated the 

corresponding operating costs by applying the marginal prices to the energy (both energy and 

electricity system capacity) used by the stock of transformers for each year, for both a base case 

and a standards case. Over time in the standards case, more-expensive, but more-efficient 

transformers gradually replace less-efficient transformers. Thus, the operating cost per unit 

capacity used by the stock of transformers gradually decreases in the standards case relative to the 

base case, while the equipment costs increase. 

10-14


 EE-RM/STD-00-550 COMMENT 196
DOE discounted purchases, expenses, and operating costs for transformers using a simple 

national average discount factor. The discount factor converts a future expense or benefit to a 

present value. The difference in present value of all expenses and benefits between the base case 

and standards scenario is the national NPV impact. DOE calculated the NPV impact from 

transformers that were purchased between the effective date of the standard and 2038, inclusive, 

to calculate the total NPV impact from purchases during the forecast period. 

Mathematically, NPV is the value in the present time of a time series of costs and savings, 

described by the equation: 

Eq. 10.12 

where: 

PVS = the present value of electricity savings, and 


PVC = the present value of equipment costs including installation. 


PVS and PVC are determined according to the following expressions: 

Eq. 10.13 

where: 

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, defined in Eq. 10.14. 

Eq. 10.14 

where: 

reference year= year 2007, and 

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

10-15 

 EE-RM/STD-00-550 COMMENT 196
Eq. 10.15 

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. 

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 

trial standards case and a base case scenario without national standards. It discounted future 

costs and savings to the present. 

DOE calculated a discount factor from the discount rate and the number of years between 

the year to which the sum is being discounted (2007) and the year in which the costs and savings 

occur. The NPV is the sum over time (2010–2073) of the discounted net financial savings. 

The following sections describe the inputs specific to the NPV calculation. 

10.3.2 Net Present Value Inputs 

The NPV model inputs include cost inputs, inputs important for detailing electricity 

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

details on those inputs that have not yet been described as part of the NES and shipments models. 

The specific list of inputs for the NPV is as follows: 

1. First cost 

2. Operating cost 

3. Peak responsibility factor 

4. Initial peak load 

5. Electricity price forecast scalar 

6. Marginal electricity costs 

7. Discount rate 

10-16 

 EE-RM/STD-00-550 COMMENT 196
10.3.2.1	 First Cost 

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

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	 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. 


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

averages for specific design lines. DOE applied an adjustment factor to convert the first cost of a 

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

particular product class. The adjustment incorporates the 0.75 scaling rule and the design-line-toproduct-class mapping. This adjustment factor is explained in detail in sections 10.2.2.1 and 

10.2.2.2. The costs are expressed in units of 2006$ per kVA of rated transformer capacity. 

Tables 10.3.1 and 10.3.2 show the resulting mean first costs per kVA for distribution 

transformers by trial standard level (TSL) and product class. Note that for the liquid-immersed 

transformers, DOE examined two sets of TSLs: TSLs 1 through 6 are those levels DOE 

investigated in the notice of proposed rulemaking (NOPR), while for this final rule DOE labeled 

recombinations of these TSLs that maintained consistency between single-phase and three-phase 

efficiency as TSLs A through D. 

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

Class (2006$/kVA, TSL 1 through TSL 6) 

Product Class Base TSL 1* 

(TP 1) 

TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 

PC 1, Liquid-Immersed, MV, Single-Phase 63.82 65.04 65.27 65.23 66.31 73.56 116.98 

PC 2, Liquid-Immersed, MV, Three-Phase 22.75 23.77 25.05 26.94 27.44 41.04 43.30 

PC 5, Dry-Type, MV, Single-Phase 29.34 30.42 31.75 33.85 38.84 52.84 52.84 

PC 6, Dry-Type, MV, Three-Phase 23.75 25.20 26.62 28.40 31.35 42.72 42.72 

PC 7, Dry-Type, MV, Single-Phase 35.60 36.74 37.81 39.75 43.50 55.11 55.11 

PC 8, Dry-Type, MV, Three-Phase 25.72 26.31 26.96 28.00 30.47 43.35 43.35 

PC 9, Dry-Type, MV, Single-Phase 31.71 31.96 33.23 34.65 40.98 57.18 57.18 

PC 10, Dry-Type, MV, Three-Phase 24.64 24.83 25.82 26.93 31.85 44.43 44.43 

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 EE-RM/STD-00-550 COMMENT 196
*TSL = T rial Standa rd Level 

Table 10.3.2	 First Cost of Distribution Transformers by Trial Standard Level and Product 

Class (2006$/kVA, TSL A through TSL D) 

Product Class Base TSL A TSL B TSL C TSL D 

PC 1, Liquid-Immersed, MV, Single-Phase 63.82 76.07 69.41 69.38 66.15 

PC 2, Liquid-Immersed, MV, Three-Phase 22.75 29.73 25.91 25.41 25.41 

*TSL = T rial Standa rd Level 

10.3.2.2	 Operating Cost 

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

complex, yet essential, part of calculating the national economic impact of a distribution 

transformer standard. DOE used distinct costs to calculate value of different types of losses and 

peak capacity savings. Potential load growth also requires a load growth adjustment factor. Peak 

loading, peak load coincidence, and average loading require additional factors to characterize load 

losses. Finally, DOE used an electricity price forecast scalar to characterize future trends in 

electricity prices consistent with the AEO2007 forecast.

 DOE assumed zero incremental maintenance cost in calculating the transformer operating 

costs. It calculated annual operating costs using the following formula to capture the diversity of 

potential factors that can affect these costs: 

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

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

where: 

E

E

OC = the operating cost, 


Cap = the rated capacity of the transformer, 


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


NL = the no-load losses at rated load,


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


NLLMEC = the no-load loss marginal energy cost,


LL = the load losses at rated load,


LAdjust(y) = the load growth adjustment factor in year y,


PRF = the peak responsibility factor, 


PL = the initial peak load,


LLMCC = the load loss marginal cost of capacity, 


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


LLMEC = the load loss marginal energy cost.


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 EE-RM/STD-00-550 COMMENT 196
DOE expressed the operating costs in units of 2006$ per kVA of rated capacity. As in the 

NES calculation (see sections 10.2.2.1 and 10.2.2.2), DOE also applied an adjustment factor to 

incorporate the 0.75 scaling rule to ENL and ELL, 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. 

10.3.2.3 Peak Responsibility Factor 

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

that is coincident with the system peak, calculated by taking the square of the ratio of the 

transformer load at the time of the customer peak load to the transformer peak load. In 

combination with the initial peak loading, the PRF is necessary for estimating the capacity cost 

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

analysis for the liquid-immersed and dry-type transformers, respectively, as reported in the LCC 

analysis. Table 10.3.3 presents the PRFs used in the analysis for the 8 product classes. 

Table 10.3.3 Peak Responsibility Factors by Product Class 

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

PRF 0.34 0.50 0.52 0.53 0.52 0.53 0.54 0.54 

10.3.2.4 Initial Peak Load 

The initial peak loading is the annual per-unit peak load on the transformer during the first 

year of operation. This factor, in combination with the PRF, is necessary for calculating capacity 

cost impacts from transformer load losses. The initial peak load is estimated as a percentage of 

the rated peak load of the transformer. The IEEE’s Draft Guide for Distribution Transformer 

Loss 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, DOE characterized a range 

of possible initial peak loads by defining a distribution of initial peak loads. Chapter 6, sections 

6.2.3.3 and 6.3.3.3, provide further description of DOE’s method. Table 10.3.4 presents the 

initial peak loadings used in the analysis for the 8 product classes. 

Table 10.3.4 Initial Peak Loading by Product Class 

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

Initial Peak Loading 0.86 0.86 0.75 0.75 0.75 0.75 0.75 0.75 

10-19 

 EE-RM/STD-00-550 COMMENT 196
10.3.2.5 Electricity Price Forecast Scalar 

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

for the period 2004–2073. The electricity price forecast scalar is the ratio of the unit cost of 

electricity in real dollars in a given year to the real cost of electricity in the year 2006. DOE used 

AEO20074 forecasts to obtain the electricity price forecast scalar. For the period beyond 2025, 

DOE used the BEA real dollar price trend from 2015 to 2025 to extrapolate the electricity price 

scalar. 

10.3.2.6 Marginal Electricity Costs 

The characterization of four distinct marginal electricity costs was necessary to calculate 

the operating costs of transformers and the financial impact of transformer efficiency standards. 

The four types of marginal costs are: no-load loss marginal capacity cost (NLLMCC), load loss 

marginal capacity cost (LLMCC), no-load loss marginal energy cost (NLLMEC), and load loss 

marginal energy cost (LLMEC). In an electricity system, there are both energy costs and capacity 

costs. Depending on the load shape of a particular load, the average value of capacity costs and 

energy costs are different. Since no-load losses and load losses have distinct load shapes, and 

since different customers have different load shapes, costs vary both by loss type and by the 

product class of the transformer. DOE therefore used distinct marginal energy and capacity costs 

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

is necessary for the marginal costs, although DOE needed to apply the design-line-to-productclass mapping described in section 10.2.2.2 to convert the design line output from the LCC to 

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

2006$/kW/year, and energy costs in units of 2006$/kWh. Table 10.3.5 summarizes the four 

marginal costs for the 8 product classes. 

Table 10.3.5 Marginal Energy and Demand Costs by Product Class 

Marginal Energy Cost by Product Class ($/kWh) 

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

NLL 0.032 0.031 0.054 0.054 0.054 0.054 0.054 0.054 

LL 0.042 0.049 0.057 0.056 0.057 0.056 0.056 0.056 

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

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

NLL 103.82 119.56 97.75 98.97 97.94 99.21 99.62 99.62 

LL 55.80 62.28 74.88 76.70 75.18 77.04 78.47 78.47 

10-20 

 EE-RM/STD-00-550 COMMENT 196
10.3.2.7 Discount Rate 

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

calculation. DOE used real discount rates of three and seven percent, as established by the U.S. 

Office of Management and Budget (OMB) guidelines on regulatory analysis.8 In selecting the 

discount rate corresponding to a public investment, OMB directs agencies to use "the real 

Treasury borrowing rate on marketable securities of comparable maturity to the period of 

analysis." Office of Management and Budget (OMB) Circular No. A-94, "Guidelines and 

Discount Rates for Benefit-Cost Analysis of Federal Programs," dated October 29, 1992, section 

8.c.1. The discount rates DOE used in the LCC are distinct from those it used in the NPV 

calculations, in that the NPV discount rates represent the societal rate of return on capital, 

whereas LCC discount rates reflect the owner cost of capital and the financial environment of 

electric utilities and commercial and industrial entities. 

To address comments received in response to the NOPR, DOE also reports results for the 

4.2 percent discount rate in Appendix 10A of this TSD. 

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10.4 RESULTS 

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

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

TSL 1 through TSL 6 and TSL A through TSL D. It should be reiterated that, currently, the 

NES spreadsheet model uses discrete point-values rather than a distribution of values for all 

inputs. Savings for the dry-type units are substantially different from the estimates in the advance 

notice of proposed rulemaking (ANOPR) analyses.9 The difference in savings originates 

predominantly from the exclusion of dry-type, low-voltage transformers from the later analyses, 

since these types of transformers were regulated by the Energy Policy Act of 2005, enacted on 

August 8, 2005. 42 U.S.C. 6295(y) 

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

Present Value (2010–2073) Impact 

Trial Standard Level Discount Distribution 

Transformers 

Liquid-


Immersed


Dry-Type 

Rate 

% 

TSL 1 

(TP 1) 

TSL 

2 

TSL 

3 

TSL 

4 

TSL 

5 

TSL 

6 

TSL 

A 

TSL 

B 

TSL 

C 

TSL 

D 

NES 

quads 1.38 1.94 2.76 3.00 5.07 7.37 4.07 2.75 2.61 2.18 

NPV 

billion 

2006$ 

3 5.57 7.06 9.17 9.33 1.40 -26.1 4.47 7.26 6.95 7.56 

7 1.68 1.95 2.37 2.13 -4.89 -23.3 -1.89 1.11 1.11 1.91 

NES 

quads 0.06 0.13 0.19 0.27 0.40 0.40 

NPV 

billion 

2006$ 

3 0.47 0.85 1.18 1.55 1.02 1.02 

7 0.16 0.28 0.38 0.45 -0.08 -0.08 

Analysis 

10.4.1.1 Liquid-Immersed Results 

Table 10.4.2 presents the NES and NPV results for liquid-immersed transformers by 

product class. Figure 10.4.1 illustrates the typical pattern of primary energy savings and costs 

resulting from standards for liquid-immersed transformers over time. The figure shows the nature 

of net savings for all ten TSLs relative to the base case. In this figure, the levels are ordered from 

lowest to highest energy savings. The levels with letter names have consistency between singlephase and three-phase design lines. The constraint created by such consistency lowers the NPV 

for these levels. 

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 EE-RM/STD-00-550 COMMENT 196
Table 10.4.2 Summary of Cumulative National Energy Savings (2010–2038) and Net 

Present Value (2010–2073) Impact for Liquid-Immersed Transformers 

Distribution 

Transformers Analysis 

Discount 

Rate 

% 

Trial Standard Level 

TSL 1 

(TP 1) 

TSL 

2 

TSL 

3 

TSL 

4 

TSL 

5 

TSL 

6 

TSL 

A 

TSL 

B 

TSL 

C 

TSL 

D 

LiquidNES 

quads 0.81 0.90 0.94 1.05 1.72 3.97 1.88 1.45 1.45 1.02 

Immersed 

Single-Phase 

NPV 

billion 

2006$ 

3 3.15 3.42 3.74 3.60 1.02 -24.5 -0.31 2.98 2.97 3.58 

7 0.98 1.04 1.17 0.93 -1.33 -18.5 -2.28 0.14 0.14 0.94 

LiquidNES 

quads 0.57 1.04 1.82 1.96 3.36 3.41 2.19 1.30 1.16 1.16 

Immersed 

Three-Phase 

NPV 

billion 

2006$ 

3 2.42 3.64 5.42 5.72 0.38 -1.58 4.78 4.28 3.98 3.98 

7 0.71 0.91 1.20 1.21 -3.56 -4.75 0.38 0.97 0.96 0.96 

Figure 10.4.1 Liquid-Immersed Distribution Transformers: National 

Energy Savings and Net Present Value Impacts 

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 EE-RM/STD-00-550 COMMENT 196
10.4.1.2	 Dry-Type Results 

Tables 10.4.3 and 10.4.4 present NES and NPV results for dry-type transformers by 

product class. Figure 10.4.2 shows the typical pattern of national savings and costs resulting from 

standards for dry-type transformers over time. Again, the figure shows the nature of net savings 

for six dry-type transformer TSLs relative to the base case. 

Table 10.4.3	 Cumulative Primary Energy Savings During 2010–2038: Dry-Type 

Transformers by Product Class 

Product Class 

Cumulative Primary Energy Savings 

quads 

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

 5. Dry-Type, MV, Single-Phase, 20-45 kV BIL 0.0003 0.0005 0.0008 0.0011 0.0014 0.0014

 6. Dry-Type, MV, Three-Phase, 20-45 kV BIL 0.015 0.028 0.040 0.052 0.068 0.068

 7. Dry-Type, MV, Single-Phase, 46-95 kV BIL 0.0004 0.0007 0.0009 0.0013 0.0016 0.0016

 8. Dry-Type, MV, Three-Phase, 46-95 kV BIL 0.045 0.096 0.134 0.196 0.301 0.301

 9. Dry-Type, MV, Single-Phase, >96 kV BIL 0.00001 0.00006 0.00011 0.00018 0.00025 0.00025 

10. Dry-Type, MV, Three-Phase, >96 kV BIL 0.0010 0.0064 0.0115 0.0199 0.0267 0.0267 

Total 0.062 0.1131 0.187 0.270 0.399 0.399 

10-24


 EE-RM/STD-00-550 COMMENT 196
Table 10.4.4 Net Present Value During 2010–2073: Dry-Type Transformers by Product 

Class 

Net Present Value 

Product Class 

$billion 

Discount Rate: 3% Discount Rate: 7% 

TSL 1 

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

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

 5. Dry-Type, MV, 0.002 0.003 0.005 0.006 0.004 0.004 0.001 0.001 0.002 0.002 0.000 0.000

Single-Phase, 

20-45 kV BIL 

6. Dry-Type, MV, 0.108 0.166 0.233 0.276 0.192 0.192 0.035 0.052 0.070 0.075 -0.002 -0.002

Three-Phase, 

20-45 kV BIL 

7. Dry-Type, MV, 0.003 0.005 0.006 0.008 0.006 0.006 0.001 0.002 0.002 0.002 0.001 0.001

Single-Phase, 

46-95 kV BIL 

8. Dry-Type, MV, 0.346 0.639 0.868 1.160 0.777 0.777 0.119 0.217 0.283 0.344 -0.058 -0.058

Three-Phase, 

46-95 kV BIL 

9. Dry-Type, MV, 0.000 0.000 0.001 0.001 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

Single-Phase, 

>96 kV BIL 

10. Dry-Type, MV, 0.007 0.037 0.067 0.095 0.037 0.037 0.002 0.012 0.022 0.022 -0.023 -0.023 

Three-Phase, 

>96 kV BIL 

Total 0.466 0.851 1.182 1.546 1.018 1.018 0.159 0.283 0.379 0.445 -0.085 -0.085 

10-25


 EE-RM/STD-00-550 COMMENT 196
Figure 10.4.2 Dry-Type Distribution Transformers: National Energy 

Savings and Net Present Value Impacts 

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

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers. 

html. Instructions for using the spreadsheet are in Appendix 10A of this TSD. 

10.4.1.3 Discounted Cumulative Energy Impacts 

In the ANOPR, DOE stated that, for its NOPR analysis, it would calculate discounted 

values for future national energy savings. DOE used the same discount rates that it used in 

calculating the NPV (seven percent and three percent real) to calculate discounted cumulative 

NES. As described in section 10.3.2.7, it used the seven-percent and three-percent real discount 

rates in accordance with the OMB guidelines on regulatory analysis.8 Table 10.4.5 shows the 

discounted national energy savings for both liquid-immersed and dry-type, medium-voltage 

transformers. 

The seven-percent and three-percent real discount rate values are meant to capture the 

present value of costs and benefits associated with projects facing an average degree of risk. 

Other discount rates may be more applicable for discounting costs and benefits associated with 

projects facing different risks and uncertainties. Risk adjustment theory suggests that lower 

discount rates may be called for to calculate the present value of future energy consumption or 

saving. 

10-26


 EE-RM/STD-00-550 COMMENT 196
Table 10.4.5 Discounted Cumulative Energy Impacts, Liquid-Immersed and Dry-Type, 

Medium-Voltage Transformers 

Liquid-Immersed Dry-Type, Medium-Voltage 

Cumulative Cumulative Cumulative Cumulative 

2010-2038 2010-2038 2010-2038 2010-2038 

3% discount 7% discount 3% discount 7% discount 

TSL1 quads 0.768 0.391 0.034 0.018 

TSL2 quads 1.080 0.550 0.073 0.037 

TSL3 quads 1.534 0.780 0.104 0.053 

TSL4 quads 1.672 0.851 0.199 0.099 

TSL5 quads 2.824 1.439 0.222 0.113 

TSL6 quads 4.105 2.093 0.222 0.113 

TSLA quads 2.267 1.154 

TSLB quads 1.531 0.780 

TSLC quads 1.450 0.738 

TSLD quads 1.213 0.618 

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 EE-RM/STD-00-550 COMMENT 196
REFERENCES


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 EE-RM/STD-00-550 COMMENT 196
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