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CHAPTER 11: LIFE-CYCLE COST SUBGROUP ANALYSIS

TABLE OF CONTENTS

11.1 INTRODUCTION .................................................... 11-1

11.2 ANALYSIS APPROACH .............................................. 11-1

11.2.1 Adjustment Factors for Analysis Inputs .............................. 11-1

11.2.2 How the Department Estimated The Adjustment Factors ................ 11-2

11.3 LIFE-CYCLE COST SUBGROUP RESULTS .............................. 11-3

11.3.1 Municipal Utilities Subgroup Results ............................... 11-3

11.3.1.1 Design Line 1 Results ............................... 11-3

11.3.1.2 Design Line 2 Results ............................... 11-4

11.3.1.3 Design Line 3 Results ............................... 11-5

11.3.1.4 Design Line 4 Results ............................... 11-6

11.3.1.5 Design Line 5 Results ............................... 11-6

11.3.2 Rural Cooperatives Subgroup Results ............................... 11-7

11.3.2.1 Design Line 1 Results ............................... 11-7

11.3.2.2 Design Line 2 Results ............................... 11-8

11.3.2.3 Design Line 3 Results ............................... 11-9

11.3.2.4 Design Line 4 Results ............................... 11-9

11.3.2.5 Design Line 5 Results .............................. 11-10

11.4 PAYBACK PERIOD RESULTS ........................................ 11-11

11.4.1 Municipal Utilities Subgroup Results .............................. 11-11

11.4.1.1 Design Line 1 Results .............................. 11-11

11.4.1.2 Design Line 2 Results .............................. 11-12

11.4.1.3 Design Line 3 Results .............................. 11-13

11.4.1.4 Design Line 4 Results .............................. 11-14

11.4.1.5 Design Line 5 Results .............................. 11-14

11.4.2 Rural Cooperatives Subgroup Results .............................. 11-15

11.4.2.1 Design Line 1 Results .............................. 11-15

11.4.2.2 Design Line 2 Results .............................. 11-16

11.4.2.3 Design Line 3 Results .............................. 11-17

11.4.2.4 Design Line 4 Results .............................. 11-17

11.4.2.5 Design Line 5 Results .............................. 11-18

LIST OF TABLES

Table 11.2.1 Consumer Subgroup Economic Adjustment Factors .................... 11-2

Table 11.3.1 Design Line 1 Results ........................................... 11-4

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Table 11.3.2 Design Line 2 Results ........................................... 11-5

Table 11.3.3 Design Line 3 Results ........................................... 11-5

Table 11.3.4 Design Line 4 Results ........................................... 11-6

Table 11.3.5 Design Line 5 Results ........................................... 11-7

Table 11.3.6 Design Line 1 Results ........................................... 11-8

Table 11.3.7 Design Line 2 Results ........................................... 11-8

Table 11.3.8 Design Line 3 Results ........................................... 11-9

Table 11.3.9 Design Line 4 Results .......................................... 11-10

Table 11.3.10 Design Line 5 Results .......................................... 11-10

Table 11.4.1 Design Line 1 Results .......................................... 11-12

Table 11.4.2 Design Line 2 Results .......................................... 11-13

Table 11.4.3 Design Line 3 Results .......................................... 11-13

Table 11.4.4 Design Line 4 Results .......................................... 11-14

Table 11.4.5 Design Line 5 Results .......................................... 11-15

Table 11.4.6 Design Line 1 Results .......................................... 11-16

Table 11.4.7 Design Line 2 Results .......................................... 11-16

Table 11.4.8 Design Line 3 Results .......................................... 11-17

Table 11.4.9 Design Line 4 Results .......................................... 11-18

Table 11.4.10 Design Line 5 Results .......................................... 11-18

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CHAPTER 11: LIFE-CYCLE COST SUBGROUP ANALYSIS

11.1 INTRODUCTION

The life-cycle cost (LCC) subgroup analysis evaluates impacts on any identifiable groups

of customers who may, because of their particular socio-economic characteristics, be

disproportionately affected by any national energy-efficiency standard level. This chapter of the

TSD describes how the Department performed its life-cycle cost consumer subgroup analysis for

the distribution transformer energy-efficiency standard rulemaking. 

The Department conducted this evaluation for the Notice of Proposed Rulemaking

(NOPR), in part, by analyzing the LCC and payback periods for those customers that fall into

identified subgroups. For this rulemaking, the Department defined consumer subgroups in terms

of retail utility ownership type. The specific consumer subgroups that the Department chose to

examine are rural electric cooperatives and municipal utilities.

11.2 ANALYSIS APPROACH

As part of the regular life-cycle cost analysis, the Department built spreadsheet analysis

tools that provide a consumer economic analysis for a nationally representative sample of

utilities. The Department developed a simplified approach to perform the consumer subgroup

calculations. This approach adjusts the national data distributions for key analysis inputs by an

appropriate scaling factor to produce an approximation of the input data for the consumer

subgroup analysis. To estimate the economic impacts for the consumer subgroups, the

Department then re-calculates the LCC with the adjusted input distributions. The subgroups

examined are both subsets of the entire national electric utility sample and hence the analysis is

limited to liquid-immersed distribution transformers, represented by design lines 1-5. The drytype distribution transformers, represented by design lines 6-13, were not included in the LCC

subgroup analysis since electric utilities use few, if any, dry-type transformers. 

11.2.1 Adjustment Factors for Analysis Inputs

The Department selected four key data inputs that it adjusted for the consumer subgroup

analysis:

1. Cost of electricity

2. Transformer loading

3. Transformer selection A and B factors

4. Fraction of purchasers performing loss evaluation

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The Department implemented these adjustment factors with an “LCC Subgroup” pulldown menu included as part of its LCC spreadsheet tool. Table 11.2.1 shows the adjustment

factors for the national sample and the subgroups.

Table 11.2.1 Consumer Subgroup Economic Adjustment Factors

Subgroup Cost of

Electricity

Transformer

Loading

A and B

Factors % Evaluators

National sample 1.00 1.00 1.00 75

Rural cooperatives 0.98 0.75 0.90 100

Municipal utilities 0.93 1.20 1.00 100

11.2.2 How the Department Estimated The Adjustment Factors

This section describes how the Department estimated the four adjustment factors for each

of the two selected consumer subgroups.

For the cost of electricity, the Department examined the distribution of average electricity

revenues per kWh for all utilities using EIA Form 861 data for different ownership classes

(privately owned, cooperatives, and municipal utilities).1 For the purposes of this analysis, the

Department assumed that the EIA ownership classification of “Political Subdivision”

corresponded to a type of municipal utility. This examination revealed that the distribution of

unit revenues for different retail utility ownership classes is very similar. The Department then

calculated the weighted average unit revenues for the different ownership classes of retail

utilities. It found that the average unit revenue for rural cooperatives is 98 percent of that for the

national sample and that average unit revenue for municipal utilities is 93 percent of that for the

national sample.

For transformer loading estimates, the data available to the Department consisted of

rough loading estimates mentioned in stakeholder comments. The Department’s estimate of

average root mean square (RMS) loading for a 50 kVA pad-mounted transformer for the national

sample is 35 percent. Stakeholders commented that rural cooperative transformers tend to be

loaded less because of oversizing for voltage flicker and lack of load diversity, while municipal

utility transformers tend to have more diversity and subsequently higher loading. The typical

rural cooperative transformer will serve a single customer while the typical urban transformer

will serve multiple customers. Thus the Department estimated an adjustment factor of 0.75 for

rural cooperatives, and 1.20 for municipal utilities, which results in average RMS loading

estimates of 26 percent and 42 percent for 50 kVA transformers for rural cooperatives and

municipal utilities, respectively.

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For customer evaluation A and B factors, the Department was given factors for rural

cooperatives by the National Rural Electric Cooperative Association (NRECA) in stakeholder

comments and compiled data from public sources for both municipal utilities and other entities. 

The Department found the evaluation parameters for rural cooperatives to be slightly lower than

the national sample average and the parameters for municipal utilities to be approximately the

same as the national sample average for the available data. 

For percent evaluators, the Department has not been given any examples of rural

cooperatives or municipal utilities that do not evaluate losses for distribution transformer

purchases. Thus the Department assumed the 100 percent evaluation case for rural cooperatives

and municipal utilities.

11.3 LIFE-CYCLE COST SUBGROUP RESULTS

This section presents the results of the LCC subgroups analysis for municipal utilities and

rural electric cooperatives. The section presents the results for each subgroup and each design

line in the form of tables that report the efficiency level, the mean LCC savings, and the fraction

of transformers that have net savings, no impact, and net LCC cost (i.e., negative savings).

11.3.1 Municipal Utilities Subgroup Results

The LCC results for the municipal utilities subgroup are a reflection of two key features

of this subgroup. The first key feature is that virtually all municipal utilities perform some type

of economic evaluation of transformer losses when they make a purchase. This means that for

those purchases, efficiency levels associated with the lower candidate standards are already

economic for most transformers and there will be little or no impact from an efficiency standard. 

The second key feature is that transformers purchased by municipal utilities tend to serve more

diverse, urban loads than transformers that serve more rural areas. The increased load diversity

increases the load factor and the transformer loading, thus increasing the potential savings from

reduced load losses. Thus, compared to the other subgroup (rural cooperatives), the benefits from

efficiency improvements are on average greater. 

11.3.1.1 Design Line 1 Results

Table 11.3.1 presents the summary of the LCC subgroup analysis for municipal utilities

for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 87 percent of the

transformers are not impacted by candidate standard level (CSL) 1, while more than 93 percent

of transformers are impacted by a CSL 4 standard level or higher. CSL 2 has similar fractions of

affected transformers with net savings and net costs while CSLs 3, 5, and 6 have transformers

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dominated by those experiencing a net cost as a result of a standard. CSL 4 has a slight majority

of affected transformers experiencing a net savings. There is a net average LCC savings for

CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. For CSLs 1

through 5, the net average LCC impact is less than two percent of the average baseline LCC of

$4,756.

Table 11.3.1 Design Line 1 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Efficiency (%) 98.90 99.04 99.19 99.33 99.49 99.59

Transformers having LCC Savings > $0 (%) 8.7 16.0 25.6 58.8 34.8 8.6

Transformers having LCC Savings = $0 (%) 86.9 68.0 20.5 7.0 2.8 0.0

Transformers having LCC Savings < $0 (%) 4.4 16.0 54.0 34.3 62.4 91.4

Mean LCC Savings ($) 12 20 -29 78 -36 -675

11.3.1.2 Design Line 2 Results

Table 11.3.2 presents the summary of the LCC subgroup analysis for municipal utilities

for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 89 percent of the

transformers are not impacted by CSL 1, while more than 66 percent of transformers are

impacted by a CSL 5 standard level or higher. CSL 4 has similar fractions of affected

transformers with net savings and net costs, while CSLs 5 and 6 have transformers dominated by

those experiencing a net cost as a result of a standard. CSLs 1 through 3 have the largest

majority of affected transformers experiencing a net savings. There is a net average LCC savings

for CSLs 1 through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1

through 5, the net average LCC impact is less than two percent of the average baseline LCC of

$2,979.

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Table 11.3.2 Design Line 2 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Efficiency (%) 98.70 98.73 98.76 98.79 98.96 99.46

Transformers having LCC Savings > $0 (%) 9.7 10.6 13.6 14.8 14.6 0.7

Transformers having LCC Savings = $0 (%) 88.8 86.1 80.9 74.7 33.5 0.0

Transformers having LCC Savings < $0 (%) 1.6 3.3 5.5 10.6 51.9 99.4

Mean LCC Savings ($) 10 10 11 9 -40 -974

11.3.1.3 Design Line 3 Results

Table 11.3.3 presents the summary of the LCC subgroup analysis for municipal utilities

for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that over 98 percent of the

transformers are not impacted by CSL 1, while more than 94 percent of transformers are

impacted by a CSL 4 standard level or higher. CSL 4 has similar fractions of affected

transformers with net savings and net costs while CSLs 5 and 6 have transformers dominated by

those experiencing a net cost as a result of a standard. CSLs 1 through 3 have the largest

majority of affected transformers experiencing a net savings. There is a net average LCC savings

for CSLs 1 through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1

through 5, the net average LCC impact is less than five percent of the average baseline LCC of

$22,168.

Table 11.3.3 Design Line 3 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Efficiency (%) 99.30 99.38 99.46 99.54 99.74 99.75

Transformers having LCC Savings > $0 (%) 1.5 11.0 27.9 45.9 25.2 21.9

Transformers having LCC Savings = $0 (%) 98.3 87.7 65.8 5.6 0.2 0.0

Transformers having LCC Savings < $0 (%) 0.2 1.3 6.3 48.6 74.6 78.1

Mean LCC Savings ($) 54 259 734 833 -1,177 -1,804

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11.3.1.4 Design Line 4 Results

Table 11.3.4 presents the summary of the LCC subgroup analysis for municipal utilities

for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that more than 85 percent of the

transformers are not impacted by CSL 1, while more than 85 percent of transformers are

impacted by a CSL 3 standard level or higher. CSL 4 has similar fractions of affected

transformers with net savings and net costs while CSLs 3, 5, and 6 have transformers dominated

by those experiencing a net cost as a result of a standard and CSLs 1 and 2 have the majority of

affected transformers obtaining a net savings from a standard. There is a net average LCC

savings for CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. For

CSLs 1 through 5, the net average LCC impact is less than a few percent of the average baseline

LCC of $11,844.

Table 11.3.4 Design Line 4 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Efficiency (%) 98.90 99.08 99.26 99.45 99.58 99.61

Transformers having LCC Savings > $0 (%) 11.5 29.0 30.3 46.8 29.5 20.8

Transformers having LCC Savings = $0 (%) 85.7 53.4 14.6 12.3 1.0 0.0

Transformers having LCC Savings < $0 (%) 2.9 17.6 55.1 40.9 69.5 79.2

Mean LCC Savings ($) 112 249 -43 302 -206 -773

11.3.1.5 Design Line 5 Results

Table 11.3.5 presents the summary of the LCC subgroup analysis for municipal utilities

for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that 96 percent of the

transformers are not impacted by CSL 1, while more than 68 percent of transformers are

impacted by a CSL 3 standard level or higher. CSLs 5 and 6 have transformers dominated by

those incurring a net cost as a result of a standard and CSLs 1 through 4 have the majority of

affected transformers obtaining a net savings from a standard. There is a net average LCC

savings for all CSLs. For CSLs 1 through 5, the net average LCC impact is less than five percent

of the average baseline LCC of $65,545.

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Table 11.3.5 Design Line 5 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Efficiency (%) 99.30 99.36 99.42 99.47 99.71 99.71

Transformers having LCC Savings > $0 (%) 3.9 15.1 36.0 51.1 40.3 40.8

Transformers having LCC Savings = $0 (%) 96.0 83.8 53.2 31.2 0.1 0.1

Transformers having LCC Savings < $0 (%) 0.1 1.2 10.9 17.7 59.7 59.2

Mean LCC Savings ($) 429 1,253 2,174 3,157 1,524 1,580

11.3.2 Rural Cooperatives Subgroup Results

The LCC results for the rural cooperatives subgroup are a reflection of two key features

of this subgroup. The first key feature is that virtually all rural cooperatives perform some type

of economic evaluation of transformer losses when they make a purchase. This means that for

those purchases, efficiency levels associated with the lower candidate standards are already

economic for most transformers and there will be little or no impact from an efficiency standard. 

The second key feature is that distribution transformers purchased by rural cooperatives tend to

serve smaller loads than transformers that serve urban areas. The lower loading decreases the

potential savings from reduced load losses and thus the benefits from efficiency improvements

are on average less than the national average case per affected transformer. 

11.3.2.1 Design Line 1 Results

Table 11.3.6 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 86 percent of

transformers are impacted by a CSL 1 standard level while 97 percent of transformers are

impacted by a CSL 4 standard level. There is a net average LCC savings from CSLs 1 and 4,

while there is a net average LCC cost for CSLs 2, 3, 5, and 6. For all standard levels except CSL

6, the net average LCC impact is less than five percent of the average baseline LCC of $4,402.

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Table 11.3.6 Design Line 1 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Efficiency (%) 98.90 99.04 99.19 99.33 99.49 99.59

Transformers having LCC Savings > $0 (%) 8.04 11.12 18.59 63.93 28.17 1.82

Transformers having LCC Savings = $0 (%) 85.57 67.18 15.20 2.89 1.24 0.00

Transformers having LCC Savings < $0 (%) 6.39 21.70 66.21 33.18 70.59 98.18

Mean LCC Savings ($) 8 -15 -134 89 -147 -890

11.3.2.2 Design Line 2 Results

Table 11.3.7 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 87 percent of rural

cooperative transformers are not impacted by a CSL 1 standard level while nearly 75 percent of

transformers are impacted by a CSL 5 standard level. Transformers that incur a net LCC cost

resulting from a standard dominate the affected transformers for candidate standard levels 5 and

6, while CSLs 1 through 3 have more affected transformers with net savings and CSL 4 has

approximately equal numbers of affected transformers that incur net costs and net savings. There

is a net average LCC savings for CSLs 1, 2, 3, and 4, while there is a net average LCC cost for

CSLs 5 and 6. For all standard levels except CSLs 5 and 6, the net average LCC impact is less

than one percent of the average baseline LCC of $2,821. 

Table 11.3.7 Design Line 2 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Efficiency (%) 98.70 98.73 98.76 98.79 98.96 99.46

Transformers having LCC Savings > $0 (%) 11.2 13.2 14.1 15.8 11.2 0.1

Transformers having LCC Savings = $0 (%) 86.6 81.6 77.1 69.7 25.4 0.0

Transformers having LCC Savings < $0 (%) 2.2 5.2 8.8 14.5 63.5 99.9

Mean LCC Savings ($) 11 11 9 6 -72 -1,073

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11.3.2.3 Design Line 3 Results

Table 11.3.8 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 98 percent of the

transformers are not impacted by CSL 1, while more than 97 percent of transformers are

impacted by a CSL 4 standard level or higher. CSLs 4 through 6 have transformers dominated by

transformers with a net cost as a result of a standard and CSLs 1 through 3 have the majority of

affected transformers incurring a net savings. There is a net average LCC savings for CSLs 1

through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1 through 4, the net

average LCC impact is less than five percent of the average baseline LCC of $17,633.

Table 11.3.8 Design Line 3 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Efficiency (%) 99.30 99.38 99.46 99.54 99.74 99.75

Transformers having LCC Savings > $0 (%) 2.1 10.4 22.8 35.3 7.8 5.7

Transformers having LCC Savings = $0 (%) 97.8 86.9 64.7 2.7 0.1 0.0

Transformers having LCC Savings < $0 (%) 0.1 2.7 12.4 62.0 92.1 94.3

Mean LCC Savings ($) 40 133 250 58 -3,188 -4,106

11.3.2.4 Design Line 4 Results

Table 11.3.9 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that more than 85 percent of the

transformers are not impacted by CSL 1, while more than 91 percent of transformers are

impacted by a CSL 3 standard level or higher. CSL 4 has similar fractions of affected

transformers with net savings and net costs while CSLs 2, 3, 5, and 6 have transformers

dominated by those experiencing a net cost as a result of a standard. CSLs 1 and 2 have the

majority of affected transformers obtaining a net savings from a standard. There is a net average

LCC savings for CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. 

For CSLs 1 through 5, the net average LCC impact is less than a few percent of the average

baseline LCC of $10,391.

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Table 11.3.9 Design Line 4 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Efficiency (%) 98.90 99.08 99.26 99.45 99.58 99.61

Transformers having LCC Savings > $0 (%) 9.7 21.7 28.8 46.0 13.6 6.9

Transformers having LCC Savings = $0 (%) 85.3 50.9 8.4 7.9 0.8 0.0

Transformers having LCC Savings < $0 (%) 5.0 27.5 62.8 46.1 85.6 93.1

Mean LCC Savings ($) 45 19 -220 80 -918 -1,637

11.3.2.5 Design Line 5 Results

Table 11.3.10 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that nearly 96 percent of the

transformers are not impacted by CSL 1, while more than 71 percent of transformers are

impacted by a CSL 3 standard level or higher. CSLs 5 and 6 have transformers dominated by

those incurring a net cost as a result of a standard and CSLs 1 through 4 have the majority of

affected transformers incurring a net savings from a standard. There is a net average LCC

savings for CSLs 1 through 4. For CSLs 1 through 5, the net average LCC impact is less than

two percent of the average baseline LCC of $46,773.

Table 11.3.10 Design Line 5 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Efficiency (%) 99.30 99.36 99.42 99.47 99.71 99.71

Transformers having LCC Savings > $0 (%) 3.9 14.4 28.2 38.0 11.1 11.4

Transformers having LCC Savings = $0 (%) 95.7 82.9 51.4 28.8 0.1 0.0

Transformers having LCC Savings < $0 (%) 0.4 2.7 20.4 33.3 88.9 88.6

Mean LCC Savings ($) 199 507 597 660 -6,229 -6,226

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11.4 PAYBACK PERIOD RESULTS

As described in more detail in section 8.6, a common technique for evaluating investment

decisions is to perform a payback period (PBP) analysis. A more energy-efficient device will

usually cost more to purchase than a device of standard energy efficiency, while the more

efficient device will usually cost less to operate. Operating expenses decrease due to a reduction

in energy use. The payback period is the time (usually expressed in years) it takes to recover the

additional first cost of the efficiency device with its energy cost savings. Because the Department

analyzes the economics of a nationally representative distribution of transformers, DOE provides

results in terms of a distribution of payback periods. 

There are several potential complications to performing an analysis of a distribution of

PBP estimates that are discussed in more detail in section 8.6. Specifically, a payback period is a

ratio of increased first cost and decreased operating expenses. When there is a distribution of

changes for both first cost and operating expense reductions, the average of the ratio does not

equal the ratio of the averages. Therefore, in the tables below, the Department reports all

quantities of interest: the mean PBP, the average increase in first cost, and the average decrease

in annual operating expenses (in the first year of operation). These quantities allow stakeholders

to compare the average PBP to a ratio of the average first cost increase and the average operating

cost decrease. These two values are comparable, but not equal because not all transformer

purchase decision computations have well-defined PBPs. 

11.4.1 Municipal Utilities Subgroup Results

The PBP results for the municipal utilities subgroup are a reflection of two key features of

this subgroup. The first key feature is that virtually all municipal utilities perform some type of

economic evaluation of transformer losses when they make a purchase. This means that for those

purchases, efficiency levels associated with the lower candidate standards are already economic

for most transformers and there will be little or no impact from an efficiency standard. The

second key feature is that distribution transformers purchased by municipal utilities tend to serve

more diverse, urban loads than transformers that serve more rural areas. The increased load

diversity increases the load factor and the transformer loading, thus increasing the potential

savings from reduced load losses. Compared to the rural cooperatives subgroup, the benefits

from efficiency improvements are on average greater and the PBP tends to be slightly smaller

than that for rural cooperatives. 

11.4.1.1 Design Line 1 Results

Table 11.4.1 presents the summary of the PBP subgroup analysis for municipal utilities

for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 87 percent of the

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 Undefined refers to all invalid PBP computations. See section 8.6 for a full discussion.

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transformers are not impacted by CSL 1, while more than 93 percent of transformers are

impacted by a CSL 4 standard level or higher. Undefineda PBPs remain below 4 percent for all

CSLs. Mean distribution PBPs for this design line range from 16.9 to 47.2 years, with the

minimum distribution PBP seen for CSL 4.

Table 11.4.1 Design Line 1 Results

Candidate Standard Level

1

 (TP 1)

2 3 4 5 6

Mean Payback (Years) 20.6 29.7 39.9 16.9 25.5 47.2

Transformers Not Impacted by the Standard (%) 86.9 68.0 20.5 7.0 2.8 0.0

Transformers having Well-Defined Payback Period (%) 12.2 30.7 75.9 92.5 97.1 99.6

Transformers having Undefined Payback Period (%) 0.9 1.3 3.7 0.5 0.1 0.5

Mean Incremental First Cost ($) 137 257 385 422 757 1545

Mean Operating Cost Savings ($) 11 14 15 26 34 40

11.4.1.2 Design Line 2 Results

Table 11.4.2 presents the summary of the PBP subgroup analysis for municipal utilities

for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 89 percent of the

transformers are not impacted by CSL 1, while more than 66 percent of transformers are

impacted by a CSL 5 standard level or higher. Undefined PBPs are below 4 percent for all CSLs. 

Mean PBPs for this design line range from 10.9 to 72.4 years, with a monotonic increase in mean

PBP with increasing candidate standard level.

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Table 11.4.2 Design Line 2 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 10.9 16.0 17.2 22.5 39.1 72.4

Transformers Not Impacted by the Standard (%) 88.8 86.1 80.9 74.7 33.5 0.0

Transformers having Well-Defined Payback Period (%) 8.9 12.7 16.5 22.4 63.0 100.0

Transformers having Undefined Payback Period (%) 2.4 1.2 2.6 2.9 3.5 0.0

Mean Incremental First Cost ($) 28 45 52 76 212 1,418

Mean Operating Cost Savings ($) 6 6 5 5 7 21

11.4.1.3 Design Line 3 Results

Table 11.4.3 presents the summary of the PBP subgroup analysis for municipal utilities

for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that over 98 percent of the

transformers are not impacted by CSL 1, while more than 94 percent of transformers are

impacted by a CSL 4 standard level or higher. Undefined PBPs remain below 5 percent for all

CSLs. For this design line, PBPs increase monotonically from 3.6 to 34.6 years with increasing

CSL. 

Table 11.4.3 Design Line 3 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 3.6 8.1 13.8 23.6 31.7 34.6

Transformers Not Impacted by the Standard (%) 98.3 87.7 65.8 5.6 0.2 0.0

Transformers having Well-Defined Payback Period (%) 1.2 11.9 33.6 90.1 99.8 100.0

Transformers having Undefined Payback Period (%) 0.5 0.5 0.6 4.3 0.0 0.0

Mean Incremental First Cost ($) 236 591 1,053 1,498 7,859 8,940

Mean Operating Cost Savings ($) 155 115 131 104 300 317

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11.4.1.4 Design Line 4 Results

Table 11.4.4 presents the summary of the PBP subgroup analysis for municipal utilities

for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that more than 85 percent of the

transformers are not impacted by CSL 1, while more than 85 percent of transformers are

impacted by a CSL 3 standard level or higher. For this design line, transformers with undefined

PBPs are one percent or fewer of all transformers. Mean distribution PBP ranges from 14.3 to

36.7 years with the Department calculating second lowest mean PBP for CSL 4. 

Table 11.4.4 Design Line 4 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 14.3 21.7 26.3 19.0 30.6 36.7

Transformers Not Impacted by the Standard (%) 85.7 53.4 14.6 12.3 1.0 0.0

Transformers having Well-Defined Payback Period (%) 13.3 45.9 84.5 87.6 98.8 99.9

Transformers having Undefined Payback Period (%) 1.0 0.8 1.0 0.0 0.2 0.1

Mean Incremental First Cost ($) 411 688 1,384 1,731 3,029 3,880

Mean Operating Cost Savings ($) 51 51 67 103 130 140

11.4.1.5 Design Line 5 Results

Table 11.4.5 presents the summary of the PBP subgroup analysis for municipal utilities

for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that 96 percent of the

transformers are not impacted by CSL 1, while more than 68 percent of transformers are

impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 2 percent of

transformers for all CSLs. Mean distribution PBP ranges from 4.3 to 26.8 years and increases

monotonically with CSL. 

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Table 11.4.5 Design Line 5 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 4.3 8.1 15.5 16.0 27.0 26.8

Transformers Not Impacted by the Standard (%) 96.0 83.8 53.2 31.2 0.1 0.1

Transformers having Well-Defined Payback Period (%) 4.0 16.1 45.4 67.7 99.9 99.9

Transformers having Undefined Payback Period (%) 0.1 0.2 1.4 1.1 0.0 0.0

Mean Incremental First Cost ($) 1,343 1,786 2,243 3,510 18,239 18,352

Mean Operating Cost Savings ($) 497 391 281 340 867 880

11.4.2 Rural Cooperatives Subgroup Results

The PBP results for the rural cooperatives subgroup are a reflection of two key features of

this subgroup. The first key feature is that virtually all rural cooperatives perform some type of

economic evaluation of transformer losses when they make a purchase. This means that for those

purchases, efficiency levels associated with the lower candidate standards are already economic

for most transformers and there will be little or no impact from an efficiency standard. The

second key feature is that distribution transformers purchased by rural cooperatives tend to serve

smaller loads than transformers that serve urban areas. The lower loading decreases the potential

savings from reduced load losses, and thus the benefits from efficiency improvements are on

average less than the national average case per affected transformer, and payback times will be

longer than the national average.

11.4.2.1 Design Line 1 Results

Table 11.4.6 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 86 percent of

transformers are impacted by a CSL 1 standard level, while 97 percent of transformers are

impacted by a CSL 4 standard level. Undefined paybacks remain below 3 percent for all CSLs

except CSL 3. CSL 4 has the minimum mean distribution PBP of all CSLs which range from

16.3 to 53.8 years. 

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Table 11.4.6 Design Line 1 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 25.4 38.9 49.5 16.3 27.1 53.8

Transformers Not Impacted by the Standard (%) 85.6 67.2 15.2 2.9 1.2 0.0

Transformers having Well-Defined Payback Period (%) 12.9 29.9 77.4 96.8 98.4 99.1

Transformers having Undefined Payback Period (%) 1.5 2.9 7.4 0.3 0.3 1.0

Mean Incremental First Cost ($) 142 265 374 423 759 1560

Mean Operating Cost Savings ($) 9 10 10 27 31 32

11.4.2.2 Design Line 2 Results

Table 11.4.7 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 87 percent of rural

cooperative transformers are not impacted by a CSL 1 standard level, while nearly 75 percent of

transformers are impacted by a CSL 5 standard level. Undefined PBPs remain below 6 percent

for all CSLs. Mean PBPs for this design line range from 12.4 to 80.0 years, with a monotonic

increase in mean PBP with increasing candidate standard level.

Table 11.4.7 Design Line 2 Results

Candidate Standard Level

1 

(TP1)

2 3 4 5 6

Mean Payback Period (Years) 12.4 17.6 20.3 24.9 45.4 80.0

Transformers Not Impacted by the Standard (%) 86.6 81.6 77.1 69.7 25.4 0.0

Transformers having Well-Defined Payback Period (%) 10.6 16.1 19.0 25.0 69.0 100.0

Transformers having Undefined Payback Period (%) 2.8 2.3 3.9 5.3 5.6 0.0

Mean Incremental First Cost ($) 27 43 53 74 220 1,448

Mean Operating Cost Savings ($) 6 5 5 5 6 19

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11.4.2.3 Design Line 3 Results

Table 11.4.8 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase

distribution transformer. For this unit, the Department forecasts that nearly 98 percent of the

transformers are not impacted by CSL 1, while more than 97 percent of transformers are

impacted by a CSL 4 standard level or higher. Undefined PBPs remain below 3 percent for all

CSLs. For this design line, PBPs increase monotonically from 3.9 to 43.3 years with increasing

CSL. 

Table 11.4.8 Design Line 3 Results

Candidate Standard Level

1

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 3.9 13.1 21.7 27.2 38.8 43.3

Transformers Not Impacted by the Standard (%) 97.8 86.9 64.7 2.7 0.1 0.0

Transformers having Well-Defined Payback Period (%) 1.5 12.5 34.2 94.8 99.9 100.0

Transformers having Undefined Payback Period (%) 0.7 0.6 1.1 2.5 0.0 0.0

Mean Incremental First Cost ($) 205 593 1,044 1,487 7,932 8,999

Mean Operating Cost Savings ($) 108 73 77 74 229 234

11.4.2.4 Design Line 4 Results

Table 11.4.9 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that more than 85 percent of the

transformers are not impacted by CSL 1, while more than 91 percent of transformers are

impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 2 percent of

transformers for all CSLs. Mean distribution PBP ranges from 19.7 to 42.4 years with the

Department calculating lowest mean PBP for CSL 4. 

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Table 11.4.9 Design Line 4 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 21.3 30.8 30.2 19.7 34.8 42.4

Transformers Not Impacted by the Standard (%) 85.3 50.9 8.4 7.9 0.8 0.0

Transformers having Well-Defined Payback Period (%) 12.8 47.4 91.4 92.0 98.5 99.7

Transformers having Undefined Payback Period (%) 1.9 1.8 0.2 0.1 0.7 0.3

Mean Incremental First Cost ($) 400 679 1,419 1,741 3,110 3,958

Mean Operating Cost Savings ($) 32 32 60 94 106 111

11.4.2.5 Design Line 5 Results

Table 11.4.10 presents the summary of the LCC subgroup analysis for rural cooperatives

for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase

distribution transformer. For this unit, the Department forecasts that nearly 96 percent of the

transformers are not impacted by CSL 1, while more than 71 percent of transformers are

impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 3 percent of

transformers for all CSLs. Mean distribution PBP ranges from 7.7 to 32.8 years and increases

monotonically with increasing CSL. 

Table 11.4.10 Design Line 5 Results

Candidate Standard Level

1 

(TP 1)

2 3 4 5 6

Mean Payback Period (Years) 7.7 12.6 23.4 21.3 32.7 32.8

Transformers Not Impacted by the Standard (%) 95.7 82.9 51.4 28.8 0.0 0.0

Transformers having Well-Defined Payback Period (%) 4.2 16.8 46.3 70.5 99.8 99.8

Transformers having Undefined Payback Period (%) 0.1 0.3 2.3 0.7 0.2 0.2

Mean Incremental First Cost ($) 1,363 1,820 2,192 3,429 18,716 18,647

Mean Operating Cost Savings ($) 288 232 167 223 668 662

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REFERENCES

1. U.S. Department of Energy - Energy Information Administration. Form EIA-861: Annual

Electric Utility Data. 2001. (Last accessed July, 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/cneaf/electricity/page/eia861.html>

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