11-i

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 Life-Cycle Cost Results .................. 11-3

11.3.1.1 Design Line 1 Life-Cycle Cost Results .................. 11-4

11.3.1.2 Design Line 2 Life-Cycle Cost Results .................. 11-4

11.3.1.3 Design Line 3 Life-Cycle Cost Results .................. 11-5

11.3.1.4 Design Line 4 Life-Cycle Cost Results .................. 11-5

11.3.1.5 Design Line 5 Life-Cycle Cost Results .................. 11-6

11.3.2 Rural Cooperatives Subgroup Life-Cycle Cost Results .................. 11-7

11.3.2.1 Design Line 1 Life-Cycle Cost Results .................. 11-7

11.3.2.2 Design Line 2 Life-Cycle Cost Results .................. 11-8

11.3.2.3 Design Line 3 Life-Cycle Cost Results .................. 11-8

11.3.2.4 Design Line 4 Life-Cycle Cost Results .................. 11-9

11.3.2.5 Design Line 5 Life-Cycle Cost Results ................. 11-10

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

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

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

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

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

11.4.1.4 Design Line 4 Payback Period Results ................. 11-13

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

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

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

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

11.4.2.3 Design Line 3 Payback Period Results ................. 11-16

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

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

LIST OF TABLES

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

Table 11.3.1 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 1 ..... 11-4

Table 11.3.2 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 2 ..... 11-5

Table 11.3.3 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 3 ..... 11-5
11-ii

Table 11.3.4 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 4 ..... 11-6

Table 11.3.5 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 5 ..... 11-7

Table 11.3.6 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 1 ..... 11-8

Table 11.3.7 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 2 ..... 11-8

Table 11.3.8 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 3 ..... 11-9

Table 11.3.9 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 4 .... 11-10

Table 11.3.10 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 5 .... 11-10

Table 11.4.1 Municipal Utilities Subgroup Payback Period Results: Design Line 1 .... 11-12

Table 11.4.2 Municipal Utilities Subgroup Payback Period Results: Design Line 2 .... 11-13

Table 11.4.3 Municipal Utilities Subgroup Payback Period Results: Design Line 3 .... 11-13

Table 11.4.4 Municipal Utilities Subgroup Payback Period Results: Design Line 4 .... 11-14

Table 11.4.5 Municipal Utilities Subgroup Payback Period Results: Design Line 5 .... 11-15

Table 11.4.6 Rural Cooperatives Subgroup Payback Period Results: Design Line 1 .... 11-16

Table 11.4.7 Rural Cooperatives Subgroup Payback Period Results: Design Line 2 .... 11-16

Table 11.4.8 Rural Cooperatives Subgroup Payback Period Results: Design Line 3 .... 11-17

Table 11.4.9 Rural Cooperatives Subgroup Payback Period Results: Design Line 4 .... 11-18

Table 11.4.10 Rural Cooperatives Subgroup Payback Period Results: Design Line 5 .... 11-18
11-1

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

technical support document (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 LCC 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: It

adjusted 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-calculated the LCC with

the adjusted input distributions. The subgroups examined are both subsets of the entire national

electric utility sample and, hence, the analysis was limited to liquid-immersed distribution

transformers, represented by design lines 1–5. The Department did not include dry-type

distribution transformers, represented by design lines 9–13, 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 three 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
11-2

The Department implemented these adjustment factors using 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

National sample 1.00 1.00 1.00

Rural cooperatives 0.98 0.75 0.90

Municipal utilities 0.93 1.20 1.00

11.2.2 How the Department Estimated the Adjustment Factors

This section describes how the Department estimated the three 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 kilowatt-hour (kWh) for all utilities using Energy Information Administration (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. Its

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 kilovolt-ampere (kVA) pad-mounted

transformer for the national sample is 35 percent. Stakeholders commented that rural

cooperative transformers tend to have lower loadings because of oversizing to control for voltage

flicker and lack of load diversity, while municipal utility transformers tend to have more diversity

and, thus, higher loadings. 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.

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; it compiled data from public sources for municipal utilities. The Department found

the evaluation parameters for rural cooperatives to be 10 percent lower than the national sample
a

 In this chapter of the TSD, LCC results are described in terms of candidate standard levels (CSLs). In the NOPR itself,

LCC results are described in terms of trial standard levels (TSLs). The TSLs are the efficiency levels used in post-LCC

analyses and they are also used to describe the standard levels considered by the Department for the proposed standard.

TSLs are based on the CSLs selected for the LCC. However, because of special considerations concerning manufacturer

impacts and design lines (DLs) contained within the same product class, efficiency levels— and therefore CSLs—do not

change for some standard level increments for DL1 and DL4. See TSD chapter 10 for a more detailed explanation. The

table below shows the mapping from the design line CSLs to the TSLs. The analysis reported in this chapter and in the

NOPR is the same, but is reported in slightly different formats in the two documents, according to this CSL-to-TSL

mapping.

Mapping of the Candidate Standard Levels to Trial Standard Levels

DL1 DL2 DL3 DL4 DL5 DL9 DL10 DL11 DL12 DL13

TSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1

TSL2 CSL1 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2

TSL3 CSL1 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3

TSL4 CSL2 CSL4 CSL4 CSL3 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4

TSL5 CSL3 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5

TSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6

11-3

average and the parameters for municipal utilities to be approximately the same as the national

sample average for the available data. 

11.3 LIFE-CYCLE COST SUBGROUP RESULTS

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

rural electric cooperatives. The results for each subgroup and each design line are presented in

tables that report the candidate standard level,a the percentage of transformers that have net

savings, no impact, and net LCC cost (i.e., negative savings); and the mean LCC savings. 

11.3.1 Municipal Utilities Subgroup Life-Cycle Cost Results

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

this subgroup: 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. Because of the increased savings from reduced load losses, the LCC savings for the

municipal utilities subgroup are slightly higher than for the national sample. The extra LCC

savings vary as a function of both the design line and the standard level, since the relative

importance of load losses varies with both design line and transformer efficiency.
11-4

11.3.1.1 Design Line 1 Life-Cycle Cost 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 65 percent of the

transformers are not impacted by candidate standard level (CSL) 1, while more than 95 percent

of transformers are impacted by a CSL 4 standard level or higher. CSLs 3, 5, and 6 result in a

majority of transformers experiencing a net cost due to a standard. With CSLs 1, 2, and 4, a

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

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

the net average LCC impact is less than 4 percent of the average baseline LCC of $4,842.

Table 11.3.1 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 1

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.9 99.04 99.19 99.33 99.49 99.59

Transformers having LCC Savings > $0 (%) 30.60 34.34 36.22 65.04 41.88 12.65

Transformers having LCC Savings = $0 (%) 64.69 51.40 15.20 4.98 2.03 0.00

Transformers having LCC Savings < $0 (%) 4.71 14.26 48.58 29.98 56.09 87.35

Mean LCC Savings ($) 95 120 64 177 57 -594

11.3.1.2 Design Line 2 Life-Cycle Cost 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 over 66 percent of the

transformers are not impacted by CSL 1, while 75 percent or more of transformers are impacted

by a CSL 5 standard level or higher. CSLs 5 and 6 result in a majority of transformers

experiencing a net cost due to a standard. With CSLs 1 through 4, the majority of affected

transformers experience a net savings. There is a net average LCC savings for CSLs 1 through 5,

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

impact is less than 3 percent of the average baseline LCC of $3,025.
11-5

Table 11.3.2 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 2

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.7 98.73 98.76 98.79 98.96 99.46

Transformers having LCC Savings > $0 (%) 32.6 31.7 34.1 35.4 32.1 1.4

Transformers having LCC Savings = $0 (%) 66.1 65.3 60.7 55.9 25.1 0.0

Transformers having LCC Savings < $0 (%) 1.4 3.0 5.2 8.7 42.8 98.6

Mean LCC Savings ($) 69 66 70 73 17 -926

11.3.1.3 Design Line 3 Life-Cycle Cost 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 73 percent of the

transformers are not impacted by CSL 1, while 96 percent or more of transformers are impacted

by a CSL 4 standard level or higher. CSLs 5 and 6 result in a majority of transformers

experiencing a net cost due to a standard. With CSLs 1 through 4, a majority of affected

transformers experience a net savings. There is a net average LCC savings for all levels. For

CSLs 2 through 4, the net average LCC savings are greater than 10 percent of the average

baseline LCC of $25,200.

Table 11.3.3 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 3

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 99.3 99.38 99.46 99.54 99.74 99.75

Transformers having LCC Savings > $0 (%) 26.0 34.0 45.3 57.2 39.3 35.9

Transformers having LCC Savings = $0 (%) 73.9 64.8 49.6 4.0 0.1 0.0

Transformers having LCC Savings < $0 (%) 0.1 1.2 5.1 38.8 60.6 64.1

Mean LCC Savings ($) 2,109 2,765 3,607 3,693 1,745 1,102

11.3.1.4 Design Line 4 Life-Cycle Cost 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 64 percent of the
11-6

transformers are not impacted by CSL 1, while more than 88 percent of transformers are

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

transformers with net savings and net costs, while CSLs 5 and 6 result in a majority of

transformers experiencing a net cost due to a standard. With CSLs 1, 2, and 4, the majority of

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

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

the net average LCC impact is less than 8 percent of the average baseline LCC of $12,501.

Table 11.3.4 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 4

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.9 99.08 99.26 99.45 99.58 99.61

Transformers having LCC Savings > $0 (%) 32.9 45.9 46.4 57.6 41.6 30.7

Transformers having LCC Savings = $0 (%) 64.1 39.8 11.7 9.8 0.8 0.0

Transformers having LCC Savings < $0 (%) 3.0 14.4 41.9 32.6 57.7 69.3

Mean LCC Savings ($) 608 808 512 905 435 -165

11.3.1.5 Design Line 5 Life-Cycle Cost 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 72 percent of the

transformers are not impacted by CSL 1, while more than 75 percent of transformers are

impacted by a CSL 5 standard level or higher. CSLs 5 and 6 have approximately equal

proportions of transformers incurring a net cost and a net savings as a result of a standard, and

CSLs 1 through 4 result in the majority of affected transformers obtaining a net savings from a

standard. There is a net average LCC savings for all CSLs. For CSLs 3 through 6, the net

average LCC savings are more than 10 percent of the average baseline LCC of $71,738.
11-7

Table 11.3.5 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 5

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 99.3 99.36 99.42 99.47 99.71 99.71

Transformers having LCC Savings > $0 (%) 27.6 34.8 50.4 61.4 50.1 49.9

Transformers having LCC Savings = $0 (%) 72.1 64.0 40.9 24.4 0.1 0.1

Transformers having LCC Savings < $0 (%) 0.3 1.2 8.8 14.1 49.8 50.0

Mean LCC Savings ($) 4,853 6,649 8,128 9,013 7,680 7,453

11.3.2 Rural Cooperatives Subgroup Life-Cycle Cost Results

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

this subgroup: 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. Because of the

reduced savings from reduced load losses, the LCC savings for the rural cooperatives subgroup

are slightly less than for the national sample. The diminished LCC savings vary as a function of

both the design line and the standard level, since the relative importance of load losses varies

with both design line and transformer efficiency. The LCC savings for rural cooperatives are

also, on average, less than for the municipal utility case per affected transformer. 

11.3.2.1 Design Line 1 Life-Cycle Cost 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 64 percent of transformers

are impacted by a CSL 1 standard level while 98 percent of transformers are impacted by a CSL

4 standard level. 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 all standard levels except CSL 6, the net average

LCC impact is less than 3 percent of the average baseline LCC of $4,431.
11-8

Table 11.3.6 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 1

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.9 99.04 99.19 99.33 99.49 99.59

Transformers having LCC Savings > $0 (%) 29.62 29.80 25.86 67.91 32.40 3.87

Transformers having LCC Savings = $0 (%) 64.38 50.23 11.28 2.04 1.03 0.00

Transformers having LCC Savings < $0 (%) 6.00 19.97 62.86 30.05 66.57 96.13

Mean LCC Savings ($) 79 58 -91 146 -106 -861

11.3.2.2 Design Line 2 Life-Cycle Cost 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 64 percent of rural

cooperative transformers are not impacted by a CSL 1 standard level while more than 80 percent

of transformers are impacted by a CSL 5 standard level or higher. Transformers that incur a net

LCC cost resulting from a standard dominate the affected transformers for CSLs 5 and 6, while

CSLs 1 through 4 have more affected transformers with net savings. There are net average LCC

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

standard levels except CSL 6, the net average LCC impact is less than 3 percent of the average

baseline LCC of $2,849. 

Table 11.3.7 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 2

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.7 98.73 98.76 98.79 98.96 99.46

Transformers having LCC Savings > $0 (%) 33.7 33.9 35.7 36.2 27.8 0.4

Transformers having LCC Savings = $0 (%) 64.4 62.0 57.2 51.9 18.9 0.0

Transformers having LCC Savings < $0 (%) 1.9 4.1 7.2 11.9 53.3 99.6

Mean LCC Savings ($) 69 66 67 63 -25 -1,040
11-9

11.3.2.3 Design Line 3 Life-Cycle Cost 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 72 percent of 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 5 and 6 result in a majority of 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. CSL 4 has approximately equal numbers of affected transformers with net costs and

net savings. There are 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 10 percent of the average baseline LCC of $19,109.

Table 11.3.8 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 3

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 99.3 99.38 99.46 99.54 99.74 99.75

Transformers having LCC Savings > $0 (%) 27.5 33.0 41.0 49.5 21.7 17.6

Transformers having LCC Savings = $0 (%) 72.4 64.9 49.4 2.3 0.1 0.0

Transformers having LCC Savings < $0 (%) 0.1 2.2 9.6 48.3 78.3 82.4

Mean LCC Savings ($) 1,288 1,525 1,669 1,579 -1,630 -2,573

11.3.2.4 Design Line 4 Life-Cycle Cost 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 63 percent of the

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

impacted by a CSL 3 standard level or higher. CSLs 3, 5, and 6 result in a majority of

transformers experiencing a net cost as a result of a standard. CSLs 1, 2, and 4 have the majority

of affected transformers obtaining a net savings from a standard. 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 5 percent of the average baseline LCC of

$10,718.
11-10

Table 11.3.9 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 4

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 98.9 99.08 99.26 99.45 99.58 99.61

Transformers having LCC Savings > $0 (%) 31.7 38.6 43.7 56.1 22.5 14.6

Transformers having LCC Savings = $0 (%) 63.1 38.5 5.7 6.1 0.6 0.0

Transformers having LCC Savings < $0 (%) 5.2 22.9 50.6 37.8 76.9 85.4

Mean LCC Savings ($) 412 370 183 448 -599 -1,320

11.3.2.5 Design Line 5 Life-Cycle Cost 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 71 percent of the

transformers are not impacted by CSL 1, while more than 79 percent of transformers are

impacted by a CSL 4 standard level or higher. CSLs 5 and 6 result in a majority of transformers

incurring a net cost, and CSLs 1 through 4 have the majority of affected transformers incurring a

net savings from a standard. There are net average LCC savings for CSLs 1 through 4. For all

CSLs, the net average LCC impact is less than 8 percent of the average baseline LCC of $49,040.

Table 11.3.10 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 5

Candidate Standard Level

1 2 3 4 5 6

Efficiency (%) 99.3 99.36 99.42 99.47 99.71 99.71

Transformers having LCC Savings > $0 (%) 28.2 34.6 43.1 51.7 21.9 21.2

Transformers having LCC Savings = $0 (%) 70.9 62.4 39.6 20.8 0.1 0.0

Transformers having LCC Savings < $0 (%) 0.9 3.1 17.4 27.5 78.0 78.8

Mean LCC Savings ($) 2,243 3,013 3,084 3,239 -3,617 -3,775
11-11

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 analyzed 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 (see 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 mean incremental 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 mean incremental first cost increase and the mean operating cost savings. 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 Payback Period Results

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

this subgroup. This 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. While the mean PBP for the municipal utilities

subgroup is generally shorter than the PBP for the national sample, it is often within a year of the

national sample mean PBP. Compared to the rural cooperatives subgroup, the benefits from

efficiency improvements are on average greater for municipal utilities, and the PBP tends to be

slightly smaller than that for rural cooperatives. 

11.4.1.1 Design Line 1 Payback Period 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 65 percent of the

transformers are not impacted by CSL 1, while nearly 95 percent or more of transformers are
a

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

11-12

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

all CSLs. Mean distribution PBPs for this design line range from 11 to 43 years; CSL 1 has the

minimum distribution PBP.

Table 11.4.1 Municipal Utilities Subgroup Payback Period Results: Design Line 1

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 11.1 19.9 33.2 16.0 23.8 43.0

Transformers Not Impacted by Standard (%) 64.7 51.4 15.2 5.0 2.0 0.0

Transformers having Well-Defined Payback (%) 34.7 47.5 82.1 94.6 97.9 99.7

Transformers having Undefined Payback (%) 0.7 1.1 2.7 0.4 0.1 0.3

Mean Incremental First Cost ($) 165 312 492 508 879 1678

Mean Operating Cost Savings ($) 22 26 25 35 44 50

11.4.1.2 Design Line 2 Payback Period 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 66 percent of transformers

are not impacted by CSL 1, while 72 percent or more of transformers are impacted by a CSL 5

standard level or higher. Undefined PBPs are five percent or less for all CSLs. Mean PBPs for

this design line range from 5 to 65 years, with a monotonic (i.e., never reversing direction)

increase in mean PBP with increasing CSL.
11-13

Table 11.4.2 Municipal Utilities Subgroup Payback Period Results: Design Line 2

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 4.8 7.0 8.8 12.0 30.6 65.4

Transformers Not Impacted by Standard (%) 66.1 65.3 60.7 55.9 25.1 0.0

Transformers having Well-Defined Payback (%) 29.0 33.5 37.4 41.9 72.2 100.0

Transformers having Undefined Payback (%) 5.0 1.2 1.8 2.2 2.7 0.0

Mean Incremental First Cost ($) 32 49 59 76 241 1,472

Mean Operating Cost Savings ($) 12 12 12 12 13 26

11.4.1.3 Design Line 3 Payback Period 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 73 percent of the

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

4 standard level or higher. Undefined PBPs remain below 11 percent for all CSLs. For this

design line, PBPs increase monotonically from 1 to 30 years with increasing CSL. 

Table 11.4.3 Municipal Utilities Subgroup Payback Period Results: Design Line 3

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 1.2 3.8 8.7 19.2 27.4 29.9

Transformers Not Impacted by Standard (%) 73.9 64.8 49.6 4.0 0.1 0.0

Transformers having Well-Defined Payback (%) 16.0 34.9 50.1 93.0 99.8 100.0

Transformers having Undefined Payback (%) 10.1 0.3 0.3 3.0 0.0 0.0

Mean Incremental First Cost ($) 125 622 1,315 1,862 8,260 9,356

Mean Operating Cost Savings ($) 345 360 352 243 439 455

11.4.1.4 Design Line 4 Payback Period 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 64 percent of the

transformers are not impacted by CSL 1, while more than 88 percent of transformers are
11-14

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

PBPs are 1 percent or fewer of all transformers. Mean distribution PBP ranges from 8 to 30

years, with a dip in mean PBP for CSL 4. 

Table 11.4.4 Municipal Utilities Subgroup Payback Period Results: Design Line 4

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 7.7 15.0 21.5 16.9 27.1 32.5

Transformers Not Impacted by Standard (%) 64.1 39.8 11.7 9.8 0.8 0.0

Transformers having Well-Defined Payback (%) 34.8 59.5 87.7 90.1 99.1 100.0

Transformers having Undefined Payback (%) 1.0 0.7 0.6 0.1 0.2 0.0

Mean Incremental First Cost ($) 480 902 1,542 1,951 3,341 4,193

Mean Operating Cost Savings ($) 99 99 104 142 172 181

11.4.1.5 Design Line 5 Payback Period 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 72 percent of the

transformers are not impacted by CSL 1, while 75 percent or more of transformers are impacted

by a CSL 4 standard level or higher. Undefined PBPs remain below 2 percent of transformers for

all CSLs. Mean distribution PBP ranges from 3 to 24 years and increases monotonically with

increasing CSL. 
11-15

Table 11.4.5 Municipal Utilities Subgroup Payback Period Results: Design Line 5

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 2.9 5.1 11.0 12.9 23.7 23.7

Transformers Not Impacted by Standard (%) 72.1 64.0 40.9 24.4 0.1 0.1

Transformers having Well-Defined Payback (%) 27.9 35.9 58.1 74.7 99.9 99.9

Transformers having Undefined Payback (%) 0.0 0.1 1.1 0.9 0.0 0.0

Mean Incremental First Cost ($) 1,468 2,552 3,041 4,430 19,660 19,607

Mean Operating Cost Savings ($) 759 855 683 685 1,183 1,168

11.4.2 Rural Cooperatives Subgroup Payback Period Results

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

this subgroup: 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 Payback Period 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 65 percent of

transformers are not impacted by a CSL 1 standard level, while 98 percent of transformers are

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

CSLs except CSL 3. CSL 1 has the minimum mean distribution PBP and CSL 4, at 16 years,

also has relatively low PBP. The PBP ranges from 12 to 49 years over the range of CSLs. 
11-16

Table 11.4.6 Rural Cooperatives Subgroup Payback Period Results: Design Line 1

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 12.4 25.2 41.2 16.0 25.6 49.3

Transformers Not Impacted by Standard (%) 64.4 50.2 11.3 2.0 1.0 0.0

Transformers having Well-Defined Payback (%) 34.5 47.4 82.7 97.7 98.8 99.4

Transformers having Undefined Payback (%) 1.2 2.4 6.0 0.3 0.2 0.6

Mean Incremental First Cost ($) 164 312 486 508 879 1687

Mean Operating Cost Savings ($) 20 20 18 34 38 40

11.4.2.2 Design Line 2 Payback Period 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 65 percent of rural

cooperative transformers are not impacted by a CSL 1 standard level, while over 76 percent of

transformers are impacted by a CSL 5 standard level or higher. Undefined PBPs remain below

six percent for all CSLs. Mean PBPs for this design line range from 5 to 72 years, with a

monotonic increase in mean PBP with increasing CSL.

Table 11.4.7 Rural Cooperatives Subgroup Payback Period Results: Design Line 2

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 5.4 7.6 9.9 14.0 35.6 72.5

Transformers Not Impacted by Standard (%) 64.4 62.0 57.2 51.9 18.9 0.0

Transformers having Well-Defined Payback (%) 29.9 36.4 39.5 44.2 76.7 100.0

Transformers having Undefined Payback (%) 5.7 1.6 3.3 3.9 4.4 0.0

Mean Incremental First Cost ($) 31 48 58 75 243 1,496

Mean Operating Cost Savings ($) 12 12 11 10 11 23

11.4.2.3 Design Line 3 Payback Period 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 73 percent of the
11-17

transformers are not impacted by CSL 1, while more than 95 percent of transformers are

impacted by a CSL 4 standard level or higher. Undefined PBPs remain below 10 percent for all

CSLs. For this design line, PBPs increase monotonically from 2 to 38 years with increasing

CSL.

Table 11.4.8 Rural Cooperatives Subgroup Payback Period Results: Design Line 3

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 1.6 5.7 13.7 22.5 33.9 37.7

Transformers Not Impacted by Standard (%) 72.4 64.9 49.4 2.3 0.1 0.0

Transformers having Well-Defined Payback (%) 17.5 34.7 49.8 95.8 99.9 100.0

Transformers having Undefined Payback (%) 10.2 0.5 0.8 2.0 0.0 0.0

Mean Incremental First Cost ($) 132 615 1,310 1,859 8,319 9,393

Mean Operating Cost Savings ($) 219 220 204 157 315 318

11.4.2.4 Design Line 4 Payback Period 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 63 percent of the

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

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

transformers for all CSLs. Mean distribution PBP ranges from 11 to 38 years; the Department

calculated the lowest mean PBP for CSL 1. 
11-18

Table 11.4.9 Rural Cooperatives Subgroup Payback Period Results: Design Line 4

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 10.8 22.2 25.4 18.0 31.4 37.7

Transformers Not Impacted by Standard (%) 63.1 38.5 5.7 6.1 0.6 0.0

Transformers having Well-Defined Payback (%) 35.3 59.8 94.2 93.8 98.9 99.8

Transformers having Undefined Payback (%) 1.6 1.7 0.1 0.0 0.6 0.2

Mean Incremental First Cost ($) 475 878 1,545 1,957 3,402 4,276

Mean Operating Cost Savings ($) 75 69 88 123 135 141

11.4.2.5 Design Line 5 Payback Period 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 71 percent of the

transformers are not impacted by CSL 1, while more than 79 percent of transformers are

impacted by a CSL 4 standard level or higher. Undefined PBPs remain two percent or fewer of

transformers for all CSLs. Mean distribution PBP ranges from 5 to 29 years and increases

monotonically with increasing CSL. 

Table 11.4.10 Rural Cooperatives Subgroup Payback Period Results: Design Line 5

Candidate Standard Level

1 2 3 4 5 6

Mean Payback (Years) 4.9 8.4 16.9 17.4 29.4 29.4

Transformers Not Impacted by Standard (%) 70.9 62.4 39.6 20.8 0.0 0.0

Transformers having Well-Defined Payback (%) 29.0 37.4 58.5 78.7 99.8 99.9

Transformers having Undefined Payback (%) 0.1 0.2 2.0 0.5 0.1 0.1

Mean Incremental First Cost ($) 1,486 2,576 3,014 4,400 20,006 19,934

Mean Operating Cost Savings ($) 440 503 393 419 853 845
11-19

REFERENCES

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

Electric Utility Data. 2003. (Last accessed September, 2005.) This material is available

in Docket #86. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy,

Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW,

Washington, DC, 20585-0121, telephone (202) 586-2945 for more information.

<http://www.eia.doe.gov/cneaf/electricity/page/eia861.html>