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 DOE 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 .................. 11-3


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


11.3.1.3 Design Line 3 Life-Cycle Cost Results .................. 11-4


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


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


11.3.2 Rural Cooperatives Subgroup Life-Cycle Cost Results ............ 11-6


11.3.2.1 Design Line 1 Life-Cycle Cost Results .................. 11-6


11.3.2.2 Design Line 2 Life-Cycle Cost Results .................. 11-7


11.3.2.3 Design Line 3 Life-Cycle Cost Results .................. 11-7


11.3.2.4 Design Line 4 Life-Cycle Cost Results .................. 11-8


11.3.2.5 Design Line 5 Life-Cycle Cost Results .................. 11-8


11.3.3 Vault Transformer Subgroup Life-Cycle Cost Results ............ 11-9


11.3.3.1	 Design Line 5 Life-Cycle Cost Results, Medium Vault Cost Case


................................................. 11-9


11.3.3.2	 Design Line 5 Life-Cycle Cost Results, Very High Vault Cost Case


................................................ 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 ........... 11-14


11.4.2.1 Design Line 1 Payback Period Results ................. 11-14


11.4.2.2 Design Line 2 Payback Period Results ................. 11-15


11.4.2.3 Design Line 3 Payback Period Results ................. 11-15


11.4.2.4 Design Line 4 Payback Period Results ................. 11-16


11.4.2.5 Design Line 5 Payback Period Results ................. 11-16


11.4.3 Vault Transformer Subgroup Payback Period Results ............ 11-17


11.4.3.1	 Design Line 5 Payback Period Results, Medium Vault Cost Case


................................................ 11-17


11-i 

 EE-RM/STD-00-550 COMMENT 196
Table 11.2.1
 Consumer Subgroup Economic Adjustment Factors .................... 11-2 

..... 11-4 

..... 11-4 

..... 11-5 

..... 11-5 

..... 11-6 

..... 11-6 

..... 11-7 

..... 11-8 

..... 11-8 

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

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

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

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

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

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

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

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

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

11.4.3.2	 Design Line 5 Payback Period Results, Very High Vault Cost Case


................................................ 11-18


LIST OF TABLES 

Table 11.3.10 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 5 ..... 11-9


Table 11.3.11 Vault Transformer Subgroup Life-Cycle Cost Results, Medium Vault Cost Case: 


Design Line 5 .................................................. 11-9


Table 11.3.12 Vault Transformer Subgroup Life-Cycle Cost Results, Very High Vault Cost


Case: Design Line 5 ........................................... 11-10 

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

.... 11-12 

.... 11-13 

.... 11-13 

.... 11-14 

.... 11-15 

.... 11-15 

.... 11-16 

.... 11-16 

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

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

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

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

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

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

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

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

Table 11.4.10 Rural Cooperatives Subgroup Payback Period Results: Design Line 5 .... 11-17


Table 11.4.11 Vault Transformer Subgroup Payback Period Results, Medium Vault Cost Case: 


Design Line 5 ................................................. 11-17


Table 11.4.12 Vault Transformer Subgroup Payback Period Results, Very High Vault Cost Case: 


Design Line 5 ................................................. 11-18


11-ii 

 EE-RM/STD-00-550 COMMENT 196
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 of Energy (DOE) performed its 

life-cycle cost consumer subgroup analysis for the distribution transformer energy-efficiency 

standard rulemaking. 

DOE 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, DOE defined consumer subgroups in terms of retail utility ownership type 

and transformer installations that could incur disproportionate costs. The specific consumer 

subgroups that DOE chose to examine are rural electric cooperatives, municipal utilities, and 

utilities with space-constrained vault transformers. 

11.2 ANALYSIS APPROACH 

As part of the regular LCC analysis, DOE built spreadsheet analysis tools that provide a 

consumer economic analysis for a nationally representative sample of utilities. DOE 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, DOE 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. DOE 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 

DOE 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. Space-constrained installation costs 

11-1 

 EE-RM/STD-00-550 COMMENT 196
DOE implemented the first three of these adjustment factors using an “LCC Subgroup” 

pull-down menu included as part of its LCC spreadsheet tool. Table 11.2.1 shows the adjustment 

factors for the national sample and the subgroups for rural cooperatives and municipal utilities. 

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 

For owners of vault transformers, DOE provided a transformer vault change cost function 

that is described in section 7.3.5 of this TSD. 

11.2.2 How DOE Estimated the Adjustment Factors 

This section describes how DOE estimated the the adjustment factors for each of the 

selected consumer subgroups. 

For the cost of electricity, DOE 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, DOE 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. DOE 

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 DOE consisted of rough loading 

estimates mentioned in stakeholder comments. DOE’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, DOE 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, DOE 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. DOE found the evaluation parameters 

11-2 

 EE-RM/STD-00-550 COMMENT 196
for rural cooperatives to be 10 percent 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 vault transformers, DOE applied a fixed and variable cost to the installation of a 

transformer when the transformer exceeded a threshold size. DOE selected the median 

transformer size at the threshold and set the fixed component of the extra installation cost at $XX 

for DL4 and $YY for DL5. The variable portion of the vault modification cost was set at $ZZ 

per cubic foot. 

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,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. 

11.3.1.1 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, DOE forecasts that two thirds of the transformers are not 

impacted by trial standard level (TSL) 1 through 3, while more than 93 percent of transformers 

are impacted by a TSL 4 standard level or higher. TSLs 5, 6, and A result in a majority of 

transformers experiencing a net cost due to a standard. With TSLs 1, 2, 3, 4, B, C, and D a 

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

for TSLs 1 through 4 and B through D, while there is a net average LCC cost for TSLs 5, 6, and 

A. 

11-3 

 EE-RM/STD-00-550 COMMENT 196
Table 11.3.1 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 1 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.90 

1.9 

66.1 

32.0 

118 

347 

2 

98.90 

1.9 

66.1 

32.0 

118 

347 

3 

98.90 

1.9 

66.1 

32.0 

118 

347 

4 

99.04 

15.1 

50.0 

35.0 

116 

233 

5 

99.19 

60.8 

7.0 

32.2 

-23 

-25 

6 

99.59 

94.8 

0.0 

5.2 

-1003 

-1003 

A 

99.19 

60.8 

7.0 

32.2 

-23 

-25 

B 

99.08 

23.3 

38.8 

38.0 

109 

177 

C 

99.08 

23.3 

38.8 

38.0 

109 

177 

D 

99.04 

15.1 

50.0 

35.0 

116 

233 

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, DOE forecasts that 42 percent of the transformers are not 

impacted by TSL 1, while 83 percent or more of transformers are impacted by a TSL 5 standard 

level or higher. TSLs C, B, 5, A and 6 result in a majority of transformers experiencing a net 

cost due to a standard. With TSLs 1 through 4 and D, the majority of affected transformers 

experience a net savings. There is a net average LCC savings for TSLs 1 through 5, D, C, and B, 

while there is a net average LCC cost for TSLs 5, 6 and A. 

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

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.70 

12.2 

42.0 

45.8 

55 

95 

2 

98.73 

10.7 

38.4 

50.9 

59 

97 

3 

98.76 

9.2 

36.3 

54.5 

74 

116 

4 

98.79 

11.9 

34.1 

54.0 

75 

113 

5 

98.96 

57.1 

10.0 

32.9 

-19 

-21 

6 

99.46 

99.1 

0.0 

0.9 

-1073 

-1073 

A 

99.04 

78.9 

0.1 

21.0 

-106 

-106 

B 

98.91 

42.9 

16.5 

40.6 

21 

25 

C 

98.91 

42.9 

16.5 

40.6 

21 

25 

D 

98.79 

11.9 

34.1 

54.0 

75 

113 

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, DOE forecasts that two thirds of the transformers are not 

impacted by TSL 1, while 97 percent or more of transformers are impacted by a TSL 4 standard 

level or higher. TSLs 5 and 6 result in a majority of transformers experiencing a net cost due to a 

standard. With TSLs 1 through 4 and A through D, a majority of affected transformers 

experience a net savings. There is a net average LCC savings for all levels except TSLs 5 and 6. 

11-4 

 EE-RM/STD-00-550 COMMENT 196
Table 11.3.3 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 3 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

1.6 

66.6 

31.8 

1357 

4064 

2 

99.38 

1.7 

59.0 

39.4 

1691 

4118 

3 

99.46 

6.8 

49.1 

44.2 

1885 

3701 

4 

99.54 

45.5 

2.1 

52.4 

1674 

1710 

5 

99.74 

80.5 

0.2 

19.4 

-1779 

-1782 

6 

99.75 

83.9 

0.0 

16.1 

-2837 

-2837 

A 

99.54 

45.5 

2.1 

52.4 

1674 

1710 

B 

99.47 

7.3 

47.1 

45.6 

1920 

3630 

C 

99.42 

2.5 

56.5 

41.0 

1798 

4135 

D 

99.38 

1.7 

59.0 

39.4 

1690 

4118 

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, DOE forecasts that more than 54 percent of the 

transformers are not impacted by TSL 1, while more than 87 percent of transformers are 

impacted by a TSL 3 standard level or higher. TSL 4 and lower has a majority of affected 

transformers experiencing a net savings, while TSLs 5 and 6 result in a majority of transformers 

experiencing a net cost due to a standard. With all TSLs except 5 and 6, there is a net average 

LCC savings. 

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

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.90 

7.9 

54.4 

37.7 

435 

955 

2 

99.08 

19.2 

20.6 

60.2 

577 

727 

3 

99.26 

22.5 

13.0 

64.5 

661 

760 

4 

99.26 

22.5 

13.0 

64.5 

661 

760 

5 

99.58 

74.7 

0.1 

25.2 

-563 

-563 

6 

99.61 

83.4 

0.0 

16.6 

-1338 

-1338 

A 

99.19 

33.5 

13.0 

53.5 

442 

508 

B 

99.08 

19.2 

20.6 

60.2 

577 

727 

C 

99.08 

19.2 

20.6 

60.2 

577 

727 

D 

99.08 

19.2 

20.6 

60.2 

577 

727 

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, DOE forecasts that two thirds of the transformers are not 

impacted by TSL 1, while more than two thirds of transformers are impacted by a TSL 4 standard 

level or higher. TSL A has similar proportions of transformers incurring a net cost and a net 

savings as a result of a standard, and TSLs 1 through 4 and B through D result in the majority of 

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

savings for all TSLs except 5 and 6. 

11-5 

 EE-RM/STD-00-550 COMMENT 196
Table 11.3.5 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 5 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

3.8 

66.7 

29.6 

2370 

7105 

2 

99.36 

3.4 

61.7 

34.9 

3154 

8230 

3 

99.42 

9.7 

45.5 

44.9 

3708 

6799 

4 

99.47 

17.0 

33.0 

50.0 

4094 

6114 

5 

99.71 

77.4 

0.0 

22.6 

-3192 

-3193 

6 

99.71 

77.4 

0.0 

22.6 

-3192 

-3193 

A 

99.54 

51.3 

4.7 

44.1 

2096 

2199 

B 

99.47 

17.0 

33.0 

50.0 

4094 

6114 

C 

99.42 

9.7 

45.5 

44.9 

3708 

6799 

D 

99.42 

9.7 

45.5 

44.9 

3708 

6799 

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, DOE forecasts that 65 percent of transformers are 

impacted by a TSL 1 standard level while 95 percent of transformers or more are impacted by 

standards at TSL5 or higher. There is a net average LCC savings for TSLs 1, through 4 and B 

through D, while there is a net average LCC cost for TSLs 5, 6 and A. 

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

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.90 

2.4 

65.2 

32.4 

120 

343 

2 

98.90 

2.4 

65.2 

32.4 

120 

343 

3 

98.90 

2.4 

65.2 

32.4 

120 

343 

4 

99.04 

20.2 

49.7 

30.1 

61 

122 

5 

99.19 

70.8 

4.6 

24.5 

-131 

-137 

6 

99.59 

98.7 

0.0 

1.3 

-1218 

-1218 

A 

99.19 

70.8 

4.6 

24.5 

-131 

-137 

B 

99.08 

29.5 

36.8 

33.8 

49 

78 

C 

99.08 

29.5 

36.8 

33.8 

49 

78 

D 

99.04 

20.2 

49.7 

30.1 

61 

122 

11-6 

 EE-RM/STD-00-550 COMMENT 196
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, DOE forecasts that 36 percent of rural cooperative 

transformers are not impacted by a TSL 1 standard level while more than 88 percent of 

transformers are impacted by a TSL C standard level or higher. Transformers that incur a net 

LCC cost resulting from a standard dominate the affected transformers for TSLs 5, 6 and A 

through C, while TSLs 1 through 4 and D have more affected transformers with net savings. 

There are net average LCC savings for TSLs 1 through 4 and B through D, while there is a net 

average LCC cost for TSLs 5, 6 and A. 

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

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.70 

15.6 

35.8 

48.6 

54 

85 

2 

98.73 

13.5 

32.1 

54.3 

61 

90 

3 

98.76 

13.1 

30.1 

56.8 

71 

102 

4 

98.79 

16.5 

28.0 

55.5 

67 

94 

5 

98.96 

66.7 

6.1 

27.2 

-51 

-55 

6 

99.46 

99.7 

0.0 

0.3 

-1174 

-1174 

A 

99.04 

84.7 

0.1 

15.2 

-148 

-148 

B 

98.91 

50.0 

11.5 

38.5 

4 

5 

C 

98.91 

50.0 

11.5 

38.5 

4 

5 

D 

98.79 

16.5 

28.0 

55.5 

67 

94 

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, DOE forecasts that 63 percent of transformers are not 

impacted by TSL 1, while more than 99 percent of transformers are impacted by a TSL 4 

standard level or higher. TSLs 5 and 6 result in a majority of transformers with a net cost as a 

result of a standard, and TSLs 1 through 3 and B through D have the majority of affected 

transformers incurring a net savings. TSL 4 and A have similar numbers of affected transformers 

with net costs and net savings. There are net average LCC savings for TSLs 1 through 4 and A 

through D, while there is a net average LCC cost for TSLs 5 and 6. 

11-7 

 EE-RM/STD-00-550 COMMENT 196
Table 11.3.8 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 3 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

2.5 

63.1 

34.4 

835 

2264 

2 

99.38 

2.1 

55.2 

42.8 

1151 

2566 

3 

99.46 

9.4 

46.0 

44.6 

1114 

2061 

4 

99.54 

44.1 

0.8 

55.1 

786 

793 

5 

99.74 

90.0 

0.0 

10.0 

-3324 

-3324 

6 

99.75 

93.1 

0.0 

6.9 

-4518 

-4518 

A 

99.54 

44.1 

0.8 

55.1 

786 

793 

B 

99.47 

10.0 

43.2 

46.8 

1155 

2034 

C 

99.42 

3.2 

53.1 

43.7 

1215 

2591 

D 

99.38 

2.1 

55.2 

42.8 

1151 

2566 

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, DOE forecasts that 53 percent of the transformers are not 

impacted by TSL 1, while more than 92 percent of transformers are impacted by a TSL 3 

standard level or higher. TSLs 5, and 6 result in a majority of transformers experiencing a net 

cost as a result of a standard. TSLs 1, through 4 and B through D have the majority of affected 

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

TSLs 1 through 4 and A through D, while there is a net average LCC cost for TSLs 5 and 6. 

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

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

98.90 

13.5 

52.9 

33.7 

247 

523 

2 

99.08 

26.7 

14.8 

58.5 

353 

414 

3 

99.26 

23.2 

7.8 

69.1 

653 

708 

4 

99.26 

23.2 

7.8 

69.1 

653 

708 

5 

99.58 

87.3 

0.1 

12.6 

-1216 

-1218 

6 

99.61 

93.8 

0.0 

6.2 

-2064 

-2064 

A 

99.19 

43.4 

7.8 

48.7 

173 

188 

B 

99.08 

26.7 

14.8 

58.5 

353 

414 

C 

99.08 

26.7 

14.8 

58.5 

353 

414 

D 

99.08 

26.7 

14.8 

58.5 

353 

414 

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, DOE forecasts that more than 65 percent of the 

transformers are not impacted by TSL 1, while more than 70 percent or more of transformers are 

impacted by a TSL 4 standard level or higher. TSLs 5, 6 and A result in a majority of 

transformers incurring a net cost, and all other TSLs have the majority of affected transformers 

incurring a net savings from a standard. There are net average LCC savings for all TSLs except 5 

and 6. 

11-8 

 EE-RM/STD-00-550 COMMENT 196
Table 11.3.10 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 5 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

8.0 

65.5 

26.5 

945 

2739 

2 

99.36 

7.9 

59.9 

32.2 

1371 

3419 

3 

99.42 

16.5 

42.0 

41.5 

1537 

2652 

4 

99.47 

26.1 

30.1 

43.8 

1505 

2152 

5 

99.71 

91.1 

0.0 

8.8 

-8122 

-8125 

6 

99.71 

91.1 

0.0 

8.8 

-8122 

-8125 

A 

99.54 

55.2 

2.0 

42.9 

292 

298 

B 

99.47 

26.1 

30.1 

43.8 

1505 

2152 

C 

99.42 

16.5 

42.0 

41.5 

1537 

2652 

D 

99.42 

16.5 

42.0 

41.5 

1537 

2652 

11.3.3 Vault Transformer Subgroup Life-Cycle Cost Results 

The LCC results for the vault transformer subgroup are a reflection of a key feature of 

this subgroup: Distribution transformers at the higher efficiency levels have larger volumes and 

higher installation costs from vault modifications. This can dramatically decrease the economic 

benefits from the highest standard levels of TSLs 5 and 6. 

11.3.3.1 Design Line 5 Life-Cycle Cost Results, Medium Vault Cost Case 

Table 11.3.11 presents the summary of the LCC subgroup analysis for the vault 

transformers subgroup for the representative unit from design line 5, a 1500 kVA, liquidimmersed, three-phase distribution transformer for the medium vault cost case. This is the 

design line that is most likely to be used in vault transformer applications. For this subgroup, 

owners tend to purchase smaller, less efficient designs in order to avoid higher installation costs. 

For the lowest standard levels, the majority of transformers are unaffected by a standard. There 

are net average LCC savings for all TSLs except 5 and 6. 

Table 11.3.11 Vault Transformer Subgroup Life-Cycle Cost Results, Medium Vault Cost 

Case: Design Line 5 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

2.3 

66.6 

31.1 

1707 

5107 

2 

99.36 

5.7 

49.0 

45.3 

2334 

4576 

3 

99.42 

16.5 

40.4 

43.1 

2523 

4232 

4 

99.47 

47.3 

4.8 

37.9 

1157 

1216 

5 

99.71 

91.6 

0.0 

8.4 

-13327 

-13327 

6 

99.71 

91.6 

0.0 

8.4 

-13327 

-13327 

A 

99.54 

61.9 

0.8 

38.1 

404 

404 

B 

99.47 

57.3 

4.8 

37.9 

1157 

1216 

C 

99.42 

16.5 

40.4 

43.1 

2523 

4232 

D 

99.42 

16.5 

40.4 

43.1 

2523 

4232 

11-9 

 EE-RM/STD-00-550 COMMENT 196
11.3.3.2 Design Line 5 Life-Cycle Cost Results, Very High Vault Cost Case 

Table 11.3.12 presents the summary of the LCC subgroup analysis for the vault 

transformers subgroup for the representative unit from design line 5, a 1500 kVA, liquidimmersed, three-phase distribution transformer. This is the design line that is most likely to be 

used in vault transformer applications. For this subgroup, owners tend to purchase smaller, less 

efficient designs in order to avoid higher installation costs. For the lowest standard levels, the 

majority of transformers are unaffected by a standard. There are net average LCC savings for all 

TSLs except 5 and 6. In this case, DOE assumes that the replacement cost for a transformer vault 

is very high. The result is that whenever possible customers will avoid making a purchase that 

requires a vault replacement. For TSLs 5 and 6 this may not be possible and the incremental cost 

of a standard can be very high as a result. 

Table 11.3.12 Vault Transformer Subgroup Life-Cycle Cost Results, Very High Vault Cost 

Case: Design Line 5 

Trial Standard Level 

Efficiency (%)


Transformers with Net LCC Cost (%)


Transformers with No Change in LCC (%)


Transformers with Net LCC Benefit (%)


Mean LCC Savings ($)


Mean LCC Savings for those effected


1 (TP 1) 

99.30 

2.3 

66.6 

31.1 

1707 

5107 

2 

99.36 

5.7 

49.0 

45.3 

2334 

4576 

3 

99.42 

16.5

40.4 

43.1 

2523 

4232 

4 

99.47 

57.3 

4.8 

37.9 

1157 

1216 

5 

99.71 

100.0 

0.0 

0.3 

-197936 

-197936 

6 

99.71 

100.0 

0.0 

0.3 

-197936 

-197936 

A 

99.54 

61.4 

0.0 

38.6 

474 

474 

B 

99.47 

57.3 

4.8 

37.9 

1157 

1216 

C 

99.42 

16.5 

40.4 

43.1 

2523 

4232 

D 

99.42 

16.5 

40.4 

43.1 

2523 

4232 

11-10 

 EE-RM/STD-00-550 COMMENT 196
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 DOE 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, DOE 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, DOE forecasts that nearly 66 percent of the transformers 

are not impacted by TSL 1, while nearly 93 percent or more of transformers are impacted by a 

11-11 

 EE-RM/STD-00-550 COMMENT 196
TSL 5 standard level or higher. Undefineda

 PBPs remain below ten percent for all TSLs. Mean 

distribution PBPs for this design line range from 5.7 to 43 years; TSL 1 has the minimum 

distribution PBP. PBP for the average transformer varies from 2.5 to 35 years depending on the 

TSL. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

5.7 

66.1 

25.0 

8.9 

59 

24 

2.5 

2 

5.7 

66.1 

25.0 

8.9 

59 

24 

2.5 

3 

5.7 

66.1 

25.0 

8.9 

59 

24 

2.5 

4 

16.4 

50.0 

48.8 

1.3 

262 

29 

9.0 

5 

32.0 

7.0 

89.5 

3.5 

481 

26 

18.5 

6 

43.4 

0.0 

99.8 

0.2 

2087 

59 

35.4 

A 

32.0 

7.0 

89.5 

3.5 

481 

26 

18.5 

B 

19.6 

38.8 

58.9 

2.3 

286 

27 

10.6 

C 

19.6 

38.8 

58.9 

2.3 

286 

27 

10.6 

D 

16.4 

50.0 

48.8 

1.3 

262 

29 

9.0 

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, DOE forecasts that 54 percent of transformers are not 

impacted by TSL 1, while 83 percent or more of transformers are impacted by a TSL C standard 

level or higher. Undefined PBPs are five percent or less for all TSLs. Mean PBPs for this design 

line range from 10 to 58 years. The PBP for the average transformer varies from approximately 8 

to 50 years. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

12.7 

42.0 

54.1 

3.9 

84 

10 

8.4 

2 

11.9 

38.4 

57.0 

4.6 

94 

11 

8.6 

3 

10.5 

36.3 

58.6 

5.1 

85 

12 

7.1 

4 

11.8 

34.1 

61.1 

4.8 

96 

12 

8.0 

5 

26.5 

10.0 

88.6 

1.4 

295 

16 

18.5 

6 

57.8 

0.0 

100.0 

0.0 

1721 

34 

50.6 

A 

33.2 

0.1 

98.0 

1.9 

409 

17 

24.0 

B 

22.2 

16.5 

81.9 

1.6 

234 

15 

15.6 

C 

22.2 

16.5 

81.9 

1.6 

234 

15 

15.6 

D 

11.8 

34.1 

61.1 

4.8 

96 

12 

8.0 

a

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

11-12 

 EE-RM/STD-00-550 COMMENT 196
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, DOE forecasts that two thirds of the transformers are not 

impacted by TSL 1, while 98 percent of transformers are impacted by a TSL 4 standard level or 

higher. Undefined PBPs remain below 3 percent for all TSLs. For this design line, PBPs 

increase monotonically from 4 to 30 years with increasing TSL stringency. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

3.7 

66.6 

31.3 

2.1 

532 

272 

2.0 

2 

5.2 

59.0 

40.2 

0.8 

991 

302 

3.3 

3 

9.7 

49.1 

50.4 

0.5 

1784 

323 

5.5 

4 

19.6 

2.1 

92.9 

5.0 

2226 

229 

9.7 

5 

29.5 

0.2 

99.8 

0.0 

9294 

426 

21.8 

6 

32.8 

0.0 

100.0 

0.0 

10629 

439 

24.2 

A 

19.6 

2.1 

92.9 

5.0 

2226 

229 

9.7 

B 

9.8 

47.1 

52.1 

0.8 

1722 

315 

5.5 

C 

6.3 

56.5 

43.1 

0.5 

1237 

317 

3.9 

D 

5.2 

59.0 

40.2 

0.8 

991 

302 

3.3 

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, DOE forecasts that more than 54 percent of the 

transformers are not impacted by TSL 1, while 87 percent or more of transformers are impacted 

by a TSL 3 standard level or higher. For this design line, transformers with undefined PBPs are 2 

percent or fewer of all transformers. Mean distribution PBP ranges from 11 to 33 years, with a 

dip in mean PBP. The PBP of the average transformer ranges from 7 to 24 years. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

11.2 

54.4 

43.8 

1.8 

669 

95 

7.0 

2 

13.7 

20.6 

77.2 

2.2 

947 

97 

9.8 

3 

13.9 

13.0 

86.9 

0.1 

1622 

138 

11.8 

4 

13.9 

13.0 

86.9 

0.1 

1622 

138 

11.8 

5 

28.8 

0.1 

99.7 

0.2 

4086 

199 

20.5 

6 

33.5 

0.0 

100.0 

0.0 

5054 

209 

24.2 

A 

16.7 

13.0 

86.9 

0.1 

1650 

124 

13.3 

B 

13.7 

20.6 

77.2 

2.2 

947 

97 

9.8 

C 

13.7 

20.6 

77.2 

2.2 

947 

97 

9.8 

D 

13.7 

20.6 

77.2 

2.2 

947 

97 

9.8 

11-13 

 EE-RM/STD-00-550 COMMENT 196
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, DOE forecasts that two thirds of the transformers are not 

impacted by TSL 1, while 55 percent or more of transformers are impacted by a TSL A standard 

level or higher. Undefined PBPs remain below 2 percent of transformers for all TSLs. Mean 

distribution PBP ranges from 8 to 28 years and increases monotonically with increasing TSL 

stringency. The PBP of the average transformer ranges from 4 to 20 years. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

7.7 

66.7 

32.3 

1.1 

2409 

561 

4.3 

2 

8.0 

61.7 

37.9 

0.4 

3693 

700 

5.3 

3 

11.6 

45.5 

53.7 

0.8 

4265 

649 

6.6 

4 

13.3 

33.0 

66.4 

0.6 

5391 

673 

8.0 

5 

28.0 

0.0 

99.9 

0.0 

22624 

1106 

20.5 

6 

28.0 

0.0 

99.9 

0.0 

22624 

1106 

20.5 

A 

21.3 

4.7 

95.0 

0.3 

9794 

693 

14.1 

B 

13.3 

33.0 

66.4 

0.6 

5391 

673 

8.0 

C 

11.6 

45.5 

53.7 

0.8 

4265 

649 

6.6 

D 

11.6 

45.5 

53.7 

0.8 

4265 

649 

6.6 

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, DOE forecasts that 65 percent of transformers are not 

impacted by a TSL 1 standard level, while about 50 percent of transformers are impacted by a 

TSL 4 standard level. Undefined paybacks remain below ten percent for all TSLs. Mean 

distribution PBPs for this design line range from 6.6 to 52 years; TSL 1 has the minimum 

distribution PBP. PBP for the average transformer varies from 2.5 to 45 years depending on the 

TSL. 

11-14 

 EE-RM/STD-00-550 COMMENT 196
Table 11.4.6 Rural Cooperatives Subgroup Payback Period Results: Design Line 1 

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

6.6 

65.2 

25.5 

9.3 

60 

24 

2.5 

2 

6.6 

65.2 

25.5 

9.3 

60 

24 

2.5 

3 

6.6 

65.2 

25.5 

9.3 

60 

24 

2.5 

4 

21.1 

49.7 

46.7 

3.6 

261 

22 

11.9 

5 

40.9 

4.6 

89.2 

6.2 

472 

19 

24.8 

6 

51.6 

0.0 

99.8 

0.2 

2094 

47 

44.6 

A 

40.9 

4.6 

89.2 

6.2 

472 

19 

24.8 

B 

25.0 

36.8 

58.4 

4.8 

282 

21 

13.4 

C 

25.0 

36.8 

58.4 

4.8 

282 

21 

13.4 

D 

21.1 

49.7 

46.7 

3.6 

261 

22 

11.9 

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, DOE forecasts that 36 percent of rural cooperative 

transformers are not impacted by a TSL 1 standard level, while over 88 percent of transformers 

are impacted by a TSL C standard level or higher. Undefined PBPs remain below six percent for 

all TSLs. Mean PBPs for this design line range from 14 to 65 years, with a monotonic increase 

in mean PBP with increasing TSL stringency. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

13.9 

35.8 

59.4 

4.8 

84 

10 

8.4 

2 

12.8 

32.1 

63.0 

4.9 

94 

11 

8.6 

3 

12.0 

30.1 

64.1 

5.8 

85 

11 

7.8 

4 

13.9 

28.0 

66.5 

5.5 

96 

11 

8.8 

5 

29.5 

6.1 

92.1 

1.8 

301 

14 

21.5 

6 

65.0 

0.0 

100.0 

0.0 

1744 

30 

58.1 

A 

36.1 

0.0 

98.2 

1.8 

427 

16 

26.7 

B 

24.2 

11.5 

86.4 

2.1 

237 

14 

16.9 

C 

24.2 

11.5 

86.4 

2.1 

237 

14 

16.9 

D 

13.9 

28.0 

66.5 

5.5 

96 

11 

8.8 

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, DOE forecasts that 63 percent of the transformers are not 

impacted by TSL 1, while more than 99 percent of transformers are impacted by a TSL 4 

standard level or higher. Undefined PBPs remain below four percent for all TSLs. For this 

design line, PBPs increase monotonically from 5.5 to 38 years with increasing TSL stringency. 

PBPs for the average transformer range from 3.3 to 31 years. 

11-15 

 EE-RM/STD-00-550 COMMENT 196
Table 11.4.8 Rural Cooperatives Subgroup Payback Period Results: Design Line 3 

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

5.5 

63.1 

34.0 

2.9 

546 

166 

3.3 

2 

6.0 

55.2 

44.3 

0.6 

999 

211 

4.7 

3 

11.6 

46.0 

52.8 

1.2 

1782 

226 

7.9 

4 

19.7 

0.8 

95.4 

3.8 

2251 

177 

12.7 

5 

33.2 

0.0 

100.0 

0.0 

9365 

339 

27.6 

6 

37.5 

0.0 

100.0 

0.0 

10710 

345 

31.0 

A 

19.7 

0.8 

95.4 

3.8 

2251 

177 

12.7 

B 

11.8 

43.2 

55.1 

1.7 

1705 

220 

7.8 

C 

7.2 

53.1 

46.6 

0.3 

1247 

227 

5.5 

D 

6.0 

55.2 

44.2 

0.6 

999 

211 

4.7 

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, DOE forecasts that 53 percent of the transformers are not 

impacted by TSL 1, while more than 92 percent of transformers are impacted by a TSL 3 

standard level or higher. Undefined PBPs remain below four percent of transformers for all 

TSLs. Mean distribution PBP ranges from 14 to 38 years. PBPs for the average transformer 

range from 10 to 30 years. 

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

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

15.2 

52.9 

43.5 

3.7 

656 

68 

9.6 

2 

16.2 

14.8 

82.4 

2.8 

910 

77 

11.8 

3 

13.7 

7.8 

92.2 

0.0 

1631 

136 

12.0 

4 

13.7 

7.8 

92.2 

0.0 

1631 

136 

12.0 

5 

31.8 

0.1 

99.0 

0.9 

4167 

166 

25.1 

6 

37.5 

0.0 

99.7 

0.3 

5136 

171 

30.0 

A 

19.1 

7.8 

92.0 

0.2 

1638 

105 

15.6 

B 

16.2 

14.8 

82.4 

2.8 

910 

77 

11.8 

C 

16.2 

14.8 

82.4 

2.8 

910 

77 

11.8 

D 

16.2 

14.8 

82.4 

2.8 

910 

77 

11.8 

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, DOE forecasts that nearly 66 percent of the transformers 

are not impacted by TSL 1, while 70 percent of transformers are impacted by a TSL 4 standard 

level or higher. Undefined PBPs remain two percent or less of transformers for all TSLs. Mean 

distribution PBP ranges from 13 to 33 years, while the PBPs for the average transformer range 

from 8 to 28 years. 

11-16 

 EE-RM/STD-00-550 COMMENT 196
Table 11.4.10 Rural Cooperatives Subgroup Payback Period Results: Design Line 5 

Trial Standard Level 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

13.4 

65.5 

32.6 

1.9 

2377 

300 

7.9 

2 

12.4 

59.9 

39.4 

0.7 

3618 

412 

8.8 

3 

15.5 

42.0 

57.0 

1.0 

4161 

398 

10.5 

4 

17.7 

30.1 

69.2 

0.7 

5330 

435 

12.2 

5 

32.7 

0.0 

99.7 

0.2 

22930 

830 

27.6 

6 

32.7 

0.0 

99.7 

0.2 

22930 

830 

27.6 

A 

25.5 

2.0 

98.0 

0.0 

9830 

582 

16.9 

B 

17.7 

30.1 

69.2 

0.7 

5330 

435 

12.2 

C 

15.5 

42.0 

57.0 

1.0 

4161 

398 

10.5 

D 

15.5 

42.0 

57.0 

1.0 

4161 

398 

10.5 

11.4.3 Vault Transformer Subgroup Payback Period Results 

The LCC results for the vault transformer subgroup are a reflection of a key feature of 

this subgroup: Distribution transformers at the higher efficiency levels have larger volumes and 

higher installation costs from vault modifications. This can dramatically decrease the economic 

benefits from the highest standard levels of TSLs 5 and 6. 

11.4.3.1 Design Line 5 Payback Period Results, Medium Vault Cost Case 

Table 11.4.11 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 the medium vault cost case. For this unit, DOE forecasts that the 

results are similar to the results for the general population of transformers. Undefined PBPs 

remain two percent or less of transformers for all TSLs. Mean distribution PBP ranges from 7 to 

28 years, while the PBPs for the average transformer range from 5 to 23 years. 

Table 11.4.11 Vault Transformer Subgroup Payback Period Results, Medium Vault Cost 

Case: Design Line 5 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

7.1 

66.6 

33.4 

0.0 

2857 

525 

5.4 

2 

8.2 

49.0 

49.8 

1.2 

2985 

498 

6.0 

3 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

Trial Standard Level 

4 

23.7 

4.8 

93.0 

2.2 

7002 

528 

13.3 

5 

34.3 

0.0 

100.0 

0.0 

32453 

1176 

27.6 

6 

34.3 

0.0 

100.0 

0.0 

32453 

1176 

27.6 

A 

20.2 

0.0 

98.5 

1.5 

10358 

690 

15.0 

B 

23.7 

4.8 

93.0 

2.2 

7002 

528 

13.3 

C 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

D 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

11-17 

 EE-RM/STD-00-550 COMMENT 196
11.4.3.2 Design Line 5 Payback Period Results, Very High Vault Cost Case 

Table 11.4.12 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 the very high vault cost case. For this unit, DOE forecasts that the 

results are similar to the results for the general population of transformers, except for the highest 

standard levels of TSLs 5 and 6. Undefined PBPs remain two percent or less of transformers for 

all TSLs. Mean distribution PBP ranges from 7 to 71 years, while the PBPs for the average 

transformer range from 5 to 61 years. 

Table 11.4.12 Vault Transformer Subgroup Payback Period Results, Very High Vault Cost 

Case: Design Line 5 

Mean Payback (Years)


Transformers Unaffected by the TSL (%)


Transformers having Well Defined Payback (%)


Transformers having Undefined Payback (%)


Mean Incremental First Cost ($)


Mean Operating Cost Savings ($)


Payback of Average Transformer


1 (TP 1) 

7.0 

66.6 

33.4 

0.0 

2857 

525 

5.4 

2 

8.2 

49.0 

49.8 

1.2 

2985 

498 

6.0 

3 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

Trial Standard Level 

4 

23.7 

4.8 

93.0 

2.2 

7002 

528 

13.3 

5 

98.7 

0.0 

100.0 

0.0 

226540 

1154 

196.3 

6 

98.7 

0.0 

100.0 

0.0 

226540 

1154 

196.3 

A 

20.1 

0.0 

98.2 

1.8 

10224 

687 

14.9 

B 

23.7 

4.8 

93.0 

2.2 

7002 

528 

13.3 

C 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

D 

12.6 

40.4 

59.5 

0.1 

5101 

609 

8.4 

11-18 

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

11-19 

 EE-RM/STD-00-550 COMMENT 196