## 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

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## Table 11.2.1
 Consumer Subgroup Economic Adjustment Factors

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.....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 Tra nsformer Subgroup Life-Cycle Cost Results, Medium Vault Cost Case: Design Line 5

..................................................11-9 Table 11.3.12 Vault Tra nsformer 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 Tra nsformer Subgroup Payback Period Results, Medium Vault Cost Case: Design Line 5

.................................................11-17 Table 11.4.12 Vault Tra nsformer Subgroup Payback Period Results, Very High Vault Cost Case: Design Line 5

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

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## CHAPTER 11. LIFE-CYCLE COST SUBGROUP ANALYSIS

11.1 INTRODUCTION The life-cycle cost (LCC) subgroup analysis evaluates impacts on any identifiable groups of customers who may, because of their particular socio-economic characteristics, be disproportionately affected by any national energy-efficiency standard level. This chapter of the 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 L CC 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

## 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 t he 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

## 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 e xceeded 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 r epresentative 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

## Table 11.3.1 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 1 Trial Standard Level

Efficiency (%) Transformers w ith 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 r epresentative 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 w ith 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 r epresentative 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.

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## Table 11.3.3 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 3 Trial Standard Level

Efficiency (%) Transformers w ith 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 r epresentative 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 w ith 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 r epresentative 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.

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## Table 11.3.5 Municipal Utilities Subgroup Life-Cycle Cost Results: Design Line 5 Trial Standard Level

Efficiency (%) Transformers w ith 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 r epresentative 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 w ith 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

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## 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 r epresentative 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 w ith 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 r epresentative 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.

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## Table 11.3.8 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 3 Trial Standard Level

Efficiency (%) Transformers w ith 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 r epresentative 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 w ith 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 r epresentative 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.

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## Table 11.3.10 Rural Cooperatives Subgroup Life-Cycle Cost Results: Design Line 5 Trial Standard Level

Efficiency (%) Transformers w ith 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 w ith 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

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## 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 w ith 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

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## 11.4 PAYBACK PERIOD RESULTS As described in more detail in section 8.6, a common technique for evaluating investment decisions is to perform a payback period (PBP) analysis. A more energy-efficient device will usually cost more to purchase than a device of standard energy efficiency, while the more efficient device will usually cost less to operate. Operating expenses decrease due to a reduction in energy use. The payback period is the time (usually expressed in years) it takes to recover the additional first cost of the efficiency device with its energy cost savings. Because 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 estima tes (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 r epresentative 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

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## 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 Unaf fected 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 r epresentative 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 Unaf fected 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.

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## 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 r epresentative 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 Unaf fected 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 r epresentative 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 Unaf fected 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

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## 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 r epresentative 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 Unaf fected 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 r epresentative 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.

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## Table 11.4.6 Rural Cooperatives Subgroup Payback Period Results: Design Line 1 Trial Standard Level

Mean Payback (Years) Transformers Unaf fected 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 r epresentative 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 Unaf fected 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 r epresentative 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.

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## Table 11.4.8 Rural Cooperatives Subgroup Payback Period Results: Design Line 3 Trial Standard Level

Mean Payback (Years) Transformers Unaf fected 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 r epresentative 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 Unaf fected 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 r epresentative 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.

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## Table 11.4.10 Rural Cooperatives Subgroup Payback Period Results: Design Line 5 Trial Standard Level

Mean Payback (Years) Transformers Unaf fected 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 r epresentative 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

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## 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 r epresentative 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

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## 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>

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