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CHAPTER 2. ANALYTICAL FRAMEWORK

TABLE OF CONTENTS

2.1 INTRODUCTION ............................................................................................... 2-1

2.2 BACKGROUND ................................................................................................. 2-2

2.2.1 Test Procedure ..................................................................................................... 2-4

2.2.1.1 Multiple/Dual-Voltage Windings......................................................... 2-4

2.2.1.2 Weighted-Average Losses from Multiple Loading Points................... 2-5

2.2.1.3 Other Aspects of the Test Procedure .................................................... 2-6

2.3 SCOPE OF COVERAGE .................................................................................... 2-6

2.4 MARKET AND TECHNOLOGY ASSESSMENT............................................ 2-7

2.4.1 Equipment Classes............................................................................................... 2-7

2.4.1.1 Less-Flammable Liquid-Immersed Transformers................................ 2-8

2.4.2 Market Assessment .............................................................................................. 2-9

2.4.2.1 National Shipments Estimate................................................................ 2-9

2.4.2.2 Distribution and Sales Channels......................................................... 2-10

2.4.2.3 Total Owning Cost Evaluation ........................................................... 2-10

2.4.3 Technology Assessment..................................................................................... 2-11

2.4.3.1 Symmetric Core Designs.................................................................... 2-11

2.4.3.2 Core Deactivation Technology ........................................................... 2-13

2.5 SCREENING ANALYSIS ................................................................................ 2-15

2.5.1 Technology Options Screened Out .................................................................... 2-15

2.5.1.1 Nanotechnology Composites.............................................................. 2-16

2.6 ENGINEERING ANALYSIS............................................................................ 2-16

2.6.1 Representative Units.......................................................................................... 2-17

2.6.2 Scaling Methodology......................................................................................... 2-19

2.6.3 Design Option Combinations............................................................................. 2-20

2.6.4 Materials Prices.................................................................................................. 2-21

2.6.5 Markups............................................................................................................. 2-21

2.6.5.1 Markups for Prefabricated Amorphous Cores.................................... 2-22

2.6.5.2 Shipping Costs.................................................................................... 2-23

2.6.6 Additional Costs for Amorphous Designs in Large Kilo-Volt Ampere, MediumVoltage Dry-Type Design Lines........................................................................ 2-23

2.6.7 Other Regulatory Impacts on the Engineering Analysis.................................... 2-24

2.6.8 Baseline Efficiency and Candidate Standard Levels Analyzed......................... 2-24

2.7 ENERGY USE AND END-USE LOAD CHARACTERIZATION ................. 2-25

2.7.1.1 Overview of the Hourly Load Model ................................................. 2-26

2.7.1.2 Overview of the Monthly Load Model............................................... 2-27

2.8 MARKUPS FOR EQUIPMENT PRICE DETERMINATION......................... 2-28

2.9 LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSES ...................... 2-29

2.9.1 Electricity Price Analysis................................................................................... 2-29

2.9.1.1 Hourly Marginal Electricity Price Model ........................................... 2-30

2.9.1.2 Monthly Marginal Electricity Price Model......................................... 2-30

2.9.2 Transformer Service Lifetime............................................................................ 2-30
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2.9.3 Maintenance Costs............................................................................................. 2-31

2.9.4 Emerging Technology Scenarios....................................................................... 2-31

2.9.4.1 Symmetric Core Transformers............................................................ 2-31

2.9.4.2 Core Deactivation Technology ........................................................... 2-31

2.10 SHIPMENTS ANALYSIS................................................................................. 2-31

2.10.1 Inputs to Shipments Analysis............................................................................. 2-32

2.10.1.1 Shipments Data ................................................................................... 2-32

2.10.2 Shipments Forecast............................................................................................ 2-33

2.10.2.1 Efficiency Distribution and Efficiency Trend .................................... 2-33

2.11 NATIONAL IMPACT ANALYSIS.................................................................. 2-34

2.12 LIFE-CYCLE COST SUBGROUP ANALYSIS .............................................. 2-34

2.12.1 Proposed Subgroups........................................................................................... 2-35

2.12.1.1 Municipal Utilities.............................................................................. 2-35

2.12.1.2 Rural Cooperatives ............................................................................. 2-35

2.12.1.3 Vault Transformers............................................................................. 2-36

2.12.2 Consumer Participation...................................................................................... 2-36

2.13 PRELIMINARY MANUFACTURER IMPACT ANALYSIS ......................... 2-36

2.13.1 Sources of Information for the Manufacturer Impact Analysis......................... 2-37

2.13.2 Industry Cash-Flow Analysis............................................................................. 2-37

2.13.3 Manufacturer Subgroup Analysis...................................................................... 2-37

2.13.4 Competitive Impacts Assessment ...................................................................... 2-38

2.13.5 Cumulative Regulatory Burden ......................................................................... 2-38

2.13.6 Preliminary Results for the Manufacturer Impact Analysis .............................. 2-38

2.13.7 Core Steel Availability....................................................................................... 2-38

2.13.8 Equipment Conversion Costs............................................................................. 2-39

2.13.9 Intellectual Property........................................................................................... 2-39

2.14 UTILITY IMPACT ANALYSIS....................................................................... 2-40

2.15 EMPLOYMENT IMPACT ANALYSIS........................................................... 2-40

2.16 ENVIRONMENTAL ASSESSMENT .............................................................. 2-40

2.16.1 Carbon Dioxide.................................................................................................. 2-41

2.16.2 Sulfur Dioxide.................................................................................................... 2-41

2.16.3 Nitrogen Oxides................................................................................................. 2-42

2.16.4 Mercury.............................................................................................................. 2-42

2.16.5 Particulate Matter............................................................................................... 2-42

2.17 MONETIZATION OF EMISSIONS REDUCTION BENEFITS..................... 2-43

2.18 REGULATORY IMPACT ANALYSIS............................................................ 2-44

LIST OF TABLES

Table 2.4.1 Distribution Transformer Equipment Classes..............................................2-8

Table 2.4.2 National Distribution Transformer Shipment Estimates for 2009.............2-10

Table 2.4.3 Options and Impacts of Increasing Transformer Efficiency......................2-11

Table 2.4.4 Symmetric Core Design Adjustments........................................................2-13

Table 2.5.1 Design Options Screened Out of the Analysis...........................................2-16

Table 2.6.1 Engineering Design Lines and Representative Units for Analysis............2-18
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LIST OF FIGURES

Figure 2.6.1 Method of Cost Accounting for Distribution Transformers Rulemaking 2-22

Figure 2.7.1 Load versus Marginal Price for Electricity Market Module Region: 

Southeastern Electric Reliability Council......................................................................2-27
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CHAPTER 2. ANALYTICAL FRAMEWORK

2.1 INTRODUCTION

This chapter provides a description of the general analytic framework the U.S. 

Department of Energy (DOE or the Department) is using to develop amended energy 

conservation standards for distribution transformers. The chapter includes a description of the 

methodology, the analytical tools, and relationships among the various analyses that are part of 

this rulemaking. In addition, chapter 2 provides an overview of any changes in the analysis 

between this rulemaking and DOE’s previous rulemaking on distribution transformers. Finally, 

chapter 2 provides citations and cross-references to other chapters presented in this preliminary 

technical support document (TSD) that address DOE’s analytical approach, inputs, and findings.

The analyses presented in this preliminary TSD include:

a market and technology assessment to characterize the distribution transformer market 

and review techniques and approaches used to produce more efficient transformers;

a screening analysis to identify design options that improve distribution transformer 

efficiency and to determine which ones DOE should evaluate and which it should screen 

out;

an engineering analysis to estimate the relationship between the manufacturer’s selling 

price (MSP) of a transformer and its efficiency level;

an energy use and end-use load characterization to generate energy use estimates and 

end-use load profiles of distribution transformers;

a markup process to convert manufacturer selling prices to customer installed prices; 

a life-cycle cost (LCC) analysis to calculate, at the customer level, the discounted savings 

in operating costs throughout the estimated average life of the distribution transformer, 

compared to any increase in the installed costs likely to result directly from the 

imposition of the amended standard;

a payback period (PBP) analysis to calculate the amount of time it takes customers to 

recover the assumed higher purchase expense of more-efficient equipment through lower 

operating costs; 

a shipments analysis to estimate shipments of distribution transformers over the time 

period examined in the analysis; and
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a national impact analysis (NIA) to assess the aggregate national impacts of consumer 

payback, net present value (NPV) of total customer LCC, national energy savings (NES), 

and national employment; and

a preliminary manufacturer impact analysis (MIA) to assess the potential impacts of 

amended energy conservation standards on manufacturers, such as impacts on capital 

conversion expenditures, marketing costs, shipments, and research and development 

costs.

The analyses DOE will perform in the subsequent Notice of Proposed Rulemaking 

(NOPR) stage include the following:

an LCC subgroup analysis to evaluate variations in customer characteristics that 

might cause a standard to affect particular customer sub-populations, such as lowincome households, differently from the overall population;

a manufacturer impact analysis to estimate the financial impact of standards on 

manufacturers and to calculate impacts on competition, employment, and 

manufacturing capacity;

a utility impact analysis to estimate the effects of proposed standards on electric, gas, 

or oil utilities;

an employment impact analysis to assess the aggregate impacts on national 

employment;

an environmental impact assessment to provide estimates of the effects of amended 

energy conservation standards on three pollutants—sulfur dioxide (SO2), nitrogen 

oxides (NOX), and mercury (Hg)—as well as carbon emissions; and

a regulatory impact analysis to present major alternatives to proposed amended 

energy conservation standards that could achieve substantially the same regulatory 

goal at a lower cost.

In addition, DOE will revise the analyses it has performed in the preliminary stage based 

on comments and new information received.

2.2 BACKGROUND

Title III of the Energy Policy and Conservation Act (EPCA) of 1975, Pub. L. No. 94-163, 

(42 United States Code (U.S.C.) 6291 et seq.) established an energy conservation program for 

major household appliances and industrial and commercial equipment. More specifically, part C

of Title III (42 U.S.C. 6291-6309) establishes the ―Energy Conservation Program for Certain 

Industrial Equipment,‖ a program covering the distribution transformers that are the focus of this 

document. EPCA requires DOE to promulgate energy conservation standards that achieve the 
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maximum improvement in energy efficiency that DOE determines is both technologically 

feasible and economically justified. 42 U.S.C. 6295(o)(2)(A)

DOE published a final rule in October 2007 that created energy conservation standards 

for liquid-immersed and medium-voltage dry-type (MVDT) distribution transformers. 10 CFR 

431.196(b)-(c); 72 FR 58190 (October 12, 2007) (the 2007 final rule) During the course of that 

rulemaking, the Energy Policy Act of 2005 (EPACT 2005), Pub. L. No. 109–58, amended EPCA 

to set standards for low-voltage dry-type (LVDT) distribution transformers. (42 U.S.C. 6295(y)) 

Consequently, DOE removed these transformers from the scope of the rulemaking. 72 FR at 

58191. 

After the publication of the 2007 final rule, certain parties filed petitions for review in the 

United States Courts of Appeals for the Second and Ninth Circuits, challenging the final rule, 

and several additional parties were permitted to intervene in support of these petitions. (All of 

these parties are referred to below collectively as ―petitioners.‖) The petitioners alleged that, in 

developing its energy conservation standards for distribution transformers, DOE did not comply 

with certain applicable provisions of EPCA and of the National Environmental Policy Act of 

1969 (NEPA), 42 U.S.C. 4321-4370f. DOE and the petitioners subsequently entered into a 

settlement agreement on July 10, 2009, to resolve the appeals. The settlement agreement outlined 

an expedited timeline for DOE to determine whether to amend the energy conservation standards 

for liquid-immersed and MVDT distribution transformers. Under the settlement agreement, DOE 

must publish by October 1, 2011, either a determination that the standards for these distribution 

transformers do not need to be amended or a notice of proposed rulemaking (NOPR) that 

includes any proposed amended standards, and that meets all applicable requirements of EPCA 

and NEPA. If DOE finds that amended standards are warranted, DOE must publish a final rule 

containing such amended standards by October 1, 2012. This document is DOE’s first step in

satisfying the requirements of the settlement agreement.

DOE is initiating this rulemaking at the preliminary analysis stage rather than the 

framework document stage. In considering new or amended standards for a given product or type 

of equipment, DOE’s current practice generally is to publish a framework document as the first 

step in the rulemaking process, and to subsequently issue a preliminary technical support 

document (TSD) that contains DOE’s preliminary analyses as to potential standards. The 

framework document generally advises interested parties of the analytical methods, data sources, 

and key assumptions DOE plans to use in considering the adoption of standards for the product 

or type of equipment. Typically, the document does not contain any analysis of the data. 

However, because the previous rulemaking to develop standards for distribution transformers 

was completed relatively recently, DOE has a set of methodologies, data sources and 

assumptions that have recently been vetted and revised according to public comments and that 

the Department can use to perform the analyses needed for this rulemaking. DOE will conduct 

the analyses referenced by the petitioners according to standard practices for energy conservation 

standard rulemakings. Therefore, DOE is initiating this rulemaking at the preliminary analysis 

stage and has prepared a preliminary TSD on which it is requesting comment.

At present, DOE plans to examine in this rulemaking amended standards for LVDT

distribution transformers, as well as amended standards for liquid-immersed and MVDT
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transformers. DOE is not required to consider LVDT distribution transformers as part of the 

settlement agreement. As such, DOE may subsequently opt to conduct a separate rulemaking for 

LVDT transformers with a different timeline. However, the preliminary analysis considers 

LVDT distribution transformers along with liquid-immersed and MVDT distribution 

transformers.

2.2.1 Test Procedure

On April 27, 2006, DOE codified a test procedure final rule for distribution transformers 

in appendix A to subpart K of Title 10 of the Code of Federal Regulations, Part 431 (10 CFR 

Part 431), ―Uniform Test Method for Measuring the Energy Consumption of Distribution 

Transformers.‖ 71 FR 24972 The test procedure outlined how manufacturers must test their 

distribution transformers to certify to DOE that their equipment complies with energy 

conservation standards and to quantify the efficiency of their equipment. Also, these test 

procedures must be used whenever testing is required in an enforcement action to determine 

whether covered equipment complies with efficiency standards. 

While the current rulemaking is specifically considering revisions to the energy 

conservation standards for distribution transformers, DOE also intends to review the current test 

procedure. DOE must amend each test procedure within seven years of its original publication. 

42 U.S.C. 6314(a)(1) This requirement took effect with the Energy Independence and Security 

Act 2007 (EISA), so the distribution transformer test procedure must be amended by 2014.

Therefore, DOE seeks comment on its current test procedure for distribution transformers. DOE 

received some feedback on the test procedure during its preliminary interviews with 

manufacturers, in particular relevant to the issue of multiple/dual-voltage windings.

2.2.1.1 Multiple/Dual-Voltage Windings

In the distribution transformer test procedure published in 2006, DOE stated that the 

manufacturer had to determine the basic model’s efficiency either at the voltage at which the 

highest losses occur or at each voltage at which the transformer is rated to operate. 71 FR 24985 

(April 27, 2006). This provision addressed the case of transformers with windings that could be 

reconfigured to input or output at different voltages. In most cases, operating voltages for which 

windings are configured in parallel are associated with lowered efficiency.

DOE is aware that this provision has had unintended consequences for manufacturers. 

Through manufacturer interviews, DOE has learned that this provision may have effectively

raised the standard levels for equipment classes with dual- or multiple-voltage transformers. The 

analysis from the previous rulemaking and the current rulemaking presumes the windings are

connected in series, but the testing requirements demand compliance with the standard in the 

parallel configuration, which is oftentimes less efficient. Additionally, the requirement to 

measure losses at the voltage with the highest losses has potentially increased testing burden for 

manufacturers that do not rely on alternate efficiency determination methods (AEDMs) for 

compliance testing. This is because the highest losses will ordinarily occur with paralleled 

windings. However, Institute of Electrical and Electronics Engineers (IEEE) requirements 

stipulate that transformers be shipped to customers with windings in series, and so manufacturers 

are obligated to reconfigure the windings after testing.
2-5

DOE proposes to eliminate the requirement for manufacturers to test in the least efficient 

secondary configuration, instead allowing manufacturers to meet the efficiency standard in any 

secondary configuration. This proposed change is based on several factors, in addition to the 

reduced testing burden discussed above. First, DOE understands that less than one percent of 

transformers are operated with their secondary windings in parallel, and furthermore, that they 

are often switched back into series with grid updates. Second, DOE believes that the differential 

efficiency between parallel and series operation is relatively small. It varies by model, but 

typically represents a very small percent of load losses. Finally, DOE believes that the 

efficiencies of parallel and series configured secondary windings will tend to increase or 

decrease together. In other words, many of the steps a manufacturer would take to increase the 

efficiency of one configuration would also benefit the other.

DOE understands that dual-voltage and multiple-voltage distribution transformers with 

reconfigurable secondaries are most commonly employed in low kVA, single-phase, liquidimmersed, pole-mounted units. Therefore, DOE could apply the exemption from testing in the 

configuration with the highest losses to that subset of transformers. DOE seeks comment on its 

proposal to change the testing requirement to allow compliance testing in any secondary 

configuration. Additionally, DOE seeks comment on whether the proposed revision should apply 

to all covered distribution transformers or a subset of transformers. DOE welcomes the 

submission of any data that would support a conclusion.

DOE understands that some transformers are also built with reconfigurable primary 

windings, but that the different primary windings oftentimes exhibit larger differences in 

efficiency than the efficiency differences between secondary windings. For example, a primary 

of 2400 x 7620 V involves an uneven number of winding sections, thereby resulting in a 

significant difference in efficiency from one configuration to the other. For this reason, DOE 

proposes to maintain the requirement that amended standards must be met at the least efficient 

primary configuration. 

Finally, DOE understands that different winding configurations might have different 

basic impulse level (BIL) ratings, such as for a primary winding of 7200 x 14400 V where the 

7200 V is at 95 kV BIL and the 14400 V is at 125 kV. To remove any ambiguity regarding 

which BIL rating should be used to meet the amended standard, DOE proposes that the lowest 

BIL for which a given configuration is rated should be used to show compliance with the 

standard. DOE asks for comment on this proposal concerning the appropriate BIL to use for 

dual/multiple-voltage distribution transformer compliance.

2.2.1.2 Weighted-Average Losses from Multiple Loading Points

DOE understands that distribution transformers experience varying levels of efficiency 

depending on the load applied. This loading varies throughout the course of operation, and also 

varies between the various end-use applications for each distribution transformer. As such, the 

current test procedure specifies a reference load factor equal to the root mean square (RMS) 

loading experienced across all transformers of a particular type. LVDT transformers are 

currently tested with a 35 percent load, while liquid-immersed and MVDT transformers are 

tested at 50 percent load. These requirements allow a consistent benchmark across all 
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transformers of a single type, and reflect the losses and efficiency at a loading consistent with the 

RMS loading experienced in service.

Certain technologies enable distribution transformers to experience lower losses at low 

loading points compared with traditional designs. An example is core deactivation technology, 

which is described further in section 2.4.3.2. This technology switches a system of transformer 

cores on and off in response to load demands, which enables energy savings at lower load factors 

compared to traditional transformer designs. The current test procedure, specifying a single load 

factor, would not capture the energy savings benefit of this technology.

DOE proposes allowing a weighted-average of losses from multiple loading points in 

determining the efficiency of technologies such as core deactivation technology. By taking a 

weighted-average of multiple load factors, the test procedure would better represent the energy 

savings potential of these technologies. The weighting applied to each load factor could be 

designated such that the weighted-average losses equal the same losses as measured at the 

current test procedure loading for traditional transformer designs. For example, DOE believes the 

following weighting would yield total losses identical to the total losses at 35 percent loading for 

traditional LVDT transformer designs: 0.31 at 0 percent, 0.22 at 15 percent, 0.20 at 35 percent, 

0.18 at 50 percent, and 0.09 at 75 percent. While this weighting would not affect the losses of 

traditional transformer designs, it would better represent the losses of a core deactivation system 

that experiences greater efficiencies at lower loading points.

DOE seeks comment on the proposal to designate a weighted-average loss calculation 

using various loadings to capture the energy savings potential of technologies that do not follow 

the ―loading vs. losses‖ relationship evident in traditional transformer designs. DOE welcomes 

comment on the appropriate weightings to use for the different load factors.

2.2.1.3 Other Aspects of the Test Procedure

During preliminary manufacturer interviews, DOE received feedback on several aspects 

of the current test procedure for distribution transformers. Topics covered included reference 

load factors, reconfigurable secondaries, and harmonization with the IEEE test procedure. DOE 

welcomes comment on all aspects of the current test procedure for distribution transformers.

2.3 SCOPE OF COVERAGE

This standards rulemaking concerns all distribution transformers, including liquidimmersed, LVDT, and MVDT distribution transformers. The definition of a distribution 

transformer was presented in EPACT 2005, and then further refined by DOE when it was 

codified in Title 10 of the Code of Federal Regulations, Part 431 (10 CFR Part 431) on April 27, 

2006, 71 FR 24972, 10 CFR 431.192, as follows:

Distribution transformer means a transformer that -

(1) Has an input voltage of 34.5 kV or less;

(2) Has an output voltage of 600 V or less;

(3) Is rated for operation at a frequency of 60 Hz; and
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(4) Has a capacity of 10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 

2500 kVA for dry-type units; but

(5) The term ―distribution transformer‖ does not include a transformer that is an–

(i) Autotransformer;

(ii) Drive (isolation) transformer;

(iii) Grounding transformer;

(iv) Machine-tool (control) transformer;

(v) Nonventilated transformer;

(vi) Rectifier transformer;

(vii) Regulating transformer;

(viii) Sealed transformer;

(ix) Special-impedance transformer;

(x) Testing transformer;

(xi) Transformer with tap range of 20 percent or more;

(xii) Uninterruptible power supply transformer; or

(xiii) Welding transformer.

Further detail on the definition of each of these terms can be found in chapter 3.

2.4 MARKET AND TECHNOLOGY ASSESSMENT

The market and technology assessment (see chapter 3 of the preliminary TSD) 

characterizes the distribution transformer markets and existing technology options for making a 

transformer more efficient. When DOE begins an energy conservation standards rulemaking, it 

develops information that provides an overall picture of the market for the equipment considered, 

including the nature of the equipment, market characteristics, and industry structure. This 

activity consists of both quantitative and qualitative efforts, based primarily on publicly available 

information.

The discussion below summarizes the analytical approach and key issues highlighted 

during DOE’s preliminary interviews with manufacturers in 2010. A more detailed discussion on 

DOE’s approach can be found in the market and technology assessment (chapter 3 of the 

preliminary TSD).

2.4.1 Equipment Classes

DOE divided the covered distribution transformers into groups called equipment classes. 

DOE divided transformers into equipment classes using the following criteria: (a) the type of 

energy used, (b) capacity, and (c) performance related features that affect customer utility or 

efficiency. Different efficiency standards apply to different equipment classes. DOE developed 

its equipment classes using information obtained from manufacturers, trade associations, and 

other interested parties. 

The equipment classes for this rulemaking are the same as the equipment classes DOE 

examined for its previous rulemaking on distribution transformers. Table 2.4.1 presents the 

equipment classes.
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Table 2.4.1 Distribution Transformer Equipment Classes

EC # Insulation Voltage Phase BIL Rating kVA Range

1 Liquid-Immersed Medium Single - 10-833 kVA

2 Liquid-Immersed Medium Three - 15-2500 kVA

3 Dry-Type Low Single - 15-333 kVA

4 Dry-Type Low Three - 15-1000 kVA

5 Dry-Type Medium Single 20-45kV BIL 15-833 kVA

6 Dry-Type Medium Three 20-45kV BIL 15-2500 kVA

7 Dry-Type Medium Single 46-95kV BIL 15-833 kVA

8 Dry-Type Medium Three 46-95kV BIL 15-2500 kVA

9 Dry-Type Medium Single ≥ 96kV BIL 75-833 kVA

10 Dry-Type Medium Three ≥ 96kV BIL 225-2500 kVA

2.4.1.1 Less-Flammable Liquid-Immersed Transformers

For the 2007 final rule, DOE solicited comment on how it should treat distribution 

transformers filled with an insulating fluid of higher flash point than that of traditional mineral 

oil. 71 FR 44369 (August 4, 2006). Known as ―less-flammable, liquid-immersed‖ (LFLI)

transformers, these units are marketed to some applications where a fire would be especially 

costly, such as indoor applications traditionally served by the dry-type market. 

During preliminary interviews with manufacturers, DOE was informed that LFLI 

transformers might offer the same utility as a dry-type transformer, since they were unlikely to 

catch fire. Furthermore, DOE heard that LFLI transformers could have an efficiency 

disadvantage relative to traditional liquid-immersed transformers because their more viscous 

insulating fluid required more internal ducting to properly circulate.

In that 2007 rulemaking, DOE determined that LFLI transformers should be considered 

in the same equipment class as traditional liquid-immersed transformers. DOE concluded that the 

design of a transformer (i.e., dry-type or liquid-immersed) was a performance-related feature that 

affects the energy efficiency of the equipment and, therefore, dry-type and liquid-immersed 

should be analyzed separately. 72 FR 58202 (October 12, 2007). Furthermore, DOE found that 

LFLI transformers could meet the same efficiency levels as traditional liquid-immersed units. As 

a result, DOE did not separately analyze LFLI transformers, but relied on the analysis for the 

mineral oil liquid-immersed transformers. 72 FR 58202 (October 12, 2007).

In the current rulemaking, DOE revisited the issue in light of additional research on LFLI 

transformers and conversations with manufacturers and industry experts. DOE first considered 

whether LFLI transformers offered the same utility as dry-type equipment, and came to the same 

conclusion as in the last rulemaking. While LFLI transformers can be used in some applications 

that historically use dry-type units, there are applications that cannot tolerate a leak or fire. In 

these applications, customers assign higher utility to a dry-type transformer. Since LFLI

transformers can achieve higher efficiencies than comparable dry-type units, including both 

types in one equipment class may result in standard levels that dry-type units are unable to meet, 

either cost-effectively or at all. Therefore, DOE decided not to analyze LFLI transformers in the 

same equipment classes as dry-type distribution transformers.
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Similarly, DOE revisited the issue of whether or not LFLI transformers should be 

analyzed separately from traditional liquid-immersed units. DOE concluded, once again, that 

LFLI transformers could achieve any efficiency level that mineral oil units could achieve. 

Although their insulating fluids are slightly more viscous, this disadvantage has little efficiency 

impact, and diminishes as efficiency increases and heat dissipation requirements decline. 

Furthermore, at least one manufacturer suggested that LFLI transformers might be capable of 

higher efficiencies than mineral oil units since their higher temperature tolerance may allow the 

unit to be downsized and run hotter than mineral oil units. For these reasons, LFLI transformers

would not be disproportionately affected by standards set in the liquid-immersed equipment 

classes based on mineral oil units. Therefore, DOE is not considering LFLI in a separate 

equipment class.

2.4.2 Market Assessment

 The market assessment examined manufacturers, trade associations, and the quantities 

and types of equipment sold and offered for sale. Issues addressed in this market assessment 

included: (1) national transformer shipments; (2) identification of the largest players in the 

transformer industry; (3) existing non-regulatory efficiency improvement initiatives; (4) 

developments around standards in States and neighboring countries; and (5) trends in equipment 

characteristics and retail markets. The information collected served as resource material that 

DOE used throughout the rulemaking. Detailed information can be found in chapter 3 of the 

preliminary TSD.

2.4.2.1 National Shipments Estimate

DOE estimated the annual transformer shipments to prepare an estimate of the national 

impact of energy conservation standards for distribution transformers. Unit shipments were 

calculated for each kVA rating within each equipment class. The foundation for DOE’s shipment 

estimate came from data provided by the National Electrical Manufacturers Association 

(NEMA). This data represented only a portion of the total market, however, so DOE contracted a 

company with considerable knowledge of the U.S. transformer industry to develop a complete 

picture of the industry shipments. The contractor used the NEMA data, its own knowledge of the 

market, and a limited number of consultative calls to compile a national estimate of shipments 

for liquid-immersed, LVDT, and MVDT transformers.

In general, the shipment data collected for 2009 represents a contraction in the 

distribution transformer market. This contraction results from the global economic downturn 

experienced during 2009, which lead to a reduction in new residential, commercial, and 

industrial development. This reduction in development decreased demand for distribution 

transformers. Table 2.4.2 shows a summary of the shipment data collected for each equipment 

class analyzed. Additional detail can be found in chapter 3 of the preliminary TSD.
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Table 2.4.2 National Distribution Transformer Shipment Estimates for 2009

Distribution Transformer Equipment Class Units 

Shipped

MVA Capacity 

Shipped

Shipment Value 

(2009 US$million)

Liquid-immersed, medium-voltage, single-phase 683,726 21,994 714.8

Liquid-immersed, medium-voltage, three-phase 49,739 32,266 786.0

Dry-type, low-voltage, single-phase 17,740 647 22.0

Dry-type, low-voltage, three-phase 206,929 15,778 394.4

Dry-type, medium-voltage, single-phase, 20-45 kV BIL 709 23 0.7

Dry-type, medium-voltage, three-phase, 20-45 kV BIL 522 257 6.2

Dry-type, medium-voltage, single-phase, 46-95 kV BIL 546 23 0.8

Dry-type, medium-voltage, three-phase, 46-95 kV BIL 2,074 3,655 98.7

Dry-type, medium-voltage, single-phase, ≥ 96 kV BIL 202 9 0.3

Dry-type, medium-voltage, three-phase, ≥ 96 kV BIL 1,286 2,206 66.2

Total 963,473 76,858 2,090.1

2.4.2.2 Distribution and Sales Channels

The market delivery channel for distribution transformers varies for different types of 

customers. Electric utilities generally purchase transformers directly from manufacturers. For 

these purchases, the utility provides a specification of the value it places on future core and coil 

losses over the life of the transformer. These values are used to generate an optimized 

transformer design with the lowest total owning cost for the utility. This market dynamic leads 

manufacturers to develop many custom designs.

The delivery channel for commercial and industrial customers can be complex, working 

through intermediaries such as stocking distributors and electrical contractors. This is because 

these customers typically purchase smaller quantities of transformers. Some larger industrial 

customers buy transformers directly from distributors or manufacturers, and similarly, many 

original equipment manufacturers (OEMs) work directly with manufacturers.

2.4.2.3 Total Owning Cost Evaluation

The total owning cost (TOC) evaluation is a formula that incorporates core and winding 

losses into the purchase decision for a distribution transformer. Following the energy price 

shocks of the 1970s, many transformer customers (such as utilities) began evaluating distribution 

transformer purchase decisions using a TOC evaluation. The TOC consists of the quoted 

transformer price and energy losses in the core and winding over the anticipated life of the unit.

Expressed as a formula,

TOC = (NL A) + (LL B) + Price Eq. 2.4.1

where:

TOC = total owning cost ($),

NL = no-load loss (Watts),

A = equivalent first-cost of no-load losses ($/Watt),
2-11

LL = load loss at the transformer’s rated load (Watts),

B = equivalent first-cost of load losses ($/Watt), and 

Price = bid price (retail price)($).

The capitalized cost per watt of no-load and load losses, the A and B factors, vary from 

one customer to another. Customers that use A and B factors compare two or more proposals 

from various manufacturers and select the one that offers them the lowest total owning cost (i.e., 

the lowest combination of first cost and operating cost over the life of the transformer). 

Additional detail can be found in chapter 3 of the preliminary TSD.

2.4.3 Technology Assessment

The technology assessment provides information about existing technology options and 

designs to construct more energy-efficient distribution transformers. There are two main types of 

losses in transformers: no-load (core) losses and load (winding) losses. Measures taken to reduce 

one type of loss typically increase the other type of losses. Some examples of design options to 

improve efficiency include: (1) higher-grade electrical core steels, (2) use of different conductor 

types and materials, and (3) adjustments to core and coil configurations.

In consultation with interested parties, DOE identified several technology options and 

designs for consideration. These technology options are presented in Table 2.4.3. Further detail 

on these technology options can be found in chapter 3 of the preliminary TSD.

Table 2.4.3 Options and Impacts of Increasing Transformer Efficiency

No-load 

losses

Load

losses

Cost 

impact

To decrease no-load losses

Use lower-loss core materials Lower No change* Higher

Decrease flux density by:

(a) Increasing core cross-sectional area (CSA)

(b) Decreasing volts per turn

Lower

Lower

Higher

Higher

Higher

Higher

Decrease flux path length by decreasing conductor CSA Lower Higher Lower

Use 120 ̊ symmetry in three-phase cores** Lower No change TBD

To decrease load losses

Use lower-loss conductor material No change Lower Higher

Decrease current density by increasing conductor CSA Higher Lower Higher

Decrease current path length by:

(a) Decreasing core CSA

(b) Increasing volts per turn

Higher

Higher

Lower

Lower

Lower

Lower

* Amorphous core materials would result in higher load losses because flux density drops, requiring a larger core 

volume.

** Sometimes referred to as a ―hexa-transformer‖ design.

2.4.3.1 Symmetric Core Designs

DOE understands that several companies worldwide are commercially producing threephase transformers with symmetric cores – those in which each leg of the transformer is 

identically connected to the other two. The symmetric core uses a continuously wound core with 

120 degree radial symmetry, resulting in a triangularly shaped core when viewed from above. In 
2-12

a traditional core, the center leg is magnetically distinguishable from the other two because it has 

a shorter average flux path to each. In a symmetric core, however, no leg is magnetically 

distinguishable from the other two.

One manufacturer of symmetric core transformers cited several advantages to the 

symmetric core. These include reduced weight, volume, no-load losses, noise, vibration, stray 

magnetic fields, inrush current, and power in the third harmonic. Thus far, DOE has only seen

limited cost and efficiency data for a few symmetric core units from testing done by 

manufacturers. DOE has not seen any designs for symmetric core units modeled in a software 

program.

Because of zero-sequence fluxes associated with wye-wye connected transformers, 

symmetric core designs are best suited to delta-delta or delta-wye connections. While traditional 

cores can circumvent the problem of zero-sequence fluxes by introducing a fourth or fifth 

unwound leg, core symmetry makes extra legs inherently impractical. Yet another way to 

mitigate zero-sequence fluxes comes in the form of a tertiary winding, which is delta-connected 

and has no external connections. This winding is dormant when the transformer’s load is 

balanced across its phases. Although symmetric core designs may, in theory, be made tolerant of 

zero-sequence fluxes by employing this method, this comes at extra cost and complexity. 

Using this tertiary winding, DOE believes that symmetric core designs can service nearly 

all distribution transformer applications in the United States. Most dry-type transformers have a 

delta connection and would not require a tertiary winding. Similarly, most liquid-immersed 

transformers serving the industrial sector have a delta connection. These market segments could 

use the symmetric core design without any modification for a tertiary winding. However, in the 

United States most utility-operated distribution transformers are wye-wye connected. These 

transformers would require the tertiary winding in a symmetric core design.

DOE understands that symmetric core designs are more challenging to manufacture and 

require specialized equipment that is currently uncommon in the industry. However, DOE did 

not find a reasonable basis to screen this technology option out of the analysis, and is aware of at 

least one manufacturer producing dry-type symmetric core designs commercially in the United 

States.

While DOE lacked the necessary data to perform a thorough engineering analysis of 

symmetric core designs, DOE used several assumptions to roughly estimate the cost-efficiency 

relationship of symmetric core designs. DOE adjusted its traditional core designs to simulate the 

cost and efficiency of a comparable symmetric core design. To do this, DOE reduced core losses 

and core weight while increasing labor costs to approximate the symmetric core designs. These 

adjustments were based on data received from manufacturers, published literature, and through 

conversations with manufacturers. Table 2.4.4 indicates the range of potential adjustments for 

each variable that DOE considered and the mean value used in the analysis. The simulated costefficiency relationships for symmetric core designs are presented in chapter 5, and the life-cycle 

cost savings are presented in chapter 8 of the preliminary TSD.
2-13

Table 2.4.4 Symmetric Core Design Adjustments

Range Core Losses (W) Core Weight (lbs) Labor Hours

[Percentage Changes]

Minimum -0.0 -12.0 +10.0

Mean -15.5 -17.5 +55.0

Maximum -25.0 -25.0 +100.0

DOE applied these adjustments to each of the traditional three-phase transformer designs 

to develop a cost-efficiency relationship for symmetric core technology. DOE did not model a 

tertiary winding for the wye-wye connected liquid-immersed design lines (DL). Based on its 

research, DOE believes that the losses associated with the tertiary winding may offset the 

benefits of the symmetric core design, and the tertiary winding will also add cost to the design. 

Instead, DOE modeled symmetric core designs for the three-phase, liquid-immersed design lines 

without a tertiary winding to examine the impact of symmetric core technology on the subgroup 

of applications that do not require the tertiary winding.

DOE seeks comment on symmetric core designs, their practicability to manufacture and 

install, and whether or not they offer potential for efficiency improvement. In particular, DOE 

seeks comment on any application types in which using a symmetric core design may be 

infeasible. DOE requests comment on the adjustments it used to estimate symmetric core costefficiency relationships, and welcomes any performance data generated from simulation or 

testing that demonstrate the performance of symmetric core designs.

2.4.3.2 Core Deactivation Technology

Core deactivation technology employs the concept that a system of smaller transformers 

can replace a single, larger transformer. For example, three transformers sized at 25 kVA and 

operated in parallel could replace a single 75 kVA transformer. 

Winding losses are proportionally smaller at lower load factors, but for any given current,

a smaller transformer will experience greater winding losses than will a larger transformer. As a 

result, those losses may be more than offset by the smaller transformer’s reduced core losses. As 

loading increases, winding losses become proportionally larger and eventually outweigh the 

power saved by using the smaller core. At that point, the control unit (which consumes little 

power itself) switches on an additional transformer, which reduces winding losses at the cost of 

additional core losses. The control unit knows how efficient each combination of transformers is 

for any given loading, and is constantly monitoring the unit’s power output so that it will use the 

optimal number of cores. In theory, there is no limit to the number of transformers that may be 

paralleled in this sort of system, but cost considerations would imply an optimal number.

DOE had the opportunity to speak with a company that is developing a core deactivation 

technology. Noting that many dry-type transformers are operated at very low loadings a large 

percentage of the time (e.g., a building at night), the company seeks to reduce core losses by 

replacing a single, traditional transformer with two or more smaller units that could be activated 

and deactivated in response to load demands. A special unit controls which transformers are 

activated and deactivated in real-time in response to the load demands.
2-14

As mentioned in section 2.2.1.2, core deactivation technology could save energy over a 

real world loading cycle, but those savings might not be represented in the current DOE test 

procedure. Presently, the test procedure specifies a single loading point of 50 percent for liquidimmersed and MVDT transformers, and 35 percent for LVDT. The real gain in efficiency for 

this technology is at loading points below the RMS loading specified in the test procedure, where 

some transformers in the system could be deactivated. At loadings where all transformers are 

activated, which may be the case at the test procedure loading, the combined core and coil losses 

of the system of transformers could exceed those of a single, larger transformer. This would 

result in a lower efficiency for the system of transformers compared to the single, larger 

transformer. Therefore, DOE proposes allowing a weighted-average loss calculation using 

various loadings to capture the energy savings potential of core deactivation technology.

For the preliminary analysis, DOE did not directly analyze core deactivation technology, 

though DOE believes it is possible to evaluate the technology using its existing transformer 

designs. To analyze this technology, DOE would consider core deactivation systems composed 

of three identical transformers, each with one-third the kVA size of the analyzed design lines. 

This creates a core deactivation system of the same total kVA size as the analyzed design lines. 

Each of these core deactivation systems could be evaluated under various loading scenarios to 

identify the energy savings potential at loadings below and above the RMS load factor. While it 

is possible to manufacture core deactivation systems using different designs for each component 

transformer, it requires additional design complexities. For example, using different component 

transformer designs necessitates a similar winding design to maintain the impedance across each 

transformer at each load factor. These complexities would not need to be considered in the 

analysis when analyzing three identical component transformer designs.

To examine each component transformer design, DOE could scale the engineering 

analysis of its existing design lines to simulate a transformer of one-third the kVA size. DOE 

would scale the losses, MSP, weight, and dimensions using the 0.75 scaling rule explained in 

section 2.6.2. The resulting designs could be analyzed as component transformers for the core 

deactivation system. DOE could then simulate a core deactivation system by combining three 

identical component transformers and considering the losses at each loading point for the 

following three scenarios: (1) all three component transformers are activated, (2) two component 

transformers are activated, and (3) only one component transformer is activated. Given this 

information, DOE could simulate the performance of a core deactivation system by evaluating 

the scenario with the least losses for a given load factor.

DOE understands that core deactivation technology is most easily implemented in LVDT

distribution transformer designs. Implementing core deactivation technology in medium-voltage 

distribution transformers is possible, but poses difficulties for switching the primary and 

secondary connections. DOE has not fully quantified these differences, but intends to examine 

core deactivation technology in more detail for all types of transformers during the analysis for 

the notice of proposed rulemaking. See chapter 5 of the preliminary TSD for further 

information.

DOE seeks comment on core deactivation technology. DOE requests input on any 

considerations necessary for analyzing core deactivation systems composed of different 
2-15

component transformers, or core deactivation systems for medium-voltage distribution 

transformers. DOE also seeks comment on the types of applications that might benefit from 

using the technology, and any other considerations relating the technology to the current test 

procedure. Finally, DOE seeks input on any intellectual property concerns related to employing 

core deactivation technology.

2.5 SCREENING ANALYSIS

After DOE identified the technologies that might improve the energy efficiency of 

distribution transformers, DOE conducted the screening analysis. The purpose of the screening 

analysis is to determine which options to consider further and which to screen out. DOE consults 

with industry, technical experts, and other interested parties in developing a list of design 

options. DOE then applies the following set of screening criteria to determine which design 

options are unsuitable for further consideration in the rulemaking (10 CFR Part 430, subpart C, 

appendix A at 4(a)(4) and 5(b)):

Technological Feasibility: DOE will consider only those technologies incorporated in 

commercial equipment or in working prototypes to be technologically feasible.

Practicability to Manufacture, Install, and Service: If mass production of a 

technology in commercial equipment and reliable installation and servicing of the 

technology could be achieved on the scale necessary to serve the relevant market at 

the time of the effective date of the standard, then DOE will consider that technology 

practicable to manufacture, install, and service.

Adverse Impacts on Equipment Utility or Equipment Availability: DOE will not 

further consider a technology if DOE determines it will have a significant adverse 

impact on the utility of the equipment to significant subgroups of customers. DOE 

will also not further consider a technology that will result in the unavailability of any 

covered equipment type with performance characteristics (including reliability), 

features, sizes, capacities, and volumes that are substantially the same as equipment 

generally available in the United States at the time.

Adverse Impacts on Health or Safety: DOE will not further consider a technology if 

DOE determines that the technology will have significant adverse impacts on health 

or safety.

For a complete discussion of the screening analysis, refer to chapter 4 of the preliminary 

TSD.

2.5.1 Technology Options Screened Out

DOE developed an initial list of efficiency enhancement design options from the 

technologies identified in the technology assessment. Then DOE reviewed the list to determine if 

the design options are practicable to manufacture, install, and service; would adversely affect 

equipment utility or equipment availability; or would have adverse impacts on health and safety. 
2-16

In the engineering analysis, DOE considered those efficiency enhancement design options that 

satisfied the four screening criteria; it did not consider those options that failed to satisfy one or 

more of the screening criteria. The design options screened out are summarized in Table 2.5.1.

Table 2.5.1 Design Options Screened Out of the Analysis

Design Option Excluded Eliminating Screening Criteria

Silver as a Conductor Material Practicability to manufacture, install, and service

High-Temperature Superconductors Technological feasibility; 

Practicability to manufacture, install, and service

Amorphous Core Material in Stacked Core 

Configuration

Technological feasibility; 

Practicability to manufacture, install, and service

Carbon Composite Materials for Heat Removal Technological feasibility

High-Temperature Insulating Material Technological feasibility

Solid-State (Power Electronics) Technology Technological feasibility;

Practicability to manufacture, install, and service

Nanotechnology Composites Technological feasibility

Chapter 4 of this preliminary TSD discusses each of these screened out design options in 

more detail, and also which design options DOE considered in the distribution transformer 

engineering analysis. The chapter also includes a list of emerging technologies that could impact 

future distribution transformer manufacturing costs. The design options screened out of this 

analysis are the same as the design options that were screened out during DOE’s previous 

rulemaking on distribution transformers, with the addition of nanotechnology composites.

2.5.1.1 Nanotechnology Composites

DOE understands that the nanotechnology field is actively researching ways to produce 

bulk material with desirable features on a molecular scale. Some of these materials may have 

high resistivity, high permeability, or other properties that make them attractive for use in 

electrical transformers. DOE knows of no current commercial efforts to employ these materials 

in distribution transformers and no prototype designs using this technology, but welcomes 

comment on such technology and its implications for the future of the industry.

2.6 ENGINEERING ANALYSIS

The engineering analysis (Chapter 5) develops cost-efficiency relationships for 

equipment types that are the subject of a rulemaking, estimating manufacturer costs of achieving 

increased efficiency levels. DOE uses manufacturing costs to determine retail prices in the LCC 

analysis, and also uses them in the MIA. The engineering analysis also determines the maximum 

technologically feasible energy efficiency level.

In general, the engineering analysis estimates the efficiency improvement potential of 

individual design options or combinations of design options that pass the four criteria in the 

screening analysis. DOE uses this cost-efficiency relationship, developed in the engineering 

analysis, in the LCC analysis.
2-17

As described in Chapter 1, DOE considered those distribution transformers that are 

designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy 

(Secretary) determines is technologically feasible and economically justified. (42 U.S.C. 

6295(o)(2)(A)) Therefore, an important role of the engineering analysis was to identify the 

maximum technologically feasible efficiency level. The maximum technologically feasible level 

is one that can be reached by adding efficiency improvements and/or design options, both 

commercially feasible and in prototypes, to the baseline units. DOE believes that the design 

options comprising the maximum technologically feasible level must have been physically 

demonstrated in at least a prototype form to be considered technologically feasible. 

In general, DOE can use three methodologies to generate the manufacturing costs needed 

for the engineering analysis. These methods are: 

1. the design-option approach – reporting the incremental costs of adding design options to 

a baseline model;

2. the efficiency-level approach – reporting relative costs of achieving improvements in 

energy efficiency; and

3. the reverse engineering or cost assessment approach – involving a "bottom up" 

manufacturing cost assessment based on a detailed bill of materials derived from 

transformer teardowns.

DOE’s analysis for the distribution transformers rulemaking is based on the designoption approach, in which design software is used to assess the cost-efficiency relationship 

between various design option combinations. This is the same approach that was taken in the 

previous rulemaking for distribution transformers.

2.6.1 Representative Units

The engineering analysis analyzed 13 key design lines that cover the range of equipment

classes within the distribution transformer market. Within each design line, DOE selected a 

representative unit to analyze in the engineering analysis. Table 2.6.1 outlines the design lines 

and representative units selected for each equipment class.
2-18

Table 2.6.1 Engineering Design Lines and Representative Units for Analysis

EC* DL Type of Distribution 

Transformer

kVA 

Range

Representative Unit for this

Engineering Design Line

1

1

Liquid-immersed, single-phase, 

rectangular tank 10–167 50 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

240/120V secondary, rectangular tank

2

Liquid-immersed, single-phase, 

round tank 10–167 25 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

120/240V secondary, round tank

3 Liquid-immersed, single-phase 250–833 500 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

277V secondary

2

4 Liquid-immersed, three-phase 15–500 150 kVA, 65 C, three-phase, 60Hz, 12470Y/7200V 

primary, 208Y/120V secondary

5 Liquid-immersed, three-phase 750–2500 1500 kVA, 65 C, three-phase, 60Hz, 

24940GrdY/14400V primary, 480Y/277V secondary

3 6

Dry-type, low-voltage, singlephase 15–333 25 kVA, 150 C, single-phase, 60Hz, 480V primary, 

120/240V secondary, 10kV BIL

4

7

Dry-type, low-voltage, threephase 15–150 75 kVA, 150 C, three-phase, 60Hz, 480V primary, 

208Y/120V secondary, 10kV BIL

8

Dry-type, low-voltage, threephase 225–1000 300 kVA, 150 C, three-phase, 60Hz, 480V Delta 

primary, 208Y/120V secondary, 10kV BIL

6

9

Dry-type, medium-voltage, 

three-phase, 20-45kV BIL 15–500 300 kVA, 150 C, three-phase, 60Hz, 4160V Delta 

primary, 480Y/277V secondary, 45kV BIL

10 Dry-type, medium-voltage, 

three-phase, 20-45kV BIL 750–2500 1500 kVA, 150 C, three-phase, 60Hz, 4160V primary, 

480Y/277V secondary, 45kV BIL

8

11 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL 15–500 300 kVA, 150 C, three-phase, 60Hz, 12470V primary, 

480Y/277V secondary, 95kV BIL

12 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL 750–2500 1500 kVA, 150 C, three-phase, 60Hz, 12470V 

primary, 480Y/277V secondary, 95kV BIL

10 13 Dry-type, medium-voltage, 

three-phase, 96-150kV BIL 225–2500 2000 kVA, 150 C, three-phase, 60Hz, 12470V 

primary, 480Y/277V secondary, 125kV BIL

* EC = Equipment Class.

DOE analyzed the same representative unit for each design line as it analyzed during the 

previous rulemaking on distribution transformers. These representative units were chosen 

because they are a high volume segment of the market for their respective design lines, and also 

provide a reasonable basis for scaling to the unanalyzed kVA ranges of the design line. During 

preliminary interviews with manufacturers, DOE received several comments on changes that 

could be made to the representative units.

Several manufacturers stated that the primary voltage for DL1 through DL3 should be 

changed. The currently proposed primary voltage is 14400V, but manufacturers recommended 

DOE consider 7200V, such as 12470GrdY/7200V, or even 19900V. Manufacturers pointed out 

that the 7200V unit has a higher shipment volume, and is thus more representative of the market. 

DOE understands that the 14400V primary is in the same insulation class as the 12470V primary, 

but that the 14400V primary requires more turns of conductor and may require more space and 

thus be a costlier unit. As such, the 14400V primary results in a more stringent analysis, while

the 12470V and 7200V would always be able to meet the same efficiency levels as the 14400V 

primary. As such, DOE proposes to leave the primary voltage for DL1 through DL3 as 14400V.
2-19

DOE welcomes comment on the representative units selected for the single-phase, liquidimmersed units in DL1 through DL3. Specifically, DOE seeks comment on its decision to use a 

14400V primary voltage for DL1 through DL3.

Some manufacturers also suggested that DOE change the primary voltage for the DL5 

representative unit from 24940GrdY/14400V to 12470 delta. This change was recommended 

because 12470 delta units have a higher shipment volume than 24940GrdY/14400V units for this 

DL. While most residential distribution transformers have a grounded wye primary, most 

industrial distribution transformers have a delta primary. DOE understands that units with a delta 

primary require full insulation on both ends of the winding and are fundamentally more costly 

than a comparable unit with a wye primary.

DOE welcomes comment on the representative unit selected for DL5, a 1500 kVA, threephase, liquid-immersed transformer. Specifically, DOE asks for comment on the appropriate 

primary voltage for analyzing this representative unit. 

Additionally, manufacturers of MVDT distribution transformers indicated that the 

primary voltage for the 2000 kVA representative unit for DL13 should be changed. DL13 

represents the 125 kV BIL insulation class. Currently, DOE has a primary voltage of 12470V for 

this representative unit, but manufacturers stated that a primary voltage of 24940V is correct for 

a 125 kV BIL unit. The representative unit must retain a BIL rating greater than 95 kV. This is 

because DOE uses this representative unit to scale results for the MVDT equipment classes 9 and 

10, which have a BIL greater than or equal to 96 kV.

DOE seeks comment on the representative unit selected for DL13, a 2000 kVA, threephase, MVDT transformer. DOE specifically would like comments on the most appropriate 

primary voltage for analyzing this representative unit.

Last, DOE received feedback on additional representative units that should be considered 

in its analysis. Manufacturers suggested many different alternatives for representative units. One 

example is a dual-secondary-voltage, liquid-immersed, 25 kVA, single-phase unit. This 

recommendation was made to address any efficiency discrepancies between DOE’s previous 

analysis and a dual-secondary-voltage transformer.

DOE welcomes comment on additional representative units or design lines that should be 

considered in its analysis. DOE welcomes comment on all aspects of its selected representative 

units and design lines.

2.6.2 Scaling Methodology

DOE performed detailed analysis on each representative unit and then extrapolated the 

results of its analysis from the unit studied to the other kVA ratings within that same engineering 

design line. DOE performed this extrapolation in the national impacts analysis (see Chapter 10 of 

the preliminary TSD). The technique it used to extrapolate the findings on the representative unit 

to the other kVA ratings within a design line is referred to as ―the 0.75 scaling rule.‖ This rule 

states that, for similarly designed transformers, costs of construction and losses scale to the ratio 

of kVA ratings raised to the 0.75 power. The relationship is valid where the optimum efficiency 
2-20

loading points of the two transformers being scaled are the same. DOE used the same 

methodology to scale its findings during the previous rulemaking on distribution transformers.

During preliminary interviews, manufacturers informed DOE that the application of this 

scaling rule during the previous rulemaking made it difficult to manufacture compliant 

transformers for certain kVA ranges. Specifically, DOE was told that MVDT distribution 

transformers at the lowest kVA values were difficult to manufacture according to the current 

energy conservation standard. The analysis for these units was based on a 300 kVA 

representative unit and then scaled down to a 15 kVA unit. Manufacturers indicated that the 

scaling relationship did not hold for these transformers because they typically use a different core 

construction from what DOE analyzed for the 300 kVA unit. The lower kVA units typically 

utilize a butt-lap construction technique because it can be difficult to miter designs for these 

smaller units as is done for the 300 kVA units.

DOE welcomes comment on the scaling approach used and whether an improved scaling 

methodology exists. DOE also welcomes comment on the extent of the impact that the previous 

scaled standard levels have had on the low kVA units for MVDT or for any other market 

segments.

2.6.3 Design Option Combinations

There are many different combinations of design options that could be considered for each 

representative unit DOE analyzes. While DOE cannot consider all the possible combinations of 

design options, DOE attempts to select design option combinations that are common in the 

industry while also spanning the range of possible efficiencies for a given DL. For each design 

option combination chosen, DOE evaluates 518 designs based on different A and B factor 

combinations. For the engineering analysis, DOE reused many of the design option combinations 

that were analyzed in the previous rulemaking for distribution transformers.

DOE considered a design option combination that uses an amorphous core for each of the 

dry-type design lines. DOE’s previous rulemaking did not consider amorphous designs for the 

dry-type design lines. Instead, DOE considered H-0 domain refined (H-0 DR) steel as the 

maximum-technologically feasible design. However, DOE is aware that amorphous designs are 

now used in dry-type distribution transformers. As such, DOE considered amorphous designs for 

each of the dry-type design lines in the preliminary analysis. DOE accounted for special cost 

considerations for the amorphous designs that are 1500 kVA or greater, as outlined in section 

2.6.6.

During preliminary interviews with manufacturers, DOE heard that it should consider 

additional design option combinations using aluminum for the primary conductor rather than 

copper. While manufacturers commented that copper is still used for the primary conductor in 

many distribution transformers, they noted that aluminum has become relatively more common. 

This is due to the relative prices of copper and aluminum. In recent years, copper has become 

more expensive relative to aluminum.

DOE also noted that certain design lines are lacking a design to bridge the efficiency 

values between the lowest efficiency amorphous designs and the next highest efficiency designs. 
2-21

Currently, DOE evaluates ZDMH and M2 core steel as the highest efficiency designs below 

amorphous for the liquid-immersed design lines. Similarly, DOE evaluates H-0 DR and M3 core 

steel as the highest efficiency designs below amorphous for dry-type design lines.

DOE seeks comment on the design option combinations selected for analyzing each 

design line. DOE would like comments on any additional design option combinations that should 

be considered in the analysis. In particular, DOE welcomes comment on any design option 

combinations that yield efficiency ratings greater than the domain refined steels used in DOE’s 

analysis. DOE considered ZDMH for liquid-immersed designs and H-0 DR for dry-type designs.

2.6.4 Materials Prices

DOE conducted the engineering analysis using materials prices over a five-year time 

period from 2006-2010, all in constant 2010$. In the previous rulemaking for distribution 

transformers, DOE considered a five-year average price for the reference case of the engineering 

analysis. DOE then considered sensitivities of the materials prices by selecting prices from a year 

with high prices and a year with low prices.

Based on feedback from manufacturer interviews conducted over the summer of 2010, 

DOE decided to use current (2010) materials prices in its analysis for the reference case 

materials price scenario. Manufacturers noted the difficulty in choosing a price that accurately 

projects future materials prices due to the recent variability in these prices. Manufacturers also 

commented that the previous five years had seen steep increases in materials prices through 

2008, after which prices declined as a result of the global economic recession. Further detail on 

these factors can be found in appendix 3A. Due to the variability in materials prices over this 

five-year timeframe, manufacturers do not believe a five-year average price would be the best 

indicator, and recommended using the current materials prices.

As such, DOE used the current 2010 price as its reference case materials price scenario. 

Similar to what was done in the previous rulemaking, DOE considered high and low materials

price sensitivities in its analysis. The low price sensitivity was based on materials prices from 

2006, while the high price sensitivity was based on materials prices from 2008.

DOE requests comment on its tentative decision to consider the current (2010) materials

prices as the reference case materials price rather than a five-year average price.

2.6.5 Markups

DOE derived the manufacturer’s selling price for each design in the engineering analysis 

by considering the full range of production costs and non-production costs. The full production 

cost is a combination of direct labor, direct materials, and overhead. The overhead contributing 

to full production cost includes indirect labor, indirect material, maintenance, depreciation, taxes, 

and insurance related to company assets. Non-production cost includes the cost of selling, 

general and administrative items (market research, advertising, sales representatives, logistics),

research and development (R&D), interest payments, warranty and risk provisions, shipping, and 

profit factor. Because profit factor is included in the non-production cost, the sum of production 

and non-production costs is an estimate of the manufacturer’s selling price (MSP). DOE utilized 
2-22

various markups to arrive at the total cost for each component of the distribution transformer. 

These markups are outlined in detail in chapter 5 of the preliminary TSD. Figure 2.6.1 presents 

the components of the MSP.

Figure 2.6.1 Method of Cost Accounting for Distribution Transformers Rulemaking

2.6.5.1 Markups for Prefabricated Amorphous Cores

For designs using an amorphous core, DOE assumed that a manufacturer would purchase 

a prefabricated amorphous core rather than purchasing amorphous ribbon and creating the core 

itself. This is consistent with how amorphous designs were modeled in the previous rulemaking 

on distribution transformers. Since DOE assumes that the manufacturer bought a finished core, 

DOE reduced its markup for scrap and handling factor from 2.5 percent to 1.5 percent. DOE also 

reduced components of the total labor hours for amorphous designs to account for the 

prefabricated core. These adjustments are consistent with how amorphous designs were treated 

in the previous rulemaking for distribution transformers.

DOE did not adjust the factory overhead markup for amorphous designs compared to the 

other designs. During preliminary interviews with manufacturers, DOE received mixed feedback 

on whether or not a prefabricated amorphous core would result in a lower factory overhead 

markup compared to designs where manufacturers produced the core. Since the factory overhead 

markup accounts for indirect production costs that are not easily tied to a particular design, it is 

applied consistently across all design types. DOE did not find that there was sufficient 

substantiation to conclude that manufacturers would apply a reduced overhead markup for a 

design with a prefabricated core. This approach is also consistent with the previous rulemaking 

for distribution transformers.

Full Cost of Product

Full Production Cost

Direct 

Labor

Direct 

Material Overhead

Indirect Labor

Indirect 

Material

Maintenance

Depreciation

Taxes

Insurance 

related to 

assets

Non-Production Cost

Selling, 

General 

& Admin.

Mkt. research

Advertising

Point of Sale 

promotion

Cust. service

Sales person 

salary + travel 

+ commission

Logistics

R & D

Costs 

associated with 

efforts to find 

new or 

improved 

products or 

production 

processes

Code 

Compliance

Modernization

Interest

Costs of 

borrowing 

funds

Warranty 

& Risk Shipping

Costs of 

freight for 

final delivery

Profit
2-23

DOE welcomes comment on its tentative decision to use the same factory overhead 

markup for designs using a prefabricated amorphous core as for designs where the manufacturer 

produces the core.

2.6.5.2 Shipping Costs

During its preliminary interviews with manufacturers, DOE was informed that 

manufacturers oftentimes pay shipping (freight) costs to the customer. Manufacturers indicated 

that they absorb the cost of shipping the units to the customer, and that they include these costs 

into their total cost structure when calculating profit markups. As such, manufacturers apply a 

profit markup to their shipping costs just like any other cost of their production process. 

Manufacturers indicated that these costs typically amount to anywhere from four to eight percent 

of revenue.

In the previous rulemaking for distribution transformers, DOE accounted for shipping 

costs exclusively in the LCC analysis. These costs were paid by the customer, and thus did not 

include a markup from the manufacturer based on its profit factor. In the preliminary analysis, 

DOE included shipping costs in the manufacturer’s cost structure, which is then marked up by a 

profit factor. These shipping costs account for shipping the units to the customer, who may then 

bear additional shipping costs to deliver the units to the final end-use location. As such, DOE 

accounts for the first leg of shipping costs in the engineering analysis and then any subsequent 

shipping costs in the LCC analysis. The shipping cost is estimated to be $0.22 per pound of the 

transformer’s total weight, and typically amounts to four to eight percent of the total 

manufacturer selling price. Additional detail on these shipping costs can be found in chapter 5 

and chapter 8 of the preliminary TSD.

DOE welcomes comment on its tentative decision to include shipping costs in the 

engineering analysis as a component of the manufacturer’s selling price. Specifically, DOE seeks 

comment on whether profit markups are applied to the shipping cost and if shipping costs are 

typically four to eight percent of total revenue for the sale of all sizes and types of distribution 

transformers. 

2.6.6 Additional Costs for Amorphous Designs in Large Kilo-Volt Ampere, MediumVoltage Dry-Type Design Lines

DOE accounted for additional labor and hardware costs in the amorphous designs for drytype design lines that are 1500 kVA or greater. The affected design lines are DLs 10, 12, and 13. 

Manufacturers and industry experts informed DOE that these large dry-type design lines would 

require special handling considerations for an amorphous core since the amorphous material is 

very thin and can be difficult to work with in such a large core. DOE increased the labor estimate 

for assembly, which includes all steps necessary to complete the core/coil assembly. DOE 

accounted for 6 hours of labor for all non-amorphous designs in these design lines, but increased 

the labor estimate by 10 hours, to 16 hours total for the amorphous designs.

Additionally, DOE accounted for hardware costs for the extra bracing that is necessary for 

dry-type amorphous designs of this size. The extra bracing is used to contain the coils and 

prevent short circuit problems that may arise. This extra bracing is necessary because the 
2-24

amorphous design uses a wound core rather than a round, cruciform core like the other designs in 

these design lines. Manufacturers and industry experts estimated the weight of the bracing as 7 

percent of the weight of the core and coil. The cost of the bracing was based on the price of 

enclosure steel. DOE added this additional hardware cost to each amorphous design in DLs 10, 

12, and 13. Additional detail can be found in chapter 5 of the preliminary TSD.

DOE seeks comment on the additional costs considered for amorphous designs in design 

lines 10, 12, and 13. Additionally, DOE seeks comment on whether these additional costs should 

be considered for liquid-immersed design lines that are 1500 kVA or greater, or whether the 

costs are specific to dry-type designs.

2.6.7 Other Regulatory Impacts on the Engineering Analysis

In conducting an engineering analysis, DOE recognizes that regulatory changes occurring 

outside of the standards-setting process can affect equipment manufacturing. Some of these 

changes can also affect the efficiency of the equipment. DOE attempts to identify all ―outside‖ 

issues that can impact the engineering analysis.

2.6.8 Baseline Efficiency and Candidate Standard Levels Analyzed

DOE analyzed designs over a range of efficiency values for each representative unit. 

Within the efficiency range, DOE developed designs that approximate a continuous function of 

efficiency. However, DOE analyzes the incremental impacts of increased efficiency by 

comparing discrete efficiency benchmarks to a constant baseline efficiency. The baseline 

efficiency evaluated for each representative unit is the existing standard level efficiency for 

distribution transformers established in DOE’s previous rulemaking. The incrementally higher 

efficiency levels, termed ―candidate standard levels‖ (CSLs), are meant to characterize the costefficiency relationship above the baseline. These CSLs are ultimately used by DOE if it decides 

to amend the existing energy conservation standards.

For the preliminary analysis, DOE considered several criteria when setting CSLs. First, 

DOE harmonized the efficiency values across single-phase transformers and the per-phase kVA 

equivalent three-phase transformers. For example, a 50 kVA single-phase transformer would 

have the same efficiency as a 150 kVA three-phase transformer. This approach is consistent with 

DOE’s methodology from the previous rulemaking. As such, DOE selected equivalent CSLs for 

several of the representative units that have equivalent per-phase kVA ratings.

Second, DOE selected equally spaced CSLs by dividing the entire efficiency range into 

five to seven evenly spaced increments. The number of increments depended on the size of the 

efficiency range. This allowed DOE to examine impacts based on an appropriate resolution of 

efficiency for each representative unit.

Finally, DOE adjusted the position of some of the equally spaced CSLs and examined 

additional CSLs. These minor adjustments to the equally spaced CSLs allowed DOE to consider 

important efficiency values based on the results of the software designs. For example, DOE 

adjusted some CSLs slightly up or down in efficiency to consider the maximum efficiency 

potential of non-amorphous design options. Other CSLs were added to consider important 
2-25

benchmark efficiencies, such as the NEMA Premium efficiency for LVDT distribution 

transformers. Last, DOE considered additional CSLs to characterize the maximumtechnologically feasible design for representative units where the harmonized per-phase 

efficiency value would have been unachievable for one of the representative units, or where 

symmetric core designs yielded an efficiency value greater than the highest efficiency achievable 

through traditional transformer designs. Additional detail on the CSLs selected for the 

preliminary analysis can be found in chapter 5 of the preliminary TSD.

For the NOPR, DOE will develop trial standard levels (TSLs) based on the CSLs for 

distribution transformers. DOE is considering several criteria in developing the TSLs, including, 

but not limited to, minimum LCC, maximum NPV, and maximum technologically feasible 

efficiency. These TSLs may include combinations of CSLs and the interaction between 

equipment classes. From the list of TSLs developed, DOE will select one as its proposed 

standard for the NOPR. DOE invites comment on the criteria it should use as the basis for 

selection of TSLs.

2.7 ENERGY USE AND END-USE LOAD CHARACTERIZATION

The energy use and end-use load characterization analysis (chapter 6 of the preliminary 

TSD) produced energy use estimates and end-use load shapes for distribution transformers. The 

energy use estimates enabled evaluation of energy savings from the operation of distribution 

transformer equipment at various efficiency levels, while the end-use load characterization 

allowed evaluation of the impact on monthly and peak demand for electricity from the operation 

of transformers.

The energy used by distribution transformers is characterized by two types of losses. The 

first are no-load losses, which are also known as core losses. No-load losses are roughly constant 

and exist whenever the transformer is energized (i.e., connected to live power lines). The second 

are load losses, which are also known as resistance or I2R losses. Load losses vary with the 

square of the load being served by the transformer. Because the application of distribution 

transformers varies significantly by type of transformer (liquid-immersed or dry-type) and 

ownership (electric utilities own approximately 95 percent of liquid-immersed transformers, 

commercial and industrial (C&I) entities use mainly dry-type), DOE performed two separate 

end-use load analyses to evaluate distribution transformer efficiency. The analysis for liquidimmersed transformers assumes that these are owned by utilities and uses hourly load and price 

data to estimate the energy, peak demand, and cost impacts of improved efficiency. For dry-type 

transformers, the analysis assumes that these are owned by C&I customers, so the energy and 

cost savings estimates are based on monthly building-level demand and energy consumption data 

and marginal electricity prices. In both cases, the energy and cost savings are estimated for 

individual transformers and aggregated to the national level using weights derived from either 

utility or C&I building data. Sections 2.7.1.1 and 2.7.1.2 provide an overview of the two 

methods of characterizing transformer loads.
2-26

2.7.1.1 Overview of the Hourly Load Model

For utilities, the cost of serving the next increment of load varies as a function of the 

current load on the system. To correctly estimate the cost impacts of improved transformer 

efficiency, it is therefore important to capture the correlation between electric system loads and 

operating costs, and between individual transformer loads and system loads. For this reason, 

DOE estimated hourly loads on individual liquid-immersed transformers using a statistical model 

that simulates two relationships: (1) the relationship between system load and system marginal 

price; and (2) the relationship between the transformer load and system load. Both are estimated 

at a regional level.

The regions used in the hourly load model are those defined in the Energy Information 

Administration’s (EIA) National Energy Modeling System (NEMS) Electricity Market Module1

(EMM). These regions are based on existing national reliability regions and, where they exist, 

areas with integrated wholesale electricity markets. Each region is in turn composed of a number 

of electric utility service territories.

The relationship between system load values and system marginal prices is derived for 

each region from hourly data collected by the Federal Energy Regulatory Commission (FERC) 

Form 714 and, where appropriate, day-ahead market data from independent system operators. 

FERC data provide hourly system load and system lambda values, in which the system lambda is 

defined approximately as the operating cost of the generating unit on the dispatch margin. Dayahead market data (collected for California, New England, and Texas) include the hourly system 

load and the market-clearing price. Data for 2008 were used, as this is the most recent year for 

which data from all sources were available. An illustration of these data for the Southeastern 

Electric Reliability Council (SERC) region is given in Figure 2.7.1.

DOE used a two-step modeling approach to define the relationship between system loads 

and system marginal prices: The data are first sorted into bins based on the size of the system 

load. These bins are illustrated in Figure 2.7.1 using different colors.

1. Within each bin, the average marginal price is calculated.

2. Within each bin, the difference between the average marginal price and the actual 

hourly marginal price is calculated (this difference is referred to as a price-delta), 

and a probability distribution for the price-deltas is estimated. The probability 

distribution of the price-deltas is modeled as a triangular distribution.
2-27

Figure 2.7.1 Load versus Marginal Price for Electricity Market Module Region: 

Southeastern Electric Reliability Council

To model the relationship between individual transformer loads and the system load, 

DOE used a joint probability distribution function (JPDF). Conceptually, this function answers 

the question: given that the system load is at a particular level relative to its maximum, what is 

the probability that the transformer load is at a given level relative to its maximum? Due to the 

lack of available data for individual transformer loads, DOE estimated the JPDF using hourly 

metered data for buildings.

DOE seeks comment on any additional sources of distribution transformer load data that 

could be used to validate the analysis.

2.7.1.2 Overview of the Monthly Load Model

Dry-type transformers are primarily installed on buildings and owned by the building 

owner/operator. Commercial and industrial (C&I) utility customers are typically billed monthly, 

with the bill based on both electricity consumption and demand. Hence, the value of improved 

transformer efficiency depends on both the load impacts on the customer’s electricity 

consumption and demand, as well as the customer’s marginal prices.

The customer sample of dry-type distribution transformer owners is taken from the EIA

Commercial Buildings Energy Consumption Survey (CBECS) databases.2,3 Survey data for the 

years 1992 and 1995 were used, as these are the only years for which monthly customer 

electricity consumption (kWh) and peak demand (kW) are provided. To account for changes in 

the distribution of building floor space by building type and size, the weights defined in the 1992 

and 1995 building samples were rescaled to reflect the distribution in the most recent 2003 

CBECS survey. CBECS covers primarily commercial buildings, but a significant fraction of 

transformers are shipped to industrial building owners. To account for this in the sample, data 

from the 2006 Manufacturing Energy Consumption Survey (MECS) were used to estimate the 

0

5 0

100

150

200

250

0 20000 40000 60000 80000 100000 120000 140000 160000

Lambda $/MWh

Load MWh
2-28

amount of floor space of buildings that might use the type of transformer covered by the 

rulemaking. The weights assigned to the building sample were rescaled to reflect this additional 

floor space. Only the weights of large buildings were rescaled.

For each DL, buildings with annual peak load less than the transformer capacity specified 

in the design were screened out of the sample, as these buildings would not house such 

transformers. The CBECS sample contains a wide variety of building sizes with widely varying 

annual peak loads. The larger buildings will undoubtedly contain multiple transformers, but DOE 

does not currently have any quantitative information on how the number of transformers 

installed in a building scales with either the building floor space or the building annual peak 

load. Thus, to account for the effect of multiple transformers on a single building, DOE used a 

simple approach in which the building sample weight is multiplied by the number of floors in the 

building. DOE seeks comment on whether this approach can be improved.

The transformer load characteristics needed for C&I building owners are the energy and 

demand savings associated with load losses. The energy savings depend on the load loss factor 

(LSF), which is proportional to the average value of the squared load. To estimate the load loss 

factor for each building, DOE used an expression that relates LSF to the load factor LF:

LSF = α*LF + (1-α)*LF2

where α is a parameter with α < 0.5. The load factor LF is equal to the ratio of the average hourly 

load to the peak load and is available from the CBECS data. DOE estimated a probability 

distribution for the parameter α based on hourly building load data from the End-use Load and 

Consumer Assessment Program (ELCAP) survey and additional confidential data. The demand 

savings depend on the coincidence between the transformer load and the building peak load, 

which is captured in a parameter known as the responsibility factor (RF). For a building with a 

single transformer the coincidence would be perfect and RF would equal one. In reality, the 

degree of coincidence depends on the details of how transformers are installed in buildings. 

Mathematically, the value of RF should also be correlated with the building load factor LF. To 

model diversity between transformer loads and the total building load, DOE constructed a 

statistical model that predicts RF as a function of LF. DOE estimated the parameters of this 

statistical model using the same hourly building load data as were used to model the loss factor.

2.8 MARKUPS FOR EQUIPMENT PRICE DETERMINATION

Chapter 7 of the preliminary TSD describes the process DOE used to determine the 

installed price of distribution transformers. DOE derived this installed price by applying markups 

to the manufacturer selling price that were determined in the engineering analysis (chapter 5 of 

the preliminary TSD). Markups, sales tax, and installation costs are the costs associated with 

bringing a manufactured transformer into service as an installed piece of electrical equipment. 

Electric utilities typically purchase liquid-immersed transformers from manufacturer 

representatives, so the sales price includes a relatively small handling markup applied to the 

manufacturer selling price. Dry-type transformers are subject to both distributor and contractor 

markups. Both liquid-immersed and dry-type distribution transformers are subject to sales tax 

and installation markups.
2-29

In the previous distribution transformer rulemaking DOE analyzed shipping costs as one 

of the markups used to determine installed equipment price. In this Preliminary Analysis, the 

markups for shipping costs have been moved into the engineering analysis; this is described in 

greater detail in section 2.6.5.2.

In the previous distribution transformers rulemaking DOE estimated the distributer 

markups factors for liquid-immersed and dry-type transformers as 1.07 and 1.15, respectively. 

These factors were based on stakeholder comments. DOE welcomes comments on these markup 

factors.

2.9 LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSES

Chapter 8 of the preliminary TSD describes the LCC analysis, which calculates the 

discounted savings in operating costs throughout the estimated average life of the covered 

equipment compared to any increase in the installed cost for the equipment that is likely to result 

directly from the imposition of a standard. In determining economic justification, the Energy 

Policy and Conservation Act (EPCA) directs DOE to consider a number of different factors, 

including the economic impact of potential standards on consumers. (42 U.S.C. 6295 

(o)(2)(B)(i))

To consider the economic impacts of standards, DOE calculated changes in life-cycle 

cost (LCC) that are likely to result from the CSL, as well as a simple payback period (PBP). 

DOE calculated both the LCC and the PBP using a Monte Carlo framework (described in 

Appendix 8B), so results are represented by distributions. The effect of amended standards on 

individual consumers includes a change in operating expense (usually decreased) and a change in 

purchase price (usually increased). DOE analyzed the net effect by calculating the change in 

LCC as compared to the base case. Inputs to the LCC calculation include the installed consumer 

cost (purchase price−including shipping, sales tax, and installation cost), operating expenses 

(energy and maintenance costs), lifetime of the equipment, and a discount rate.

Chapter 8 of the preliminary TSD also describes the PBP analysis, which calculates the 

amount of time needed to recover the additional cost that consumers pay for increased efficiency. 

Numerically, the simple PBP is the ratio of the increase in purchase price to the decrease in 

annual energy costs.

2.9.1 Electricity Price Analysis

DOE performed two electricity price analyses to determine the appropriate marginal 

prices for (1) liquid-immersed distribution transformers owned primarily by utility companies 

and (2) dry-type distribution transformers owned primarily by C&I building owners. For utility 

companies, the appropriate marginal price is the hourly system lambda or market-clearing price 

discussed in section 2.7. For building owners, the electricity prices are derived from a tariffbased analysis. The two approaches are described in more detail below.
2-30

2.9.1.1 Hourly Marginal Electricity Price Model

For liquid-immersed transformers, DOE based its energy price analysis on hourly system 

load and system lambda data collected from FERC (for regions without wholesale markets) or on 

hourly system load and day-ahead market clearing price data. In both cases, these prices 

represent the operating cost to the utility of meeting the next increment of load at any given time. 

In any given hour, a utility’s marginal price can be higher or lower than its average price; in 

general, the hourly price can be represented as a function of the system load level, as described 

in section 2.7.1.1. 

In addition to the hourly energy cost, there is a capacity cost saving associated with 

improved transformer efficiency. If the efficiency of a utility’s transformers is increased, then 

the utility will require less generation and transmission capacity to serve its customers’ load. The 

size of the capacity savings is dependent on the total reduction in load over all the transformers 

owned by the utility during the hour of system peak. The reduction in system-coincident 

transformer peak load is determined by the joint probability distribution function between system 

and transformer loads. The cost of capacity is estimated using the 2010 annual auction clearing 

prices for regions with functioning capacity markets and using capacity cost factors from the 

AEO 2010 for the other regions.

2.9.1.2 Monthly Marginal Electricity Price Model

For C&I building owners of dry-type transformers, DOE used marginal prices derived 

from a detailed analysis of utility tariffs (Coughlin et al., 2006). The tariff data and calculation 

tools were first developed by DOE for use in the Commercial Unitary Air Conditioning 

rulemaking.4

For each of the CBECS 1992 and 1995 records used in the building sample, DOE used the 

monthly energy consumption and demand data, along with tariff data, to calculate a baseline 

electricity bill. To obtain marginal prices, two additional calculations were done. Because the 

electricity bill depends on both energy consumption and demand, separate marginal prices are 

needed to represent the effect of varying these two quantities independently. The monthly 

marginal energy consumption (or demand) price is calculated simply by decrementing the energy 

consumption (or demand) and recalculating the bill. The tariff data were collected in 2004. To 

update prices to the analysis year (2010), two other datasets were used: the report ―Average 

Regulated Retail Price of Electricity‖ (Regulatory Research Associates, 2008) was used to 

estimate price increases between 2004 and 2007; and the ―Typical Bill and Average Price 

Reports‖ (Edison Electric Institute, 2007–2010) was used to estimate price increases from 2007 

to 2010.

2.9.2 Transformer Service Lifetime

DOE defined distribution transformer service life as the age at which the transformer 

retires from service. DOE assumed, based on ORNL-6847, ―Determination Analysis of Energy 

Conservation Standards for Distribution Transformers‖ (Barnes, 1996), that the average life of 

distribution transformers is 32 years. This lifetime assumption includes a constant failure rate of 

0.5 percent/year due to lightning and other random failures unrelated to transformer age and an 
2-31

additional corrosive failure rate of 0.5 percent/year starting at year 15. DOE adjusted the 

retirement distribution to maintain an average life of 32 years.

2.9.3 Maintenance Costs

The maintenance cost is the cost to the consumer of maintaining equipment operation. 

The maintenance cost is not the cost associated with the replacement or repair of components 

that have failed. Rather, it is associated with general maintenance. DOE assumed that the cost for 

general maintenance will not change with increased efficiency. In practice, there is little 

scheduled maintenance for transformers. Maintenance consists of brief annual checks for dust 

buildup, vermin infestation, and accidental or lightning damage.

2.9.4 Emerging Technology Scenarios

DOE will also conduct additional analysis on the potential energy savings for the 

following emerging technologies: symmetric core designs and core deactivation technology. 

These technologies are only feasible for a subset of the available design lines; therefore, the 

analysis of symmetric core transformers will be limited to three phase transformers, represented 

by DLs 4, 5 and 7−13; and transformers using core deactivation technology will be limited to 

LVDT, represented by DLs 6−8. These technologies are described in detail in chapter 5 of the 

preliminary TSD. 

2.9.4.1 Symmetric Core Transformers

Symmetric core transformers use a continuously wound core with 120 degree radial 

symmetry, resulting in a triangularly shaped core when viewed from above. One of the cited 

advantages of this core design lower no-load losses at the expense of higher manufacturing costs.

Symmetric core transformers are best suited to delta-delta or delta-wye connections, and would 

require the addition of a tertiary winding for wye-wye connections; this is described in greater 

detail in chapter 5 of the preliminary TSD. DOE recognizes that most utility-operated 

distribution transformers are wye-wye connected, and will analyze symmetric core transformers 

for C&I sectors where delta connections are common practice.

2.9.4.2 Core Deactivation Technology

Core deactivation technology employs the concept that a system of smaller transformers 

can replace a single, larger transformer. The smaller transformers that compose the system can 

then be activated and deactivated using core deactivation technology based on the loading 

demand, thus reducing the overall amount of core losses than would be seen with a single, larger, 

transformer. DOE only considered core deactivation technology for LVDT in the preliminary 

analysis. More information on core deactivation technology can be found in chapter 5.

2.10 SHIPMENTS ANALYSIS

One of the more important components of any estimate of future impacts from energy 

efficiency standards is equipment shipments (chapter 9). DOE must obtain forecasts of 

shipments for the base case and each potential standards case as inputs to the National Energy 
2-32

Savings (NES) Model. For the distribution transformer rulemaking, DOE chose an accounting 

model method to prepare shipment scenarios for the base case and the CSLs. The model keeps 

track of the aging and replacement of transformer capacity, given a projection of future 

transformer sales growth. New transformer capacity demand is created by growth in electrical 

demand. Transformer shipments, a retirement function, and the initial number of transformers in 

service influence how transformers in service and supply of transformer capacity change over 

time.

2.10.1 Inputs to Shipments Analysis

2.10.1.1 Shipments Data

The Department used historical transformer shipments data to calibrate a forecast of 

future transformer shipments and in-service stocks. DOE contractors provided an estimate of 

sales for the year 2009, disaggregated by equipment class and kilovolt-ampere (kVA) rating. In 

addition, the analysis made use of the sales data from the previous distribution transformers 

rulemaking for the year 2001,5also disaggregated by equipment class and kVA rating. The 

estimated sales data show a drop in shipments in 2009 relative to 2001 for liquid-immersed and 

LVDT transformers. In terms of total capacity of liquid-immersed shipments, the drop is about 

40 percent for single-phase units and 25 percent for three-phase units. The Department also 

observed a 33 percent drop in total capacity shipments for LVDT units. There are several factors 

contributing to the drop observed in the shipments, including declining housing starts and slow 

economic activity in most sectors. The Department corroborated the drop in estimated shipments 

of liquid-immersed units by reviewing the quantity indices of ―Power, distribution, and specialty 

transformer manufacturing‖ –North American Industry Classification System (NAICS) code 

335311, and ‖Electric power generation, transmission, and distribution‖ - NAICS code 221100. 

The quantity index data are available from the U.S. Bureau of Economic Affairs (BEA). NAICS

code 335311 indicates a decline of 12 percent in 2008acompared to 2001, while NAICS code 

221100 registered a decline of 44 percent in 2008 compared to the 2001 quantity index. The 

Department considers NAICS code 221100 to reasonably represent the trend in infrastructural 

spending of the utilities on distribution infrastructureb. The Department assumed the declining 

trend to continue into 2009, concluding that the drop in estimated shipments is validated through 

other comparable indicators.

The historical series of the power distribution and specialty transformer manufacturing 

(NAICS code 335311) quantity index for 1977 to 2008 is available from the BEA. The BEA 

transformer manufacturing quantity index provides information on how the aggregate shipments 

of transformers have changed over the 1977 to 2008 period. The Department used the 2001 and 

2009 shipments estimate by equipment class and kVA rating to determine the market shares for 

both liquid-immersed and dry-type distribution transformers. The Department used the BEA 

quantity index data to estimate aggregate transformer shipments from 1977 to 2000, and from 

2002-2008, using the sales estimates for the period from 2001 and 2009 as reference points.

 

a

2008 is the latest year for which quantity index data is available from BEA.

b Edison Electric Institute estimates 25 percent–30 percent of utilities’ infrastructural spending on distribution 

(Transforming America’s Power Industry: Investment Challenge 2010-2030. 2008)
2-33

2.10.2 Shipments Forecast

The Department constructed a simplified forecast of transformer shipments for the base 

case scenario based on the concept that long-term growth in transformer shipments will be driven 

by long-term growth in electricity consumption. The detailed dynamics of transformer shipments 

is highly complex. This complexity can be seen in the fluctuations in the total quantity of 

transformers manufactured as expressed by the BEA transformer quantity index. The Department 

examined the possibility of modeling the fluctuations in transformers shipped using a bottom-up 

model where the shipments are triggered by retirements and new capacity additions, but found 

that there were no sufficient data to calibrate model parameters within an acceptable margin of 

error. Hence, the Department de-coupled the overall shipments and retirement in the construction 

of the shipments forecast and maintained the age distribution of the in-service transformer stock 

using the retirement function.

The Department constructed the transformer shipments forecast assuming that transformer 

shipments growth is equal to forecasted growth in electricity consumption as given by EIA’s

AEO 2010 forecast up to the year 2035. For the years from 2036 to 2045, DOE extrapolated the

AEO 2010 forecast with the growth rate of electricity consumption for the period from 2025 to 

2035.

Distribution transformer shipments are organized into two categories: replacements and 

new capacity. Replacements occur when old transformers break down, corrode, are struck by 

lightning, or otherwise need to be replaced. New capacity purchases occur due to increases in 

electricity use that may be driven by increasing population, increasing commercial and industrial 

activity, or growth in electricity distribution systems. The model starts with an estimate of the 

overall growth in transformer capacity and then estimates shipments for particular design lines 

and transformer sizes using estimates of the relative market share for different design and size 

categories. Chapter 9 of the preliminary TSD provides a detailed description of how DOE 

conducted its shipments forecasts.

DOE seeks comment on recent changes in utility distribution transformer replacement and 

maintenance practices. In particular, DOE would like comments on any additional sources of 

utility replacement rates or maintenance and repair costs that should be considered in the 

analysis.

2.10.2.1 Efficiency Distribution and Efficiency Trend

The key inputs for calculating energy losses in the NIA include inputs from the LCC 

analysis that provide average rated losses for both no-load and load losses for each equipment 

class. These inputs incorporate efficiency distribution of the transformer market for the 

considered product, and therefore efficiency distribution is not treated separately in the NIA. The 

Department has considered a frozen efficiency for the analysis period.

DOE seeks comment on recent changes in distribution transformer sizing practices. In 

particular, DOE would like comments on any additional sources of trends in market share across 

equipment classes for either liquid-immersed or dry-type transformers that should be considered 

in the analysis. 
2-34

The Department seeks further comment on its tentative decision to use frozen efficiencies 

for the analysis period. Specifically, DOE would like comments on additional sources of data on 

trends in efficiency improvement.

2.11 NATIONAL IMPACT ANALYSIS

The NIA assesses the NPV to the Nation of total consumer LCC and NES. DOE 

determined both the NPV and NES for the efficiency levels considered for the equipment classes 

analyzed. The NES and NPV impacts are the cumulative energy and economic effects of a 

transformer energy conservation standard (chapter 10 of the preliminary TSD). DOE projected 

the impacts from the year the standard would take effect through a selected number of years in 

the future. DOE analyzed energy savings, energy cost savings, equipment costs, and NPV of 

savings (or costs) for each CSL. The national energy and cost savings (or increases) that would 

result from energy conservation standards depend on the projected energy savings per 

transformer and the anticipated numbers of transformers sold. DOE created base case 

transformer shipments projections that include units at various efficiency levels. It based the 

projections on historical information plus forecasts of market influences, national economic 

growth, and electricity consumption. DOE then derived energy savings for various CSLs from 

the cost-efficiency schedules.

As discussed in chapter 10 of the preliminary TSD, the NIA assesses the NPV of total 

national economic impacts. Analyzing impacts of Federal energy efficiency standards requires a 

comparison of projected U.S. energy consumption with and without amended standards. The 

base case, which is the projected U.S. energy consumption without amended standards, includes 

the mix of efficiencies being sold at the time the amended standard becomes effective.

DOE estimated national energy consumption for each year beginning with the expected 

effective date of the amended standard. It calculated national annual energy savings as the 

difference between two projections: a base case and an amended standards case. The analysis 

included estimated energy savings by fuel type used for generating electricity. DOE estimated 

energy consumption and savings based on site energy (kilowatt-hours (kWh) of electricity) and 

then converted the electricity consumption and savings to primary energy consumption.

2.12 LIFE-CYCLE COST SUBGROUP ANALYSIS

DOE will conduct the LCC sub-group analysis after the preliminary analysis and report 

the results in the NOPR.

While DOE expects amended distribution transformer energy conservation standards to 

reduce overall costs to the economy and consumers, there may be groups of consumers who see 

some increase in cost. In the next phase of the rulemaking, DOE will consider the results from 

the LCC analysis to evaluate the cost impacts on consumer sub-groups, such as other categories 

of transformer owners, including utilities, to see if they are differentially affected by potential 

amended energy conservation standards in a significant manner.
2-35

The analysis of these subgroups of transformer owners depends on identifying 

characteristics related to transformer use or economics that sets the subgroup apart from other 

transformer owners. DOE will analyze the effects on these groups by comparing the transformer 

owners’ capital and operating costs with and without an amended energy conservation standard. 

DOE will use LCC analysis methods for consumer sub-group analysis by modifying cost 

assumptions to reflect the situations of the subgroups. Factors that could result in differential 

impacts to subgroups include differences in energy prices and transformer loading.

DOE plans to evaluate variations in regional energy prices, variations in energy use, and 

variations in installation costs that might affect the NPV of an amended standard to consumer 

sub-populations. To the extent possible, DOE obtains estimates of the variability in each input 

quantity and considers this variability in its calculation of consumer impacts. The analysis is 

structured to answer questions such as: How many companies are better off with amended 

standards and by how much? How many companies are not better off and by how much? DOE 

discusses the variability in each input quantity and likely sources of information with the 

interested parties.

2.12.1 Proposed Subgroups

In the 2007 final rule, DOE evaluated the impacts of a standard on the following 

subgroups: municipal utilities, rural cooperatives and vault transformers5. DOE intends to repeat 

these analyses in the NOPR. The subgroups to be examined are both subsets of the entire 

national electric utility sample and, hence, the analysis will be limited to liquid-immersed 

distribution transformers, represented by DLs 1–5. DOE did not include dry-type distribution 

transformers, represented by DLs 6–13, in the LCC subgroup analysis since electric utilities use 

few, if any, dry-type transformers.

2.12.1.1 Municipal Utilities

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. When evaluated in the 2007 final rule, the increased savings from reduced load 

losses resulted in LCC savings for the municipal utilities subgroup that are slightly higher than 

for the national sample6. The extra LCC savings vary as a function of both the design line and 

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

transformer efficiency.

2.12.1.2 Rural Cooperatives

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. When evaluated in the 

2007 final rule, the reduced savings from reduced load losses resulted in LCC savings for the 

rural cooperatives subgroup that are slightly less than for the national sample.6The diminished 

LCC savings vary as a function of both the design line and the standard level, because the 
2-36

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.

2.12.1.3 Vault Transformers

Distribution transformers at higher efficiency levels have larger volumes and higher 

installation costs, due to required modifications to enlarge the vaults that house them. This can 

dramatically decrease the economic benefits from the highest standard levels.

DOE will be sensitive to purchase price increases that might negatively impact 

identifiable population groups. Additionally, DOE will assess the likely impacts of purchase 

price increases on equipment sales.

2.12.2 Consumer Participation

DOE seeks to inform and involve consumers and consumer representatives in the process 

of developing amended standards. This includes notification of consumer representatives during 

the rulemaking process and, where appropriate, seeking direct consumer input.

2.13 PRELIMINARY MANUFACTURER IMPACT ANALYSIS

The purpose of the MIA is to identify and quantify the likely impacts of amended energy 

conservation standards on manufacturers. DOE will identify and discuss a wide range of 

quantitative and qualitative industry impacts in interviews with manufacturers and other 

interested parties during the NOPR stage of the analysis. DOE will use the manufacturer 

interviews as well as the methodology described below in its evaluation of amended standards 

for distribution transformers.

DOE will conduct the MIA in three phases, and will further tailor the analytical 

framework based on the comments it receives. In Phase I, DOE will create an industry profile to 

characterize the industry and identify important issues that require consideration. In Phase II, 

DOE will prepare an industry cash flow model and a detailed interview questionnaire to guide 

subsequent discussions with manufacturers. In Phase III, DOE will interview manufacturers and 

assess the impacts of amended energy conservation standards both quantitatively and 

qualitatively. DOE assesses industry and subgroup cash flow impacts and industry NPV using 

the Government Regulatory Impact Model (GRIM), which considers potential investments, 

production costs, revenue impacts, and different shipment scenarios to assess the financial 

impact on the industry. DOE also assesses impacts on competition, manufacturing capacity, 

employment, and regulatory burden based on manufacturer interview feedback and discussions.

Until recently, DOE reported MIA results in its standards rulemakings only in the NOPR 

stage of the rulemaking. However, DOE is now evaluating and reporting preliminary MIA 

information at this preliminary analytical stage. DOE gathered the information for the analysis 

during the manufacturer interviews conducted after the engineering analysis. See chapter 12 of 

the preliminary TSD for more detail on the MIA.
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2.13.1 Sources of Information for the Manufacturer Impact Analysis

Many of the previously described analyses provide important information applicable to 

the MIA. Such information includes manufacturing costs and prices from the engineering 

analysis, as well as retail price and shipment forecasts. DOE will supplement this information 

with company financial data and other information gathered during interviews with 

manufacturers.

The interview process plays a key role in the MIA because it allows interested parties to 

express their views on important issues privately. DOE’s contractor has a non-disclosure 

agreement in place with interviewees to allow consideration of confidential or sensitive 

information in the decision-making process. Confidential information will not be made available 

in the public record. To preserve confidentiality, DOE’s contractor aggregates these perspectives 

across manufacturers, creating a combined opinion or estimate for DOE to use in analyzing the 

impacts standards will have on manufacturers. This process enables DOE to account for sensitive 

information shared by manufacturers during the rulemaking process.

The process also includes detailed interviews with manufacturers to gain insight into the 

range of potential impacts of amended energy conservation standards. Typically, the interviews 

solicit both quantitative and qualitative information on the potential impacts of efficiency levels 

on sales, direct employment, capital assets, and industry competitiveness. An interactive 

interview process, rather than a written response to a questionnaire, is used because it helps 

clarify responses and identify additional issues. Before the interviews, DOE will circulate a draft 

document showing estimates of the financial parameters based on publicly available information. 

DOE will solicit comments on these estimates during the interviews. See chapter 12 of the 

preliminary TSD for more detail on the methodology used in the MIA.

2.13.2 Industry Cash-Flow Analysis

The industry cash-flow analysis relies primarily on the GRIM. DOE uses the GRIM to 

analyze the expected financial impacts of more stringent energy conservation standards on the 

industry.

The GRIM analysis uses several factors to determine annual cash flows from an amended 

energy conservation standard: annual expected revenues; manufacturer costs, including cost of 

goods sold, depreciation, research and development, selling, general and administrative 

expenses; taxes; and conversion capital expenditures. DOE compares the results against base 

case projections that involve no amended energy conservation standards. The financial impact of 

amended energy conservation standards is the difference between the two sets of discounted 

annual cash flows. Other performance metrics, such as return on invested capital, also are 

available from the GRIM. See chapter 12 of the preliminary TSD for more information on the 

industry cash-flow analysis.

2.13.3 Manufacturer Subgroup Analysis

Industry cost estimates are inadequate to assess differential impacts among subgroups of 

manufacturers because these subgroups may have different cost structures or regulatory 
2-38

frameworks that affect their respective business models. For example, small and niche 

manufacturers, or manufacturers whose cost structure differs significantly from the industry 

average, could experience a more negative impact. While considering impacts on an individual 

firm basis would be ideal, such an approach is typically impractical given the number of firms 

involved. In place of this approach, DOE typically groups manufacturers exhibiting similar 

characteristics together to characterize the industry.

During the interview process, DOE will discuss the potential subgroups and subgroup 

members it has identified for the analysis. DOE will encourage manufacturers to recommend 

subgroups or characteristics that are appropriate for the subgroup analysis. See chapter 12 of the 

preliminary TSD for more detail on the manufacturer subgroup analysis.

2.13.4 Competitive Impacts Assessment

Section 342 (6)(B)(i)(V) of EPCA directs DOE to consider any lessening of competition 

likely to result from imposition of standards. DOE will consider whether an amended energy 

conservation standard is likely to reduce industry competition and will ask the U.S. Attorney 

General to determine the impacts, if any. The assessment will be based on manufacturer cost data 

and other information collected from manufacturer interviews. DOE will make a determined 

effort to gather and report firm-specific financial information and impacts. When assessing 

competitive impacts, DOE’s interviews generally focus on assessing asymmetrical cost 

increases, the potential increase in business risks from an increased proportion of fixed costs, and 

potential barriers to market entry (e.g., proprietary technologies). The competitive analysis may 

also focus on assessing any differential impacts on smaller manufacturers.

2.13.5 Cumulative Regulatory Burden

DOE recognizes and seeks to mitigate the overlapping effects on manufacturers of new 

or amended DOE standards and other regulatory actions affecting the same equipment. DOE will 

analyze and consider the impact on manufacturers of multiple, equipment-specific regulatory

actions.

2.13.6 Preliminary Results for the Manufacturer Impact Analysis

DOE conducted a series of preliminary interviews with manufacturers to discuss impacts 

that may result from a revised regulatory standard for distribution transformers. In general, 

manufacturers and other parties identified three areas of concern: (1) core steel availability, (2) 

equipment conversion costs, and (3) intellectual property.

DOE requests comment on its identification of key issues and requests data and 

information from interested parties that can assist in evaluating the potential impact of amended 

standards on manufacturers.

2.13.7 Core Steel Availability

Manufacturers commented that there is limited global supply for the types of core steel 

necessary to build higher efficiency distribution transformers. In particular, a standard level that 

required the use of an M2 grade steel or better could result in supply issues due to a lack of 
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qualified supply sources. Only a handful of global steel providers are capable of supplying M2 

grade steel and only one supplier is able to produce amorphous ribbon. As such, a sudden 

increase in demand for these core materials would likely result in a shortage, according to 

manufacturers. The increased demand for electrical steel from growing economies like China 

and India exacerbates the tight supply market. While the current global economic downturn has 

abated most supply issues, manufacturers indicated that a return of solid economic growth would 

only further strain the limited supply of these high quality core steels.

DOE welcomes comment on the supply of core steels used in its designs. In particular, 

DOE seeks comment on the global supply of M3, M2, and amorphous core steels compared to 

the projected consumption based on candidate standard levels.

2.13.8 Equipment Conversion Costs

Some manufacturers commented that certain technology options considered in the 

analysis may require large capital investments and retooling and strand existing assets. For 

example, entirely new machinery and manufacturing processes would be required to create 

symmetric core transformer designs. Similarly, if manufacturers decided to create their own 

amorphous cores for the amorphous design types, they would need to make large investments in 

new machinery to handle the amorphous material. While manufacturers could purchase 

prefabricated amorphous cores, an amended standard level that necessitates an amorphous design 

could cause the manufacturer to pursue its own amorphous core production to develop a 

competitive advantage in the marketplace. Last, an amended standard level requiring that mitered 

core construction completely replace butt-lapped cores would require some manufacturers to 

purchase additional mitering machines. Most small manufacturers do not currently have mitering 

capabilities, so they would have to outsource core production or face large capital investments. 

For each of the capital investments described, some portion of the manufacturers’ existing 

machinery for core production would be stranded. Additionally, manufacturers indicated that 

there are often very long lead times for obtaining advanced machinery. Several manufacturers 

commented that it would take approximately two years between the purchase request and the 

completed installation of new machinery for some of these capital investments.

2.13.9 Intellectual Property

Manufacturers expressed concerns about intellectual property rights pertaining to 

symmetric core designs. While the concept of a symmetric core transformer has existed for over 

a century, the practical implementation of the design was not developed until relatively recently. 

There are currently a small handful of companies in the world that have developed feasible 

symmetric core designs. Each of these companies owns patents for the designs, which are then 

licensed to other manufacturers who produce their own symmetric cores. This intellectual 

property would be a high hurdle for any manufacturer seeking to produce the technology on a 

large-scale.
2-40

2.14 UTILITY IMPACT ANALYSIS

The utility impact analysis includes an analysis of the effects of new energy conservation 

standards on the electric utility industry. For this analysis, DOE adapted NEMS, which is a large, 

multi-sectoral, partial-equilibrium model of the U.S. energy sector that the EIA has developed 

throughout the past decade, primarily for preparing EIA’s Annual Energy Outlook (AEO). In 

previous rulemakings, a variant of NEMSa, was developed to better address the specific impacts 

of an amended energy conservation standard. NEMS, which is available in the public domain, 

produces a widely recognized baseline energy forecast for the United States through the year 

2035. The typical NEMS outputs include forecasts of electricity sales, prices, and electric 

generating capacity.

DOE typically conducts the utility impact analysis as a scenario that departs from the 

latest AEO reference case. In other words, the energy savings impacts from amended energy 

conservation standards are modeled using NEMS-BT to generate forecasts that deviate from the 

AEO reference case.

2.15 EMPLOYMENT IMPACT ANALYSIS

The imposition of standards can affect employment both directly and indirectly. Direct 

employment impacts are changes, produced by new standards, in the number of employees at 

plants that produce the covered equipment and at the affiliated distribution and service 

companies. DOE evaluated direct employment impacts in the manufacturer impact analysis. 

Indirect employment impacts that occur because of the imposition of standards may result from 

customers shifting expenditures between goods (the substitution effect) and from changes in 

income and overall expenditure levels (the income effect).

DOE plans to utilize Pacific Northwest National Laboratory’s impact of sector energy 

technologies (ImSET) model to investigate the combined direct and indirect employment 

impacts. The ImSET model, which was developed for DOE’s Office of Planning, Budget, and 

Analysis, estimates the employment and income effects energy-saving technologies produced in 

buildings, industry, and transportation. In comparison with simple economic multiplier 

approaches, ImSET allows for more complete and automated analysis of the economic impacts 

of energy conservation investments.

2.16 ENVIRONMENTAL ASSESSMENT

Pursuant to the National Environmental Policy Act of 1969 and the requirements of 42 

U.S.C. 6295(o)(2)(B)(i)(VI) and 6316(a), DOE intends to prepare an environmental assessment 

of the impacts of amended energy conservation standards distribution transformers. The primary 

environmental effects of these standards would be reduced power plant emissions resulting from 

reduced consumption of electricity. DOE will assess these environmental effects by using 

 

a

currently termed NEMS-BT, BT referring to DOE’s Building Technologies Program
2-41

NEMS-BT to provide key inputs to its analysis. The portion of the environmental assessment 

that will be produced by NEMS-BT considers carbon dioxide (CO2), nitrogen oxides (NOx), and 

mercury (Hg). The environmental assessment also considers impacts on SO2 emissions and 

discusses particulate matter (PM) emissions. After a brief discussion of general methodology, 

this section will address each of the relevant emissions. The following section, Section 2.16.1, 

explains how DOE plans to monetize the benefits associated with emissions reductions.

2.16.1 Carbon Dioxide

In the absence of any Federal emissions control regulation of power plant emissions of 

CO2, a DOE standard is likely to result in reductions of these emissions. The CO2 emission 

reductions likely to result from a standard will be estimated using NEMS-BT and national energy 

savings estimates drawn from the NIA spreadsheet model. The net benefit of the standard is the 

difference between emissions estimated by NEMS-BT at each standard level considered and the 

AEO Reference Case. NEMS-BT tracks CO2 emissions using a detailed module that provides 

results with broad coverage of all sectors and inclusion of interactive effects.

2.16.2 Sulfur Dioxide

SO2 emissions from affected electric generating units (EGUs) are subject to nationwide 

and regional emissions cap and trading programs, and DOE has preliminarily determined that 

these programs create uncertainty about the potential standards’ impact on SO2 emissions. Title 

IV of the Clean Air Act sets an annual emissions cap on SO2 for affected EGUs in the 48 

contiguous states and the District of Columbia (D.C.). SO2 emissions from 28 eastern states and 

D.C. are also limited under the Clean Air Interstate Rule (CAIR, 70 Fed. Reg. 25162 (May 12, 

2005)), which created an allowance-based trading program. Although CAIR has been remanded 

to EPA by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit), see 

North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008), it remains in effect temporarily, 

consistent with the D.C. Circuit’s earlier opinion in North Carolina v. EPA, 531 F.3d 896 (D.C. 

Cir. 2008). On July 6, 2010, EPA issued the Transport Rule proposal, a replacement for CAIR, 

which would limit emissions from EGUs in 32 states, potentially through the interstate trading of 

allowances, among other options. 75 FR 45210 (Aug. 2, 2010). 

The attainment of emissions caps is typically flexible among EGUs and is enforced 

through the use of emissions allowances and tradable permits. Under existing EPA regulations, 

and under the Transport Rule if it is finalized, any excess SO2 emissions allowances resulting 

from the lower electricity demand caused by the imposition of an efficiency standard could be 

used to permit offsetting increases in SO2 emissions by any regulated EGU. However, if the 

standard resulted in a permanent increase in the quantity of unused emissions allowances, there 

would be an overall reduction in SO2 emissions from the standards. While there remains some 

uncertainty about the ultimate effects of efficiency standards on SO2 emissions covered by the 

existing cap and trade system, the NEMS-BT modeling system that DOE uses to forecast 

emissions reductions currently indicates that no physical reductions in power sector emissions 

would occur for SO2. 
2-42

2.16.3 Nitrogen Oxides

A cap on NOx emissions, affecting electric generating units in the CAIR region, would 

mean that the standards for distribution transformers may have little or no physical effect on NOx

emissions in the 28 eastern states and the D.C. covered by CAIR or any states covered by the 

proposed Transport Rule if the Transport Rule if finalized. The standards would, however, 

reduce NOx emissions in those 22 states not affected by the CAIR. As a result, DOE plans to use 

NEMS-BT to estimate the emissions reductions from possible standards in the states where 

emissions are not capped.

2.16.4 Mercury

Similar to emissions of SO2 and NOx, future emissions of Hg would have been subject to 

emissions caps. In May 2005, EPA issued the Clean Air Mercury Rule (CAMR). 70 FR 28606 

(May 18, 2005). CAMR would have permanently capped emissions of mercury for new and 

existing coal-fired power plants in all states by 2010. However, on February 8, 2008, the D.C. 

Circuit issued a decision in New Jersey v. Environmental Protection Agency, in which it vacated

CAMR. 517 F.3d 574 (D.C. Cir. 2008). EPA has decided to develop emissions standards for 

power plants under the Clean Air Act (Section 112), consistent with the D.C. Circuit’s opinion 

on CAMR. See http://www.epa.gov/air/mercuryrule/pdfs/certpetition_withdrawal.pdf. Pending 

EPA's forthcoming revisions to the rule, DOE is excluding CAMR from its environmental 

assessment. In the absence of CAMR, a DOE standard would likely reduce Hg emissions and 

DOE plans to use NEMS-BT to estimate these emission reductions. However, DOE continues to 

review the impact of rules that reduce energy consumption on Hg emissions, and may revise its 

assessment of Hg emission reductions in future rulemakings.

2.16.5 Particulate Matter

DOE acknowledges that particulate matter (PM) exposure can impact human health. 

Power plant emissions can have either direct or indirect impacts on PM. A portion of the 

pollutants emitted by a power plant are in the form of particulates as they leave the smoke stack. 

These are direct, or primary, PM emissions. However, the great majority of PM emissions 

associated with power plants are in the form of secondary sulfates, which are produced at a 

significant distance from power plants by complex atmospheric chemical reactions that often 

involve the gaseous (non-particulate) emissions of power plants, mainly SO2 and NOx. The 

quantity of the secondary sulfates produced is determined by a very complex set of factors 

including the atmospheric quantities of SO2 and NOx, and other atmospheric constituents and 

conditions. Because these highly complex chemical reactions produce PM comprised of different 

constituents from different sources, EPA does not distinguish direct PM emissions from power 

plants from the secondary sulfate particulates in its ambient air quality requirements, PM 

monitoring of ambient air quality, or PM emissions inventories. For these reasons, it is not 

currently possible to determine how the amended standard impacts either direct or indirect PM 

emissions. Therefore, DOE is not planning to assess the impact of these standards on PM 

emissions. Further, as described previously, it is uncertain whether efficiency standards will 

result in a net decrease in power plant emissions of SO2, which are now largely regulated by cap 

and trade systems. 
2-43

DOE seeks input on its plans to use NEMS-BT to conduct the environmental assessment 

for the equipment covered by this rulemaking.

2.17 MONETIZATION OF EMISSIONS REDUCTION BENEFITS

DOE plans to consider the estimated monetary benefits likely to result from the reduced 

emissions of CO2 and other pollutants that are expected to result from each of the standard levels 

considered.

In order to estimate the monetary value of benefits resulting from reduced emissions of 

CO2, DOE plans to use the most current Social Cost of Carbon (SCC) values developed and/or 

agreed to by an interagency process. The SCC is intended to be a monetary measure of the 

incremental damage resulting from greenhouse gas (GHG) emissions, including, but not limited 

to, net agricultural productivity loss, human health effects, property damage from sea level rise, 

and changes in ecosystem services. Any effort to quantify and to monetize the harms associated 

with climate change will raise serious questions of science, economics, and ethics. But with full 

regard for the limits of both quantification and monetization, the SCC can be used to provide 

estimates of the social benefits of reductions in GHG emissions. 

At the time of this notice, the most recent interagency estimates of the potential global 

benefits resulting from reduced CO2 emissions in 2010, expressed in 2009$, were $4.9, $22.1, 

$36.3, and $67.1 per metric ton avoided. For emission reductions that occur in later years, these 

values grow in real terms over time. Additionally, the interagency group determined that a range 

of values from 7 percent to 23 percent should be used to adjust the global SCC to calculate 

domestic effects, although DOE will give preference to consideration of the global benefits of 

reducing CO2 emissions. To calculate a present value of the stream of monetary values, DOE 

will discount the values in each of the four cases using the discount rates that had been used to 

obtain the SCC values in each case.

DOE recognizes that scientific and economic knowledge continues to evolve rapidly as to 

the contribution of CO2 and other GHG to changes in the future global climate and the potential 

resulting damages to the world economy. Thus, these values are subject to change. 

DOE also intends to estimate the potential monetary benefit of reduced NOX emissions 

resulting from the standard levels it considers. For NOx emissions, available estimates suggest a 

very wide range of monetary values for NOX emissions, ranging from $447 to $4,591 per ton in 

2009$).aIn accordance with U.S. Office of Management and Budget (OMB) guidance, DOE will 

conduct two calculations of the monetary benefits derived using each of the economic values 

used for NOx, one using a real discount rate of 3 percent and another using a real discount rate of 

7 percent.b

 

a

For additional information, refer to U.S. Office of Management and Budget, Office of Information and Regulatory 

Affairs, 2006 Report to Congress on the Costs and Benefits of Federal Regulations and Unfunded Mandates on 

State, Local, and Tribal Entities, Washington, DC.

b

OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
2-44

DOE does not plan to monetize estimates of Hg in this rulemaking. DOE is aware of 

multiple agency efforts to determine the appropriate range of values used in evaluating the 

potential economic benefits of reduced Hg emissions. DOE has decided to await further guidance 

regarding consistent valuation and reporting of Hg emissions before it once again monetizes Hg 

in its rulemakings.

2.18 REGULATORY IMPACT ANALYSIS

In the NOPR stage, DOE will prepare a regulatory impact analysis (RIA) pursuant to 

Executive Order 12866, ―Regulatory Planning and Review,‖ 58 FR 51735 (October 4, 1993), 

which is subject to review under the Executive Order by the Office of Information and 

Regulatory Affairs at the Office of Management and Budget. The RIA addresses the potential for 

non-regulatory approaches to supplant or augment energy conservation standards in order to 

improve the energy efficiency or reduce the energy consumption of the equipment covered under 

this rulemaking.

DOE recognizes that voluntary or other non-regulatory efforts by manufacturers, utilities, 

and other interested parties can substantially affect energy efficiency or reduce energy 

consumption. DOE tentatively plans to base its assessment on the actual impacts of any such 

initiatives to date, but also will also consider, to the extent possible, information presented by 

interested parties regarding the impacts existing initiatives might have in the future (see chapter 

17 of the preliminary TSD).
2-45

REFERENCES

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<http://www.eia.doe.gov/oiaf/aeo/overview/>

2. U.S. Department of Energy-Energy Information Administration 1992 Commercial Buildings 

Energy Consumption Survey (CBECS). (1992).at 

<http://www.eia.doe.gov/emeu/cbecs/92microdat.html>

3. U.S. Department of Energy-Energy Information Administration 1995 Commercial Building 

Energy Consumption and Expenditures (CBECS). (1995).at 

<http://www.eia.gov/emeu/cbecs/microdat.html>

4. U.S. Department of Energy – Office of Energy Efficiency and Renewable Energy Appendix 

8E. Technical Aspects of The Tariff-Based Approach For Room Air Conditioner Energy 

Price. Residential Clothes Dryers and Room Air Conditioners Preliminary Technical Support 

Document (2010).at 

<http://www1.eere.energy.gov/buildings/appliance_standards/residential/pdfs/clothesdryers_ts

d/clothesdryers_roomac_preanalysis_app8e.pdf>

5. Office of Energy Efficiency and Renewable Energy Energy Conservation Program for 

Commercial and Industrial Equipment: Energy Conservation Standards for Distribution 

Transformers; Final Rule. 10 CFR Part 431 (2007).

6. U.S. Department of Energy-Office of Building Technologies Chapter 11. Life-Cycle Cost 

Subgroup Analysis. Distribution Transformers Energy Conservation Standard Technical 

Support Document (2007).